10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the Quarterly Period Ended September 30, 2014

OR

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

for the transition period from _______________ to _______________

Commission File Number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)

Delaware	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

i

GLOSSARY OF TERMS

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

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

Bcf. One billion cubic feet.

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

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

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

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

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

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

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

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

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.

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

ii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	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.

1

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.

2

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.

3

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.

4

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Nature of Business

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

5

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.

6

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.

7

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.

8

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.

9

LINN ENERGY, LLC

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.

10

LINN ENERGY, LLC

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.

11

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(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.

12

LINN ENERGY, LLC

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

13

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(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.

14

LINN ENERGY, LLC

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

15

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(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.

16

LINN ENERGY, LLC

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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

	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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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.

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

21

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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.

22

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

23

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(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

24

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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.

25

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

26

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

27

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	)

28

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	)

29

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	)

30

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

31

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

32

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

33

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

34

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.

35

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.

36

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

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. The acquisition included approximately 303 Bcfe of proved reserves as of the acquisition date.

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 acquisition included approximately 1,410 Bcfe of proved reserves as of the acquisition date.

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.

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.

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

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.

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

37

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.

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, as defined below, in full as well as repay a portion of the borrowings outstanding under the LINN Credit Facility.

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.

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, 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

38

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.

39

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.

40

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.

41

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.

42

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.

43

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	)

44

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.

45

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.

46

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.

47

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	%

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

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.

48

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.

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 $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.

49

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.

50

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

51

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).

52

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

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.

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

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,

54

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

55

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.

58

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

59

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

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.

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)

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EX-2.1

Exhibit 2.1

EXCHANGE AGREEMENT

by and among

LINN ENERGY HOLDINGS, LLC,

BERRY PETROLEUM COMPANY, LLC (d/b/a BERRY OIL COMPANY),

and

EXXON MOBIL CORPORATION

dated as of September 18, 2014

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EXCHANGE AGREEMENT

This Exchange Agreement (this “Agreement”) is made as of September 18, 2014, by and among Linn Energy Holdings, LLC, a Delaware limited liability company (“LINN HOLDINGS”), and Berry Petroleum Company, LLC, doing business as Berry Oil Company in the state of Texas, a Delaware limited liability company, each with a mailing address of 600 Travis Street, Suite 5100, Houston, Texas 77002 (“Berry” and collectively with LINN HOLDINGS, “LINN”), and Exxon Mobil Corporation, a New Jersey corporation (“ExxonMobil”), acting through its agent and attorney-in-fact, XTO Energy Inc., a Delaware corporation (“XTO”), with a mailing address of 810 Houston Street, Fort Worth, Texas 76102. LINN and ExxonMobil are sometimes referred to in this Agreement collectively as the “Parties” and individually as a “Party.”

WITNESSETH

WHEREAS, LINN desires to exchange certain oil and gas properties and related assets located in Eddy and Lea Counties, New Mexico, Andrews, Dawson, Ector, Glasscock, Howard, Martin, Midland, and Upton Counties, Texas, and ExxonMobil desires to exchange certain oil and gas properties and related assets located in Kern County, California, in each case on the terms and conditions provided in this Agreement, including the attached exhibits and schedules;

NOW THEREFORE, in consideration of the mutual promises of the Parties contained in this Agreement, the Parties agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1Definitions. As used in this Agreement, capitalized terms shall have the meanings given to such terms in Annex A.

ARTICLE II

EXCHANGE OF ASSETS

Section 2.1Agreement to Exchange Assets. Subject to the terms and conditions of this Agreement, LINN agrees to exchange with and assign to ExxonMobil the LINN Assets, to be effective as of the Effective Time, and ExxonMobil agrees to exchange with and assign to LINN the ExxonMobil Assets to be effective as of the Effective Time, in both cases, less and except the applicable Excluded Assets.

Section 2.2The Assets. The term “Assets” shall mean, with respect to LINN as Transferring Party, the LINN Assets and, with respect to ExxonMobil as Transferring Party, the ExxonMobil Assets.

Section 2.3Excluded Assets. The following are specifically excluded from the Assets and are reserved and retained by Transferring Party (collectively, “Excluded Assets”):

(i)all Income Tax records, and all of the corporate minute books, financial records and other business records that relate to the business generally of the Transferring Party Group (including the ownership and operation of its Assets);

(ii) all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to its Assets with respect to any period of time prior to the Effective Time;

(iii)all claims and causes of action of Transferring Party (a) arising under or with respect to any of its Existing Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds) or (b) related to Retained Liabilities;

(iv)all rights and interests of Transferring Party (a) under any policy or agreement of insurance, (b) under any bond or (c) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property;

(v)all Hydrocarbons produced from its Assets with respect to all periods prior to the Effective Time;

(vi)all claims, rights or interests of Transferring Party in or to any refunds, credits, loss carryforwards and similar Tax assets, together with any interest due thereon or penalty rebate arising therefrom, with respect to (a) Income Taxes imposed on Transferring Party or any of its Affiliates, (b) Asset Taxes or any other Taxes relating to such Transferring Party’s Assets, in each case, attributable to any period (or portion thereof) prior to the Effective Time, or (c) any Taxes attributable to Transferring Party’s Excluded Assets;

(vii)all personal computers and associated peripherals and all radio and telephone equipment unless located on the Assets to be assigned (except those items described on Schedule 2.3(vii)-LINN or Schedule 2.3(vii)-ExxonMobil, as applicable);

(viii)all documents and instruments of Transferring Party that may be protected by an attorney-client privilege;

(ix) all data that cannot be disclosed to Acquiring Party as a result of confidentiality arrangements under agreements with third parties (after using commercially reasonable efforts to obtain any consents);

(x)all audit rights arising under any of Transferring Party’s Existing Contracts or otherwise with respect to any period prior to the Effective Time or to any of Transferring Party’s Excluded Assets except for any Imbalances assumed by Acquiring Party;

(xi)all geophysical and other seismic and related technical data and information relating to Transferring Party’s Assets that cannot be transferred due to restrictions with third parties without payment of a fee or other penalty (unless Acquiring Party agrees to, and does, pay such fees and penalties), and geophysical or geological interpretations that Transferring Party reasonably deems to be proprietary;

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(xii)documents prepared or received by Transferring Party, if any, with respect to (a) lists of prospective acquirers for Transferring Party’s Assets compiled by Transferring Party, (b) offers submitted by other prospective acquirers of Transferring Party’s Assets, (c) analyses by Transferring Party of any offers submitted by any prospective acquirer, (d) correspondence between or among Transferring Party, its respective representatives, and any prospective acquirer other than Acquiring Party and (e) correspondence between Transferring Party or any of its respective representatives with respect to any offers, the prospective acquirers, or the transactions contemplated by this Agreement;

(xiii)all proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property of any member of the Transferring Party Group;

(xiv)all funds from production attributable to the Transferring Party’s Assets that are held in suspense by the Transferring Party or its Affiliates that were required by Law to be escheated to Governmental Authorities prior to or as of the Closing and any claims related thereto;

(xv)assets listed on Schedule 2.3(xv)-LINN or Schedule 2.3(xv)-ExxonMobil;

(xvi)any offices (including field offices other than those listed on Schedule 2.3(xvi)-LINN or Schedule 2.3(xvi)-ExxonMobil, as applicable), office leases, and any personal property located in or on such offices or office leases;

(xvii)with respect to the Assets being assigned by LINN, the LINN Excluded Depths and the LINN Excluded Producing Wells and Properties;

(xviii)all fee mineral interests associated with Transferring Party’s Assets (but subject to the grant of the royalty-free Oil and Gas Lease in the form attached as Exhibit H-LINN or Exhibit H-ExxonMobil, as applicable); and

(xix)concurrent rights to use all of the easements and surface rights expressly granted or implied in the Leases or the Existing Contracts but only to the extent applicable to the Excluded Assets, subject to the provisions of the applicable Joint Use Agreement by and between LINN and ExxonMobil.

Section 2.4Transfer as of the Effective Time. Ownership of the Assets shall be transferred from Transferring Party to Acquiring Party at Closing, effective as of the Effective Time. Subject to the express provisions of this Agreement, Transferring Party shall be entitled to any amount realized from and accruing to Transferring Party’s interest in the Assets prior to the Effective Time, if any, and shall be responsible for all expenses attributable to such Assets prior to the Effective Time. Subject to the express provisions of this Agreement, Acquiring Party shall be entitled to any amount realized from and accruing to such Assets on or after the Effective Time, and shall be responsible for all expenses attributable to such Assets on or after the Effective Time.

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ARTICLE III

CONSIDERATION

Section 3.1Exchange Consideration. The consideration for the transfer of the LINN Assets to ExxonMobil in accordance with this Agreement, the receipt and sufficiency of which are hereby acknowledged by the Parties, is comprised of the transfer of the ExxonMobil Assets to LINN as described in Article II above. The consideration for the transfer of the ExxonMobil Assets to LINN in accordance with this Agreement, the receipt and sufficiency of which are hereby acknowledged by the Parties, is comprised of the transfer of the LINN Assets to ExxonMobil as described in Article II above. The consideration described in this Section 3.1 shall be referred to herein as “Exchange Consideration.”

Section 3.2Exchange Consideration Allocation. To the extent required by Treasury regulations sections 1.1031(d)-1T and 1.1060-1(b)(8), the Parties shall use commercially reasonable efforts to agree to an allocation of the relevant Exchange Consideration, Assumed Obligations, and any other items constituting consideration for applicable Income Tax purposes (to the extent known at such time) among the relevant Assets that complies with Treasury regulation Sections 1.1031(d)-1T and 1.1031(j)-1(b) and Section 1060 of the Code and the Treasury regulations promulgated thereunder within sixty (60) days after the Closing Date (the “Allocation”). If the Parties reach an agreement with respect to the Allocation, (i) the Parties shall use commercially reasonable efforts to update the Allocation in a manner consistent with the forgoing provisions of the Code and Treasury regulations following any adjustment to the relevant Exchange Consideration pursuant to this Agreement, (ii) the Parties shall, and shall cause their Affiliates to, report consistently with the Allocation in all Tax returns, including IRS Form 8594 to the extent applicable, which the Parties shall timely file with the IRS, and neither Party shall take any position in any Tax return that is inconsistent with the Allocation, as adjusted, in each case, unless required to do so by a final determination as defined in Section 1313 of the Code, and (iii) each of the Parties agree to promptly advise each other regarding the existence of any Tax audit, controversy or litigation related to the Allocation.

Section 3.3 Closing Amount. The consideration for the rights and obligations of the Parties set forth in this Agreement will include an additional cash payment in the amount of the Net Closing Amount to account for the following adjustments related to each Transferring Party’s Assets adjusted from zero (as adjusted, the “Closing Amount”):

A.The “Upward Adjustments,” with respect to the Assets of a Transferring Party, shall consist of the following:

(i)The amount of all costs and expenses incurred and paid by Transferring Party in the ownership and operation of the Assets that is attributable to the period after the Effective Time, including lease operating expense, drilling and completion costs, seismic costs, workover costs, capital expenditures, lease rental and maintenance costs, royalty payments, insurance costs, joint interest billings and overhead charges under applicable operating agreements or applicable unit agreements, and all prepaid expenses related to the wells, but excluding general overhead charges, Affiliate charges, liabilities, obligations and expenses attributable to claims, investigations, administrative proceedings or litigation directly or indirectly arising out of or resulting from (a) actual or claimed personal injury, including death,

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(b) the gross negligence or willful misconduct of any member of the Transferring Party Group in the operation of its Assets prior to Closing, (c) Remediation of environmental conditions attributable to Transferring Party’s Assets in connection with an Environmental Defect, (d) Transferring Party’s Excluded Assets or Retained Liabilities, (e) curing Title Defects attributable to Transferring Party’s Assets, (f) the furnishing of make-up gas or other gas balancing obligations, (g) working interests, royalties, overriding royalties or other interests held in suspense attributable to Transferring Party’s Assets, (h) Asset Taxes or Income Taxes, or (i) any other matter for which Transferring Party is indemnifying Acquiring Party under Article XII.

(ii)The value of all Hydrocarbons in storage or existing in stock tanks, pipelines and/or plants (including inventory)as of the Effective Time that are attributable to its Assets, such value to be based on the various contract prices for such Hydrocarbons in effect as of the Effective Time (or if there is no such contract price, then the posted price in the field in which such Hydrocarbons were produced, or if no such posted price exists for such Hydrocarbons, the market price in the field in which such Hydrocarbons were produced, in each case as of the Effective Time), net of any royalties borne by and not reimbursed to Transferring Party by a purchaser of production.

(iii)The total amount of all Asset Taxes allocable to Acquiring Party in accordance with Section 13.1, but paid or payable by Transferring Party or any of its Affiliates.

(iv)To the extent provided for by the Existing Contracts of Transferring Party, with respect to each Asset of Transferring Party that is underproduced relative to other undivided interests in the same Asset, an amount equal to the underproduced mcf volume set forth on the attached Schedule 5.7-LINN or Schedule 5.7-ExxonMobil, as applicable, as of the Effective Time, multiplied by $4.57 per mcf.

(v)Any other upward adjustment agreed upon by Transferring Party and Acquiring Party.

B.The “Downward Adjustments,” with respect to the Assets of a Transferring Party, shall consist of the following:

(i)The amount of the proceeds received by Transferring Party, if any, that are attributable to its Assets after the Effective Time (net of any royalties borne by and not reimbursed to Transferring Party by a purchaser of production).

(ii)The amount of all advances and deposits received by Transferring Party relating to its Assets which accrue or have accrued on or after the Effective Time.

(iii)The total amount of all Asset Taxes allocable to Transferring Party in accordance with Section 13.1, but paid or payable by Acquiring Party or any of its Affiliates.

(iv)To the extent provided for by the Existing Contracts of Transferring Party, with respect to each Asset of Transferring Party that is overproduced relative to other undivided interests in the same Asset, an amount equal to the overproduced mcf volume set forth in the attached Schedule 5.7-LINN or Schedule 5.7-ExxonMobil, as applicable, as of the Effective Time, multiplied by $4.57 per mcf.

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(v)An amount equal to the value of all net proceeds from production attributable to such Transferring Party’s Assets that are held in suspense as of Closing in accordance with Section 12.12.

(vi)An amount equal to the Environmental Adjustment, if any in accordance with Section 4.13(D).

(vii)An amount equal to the Allocated Value of any Asset that is not being transferred at Closing in accordance with Section 7.3 or Section 7.4 below.

(viii)Any other downward adjustment agreed upon by Transferring Party and Acquiring Party.

C. Closing Settlement Statement. No later than five (5) Business Days before the Closing Date, each Transferring Party shall prepare, in accordance with Section 12.11 of this Agreement, and deliver to Acquiring Party a statement (an “Estimated Settlement Statement”) setting forth each adjustment related to Transferring Party’s Assets for purposes of determining the Closing Amount to be paid or received by the Parties, as applicable, at Closing. The Estimated Settlement Statement prepared by each Transferring Party shall be accompanied by reasonable supporting documentation. Within three (3) Business Days of receipt of the Estimated Settlement Statement, each Acquiring Party will have the right to deliver to Transferring Party a written report containing any changes (together with a reasonable description thereof) it may have to the Estimated Settlement Statement delivered by such Transferring Party. Each Estimated Settlement Statement, as agreed upon by the Parties, will be used to determine the Closing Amount; provided, that if the Parties cannot agree on the applicable Estimated Settlement Statement prior to Closing, the Estimated Settlement Statement, as presented by Transferring Party, as to its particular Assets, will be used to determine the Closing Amount. The Closing Amount for each Party’s Assets shall be set off against the other to determine the net amount to be paid at Closing, which shall be further adjusted in accordance with Section 4.8, Section 4.9 and Section 4.15, if required pursuant to such sections (as so adjusted, the “Net Closing Amount”).

ARTICLE IV

TITLE AND ENVIRONMENTAL MATTERS AND

CASUALTY DEFECTS

Section 4.1Title Examination. By September 20, 2014, Transferring Party shall make available to Acquiring Party (unless disclosure by Transferring Party is restricted by agreement with a third party or unless such data is maintained only in the Transferring Party’s business development files in the ordinary course of business) all title data in Transferring Party’s possession, and all title data to which Transferring Party has reasonable access, relating to its Assets including the following:

A.title opinions, abstracts of title, title status reports, and curative matters, but excluding acquisition title opinions;

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B.the Existing Contracts;

C.Records relating to the payment of rentals, royalties, shut-in gas royalties, and other payments due under any lease or agreement;

D.Records relating to filing of returns for or the payment of ad valorem, property, production, severance, excise and other Taxes and assessments based on or measured by the ownership of property or the production of Hydrocarbons or the receipt of proceeds therefrom; and

E.ownership reports, maps and surveys.

Acquiring Party shall be permitted, at its expense, to make copies of any of the title data. Acquiring Party shall be entitled to perform or cause to be performed, at Acquiring Party’s expense, such additional title examination as Acquiring Party deems necessary or appropriate. Transferring Party shall cooperate reasonably with Acquiring Party in Acquiring Party’s efforts to examine and approve title. Transferring Party shall also make available to Acquiring Party, upon reasonable notice during normal business hours, Transferring Party’s personnel who are knowledgeable with respect to Transferring Party’s Assets in order that Acquiring Party may make such diligent investigation as Acquiring Party considers necessary or appropriate. All investigations and due diligence conducted by Acquiring Party shall be conducted at Acquiring Party’s sole cost, risk and expense, and any conclusions made from any examination done by Acquiring Party shall result from Acquiring Party’s own independent review and judgment. Acquiring Party shall coordinate its access rights and physical inspections of Transferring Party’s Assets with Transferring Party to minimize any inconvenience to or interruption of the conduct of business by Transferring Party, and Transferring Party shall have the right to accompany Acquiring Party in connection with any physical inspection of such Assets. Acquiring Party shall abide by Transferring Party’s, and any third party operator’s safety rules, regulations, and operating policies while conducting its due diligence evaluation of such Assets, and to the extent required by any third party operator, execute and deliver any required bonding agreement of such third party operator or provide evidence that Acquiring Party maintains insurance as may be required by such third party operator.

Section 4.2Defensible Title. For purposes of this Agreement, “Defensible Title” shall mean, subject to Permitted Encumbrances:

A.With respect to each of its Assets, title that obligates Transferring Party to bear no more than the working interest set forth in Exhibit A-1 and A-5-LINN as to the LINN Wells or Exhibit B-ExxonMobil as to the ExxonMobil Wells, as applicable, without a corresponding increase in the net revenue interest;

B.With respect to each of its Assets, title that entitles Transferring Party to receive no less than the net revenue interest set forth in Exhibit A-1 and A-5-LINN as to the LINN Wells or Exhibits A-1, A-2, A-3 or A-4-LINN as to the LINN Acreage Tracts, or Exhibit B-ExxonMobil as to the ExxonMobil Wells, as applicable;

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C.In the case of LINN as Transferring Party, with respect to each of the LINN Acreage Tracts, LINN owns at least the Net Acres for such LINN Acreage Tract as is represented in Exhibits A-1, A-2, A-3 or A-4-LINN for such LINN Acreage Tract;

D.Transferring Party is not in default of a material provision of a Lease, including a failure to produce Hydrocarbons in paying quantities for all applicable periods of time after the end of the primary term of such Lease (if applicable); and

E.With respect to each of Transferring Party’s Assets, such Assets are free from all Liens other than Permitted Encumbrances.

F.With respect to the LINN Assets, the working interest and the net revenue interest of an Allocated Value Asset shall be uniform throughout the Spraberry Trend Interval unless Exhibits A-1, A-2, A-3, A-4 or A-5-LINN specifically states otherwise.

Except for Transferring Party’s special warranty of title contained in the Assignment or the royalty-free Oil and Gas Lease, as applicable, and subject to either Party’s rights to terminate this Agreement pursuant to Section 15.1B, Acquiring Party hereby acknowledges and agrees that Section 4.8 shall be Acquiring Party’s sole and exclusive remedy for any defect of title or any title matter, including any Title Defect, and Acquiring Party hereby expressly waives any and all other rights or remedies with respect thereto.

Section 4.3Permitted Encumbrances. The term “Permitted Encumbrances” shall mean:

A.Lessor’s royalties, overriding royalties, reversionary interests and similar burdens if the net cumulative effect of such burdens does not reduce the net revenue interest of Transferring Party in each of its Assets below the net revenue interest for such Asset set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, or increase the working interest of Transferring Party above that set forth on Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, without a corresponding increase in the net revenue interest.

B.Division orders and sales contracts terminable without penalty upon no more than ninety (90) days notice to the purchaser of production.

C.All third party consents to assign and preferential purchase rights listed on Schedule 5.9-LINN and Schedule 5.9-ExxonMobil.

D.Liens for Taxes or assessments not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business.

E.Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s, and other similar Liens or charges arising in the ordinary course of business (i) if they have not been filed pursuant to Law, or (ii) if filed, they have not yet become due and payable or payment is being withheld as provided by Law, or (iii) if their validity is being contested in good faith by appropriate action.

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F.All rights to consent by, required notices to, filings with, or other actions by Governmental Authorities in connection with the sale or conveyance of oil and gas leases or interests if they are customarily obtained subsequent to the sale or conveyance.

G.Rights of reassignment arising upon final intention to abandon or release the applicable Assets, or any of them.

H.Easements, rights-of-way, servitudes, permits, surface leases and other rights relating to surface operations which individually or in the aggregate do not materially diminish the value of, or impair the conduct of operations on the applicable Assets or do not reduce the net revenue interest of Transferring Party in any of its Assets below the net revenue interest set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, or increase the working interest of Transferring Party above that set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, without a corresponding increase in the net revenue interest, for such Asset.

I.All other Liens, charges, encumbrances, contracts, agreements, instruments, obligations, defects and irregularities affecting the applicable Assets which individually or in the aggregate do not interfere materially with the operation, value or use of any of the Assets, do not materially prevent Transferring Party from receiving the proceeds of production from any of its Assets, do not reduce the interest of Transferring Party with respect to any of its Assets below the net revenue interest set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, and do not increase the costs and expenses that such Transferring Party is obligated to pay above the working interest set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, without a corresponding increase in the net revenue interest, for such Asset.

J.All rights reserved to or vested in any Governmental Authority to control or regulate any of the applicable Assets in any manner, and all applicable laws, rules and orders of any Governmental Authority.

K.Any Title Defects that Acquiring Party may have expressly waived in writing or which are deemed to have been waived pursuant to Section 4.4 below.

L.Any Title Defects arising as a result of Transferring Party taking any action required by the terms of this Agreement or as a result of Acquiring Party failing to consent to allowing Transferring Party to take any action pursuant to Section 7.1.

Section 4.4Notice of Title Defects. Acquiring Party shall notify Transferring Party in writing of any Title Defect (a “Title Defect Notice”) as soon as practicable after Acquiring Party has knowledge thereof, but in no event later than 5:00 p.m. Central Daylight Time on October 31, 2014 (“Defect Deadline”). All Title Defects not asserted by Acquiring Party in a Title Defect Notice by the Defect Deadline shall be deemed waived by Acquiring Party for purposes of this Agreement, but shall not affect the special warranty of title contained in the Assignment. To be effective, each Title Defect Notice shall be in writing (which shall include email), and shall include (a) a description of the alleged Title Defect(s); (b) the Assets affected by the Title Defect; (c) supporting documents reasonably necessary for Transferring Party to verify the

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existence of the alleged Title Defect(s); (d) the amount of the decrease in the net revenue interest in the Asset or increase in the working interest in the Asset (without a corresponding increase in the net revenue interest) or amount of the decrease in Net Acres, as applicable; (e) the proposed value of the Title Defect; and (f) the proposed remedy for the Title Defect(s). A “Title Defect” shall mean any encumbrance, encroachment, irregularity, or other defect that causes Transferring Party not to have Defensible Title as of Closing in and to the applicable Assets; provided that the Permitted Title Matters shall not be considered Title Defects.

Section 4.5Value of a Title Defect. Exhibits A-1, A-2, A-3, A-4 or A-5-LINN, and Exhibit B-ExxonMobil, as applicable, lists the allocated values (“Allocated Values”) for each Asset given value by the Parties (each an “Allocated Value Asset”) for adjustments due to uncured Title Defects and Casualty Defects asserted pursuant to this Agreement. Exhibit G lists the Allocated Values for each LINN Replacement Acreage Tract. The value of an uncured Title Defect shall be calculated as follows (as so calculated the “Title Defect Value”):

A.If the Title Defect is an increase in the working interest of an Allocated Value Asset from the working interest for that Allocated Value Asset set forth in Exhibit A-1 or A-5-LINN or Exhibit B-ExxonMobil, as applicable (without a corresponding increase in the net revenue interest), then the value of the Title Defect shall equal the product of multiplying the Allocated Value of such Allocated Value Asset, as set forth in Exhibit A-1 or A-5-LINN, and Exhibit B-ExxonMobil, as applicable, for such Allocated Value Asset by a fraction, the numerator of which is an amount equal to the actual decimal working interest Acquiring Party shall be obligated for, less the decimal working interest for such Allocated Value Asset shown on Exhibit A-1 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, and the denominator of which is the working interest for such Allocated Value Asset shown on such Exhibit A-1 or A-5-LINN or Exhibit B-ExxonMobil, as applicable.

B.If the Title Defect is a decrease in net revenue interest from the net revenue interest set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, for an Allocated Value Asset, the value of the Title Defect shall equal the product of multiplying the Allocated Value of the affected Allocated Value Asset as set forth in such Exhibits A-1, A-2, A-3, A-4 or A-5-LINN, and Exhibit B-ExxonMobil, as applicable, by a fraction the numerator of which is an amount equal to the net revenue interest shown on such Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, for that Allocated Value Asset, less the actual decimal net revenue interest to which Transferring Party would be entitled to as a result of its ownership interest in that Allocated Value Asset, and the denominator of which is the net revenue interest shown in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, for that Allocated Value Asset.

C.In connection with the LINN Acreage Tracts, if the Title Defect is based on LINN owning less Net Acres than those represented on Exhibits A-1, A-2, A-3 and A-4-LINN, then the value of the Title Defect shall be equal to the product of multiplying the Allocated Value set forth inExhibits A-1, A-2, A-3 and A-4-LINN for such LINN Acreage Tract by a fraction the numerator of which is the Net Acres for such LINN Acreage Tract shown on Exhibits A-1, A-2, A-3 and A-4-LINN, less the actual Net Acres, and the dominator of which is the Net Acres shown for such LINN Acreage Tract on Exhibits A-1, A-2, A-3 or A-4-LINN.

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D.If the Title Defect is a Lien on the Assets that is liquidated in amount, then the value of the Title Defect shall equal the amount necessary to be paid to remove that Lien.

E.Notwithstanding anything to the contrary contained in this Agreement, the aggregate value of all Title Defects upon any Asset shall not exceed the Allocated Value of such Asset.

Section 4.6Title Benefits. If Transferring Party determines that the ownership of any Asset entitles Transferring Party to a larger net revenue interest or a smaller working interest (without a corresponding decrease in the net revenue interest) than that set forth on Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, or a larger amount of Net Acres than set forth on Exhibits A-1, A-2, A-3 or A-4-LINN for LINN Acreage Tracts (each a “Title Benefit”), then such Transferring Party shall notify (such notice, a “Title Benefit Notice”) Acquiring Party of such change in interest in writing as soon as practicable after Transferring Party has Knowledge thereof, but in no event later than the Defect Deadline. To be effective, each Title Benefit Notice shall be in writing and shall include (a) a description of the alleged Title Benefit(s), (b) the Assets affected by the Title Benefit, (c) the increase in net revenue interest or decrease in working interest (without a corresponding decrease in net revenue interest) or the amount of the increase in Net Acres, as applicable, in such Asset(s) affected by the Title Benefit, and (d) the proposed value of the Title Benefit, and (e) the proposed remedy for the Title Benefit. Transferring Party shall be deemed to have conclusively waived any Title Benefit of which Transferring Party fails to notify Acquiring Party in writing in the manner described in this Section 4.6. The value of any Title Benefit shall be determined as follows (as so determined the “Title Benefit Value”):

A.If Transferring Party and Acquiring Party agree on the value of such Title Benefit, then that amount shall be the value of the Title Benefit.

B.If Transferring Party and Acquiring Party do not agree on the value of such Title Benefit, then the value of the Title Benefit shall be determined by using the same formulas set forth in Sections 4.5 A, 4.5B, and 4.5C for Title Defects, as applicable.

Notwithstanding anything to the contrary contained in this Section 4.6, if there is an unresolved dispute as of the Closing pursuant to this Section 4.6 with respect to any Title Benefit properly asserted by Transferring Party, there shall be no adjustment at Closing to the Assets on account of such disputed Title Benefit, the Asset affected by such disputed Title Benefit shall be assigned to Acquiring Party at Closing notwithstanding the disputed Title Benefit, and the disputed Title Benefit shall be resolved using the same procedure for the resolution of disputed Title Defects in Section 4.9.

Section 4.7Title Defect and Title Benefit Threshold. Notwithstanding anything to the contrary, with respect to Transferring Party’s Assets, in no event shall there be any adjustments or any other remedy hereunder for any individual Title Defect or Title Benefit for which the value of such Title Defect or Title Benefit does not exceed $20,000, after which point Acquiring Party shall be entitled to an adjustment for such Title Defect or Title Benefit to the extent of the full the value of such Title Defect or Title Benefit, as applicable.

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Section 4.8Remedy for Title Defect. Transferring Party shall have the right for a period beginning when the Title Defect Notice is timely received, continuing until 5:00 p.m. Central Daylight Time on November 14, 2014, (the “Title Cure Period”) to cure a Title Defect to the reasonable satisfaction of Acquiring Party. If a Title Defect is cured to the reasonable satisfaction of Acquiring Party prior to the end of the Title Cure Period, any Well or Lease affected by such Title Defect shall be assigned to Acquiring Party at Closing without any adjustment on account of such Title Defect. If a Title Defect is not cured to the reasonable satisfaction of Acquiring Party prior to the end of the Title Cure Period, then:

A.The Title Defect Values for all Title Defects where LINN is the Transferring Party in excess of $20,000 shall be added to the Title Benefit Values for all Title Benefits where ExxonMobil is the Transferring Party to obtain the “LINN Defect Amount”. The Title Defect Values for all Title Defects where ExxonMobil is the Transferring Party in excess of $20,000 shall be added to the Title Benefit Values for all Title Benefits where LINN is the Transferring Party to obtain the “ExxonMobil Defect Amount”. The ExxonMobil Defect Amount shall be subtracted from the LINN Defect Amount to calculate the “Net Defect Amount”.

B.If the Net Defect Amount is less than Two Percent (2%) of the total Allocated Values given on Exhibits A-1, A-2, A-3, A-4 and A-5-LINN (the “Defect Deductible”) there will be no adjustments for Title Defects or Title Benefits at Closing.

C.If the absolute value of the Net Defect Amount exceeds the Defect Deductible then:

(i)in the case of a positive Net Defect Amount, the Parties will revise Exhibits A-1, A-2, A-3, A-4 or A-5-LINN by November 17, 2014 to include the Leases associated with the LINN Replacement Acreage Tract(s) onExhibit G - LINN to the extent necessary to deliver additional Net Acres to ExxonMobil of equivalent value to the Net Defect Amount less the Defect Deductible. The Parties will attempt, in good faith, to agree to such Leases to be included on Exhibits A-1, A-2, A-3, A-4 or A-5-LINN, as applicable, using, to the extent reasonably practicable, LINNReplacement Acreage Tracts covering similar Net Acres and having similar Allocated Values, working interests and net revenue interests.

(ii) in the case of a negative Net Defect Amount, the Parties will revise Exhibit A-2-LINN by November 17, 2014 to exclude the Leases associated with the LINN Acreage Tract(s) on Exhibit A-2- LINN to the extent necessary to deliver Net Acres to ExxonMobil of equivalent value to the absolute value of the Net Defect Amount less the Defect Deductible. The Parties will attempt, in good faith, to agree to such Leases to be excluded from Exhibit A-2, as applicable, excluding, to the extent reasonably practicable, LINN Replacement Acreage Tracts to the Assets associated with the ExxonMobil Defect Amount.

D.If the Net Defect Amount less the Defect Deductible is (A) a positive amount that exceeds the total Allocated Value of Exhibit G-LINN or (B) a negative amount that exceeds the total Allocated Value of Exhibit A-2- LINN, then the Parties will agree to designate additional Net Acres for adjustment under this Section 4.8, or adjust the Closing Amount by the remaining Net Defect Amount (less the Defect Deductible).

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E.If a Defect Value is greater than or equal to the entire Allocated Value for the associated Asset and either Section 4.8(C)(i) or Section 4.8(C)(ii) is applicable, the Wells and Leases associated with the asserted Title Defect may be removed from Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit A-ExxonMobil and/or Exhibit B-LINN or Exhibit B-ExxonMobil(as applicable) and retained by the Transferring Party at the Transferring Party’s option.

F.In the event the Parties do not agree on the existence of a Title Defect or Title Benefit or the amount of a Title Defect Value or Title Benefit Value, the Parties shall proceed to Closing without adjustment for the disputed Assets, and shall resolve their dispute in accordance with Section 4.9.

Section 4.9Title Dispute Resolution. LINN and ExxonMobil shall attempt, in good faith, to reach agreement on the existence of each Title Defect, Title Benefit, and the value of and remedy for each Title Defect and Title Benefit and the adequacy of any cure of any Title Defect (collectively “Title Disputes”) prior to the Closing Date. If LINN and ExxonMobil are unable to agree on any Title Dispute on or before the end of the Title Cure Period, either Party shall have the right to elect, upon written notice to the other Party, to initiate arbitration to resolve such Title Dispute. All Title Disputes shall be exclusively and finally resolved pursuant to this Section 4.9. There shall be a single arbitrator, who shall be a title attorney with at least ten (10) years experience in oil and gas titles involving properties in the state in which the Assets with the largest aggregate Allocated Value of all of the Assets in question are located (the “Title Arbitrator”). The Title Arbitrator shall not have worked as an employee or outside counsel for either Party or its Affiliates during the five (5) year period preceding the arbitration or have any financial interest in the dispute. The Title Arbitrator shall be selected by mutual agreement of LINN and ExxonMobil within fifteen (15) days after the election of a Party to utilize the provisions of this Section 4.9 with respect to a Title Dispute, or absent such agreement during the fifteen (15) day period, by the Dallas, Texas office of the AAA. In connection with the engagement of the Title Arbitrator, each Party shall execute such engagement, indemnity and other agreements as the Title Arbitrator shall require as a condition to such engagement. The place of arbitration shall be Dallas, Texas, and the arbitration shall be conducted in accordance with the AAA Rules to the extent such rules do not conflict with the terms of this Section 4.9. The Title Arbitrator’s determination shall be made within thirty (30) days after submission of Title Disputes (but in no event later than the submission of the relevant Transferring Party’s Final Settlement Statement) and shall be final and binding upon both Parties, without right of appeal. In making his or her determination, the Title Arbitrator shall be bound by the provisions of Section 4.6, Section 4.7, and Section 4.8, as applicable, and, subject to the foregoing, may consider such other matters as in the opinion of the Title Arbitrator are necessary to make a proper determination. The Title Arbitrator, however, may not award (i) Acquiring Party a greater value to a Title Defect than the value claimed by Acquiring Party in its applicable Title Defect Notice or (ii) Transferring Party a greater value to a Title Benefit than the value claimed by Transferring Party in the applicable Title Benefit Notice. The Title Arbitrator shall act for the limited purpose of determining (1) the existence of or nature of an asserted Title Defect or Title Benefit, and (2) as to a dispute about the value of a Title Defect or Title Benefit, which Parties’ calculation of the value of the Title Defect or Title Benefit should be accepted. The Title Arbitrator may not award damages (except as represented by the value of a Title Dispute), interest or penalties to either Party with respect to any Title Dispute. LINN and ExxonMobil shall each bear its own legal fees and other costs of presenting its case to the Title Arbitrator, and

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shall each bear one-half of the costs and expenses of the Title Arbitrator. Nothing herein shall operate to cause Closing to be delayed on account of any unresolved dispute pursuant to this Section 4.9 with respect to any Title Defect properly asserted by Acquiring Party or any Title Benefit properly asserted by Transferring Party. Based upon the Title Arbitrator’s decision, the Parties will, in accordance with Section 4.8, either (i) upon mutual agreement, assign or reassign, as required, the Assets necessary to place the Parties in the same position as they would have been had the Title Arbitrator’s decision been made prior to Closing, or (ii) if the Parties cannot mutually agree to the forgoing, adjust the Closing Amount by the Allocated Value of the Asset that would have been assigned or reassigned under the foregoing if the Parties had agreed to such an assignment or reassignment.

Section 4.10Environmental Assessment. Subject to Section 8.2, prior to the Defect Deadline, and upon reasonable prior notice to Transferring Party, Acquiring Party shall:

(i)have the right to enter upon the lands covered by Transferring Party’s Assets, inspect the same, and conduct such tests, examinations, investigations, and studies as Acquiring Party deems to be necessary or appropriate to determine the environmental condition of Transferring Party’s Assets (“Acquiring Party’s Environmental Assessment”); provided, however, Acquiring Party shall have no right to conduct invasive environmental testing on Transferring Party’s Assets, including a Phase II environmental assessment, without the consent of Transferring Party, which consent shall not be unreasonably withheld and shall not disclose the results of Acquiring Party’s Environmental Assessment to any Third Party other than Acquiring Party’s advisors and consultants who agree to keep it confidential; and

(ii)have reasonable access to all environmental and permitting Records relating to the Assets to the extent in Transferring Party’s possession or control.

Section 4.11Environmental Defect Notice. If Acquiring Party, in its sole discretion, determines, as a result of Acquiring Party’s Environmental Assessment, that there exists an Environmental Defect, Acquiring Party may notify Transferring Party in writing (such notice, an “Environmental Defect Notice”) of such Environmental Defect as soon as reasonably practical after its discovery, but in any event no later than the Defect Deadline. All Environmental Defects not asserted by Acquiring Party by the Defect Deadline shall be deemed waived by Acquiring Party. An “Environmental Defect” shall mean a condition that exists on or in connection with an Asset of the Transferring Party with respect to the air, land, soil, surface, subsurface strata, surface water, ground water or sediments which causes (or if brought to the attention of the applicable Governmental Authority, would cause) such Asset to be subject to fine or penalty, liability, clean-up or Remediation under any of the Environmental Laws. To be effective, an Environmental Defect Notice shall be in writing, and shall include (a) a description of the asserted Environmental Defect, including the facts and basis under Environmental Laws for such asserted Environmental Defect, (b) the Assets affected by the Environmental Defect, (c) the documentation concerning or supporting the asserted Environmental Defect and (d) an estimate of the cost of Remediation associated with the asserted Environmental Defect, including the information and computations (in reasonable detail) upon which Acquiring Party’s estimate is based.

Section 4.12 Thresholds and Value of an Environmental Defect.

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A.The value of an uncured Environmental Defect shall be the good faith estimated cost of Remediation for such uncured Environmental Defect (the “Environmental Defect Amount”).

B.Notwithstanding anything to the contrary, with respect to a Transferring Party’s Assets, in no event shall there be any adjustments or any other remedy provided by Transferring Party hereunder for any individual Environmental Defect for which the Environmental Defect Amount does not exceed $20,000.

Section 4.13Remedies for Environmental Defects.

A.Transferring Party shall have the right, at its sole expense, from receipt of an Environmental Defect Notice timely delivered until January 21, 2015 (the “Environmental Cure Period”) to Remediate any Environmental Defect.

B.If Remediation of any Environmental Defect is completed prior to Closing, the Asset affected by such Environmental Defect shall be assigned to Acquiring Party at Closing. If an Environmental Defect is not Remediated prior to Closing, but Transferring Party notifies Acquiring Party prior to Closing that it intends to Remediate the Environmental Defect, the Asset affected by such Environmental Defect shall not be assigned by Transferring Party to Acquiring Party at Closing, but if Transferring Party Remediates the Environmental Defect during the Environmental Cure Period, then Transferring Party, as soon as practicable thereafter, shall assign to Acquiring Party the Asset affected by the Remediated Environmental Defect, and any necessary adjustments in accordance with Section 12.11 for such Asset shall be made in the Final Settlement Statement.

C.If Transferring Party disputes the existence of an Environmental Defect or Acquiring Party’s estimate of the cost of Remediation, it shall, within ten (10) Business Days after Transferring Party’s receipt of the Environmental Defect Notice, notify Acquiring Party in writing, and shall, as applicable, identify (i) which Assets are the subject of the dispute; (ii) the facts and basis under Environmental Laws for disputing the existence of the asserted Environmental Defect; (iii) the documentation supporting Transferring Party’s dispute of the asserted Environmental Defect; and (iv) Transferring Party’s estimate of the cost of Remediation, if any, associated with the asserted Environmental Defect, including the information and computations on which Transferring Party’s estimate is based. The Parties shall promptly attempt, in good faith, to reach agreement regarding the existence of, nature of, or cost or adequacy of Remediation associated with any asserted Environmental Defect, or a mutually acceptable adjustment to remedy such asserted Environmental Defect. If Transferring Party and Acquiring Party are unable to agree on such matters before two (2) Business Days prior to the Closing Date, then the dispute shall be resolved pursuant to Section 4.14 below.

D.If an Environmental Defect is not Remediated prior to the Closing (or the end of the Environmental Cure Period if the Transferring Party gives proper notice under Section 4.13(B)), then

(i)If the net of all Environmental Defect Amounts where LINN is the Transferring Party less the Environmental Defect Amounts where ExxonMobil is the

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Transferring Party (the “Net Environmental Defect Amount”) exceed the Defect Deductible, then the Closing Amount will be adjusted downward for the Transferring Party’s Assets with the greater amount of Environmental Defect Amounts by the Net Environmental Defect Amount less the Defect Deductible (the “Environmental Adjustment”).

(ii)If the net of all Environmental Defect Amounts where LINN is the Transferring Party less the Environmental Defect Amounts where ExxonMobil is the Transferring Party does not exceed the Defect Deductible, then the Closing Amount will not be adjusted and any Assets withheld from Closing by the Transferring Party will be conveyed to the Acquiring Party within ten (10) Business Days thereafter.

Section 4.14Environmental Dispute Resolution. LINN and ExxonMobil shall attempt, in good faith, to reach agreement regarding the existence of, nature of, or cost or adequacy of Remediation associated with any asserted Environmental Defect prior to the Closing Date. If Transferring Party and Acquiring Party are unable to agree on or before the Closing Date about the existence of, nature of, an Environmental Defect or cost or adequacy of Remediation associated with the asserted Environmental Defect, then the Parties shall initiate arbitration to resolve such matters. All such matters shall be exclusively and finally resolved pursuant to thisSection 4.14. There shall be a single arbitrator, who shall be a reputable environmental consultant or engineer with at least ten (10) years’ experience in corrective environmental action regarding oil and gas properties (the “Environmental Arbitrator”). The Environmental Arbitrator shall not have worked as an employee or consultant for either Party or its Affiliates during the five (5) year period immediately preceding the arbitration or have any financial interest in the dispute. The Environmental Arbitrator shall be selected by mutual agreement of LINN and ExxonMobil within fifteen (15) days after the election of a Party to utilize the provisions of this Section 4.14 with respect to an alleged Environmental Defect, or absent such agreement, during the fifteen (15) day period, by the Dallas, Texas office of the AAA. In connection with the engagement of the Environmental Arbitrator, each Party shall execute such engagement, indemnity and other agreements as the Environmental Arbitrator shall require as a condition to such engagement. The place of arbitration shall be Dallas, Texas, and the arbitration shall be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of thisSection 4.13. The Environmental Arbitrator’s determination, as applicable, shall be made within thirty (30) days after submission of the matters in dispute (but in no event later than the submission of the relevant Transferring Party’s Final Settlement Statement) and shall be final and binding upon the Parties, without right of appeal. In making its determinations, the Environmental Arbitrator shall be bound by the provisions of Section 4.11, Section 4.12, and Section 4.13, and may consider such other matters as, in the opinion of the Environmental Arbitrator, are necessary or helpful to make a proper determination. The Environmental Arbitrator may consult with and engage disinterested third persons to advise the arbitrator, including other environmental consultants. The Environmental Arbitrator shall act as an expert for the limited purpose of determining (1) the existence of or nature of an asserted Environmental Defect, and (2) as to a dispute about the cost of Remediation, which of the Parties’ estimates of the cost of Remediation should be accepted. The Environmental Arbitrator may not award damages (except as represented by the value of an Environmental Defect), interest, or penalties to any Party with respect to any matter. Transferring Party and Acquiring Party shall each bear its own legal fees and other costs of presenting its respective case and shall each bear one-half of the costs and expenses of the Environmental Arbitrator.

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Section 4.15Casualty Defects; Condemnation. If, prior to Closing, any of the Assets are substantially damaged or destroyed by fire, explosion, flood, hurricane, tornado, earthquake, acts of God or other casualty or is taken by condemnation or under right of eminent domain (“Casualty Defect”), the Transferring Party of such Assets shall notify Acquiring Party promptly after such event. The Transferring Party of the Assets affected by the Casualty Defect shall have the right, but not the obligation, to cure any such Casualty Defect by repairing such damage or, in the case of personal property or fixtures, replacing the damaged Assets with equivalent items, no later than the Closing. If a Casualty Defect exists at Closing, Acquiring Party shall proceed to acquire the Assets affected by the Casualty Defect, but the Closing Amount shall be adjusted by the aggregate reduction in value due to such Casualty Defect, which value shall be determined by taking into account the Allocated Value of any Allocated Value Asset to which such Casualty Defect relates. Notwithstanding anything to the contrary contained in this Section 4.15, the Transferring Party of the Assets prior to the Closing affected by the Casualty Defect shall be entitled to retain all insurance proceeds, condemnation awards and any claims against other parties relating to any such Casualty Defect.

Section 4.16Condition of the Assets. Acquiring Party acknowledges and agrees that, subject to the provisions of this Article IV and Article V and Article XII, Acquiring Party shall acquire Transferring Party’s Assets (including such Assets for which a notice of an Environmental Defect is given pursuant to Section 4.11) in an “AS IS, WHERE IS” condition and shall assume all risks that such Assets may contain waste materials (whether toxic, hazardous, extremely hazardous or otherwise) or other adverse physical conditions, including, but not limited to, the presence of unknown abandoned wells, pumps, pits, pipelines or other waste or spill sites which may not have been revealed by Acquiring Party’s Environmental Assessment. EXCEPT AS OTHERWISE SPECIFICALLY PROVIDED FOR IN THIS AGREEMENT, UPON THE OCCURRENCE OF CLOSING, ALL RESPONSIBILITY AND LIABILITY RELATED TO SUCH CONDITIONS, WHETHER KNOWN OR UNKNOWN, FIXED OR CONTINGENT, SHALL BE TRANSFERRED FROM TRANSFERRING PARTY TO ACQUIRING PARTY WITHOUT RECOURSE AGAINST TRANSFERRING PARTY. WITHOUT LIMITING THE FOREGOING, AT CLOSING, EXCEPT AS OTHERWISE SPECFICALLY PROVIDED FOR IN THIS AGREEMENT, ACQUIRING PARTY WAIVES ITS RIGHT TO RECOVER FROM TRANSFERRING PARTY AND FOREVER RELEASES AND DISCHARGES THE TRANSFERRING PARTY GROUP AND AGREES TO DEFEND, INDEMNIFY AND HOLD TRANSFERRING PARTY GROUP HARMLESS FROM ANY AND ALL DAMAGES, CLAIMS, LOSSES, LIABILITIES, PENALTIES, FINES, LIENS, JUDGMENTS, COSTS AND EXPENSES WHATSOEVER (INCLUDING, WITHOUT LIMITATION, ATTORNEY’S FEES AND COSTS), WHETHER DIRECT OR INDIRECT, FORESEEN OR UNFORESEEN, THAT MAY ARISE OR MAY HAVE ARISEN PRIOR TO, ON OR AFTER THE EFFECTIVE TIME ON ACCOUNT OF OR IN ANY WAY CONNECTED WITH THE ENVIRONMENTAL OR OTHER PHYSICAL CONDITION OF TRANSFERRING PARTY’S ASSETS OR ANY VIOLATION BY TRANSFERRING PARTY, ACQUIRING PARTY OR ANY OTHER PARTY OF ANY APPLICABLE LEASE, CONTRACT OR OTHER INSTRUMENT (BUT ONLY TO THE EXTENT SUCH RELATES TO THE ENVIRONMENTAL OR PHYSICAL CONDITION OF SUCH ASSETS) OR OF ANY APPLICABLE EXISTING OR FUTURE ENVIRONMENTAL LAW, REGULATION, ORDER OR OTHER DIRECTIVE OF ANY

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GOVERNMENTAL AUTHORITY OR JUDICIAL ENTITY, HAVING JURISDICTION APPLICABLE THERETO, INCLUDING WITHOUT LIMITATION, THE ENVIRONMENTAL LAWS. ACQUIRING PARTY IS AWARE THAT TRANSFERRING PARTY’S ASSETS HAVE BEEN USED FOR EXPLORATION, DEVELOPMENT AND PRODUCTION OF HYDROCARBONS AND THAT THERE MAY BE PETROLEUM, PRODUCED WATER, WASTES OR OTHER MATERIALS LOCATED ON OR UNDER THE LANDS COVERED BY TRANSFERRING PARTY’S LEASES (OR LANDS POOLED OR ASSOCIATED THEREWITH). EQUIPMENT AND SITES INCLUDED IN TRANSFERRING PARTY’S ASSETS MAY CONTAIN ASBESTOS, HAZARDOUS SUBSTANCES OR NATURALLY OCCURRING RADIOACTIVE MATERIAL (“NORM”). NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS AND EQUIPMENT AS SCALE, OR IN OTHER FORMS. THE WELLS, MATERIALS AND EQUIPMENT LOCATED ON TRANSFERRING PARTY’S LEASES OR LANDS POOLED OR ASSOCIATED THEREWITH MAY CONTAIN NORM AND OTHER WASTES OR HAZARDOUS SUBSTANCES, AND NORM-CONTAINING MATERIAL AND OTHER WASTES MAY HAVE BEEN BURIED, COME IN CONTACT WITH THE SOIL, OR OTHERWISE BEEN DISPOSED OF ON OR UNDER THE LANDS COVERED BY TRANSFERRING PARTY’S LEASES OR LANDS POOLED OR ASSOCIATED THEREWITH. SPECIAL PROCEDURES MAY BE REQUIRED FOR THE REMEDIATION, REMOVAL, TRANSPORTATION OR DISPOSAL OF WASTES, ASBESTOS, HAZARDOUS SUBSTANCES AND NORM FROM TRANSFERRING PARTY’S ASSETS. EXCEPT AS OTHERWISE SPECIFICALLY PROVIDED FOR IN THIS AGREEMENT, IF CLOSING OCCURS, ACQUIRING PARTY SHALL ASSUME ALL LIABILITY FOR, AND PROTECT, DEFEND, INDEMNIFY AND HOLD HARMLESS THE TRANSFERRING PARTY GROUP FROM, SUCH REMEDIATION, REMOVAL, TRANSPORTATION AND DISPOSAL.

Section 4.17Assignment; Special Warranty of Title. The transfer of the applicable Assets by Transferring Party to Acquiring Party shall be by special warranty of title, by, through and under Transferring Party or its Affiliates, but not otherwise, by an assignment and bill of sale in substantially the form attached as Exhibit C-LINN or Exhibit C-ExxonMobil, as applicable (the “Assignment”). Notwithstanding anything to the contrary contained in this Agreement or the applicable Assignment, the special warranty of title granted by Transferring Party contained in the applicable Assignment shall be construed such that (a) the special warranty contained therein shall apply (1) with respect to the Assignment covering the transfer of the LINN Assets, only to the extent of the ownership set forth in Exhibits A-1, A-2, A-3, A-4 and A-5-LINN (as such exhibits may be updated prior to Closing in accordance with Section 7.8) and (2) with respect to the Assignment covering the transfer of the ExxonMobil Assets, only to the extent of the ownership set forth in Exhibit A-ExxonMobil and Exhibit B-ExxonMobil (as such exhibits may be updated prior to Closing in accordance with Section 7.8). By November 17, 2014, LINN shall designate the undivided percentages of the ExxonMobil Assets to be assigned under the applicable Assignment at Closing to Berry and LINN Holdings, and the Assignment to LINN shall reflect those designated percentages.

Section 4.18Due Diligence on LINN Replacement Acreage Tracts; Remedies. Notwithstanding that this Article IV provides for title and environmental due diligence related to

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the Assets, ExxonMobil shall have the right to perform title and environmental due diligence on the LINN Replacement Acreage Tracts in accordance with the terms of Article IV. In connection therewith, LINN shall make available to ExxonMobil by September 20, 2014 all information and data with respect to the LINN Replacement Acreage Tracts that LINN is required to make available under Article IV with respect to the LINN Assets. In the event that a Title Defect relating to a LINN Replacement Acreage Tract is not cured to the reasonable satisfaction of ExxonMobil, as Acquiring Party, prior to the end of the Title Cure Period, such LINN Replacement Acreage Tract shall be removed from Exhibit G and excluded from the transactions contemplated by this Agreement.

ARTICLE V

REPRESENTATIONS AND WARRANTIES OF TRANSFERRING PARTY

As of the date of this Agreement and as of the Closing Date, each Party, in its capacity as a Transferring Party, makes to the other Party the following representations and warranties as to itself and its Assets:

Section 5.1Existence and Power. Transferring Party is a limited partnership, limited liability company, or corporation duly formed, validly existing and in good standing under the laws of its state of formation and each jurisdiction where its Assets are located. Transferring Party has the power and is authorized to enter into and perform this Agreement and the transactions contemplated by this Agreement. The execution, delivery and performance of this Agreement by Transferring Party, and the transactions contemplated by this Agreement, will not violate (i) any provision of the organizational documents of Transferring Party, (ii) except with respect to any maintenance of uniform interest provision contained in any Existing Contract, and assuming the receipt of all consents and the waiver of, or compliance with, all preferential purchase rights, any agreement or instrument to which Transferring Party is a party or by which Transferring Party or any of the Assets are bound, (iii) any judgment, order, ruling, or decree applicable to Transferring Party as a party in interest, or (iv) any Law applicable to Transferring Party or its Assets, except for any such violations other than (i) above that would not, individually or in the aggregate, have a Material Adverse Effect. This Agreement constitutes a legal, valid and binding obligation of Transferring Party, enforceable in accordance with its terms, except as may be limited by bankruptcy, insolvency or similar Laws affecting creditors’ rights generally, and by general equitable principles.

Section 5.2Brokers. Transferring Party has incurred no obligation or liability for brokers’ or finders’ fees relating to the matters provided for in this Agreement which will be the responsibility of Acquiring Party, and any such obligation or liability that might exist shall be the sole obligation of Transferring Party.

Section 5.3Claims and Litigation. Except as set forth in Schedule 5.3-LINN or Schedule 5.3-ExxonMobil, as applicable, there are no legal or administrative proceedings, claims or investigations pending or, to Transferring Party’s Knowledge, threatened before any court or administrative body against Transferring Party with respect to its Assets or with respect to the ownership or operation of its Assets.

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Section 5.4Royalties. To Transferring Party’s Knowledge, all bonuses, rentals, royalties, overriding royalty interests and other payments upon, measured by or payable out of production due by Transferring Party with respect to its Assets have been properly and fully paid except for such amounts as are being held in suspense as permitted pursuant to applicable Law or Existing Contracts or are being disputed in good faith.

Section 5.5Compliance. Transferring Party has, and to Transferring Party’s Knowledge, all applicable third party operators have, complied with the provisions and requirements of all Laws applicable to the ownership and operation of its Assets, except for any failures to comply with Laws that would not, individually or in the aggregate, have a Material Adverse Effect.

Section 5.6Material Contracts. To Transferring Party’s Knowledge, Schedule 5.6-LINN and Schedule 5.6-ExxonMobil, as applicable, contains a list of all Material Contracts relating to Transferring Party’s Assets. With respect to Material Contracts: (i) all such Material Contracts are the valid and legally binding obligations of Transferring Party, and to Transferring Party’s Knowledge, the other parties thereto and are enforceable in accordance with their respective terms, except to the extent that such enforcement may be limited by applicable bankruptcy, insolvency and similar Laws affecting creditor’s rights generally, and by general equitable principles; (ii) Transferring Party is not in breach or default in any material respect of any of its obligations under any such Material Contract; and (iii) neither Transferring Party nor, to Transferring Party’s Knowledge, any other party to any such Material Contract has given or received written notice of any action to terminate, cancel, rescind or procure a judicial reformation of any such Material Contract or any provision thereof.

Section 5.7Marketing. Except as set forth on Schedule 5.7-LINN or Schedule 5.7-ExxonMobil, as applicable, no Hydrocarbons produced from Transferring Party’s Assets are subject to a sales agreement (except contracts terminable without penalty by Transferring Party on not more than ninety (90) days’ notice), and no entity has any call upon, option to purchase or similar right under any agreement with respect to such Assets or to the production therefrom. Except for Imbalances, Transferring Party has not been nor will Transferring Party be obligated by virtue of any prepayment made under any production sales contract or any other contract containing a “take-or-pay” clause, a “ship-or-pay” clause, or under any gas balancing, deferred production or similar arrangement to deliver Hydrocarbons produced from or allocated to any of such Assets at some future time without receiving full payment therefor at the time of delivery, or to pay a fee for failure to deliver Hydrocarbons to a purchaser or shipper of production. As of the Effective Time, there are no Imbalances between Transferring Party and any third party with respect to the Assets, except for such Imbalances set forth on Schedule 5.7-LINN or Schedule 5.7-ExxonMobil, as applicable.

Section 5.8Permits. Transferring Party possesses, and to Transferring Party’s Knowledge, all applicable third party operators possess, all permits, licenses, certificates, consents, approvals, and other authorizations required by any Governmental Authority, and has made all required filings with any Governmental Authority, which are necessary for Transferring Party’s ownership and operation of its Assets, except where the failure to possess any such permits, licenses, certificates, consents, approvals or other authorizations or making any such required filings would not, individually or in the aggregate, have a Material Adverse Effect.

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Section 5.9Preferential Purchase Rights and Consents to Assign. Except for consents from Governmental Authorities, approvals of assignments that are customarily obtained after Closing and consents related to maintenance of uniform interest provisions in any Existing Contract, to Transferring Party’s Knowledge, the conveyance of Transferring Party’s Assets as contemplated by this Agreement are not subject to any preferential purchase rights except for those listed on Schedule 5.9-LINN or Schedule 5.9-ExxonMobil, as applicable. There are no consents to assign where the failure to obtain such consent would cause (i) the Assignment to Acquiring Party of the Assets affected thereby to be void, or (ii) the termination of a Lease or Existing Contract under the express terms thereof.

Section 5.10AFEs. As of the Effective Time, except for those listed on Schedule 5.10-LINN or Schedule 5.10-ExxonMobil, as applicable, there are no outstanding Authorities For Expenditures (“AFE”) to drill or rework any well or for capital expenditures with respect to Transferring Party’s Assets that have been proposed by any Person having authority to do so, other than wells already drilled and completed, that exceed $100,000 on an 8/8ths basis.

Section 5.11Environmental.

A.Except as set forth on Schedule 5.11-LINN or Schedule 5.11-ExxonMobil, with respect to its Assets, Transferring Party has neither entered into nor is a party (directly or as successor in interest) to, any agreement with, plea, diversion agreement or consent, order, decree or judgment of any Governmental Authority that (i) is in existence as of the date of this Agreement, (ii) is based on any Environmental Laws that relate to the present or future use of any of the Assets and (iii) requires any Remediation or change in the present conditions of any of the Assets.

B.Except as set forth on Schedule 5.11-LINN or Schedule 5.11-ExxonMobil, as applicable, as of the date of this Agreement, Transferring Party has not received written notice from any Governmental Authority or unaffiliated third party of any release, spill, disposal, event, condition, circumstance, activity, practice or incident concerning any land, facility, asset or property included in the Assets that: (i) requires Remediation under any Environmental Law or the terms of any license or permit issued pursuant thereto or (ii) could reasonably be expected to give rise to or results in any common law or other liability of Transferring Party.

Section 5.12Taxes. Except as disclosed on Schedule 5.12-LINN or Schedule 5.12-ExxonMobil, as applicable, (a) all material Asset Taxes that have become due and payable by Transferring Party (or any of its Affiliates) prior to the Closing Date have been paid; (b) all material Tax returns with respect to Asset Taxes that are required to be filed by Transferring Party (or any of its Affiliates) prior to the Closing Date have been filed (taking into account applicable filing extensions), and (c) there are no Liens on Transferring Party’s Assets for Taxes other than for Taxes not yet due and payable.

Section 5.13Tax Partnerships. No transfer of any part of the Assets pursuant to this Agreement will be treated as a transfer of an interest in a partnership for United States federal Income Tax purposes.

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Section 5.14Payout Status. To Transferring Party’s Knowledge, Schedule 5.14-LINN or Schedule 5.14-ExxonMobil, as applicable, sets forth the payout status as of the date set forth in such Schedule of each Asset subject to a reversion or other adjustment at some level of cost recovery or payout.

Section 5.15Ownership of the Assets. No Affiliate of a Transferring Party who is not a Party to this Agreement owns any direct or beneficial right, title or interest in or to the LINN Assets or the ExxonMobil Assets, as applicable.

Section 5.16Transactions with Affiliates. Except for this Agreement or as set forth on Schedule 5.16-LINN or Schedule 5.16-ExxonMobil, as applicable, neither Transferring Party nor any member of the Transferring Party Group has entered into any Existing Contract or other agreement with any other member of the Transferring Party Group that will affect the Assets or Acquiring Party from and after the Effective Time, except for any agreement that was entered into in the ordinary course of business and upon terms no less favorable to Acquiring Party, with respect to the Assets, than would be obtainable in a comparable arm’s length transaction with a Person that is not a member of the Transferring Party Group.

Section 5.17Area of Mutual Interest Agreements. None of Transferring Party’s Assets are subject to an Area of Mutual Agreement or any similar agreement.

Section 5.18Plugging and Abandonment. Except as set forth on Schedule 5.18-LINN or Schedule 5.18-ExxonMobil, as applicable, there are no Wells that constitute part of the Assets (1) in which the Transferring Party has received an order from any Governmental Authority requiring that such Wells be plugged and abandoned; or (2) that are neither in use for purposes of production or injection, nor suspended or temporarily abandoned in accordance with applicable Law, that have not been plugged and abandoned in accordance with applicable Law except, with respect to subsection (2), to the extent that would not, individually or in the aggregate, have a Material Adverse Effect.

Section 5.19No Knowledge of Misrepresentations or Omissions. Transferring Party has no Knowledge of any breach by Acquiring Party of any representation or warranty in Article VI.

Section 5.20LINN Replacement Acreage Tracts. LINN, as Transferring Party, has not committed and will not commit any of the LINN Replacement Acreage Tracts to, and LINN shall exclude the LINN Replacement Acreage Tracts from, any other divestiture or transaction until the Closing has been consummated.

ARTICLE VI

REPRESENTATIONS AND WARRANTIES OF ACQUIRING PARTY

As of the date of this Agreement and as of the Closing Date, each Party, in its capacity as an Acquiring Party, makes to the other Party the following representations and warranties:

Section 6.1Existence and Power. Acquiring Party is a limited partnership, limited liability company or corporation duly formed, validly existing and in good standing under the laws of its state of formation and each jurisdiction where its Assets are located. Acquiring Party

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has the power and is authorized to enter into and perform this Agreement and the transactions contemplated by this Agreement. The execution, delivery and performance of this Agreement by Acquiring Party, and the transactions contemplated by this Agreement, will not violate (i) any provision of the organizational documents of Acquiring Party, (ii) any agreement or instrument to which Acquiring Party is bound, (iii) any judgment, order, ruling, or decree applicable to Acquiring Party as a party in interest, or (iv) any Law applicable to Acquiring Party, except for any such violations other than (i) above that would not, individually or in the aggregate, have a Material Adverse Effect on the transactions contemplated by this Agreement. This Agreement constitutes a legal, valid and binding obligation of Acquiring Party, enforceable in accordance with its terms, except as may be limited by bankruptcy, insolvency or similar Laws affecting creditors’ rights generally, and by general equitable principles.

Section 6.2Brokers. Acquiring Party has incurred no obligation or liability for brokers’ or finders’ fees relating to the matters provided for in this Agreement which will be the responsibility of Transferring Party, and any such obligation or liability that might exist shall be the sole obligation of Acquiring Party.

Section 6.3Claims and Litigation. Except as set forth in Schedule 5.3-LINN or Schedule 5.3-ExxonMobil, as applicable, there are no legal or administrative proceedings, claims or investigations pending or, to Acquiring Party’s Knowledge, threatened before any court or administrative body against Acquiring Party.

Section 6.4No Distribution. Acquiring Party is acquiring Transferring Party’s Assets for Acquiring Party’s own account and not with the intent to make a distribution in violation of the Securities Act of 1933 as amended (and the rules and regulations pertaining thereto), or in violation of any other applicable securities Laws.

Section 6.5Knowledge and Experience. Acquiring Party has (and had prior to negotiations regarding the acquisition of Transferring Party’s Assets) such knowledge and experience in the ownership and the operation of oil and gas properties and financial and business matters as to be able to evaluate the merits and risks of an investment in such Assets. Acquiring Party is able to bear the risks of the acquisition of such Assets, and assumption of the obligations, in accordance with and as set forth in this Agreement, and understands the risks of, and other considerations relating to, the acquisition of such Assets.

Section 6.6Merits and Risks of an Investment in Transferring Party’s Assets. Acquiring Party understands and acknowledges that: (i) an investment in Transferring Party’s Assets involves certain risks; (ii) neither the United States Securities and Exchange Commission nor any federal, state or foreign agency has passed upon such Assets or made any findings or determination as to the fairness of an investment in such Assets or the accuracy or adequacy of the disclosures made to Acquiring Party; and (iii) except as set forth in Article XV in its capacity as an Acquiring Party or a Transferring Party, Acquiring Party is not entitled to cancel, terminate or revoke this Agreement.

Section 6.7Accredited Investor. Acquiring Party is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the

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Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

Section 6.8No Knowledge of Misrepresentations or Omissions. Acquiring Party has no Knowledge of any breach by Transferring Party of any representation or warranty in Article V.

ARTICLE VII

PRE-CLOSING OBLIGATIONS OF TRANSFERRING PARTY

Section 7.1Operations. From the date of this Agreement until Closing (the “Interim Period”), except for emergency operations or unless otherwise consented to in writing by Acquiring Party (such consent not to be unreasonably withheld, conditioned or delayed), Transferring Party shall: (i) operate, or if Transferring Party is not the operator, use reasonable efforts to ensure that the operator operates, its Assets as a reasonably prudent operator; (ii) act with respect to its Assets in good faith and in the ordinary course of business consistent with past practices as if its Assets were not being assigned to Acquiring Party, except that Transferring Party shall not enter into any agreement that will be binding upon Acquiring Party or the Assets transferred to Acquiring Party from and after Closing without Acquiring Party’s prior written consent in its sole discretion; (iii) exercise reasonable diligence in safeguarding and maintaining secure and confidential all geological and geophysical maps, confidential reports and data in its possession relating to its Assets; (iv) not transfer, sell, hypothecate, encumber, abandon or otherwise dispose of any of its Assets and not solicit, entertain or encourage offers from third parties regarding the same (other than (a) as required in connection with the exercise by third parties of preferential rights to purchase any of its Assets, (b) the sale of production produced from or allocated to its Assets in the ordinary course of business, or (c) as permitted by the applicable Existing Contracts); (v) not terminate or amend in any material respect the terms of any Material Contract, unless such Material Contract terminates pursuant to its stated terms; (vi) not settle any suit or litigation or waive any material claims or rights of material value, in each case, attributable to its Assets and affecting the period after the Effective Time, and shall provide Acquiring Party with updates of material developments in any material litigation matter relating to the Assets (except to the extent any such update could result in the disclosure of information protected by the attorney-client privilege); (vii) not voluntarily relinquish its position as operator with respect to any of its Assets that Transferring Party operated as of the date of this Agreement; (viii) not extend any statute of limitations applicable to any Asset Taxes or agree to any extension of time with respect to any Tax assessment or Tax deficiency, in each case, with respect to any Asset Taxes attributable to any period after the Effective Time; and (ix) not commit to do any of the matters described in provisions (iv) through (ix) above. In addition, during the Interim Period, except for emergency operations, Transferring Party shall obtain Acquiring Party’s consent (such consent not to be unreasonably withheld, conditioned or delayed) with respect to all AFEs over $100,000 on an 8/8ths basis except AFEs or operations described on Schedule 5.10. Notwithstanding anything contrary in the foregoing, LINN, as Transferring Party will cooperate in all reasonable respects with ExxonMobil as Acquiring Party to reach satisfactory arrangements for water disposal rights associated with the Robbie Lease and will not enter into any such agreement without the consent of ExxonMobil, which may be withheld in ExxonMobil’s sole discretion.

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Section 7.2Noticesto Holders of Preferential Purchase Rights. With respect to each preferential purchase right shown on Schedule 5.9-LINN or Schedule 5.9-ExxonMobil, as applicable, by October 1, 2014, Transferring Party shall send to the holder of a preferential purchase right affecting its Assets a notice offering to sell to such holder, in accordance with the contractual provisions applicable to such right, those of its Assets covered by such right on substantially the same terms as this Agreement and for the portion of the Allocated Value allocated to such Asset in Exhibits A-1, A-2, A-3, A-4 and A-5-LINN or Exhibit B-ExxonMobil, as applicable.

Section 7.3Exerciseof Preferential Purchase Rights. If, by November 14, 2014, any holder of a preferential purchase right notifies Transferring Party that it intends to consummate the purchase of its Assets to which its preferential purchase right applies, then those Assets shall be excluded from the Assets to be conveyed to Acquiring Party under this Agreement, and the Closing Amount shall be adjusted by the Allocated Value of such Assets set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable; provided, however, that if the holder of such preferential right fails to consummate the purchase of the Assets covered by such right in accordance with and in the time period allotted by the contractual provisions applicable to such right, then Transferring Party shall promptly so notify Acquiring Party in writing, and within fifteen (15) days after Acquiring Party’s receipt of such notice from Transferring Party, Transferring Party shall sell to Acquiring Party, and Acquiring Party shall purchase such Assets from Transferring Party, for a price equal to the Allocated Value of such Assets set forth in Exhibits A-1, A-2, A-3, A-4 or A-5-LINN or Exhibit B-ExxonMobil, as applicable, upon the other terms of this Agreement. All Transferring Party’s Assets (i) that are subject to a preferential purchase right, (ii) for which such preferential purchase right has not been asserted by the holder of such right by November 14, 2014, and (iii) for which the waiting period under the applicable preferential purchase right has not expired, shall be sold to Acquiring Party at Closing pursuant to the provisions of this Agreement. If one or more of the holders of any such preferential purchase rights notifies Transferring Party subsequent to Closing that it intends to assert its preferential purchase right, Transferring Party shall give notice thereof to Acquiring Party, whereupon Acquiring Party shall satisfy all such preferential purchase right obligations of Transferring Party to such holders and Acquiring Party shall be entitled to receive (and Transferring Party hereby assigns to Acquiring Party all of Transferring Party’s rights to) all proceeds received from such holders in connection with such preferential purchase rights and Acquiring Party shall indemnify and hold harmless Transferring Party Group from and against any and all claims, liabilities, losses, costs and reasonable attorneys’ fees in connection therewith.

Section 7.4Consents to Assign. By October 1, 2014, Transferring Party shall send to each holder of a right to consent to assignment pertaining to its Assets and the transactions contemplated hereby a notice seeking such holder’s consent to the transactions contemplated hereby. If Transferring Party fails to obtain such consent by November 14,2014 and the failure to obtain such consent would cause (i) the assignment to Acquiring Party of the Assets affected thereby to be void, or (ii) the termination of a Lease or Existing Contract under the express terms thereof, or if a consent otherwise requested by Transferring Party is denied in writing, then, unless Acquiring Party otherwise elects in writing by November 17, 2014, that portion of such Asset shall be excluded from the Assets to be assigned to Acquiring Party, and the Closing Amount shall be adjusted by the Allocated Value of that portion of such Assets affected by such

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consent. If such a consent (with respect to an Asset excluded pursuant to this Section 7.4) that was not obtained by November 17, 2014 is obtained within sixty (60) days following Closing, then within ten (10) days after such consent is obtained, Acquiring Party shall acquire such portion of such Asset that was so excluded and pay to Transferring Party the amount by which the Closing Amount was adjusted because of such consent and Transferring Party shall assign to Acquiring Party such portion of such Asset (or such amount shall be included as an adjustment to the Closing Amount in the Final Settlement Statement, if resolved timely). If Transferring Party fails to obtain a required consent by November 17, 2014 and (a) the failure to obtain such consent would not cause (1) the assignment to Acquiring Party of the Asset affected thereby to be void or (2) the termination of a Lease under the express terms thereof or if a consent otherwise requested by Transferring Party is not denied in writing, or (b) Acquiring Party does not elect to exclude the portion of the Asset affected thereby pursuant to the second sentence of this Section 7.4, then the portion of the Asset subject to such failed consent shall be assigned by Transferring Party to Acquiring Party at Closing and Acquiring Party shall have no claim against, and Transferring Party shall have no liability for, the failure to obtain such consent and Acquiring Party shall indemnify and hold harmless Transferring Party Group from and against any and all claims, liabilities, losses, costs and reasonable attorneys’ fees in connection therewith. In addition, in the event Transferring Party identifies a maintenance of uniform interest provision in any Existing Contract that may be affected by the transactions contemplated by this Agreement, Transferring Party and Acquiring Party will reasonably cooperate with each other to reach an agreement on the Parties’ preferred approach regarding compliance with such provision.

Section 7.5Cooperation. Transferring Party will reasonably cooperate with Acquiring Party to assist Acquiring Party in carrying out the agreements of Acquiring Party as set forth in Article VIII below.

Section 7.6Defaults. Each Party shall give prompt written notice to the other Party of any breach of any representation, warranty, covenant or other agreement of such Party subsequent to the date of this Agreement and prior to the Closing that would cause a failure of any of the conditions to Closing of the other Party contained herein.

Section 7.7Satisfaction of Closing Conditions. Transferring Party shall use its commercially reasonable efforts to satisfy all of the conditions to Closing of Acquiring Party contained in Article IX.

Section 7.8Updated Exhibits. By November 17, 2014, Transferring Party shall update Exhibits A, A-1, A-2, A-3, A-4 and A-5-LINNExhibit B-LINN, Exhibit A-ExxonMobil and Exhibit B-ExxonMobil, as applicable, to incorporate any additional information available to such Transferring Party regarding the LINN Assets, and the ExxonMobil Assets, as applicable, to be listed therein by delivering written notice of such updated Exhibits to Acquiring Party. If Acquiring Party consents in writing to such updated Exhibits (which shall not be unreasonably withheld) or fails to respond by November 19, 2014, such Exhibits shall be deemed updated for purposes of this Agreement and the Assignment. By November 17, 2014, LINN will update Exhibits A and A-3, together with any applicable schedules to this Agreement to the extent necessary to reflect disclosures related to the LINN Replacement Acreage Tracts, if any, included in the Assets.

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Section 7.9Employment Matters. Transferring Party may offer severance or redeployment opportunities to all employees impacted by this transaction. Given that the Transferring Party’s redeployment offers will likely require relocation outside of their current work area, the Acquiring Party will, at its option, be permitted to interview and offer employment to impacted employees identified in Exhibit I (the “Impacted Employees”). By September 28, 2014, Transferring Party will provide Acquiring Party with a list of the field level Impacted Employees Transferring Party and its Affiliates available for interview and employment with Acquiring Party, which will include the following data: name and job title. For the avoidance of doubt, if Transferring Party does not include an employee of Transferring Party or its Affiliates on Exhibit I, then Acquiring Party will not, unless acting in accordance with Transferring Party’s prior written consent, solicit, encourage or otherwise induce any such employee to leave the employment of Transferring Party or become an employee of Acquiring Party in accordance with Section 12.18. Acquiring Party shall provide offers of employment to the Impacted Employees that Acquiring Party desires to hire, with each offer stipulating the Closing Date as the date for commencement of work (the “Hire Date”). Such offers shall be at a base salary equal to or greater than the Impacted Employee’s current base salary with Transferring Party, and for positions that are not a material diminution in the Impacted Employee’s recent job authority, duties or responsibilities. Acquiring Party shall provide Transferring Party with notice of the names in Exhibit I to whom Acquiring Party has made employment offers promptly after making such offers and at least ten (10) days before the Hire Date. The Impacted Employees that Acquiring Party hires as of the Hire Date are referred to as the “New Employees.” No Impacted Employee shall become a New Employee unless he or she (a) accepts Acquiring Party’s offer of employment under the terms provided in Acquiring Party’s offer, (b) passes any required pre-employment screening required by Acquiring Party and (c) on the Hire Date, is actively at work. Until an Impacted Employee becomes a New Employee, if at all, the Impacted Employee shall remain the employee of the Transferring Party, who will remain responsible for: (1) the base salary or wage (including any overtime) of the Impacted Employee, (2) any bonuses to which the Impacted Employee may be entitled, (3) the costs of the Impacted Employee’s participation in any employee benefit plans sponsored by Transferring Party, (4) workers compensation coverage of the Impacted Employee, and (5) all applicable employee taxes and tax withholding, until such time as Impacted Employee becomes a New Employee. To the extent ExxonMobil hires a New Employee, it agrees to provide certain severance benefits for each New Employee who is terminated during the eighteen (18) month period immediately following the New Employee’s Hire Date withExxonMobil as provided in Exhibit J -LINN; provided, however, that ExxonMobil will not be obligated to provide any severance benefits for any New Employee who is terminated for cause, as defined by Exhibit J-LINN. Acquiring Party makes no representation as to how it will staff the Assets and nothing in this Agreement shall require or be construed or interpreted as requiring Acquiring Party to offer employment to any employee of Transferring Party or to continue the employment of any employee of Transferring Party (including any New Employees) following their respective Hire Date, or to prevent Acquiring Party thereof from changing the terms and conditions of employment (including compensation and benefits) of any of its employees (including any New Employees) following their respective Hire Dates. Prior to the Hire Date, if any, of an Impacted Employee, Transferring Party shall have the right to control and direct such Impacted Employee as to the performance of duties and as to the means by which such duties are performed, including the right to terminate the employment of any Impacted Employee. Transferring Party shall fully and

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timely inform Acquiring Party of and consult Acquiring Party with respect to, all employment, benefit, workplace and performance matters relating to Impacted Employees prior to the Hire Date that, in the reasonable judgment of Transferring Party’s management, could have a material impact on Acquiring Party prior to taking any actions or making any decisions with respect to such matters, subject to applicable Law. Notwithstanding any other provisions of this Agreement, the provisions of this Section 7.9 are not intended to and shall not create or confer any third-party beneficiary rights respecting any Impacted Employee or New Employee.

Section 7.10Certain Agreements. Each of the Parties shall enter into at Closing, (a) a Transition Services Agreement generally in the form attached hereto as Exhibit D-1 and Exhibit D-2 with respect to the Assets being assigned by each Transferring Party at Closing pursuant to which Transferring Party will agree to provide certain transition services on behalf of Acquiring Party relating to such Assets and (b) a Joint Use Agreement generally in the form attached hereto as Exhibit E, pursuant to which the Parties will set forth certain rights and obligations regarding the use of the LINN Assets. As soon as practical after the date of this Agreement but in no event later than October 31, 2014, the Parties will enter a Joint Use Agreement covering the Eddy County and Lea County, New Mexico Assets. The Parties will use as a starting point for the negotiations of such Joint Use Agreement the form of Joint Use Agreement attached hereto as Exhibit E.

Section 7.11Financial Data. Linn has advised ExxonMobilthat LINN and/or its Affiliates may be required to include statements of revenues and direct operating expenses and other financial data required by the rules and regulations promulgated by the Securities and Exchange Commission (SEC) relating to the Assets (“Financial Data”) in documents required to be filed with the SEC by LINN and/or its Affiliates pursuant to the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended.  LINN will retain and pay for the services of an agreed independent registered public accounting firm to perform an audit of the Financial Data in accordance with US GAAP to facilitate the preparation of the LINN disclosures required by the SEC.  Financial Data and support of the audit will be provided by ExxonMobil for such a period to meet SEC requirements. The Financial Data will be prepared and filed at LINN’s sole expense. LINN will protect, defend, indemnify and hold harmless ExxonMobil and its Affiliates from and against any and all claims relating to, arising out of, or connected with the preparation of the Financial Data or other disclosures in SEC filings or ExxonMobil’s furnishing of any information or records in connection with the preparation of the Financial Data or disclosures, and ExxonMobil shall in no event be required to create new records relating to the Assets.

ARTICLE VIII

PRE-CLOSING OBLIGATIONS OF ACQUIRING PARTY

Section 8.1Return of Data. Acquiring Party agrees that if this Agreement is terminated for any reason whatsoever, Acquiring Party shall promptly return to Transferring Party or destroy all information and data furnished to any member of the Acquiring Party Group by Transferring Party Group in connection with this Agreement or Acquiring Party’s investigation of Transferring Party’s Assets, and Acquiring Party for itself and each member of the Acquiring Party Group agrees not to retain any copies of such information or data. In the event of such termination, no later than the date that is fifteen (15) days following such

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termination, Acquiring Party shall deliver to Transferring Party a certificate specifying that Acquiring Party has returned or destroyed all such information or data pursuant to this Section 8.1. Notwithstanding the foregoing, (i) one copy of any such information may be retained by the Acquiring Party solely for the purpose of defending or prosecuting claims arising from this Agreement or the transactions contemplated hereby, (ii) Acquiring Party shall not be deemed to have retained or failed to destroy any such information which is contained on servers or back-up sources if such information is deleted from local hard drives and no attempt is made to recover such information from such servers or back-up sources, (iii) Acquiring Party may retain any such information required by applicable Law including stock exchange regulations or by governmental order, decree regulation or rule, and (iv) copies of such information included in materials presented to the applicable board of directors (or similar management body) in connection with the transaction contemplated by this Agreement. This Section 8.1 shall not apply to information that (i) was developed by Acquiring Party or its Affiliates or already in the possession of Acquiring Party or its Affiliates; (ii) at the time of disclosure, was in the public domain or which after disclosure became a part of the public domain through no action or failure to act on the part of Acquiring Party or its Affiliates; or (iii) at the time of disclosure, was or is thereafter lawfully acquired by Acquiring Party or its Affiliates from a source other than Transferring Party, provided that Acquiring Party reasonably believes, after diligent inquiry, that such source was not under an obligation of confidence with respect thereto and did not acquire such information directly or indirectly from Transferring Party.

Section 8.2Indemnity Regarding Access. Acquiring Party agrees to indemnify, defend and hold harmless each member of the Transferring Party Group, from and against any and all Losses arising out of or relating to the access of any member of the Acquiring Party Group to Transferring Party’s Assets and Records and other related information as permitted under this Agreement, EVEN IF SUCH LOSSES ARISE OUT OF OR RELATE TO, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF, OR THE VIOLATION OF LAW BY, A MEMBER OF THE TRANSFERRING PARTY GROUP, EXCEPT TO THE EXTENT SUCH LOSSES RESULT FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF THE Transferring Party Group.

Section 8.3Cooperation. Acquiring Party will reasonably cooperate with Transferring Party to assist Transferring Party in carrying out the agreements of Transferring Party as set forth in Article VII above.

Section 8.4Bonds and Credit Support. Acquiring Party acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by Transferring Party Group with Governmental Authorities and relating to Transferring Party’s Assets are transferable to Acquiring Party. At or prior to Closing, Acquiring Party shall deliver to Transferring Party evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements (if any) of such authorities to own and/or operate Transferring Party’s Assets.

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Section 8.5Satisfaction of Closing Conditions. Acquiring Party shall use its commercially reasonable efforts to satisfy all of the conditions to Closing of Transferring Party contained in Article X.

Section 8.6HSR Act. No later than October 15, 2014, the Parties shall make all premerger notification filings required, if any, under the HSR Act and other comparable laws. Each Party shall: (i) cooperate fully with each other and shall furnish to the other such necessary information and reasonable assistance as the other may reasonably request in connection with its preparation of any filings under any premerger notification rules; (ii) furnish the other Party with copies of any notices, correspondence or other written communication received by it from any Governmental Authority relating to such filings; (iii) permit the other Party to review and incorporate the other Party’s reasonable comments in any communication given by it to any Governmental Authority in a manner that protects attorney-client or attorney work product privilege; and (iv) give the other Party reasonable prior notice of, and an opportunity to participate, if it intends to participate in any meeting with any Governmental Authority with respect to such filings. Each Party shall each use commercially reasonable efforts to obtain all consents required under the antitrust Laws, and shall cooperate fully with the other Party and its officers, directors, employees, agents, counsel, accountants and other designees. Each Party shall promptly make any supplemental submissions required of it and shall cooperate in the preparation of such filings as is reasonably necessary and appropriate. In connection with any filings made under the HSR Act, the Parties shall request early termination of the HSR Act waiting period. Notwithstanding anything in this Agreement to the contrary, in no event will either Party be obligated to propose or agree to accept any undertaking or condition, to enter into any consent decree, to make any divestiture, to accept any operational restriction, or take any other action to obtain early termination of the HSR Act waiting period or a consent order issued by or from the applicable Governmental Authorities that, in the reasonable judgment of the Party, could be expected to limit the right of the Party to own or operate all or any portion of its businesses or assets.

ARTICLE IX

ACQUIRING PARTY’S CONDITIONS TO CLOSING

The obligations of each Party, in its capacity as an Acquiring Party, to consummate the transactions provided for herein are subject, at the option of such Acquiring Party, to the fulfillment by the applicable Transferring Party or waiver by such Acquiring Party, on or prior to the Closing Date of each of the following conditions:

Section 9.1Representations. The representations and warranties of Transferring Party set forth in Article V shall be true and correct in all respects (without regard to materiality or Material Adverse Effect qualifiers) on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that individually or in the aggregate would not have a Material Adverse Effect.

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Section 9.2Performance. Transferring Party shall have performed or complied in all material respects with all obligations, agreements, and covenants contained in this Agreement as to which performance or compliance by Transferring Party is required prior to or at the Closing Date.

Section 9.3No Legal Proceedings. No order, award or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal, or awarding substantial damages in connection with, the transactions contemplated by this Agreement.

Section 9.4Release of Liens. All Liens, production payments or other encumbrances burdening the Transferring Party’s Assets securing any indenture, mortgage, loan, credit or sale-leaseback or similar financial contract of Transferring Party or any of its Affiliates shall have been released at or before Closing, and Transferring Party shall have provided evidence of such releases in form and substance reasonably satisfactory to Acquiring Party at or before Closing.

Section 9.5Closing Deliverables. Transferring Party shall have delivered (or be ready, willing and able to deliver at Closing) to Acquiring Party the documents, which are recordable and acceptable to the county clerk, and other items required to be delivered by Transferring Party pursuant to Section 11.2.

Section 9.6Defects, Benefits, and Casualty Defects. The total of the value of (a) the Net Defect Amount under Section 4.8, plus (b) all Remediation costs for uncured Environmental Defects determined under Section 4.12, plus (c) the amount of all Casualty Losses, shall be less than 25% of the total Allocated Value of Transferring Party’s Assets.

Section 9.7HSR Act. If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions hereby shall have expired, notice of early termination shall have been received or a consent order issued (any such consent order in form and substance satisfactory to Acquiring Party) by or from the applicable Governmental Authorities.

ARTICLE X

TRANSFERRING PARTY’S CONDITIONS TO CLOSING

The obligations of each Party, in its capacity as a Transferring Party, to consummate the transactions provided for herein are subject, at the option of such Transferring Party, to the fulfillment by the applicable Acquiring Party or waiver by such Transferring Party on or prior to the Closing Date of each of the following conditions:

Section 10.1Representations. The representations and warranties of Acquiring Party set forth in Article VI shall be true and correct in all respects (without regarding to materiality or Material Adverse Effect qualifiers) on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that individually or in the aggregate would not have a Material Adverse Effect.

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Section 10.2Performance. Acquiring Party shall have performed or complied in all material respects with all obligations, agreements, and covenants contained in this Agreement as to which performance or compliance by Acquiring Party is required prior to or at the Closing Date.

Section 10.3No Legal Proceedings. No order, award or judgment shall have been issued by any Governmental Authority or arbitrator to restrain, prohibit, enjoin or declare illegal, or awarding substantial damages in connection with the transactions contemplated by this Agreement.

Section 10.4Closing Deliverables. Acquiring Party shall have delivered (or be ready, willing and able to deliver at Closing) to Transferring Party the documents, which are recordable and acceptable to the county clerk, and other items required to be delivered by Acquiring Party pursuant to Section 11.2.

Section 10.5Title Defects, Benefits, and Casualty Defects. The total of the value of (a) the Net Defect Amount under Section 4.8 plus (b) all Remediation costs for uncured Environmental Defects determined under Section 4.12, plus (c) the amount of all Casualty Losses, shall be less than 25% of the total Allocated Value of Transferring Party’s Assets.

Section 10.6HSR Act. If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions hereby shall have expired, notice of early termination shall have been received or a consent order issued (any such consent order in form and substance satisfactory to Acquiring Party) by or from the applicable Governmental Authorities.

ARTICLE XI

CLOSING

Section 11.1Time and Place of Closing. The consummation of the transactions contemplated by this Agreement (the “Closing”) shall be held on or before November 21, 2014 (the “Targeted Closing Date”), or if all conditions to Closing in Articles IX and X have not yet been satisfied or waived by the Targeted Closing Date, then three (3) Business Days after such conditions have been satisfied or waived, or such other date as the Parties may agree upon in writing, but in no event later than January 21, 2015 (the “Outside Date”), at XTO’s offices or such other place as the Parties may agree. The date the Closing occurs shall be the “Closing Date.”

Section 11.2Closing Obligations. At Closing:

A.Transferring Party and Acquiring Party shall, and shall cause its Affiliates (if applicable) to, execute, acknowledge and deliver to the other Party the applicable Assignment, dated as of the Closing Date but to be effective as of the Effective Time, which will convey to Acquiring Party title to Transferring Party’s Assets, and deliver possession thereof to Acquiring Party.

B.Each Party shall execute and deliver to the other Party the Transition Services Agreement and the Joint Use Agreement provided for Section 7.10.

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C.Each Transferring Party shall deliver to the other Party a certificate of non-foreign status, from each of the tax owners of the Assets for U.S. federal income tax purposes, meeting the requirements of Treasury Regulation Section 1.1445-2(b)(2) and reasonably acceptable to the Acquiring Party.

D.Each Party, as a Transferring Party, shall provide to Acquiring Party a list showing the value of all net proceeds from production attributable to such Transferring Party’s Assets that are held in suspense as of Closing pursuant to Section 12.12.

E.Each Party shall execute such other instruments, including change of operator forms and letters in lieu, and take such other action as may be necessary or advisable to carry out its obligations under this Agreement.

F.The applicable Party shall pay the other Party the Net Closing Amount by wire transfer of immediately available funds to the account designated by LINN or ExxonMobil, as applicable.

G.In the cases of the ExxonMobil Assets, ExxonMobil shall execute a waiver of calls on production for its Assets held by ExxonMobil, if applicable, if and when requested by LINN.

H.Each of ExxonMobil and LINN shall execute and deliver to the other the Oil and Gas Lease in substantially the forms attached hereto as Exhibit H-LINN andExhibit H-ExxonMobil , which will convey a royalty free leasehold interest in all Hydrocarbons in minerals owned in fee by ExxonMobil and LINN that are associated with each Party’s respective Assets, if any.

ARTICLE XII

POST-CLOSING OBLIGATIONS

Section 12.1Acquiring Party’s Assumption of Certain Obligations. Subject to the indemnification obligations of Transferring Party in Section 12.3, subject to adjustments in accordance with Sections 3.3 and 12.11 and except for any Retained Liabilities, if Closing occurs, each Acquiring Party, shall assume and shall fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of Transferring Party, known or unknown, arising from, based upon or associated with Transferring Party’s Assets that are acquired by Acquiring Party pursuant to this Agreement that arose or which arise on or after the Effective Time, including all obligations and liabilities relating in any manner to the use, ownership or operation of such Assets, as well as the following obligations and liabilities (collectively the “Assumed Obligations”):

A.To disburse funds held in suspense to the extent same are transferred to Acquiring Party in accordance with Section 12.12 below.

B.To properly plug and abandon all wells (including but not limited to producing, inactive, injection and saltwater disposal wells) now or hereafter located on the lands covered by Transferring Party’s Leases or pooled or used in connection therewith, whether such

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obligations arose prior to, on or after the Effective Time in accordance with the provisions of the applicable Lease.

C.To furnish make-up gas according to the terms of applicable gas sales, gathering or transportation agreements, and to satisfy all other gas balancing and “ship or pay” obligations, if any, related to Transferring Party’s Assets, whether such obligations arose prior to, on or after the Effective Time.

D.Those that relate to the environmental and physical condition of Transferring Party’s Assets, whether such condition existed before, on or after the Effective Time, and the existence of Environmental Defects, if any, with respect to such Assets, whether or not asserted by Acquiring Party in accordance with this Agreement, including the clean-up, restoration and Remediation of such Assets in accordance with applicable law, including all Environmental Laws.

Section 12.2Acquiring Party’s Indemnity. From and after the Closing, each Acquiring Party, shall protect, indemnify, defend and hold harmless the Transferring Party Group, REGARDLESS OF FAULT, from and against any and all Losses that are attributable to:

A.The Assumed Obligations.

B.Any breach of any representation or warranty made by Acquiring Party in Article VI or any covenant made by Acquiring Party in this Agreement.

C.Asset Taxes (i) allocable to such Acquiring Party pursuant to Section 13.1 to the extent such Asset Taxes were not the subject of an Upward Adjustment pursuant to Section 3.3A(iii) and (ii) allocable to Transferring Party pursuant to Section 13.1 to the extent such Asset Taxes were the subject of a Downward Adjustment pursuant to Section 3.3B(iii).

D.Transfer Taxes allocable to such Acquiring Party pursuant to Section 13.2.

Section 12.3Transferring Party’s Indemnity. From and after the Closing, each Transferring Party, shall indemnify, defend and hold harmless the Acquiring Party Group, REGARDLESS OF FAULT, from and against any and all Losses that are attributable to:

A.Personal injuries, including death, relating to Transferring Party’s Assets, prior to the Closing.

B.The gross negligence or willful misconduct of any member of Transferring Party Group in the operation of Transferring Party’s Assets prior to the Closing.

C.Any offsite disposal of waste, hazardous substances, hazardous materials or hazardous waste arising from the operation or use of the Transferring Party’s Assets prior to the Closing.

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D.The proper payment or accounting for royalties or other lease burdens relating to the production of Hydrocarbons from the Transferring Party’s Assets prior to the Effective Time.

E.The Excluded Assets.

F.Any breach of any representation or warranty made by Transferring Party in Article V or any covenant made by Transferring Party in this Agreement.

G.Asset Taxes (i) allocable to such Transferring Party pursuant to Section 13.1 to the extent such Asset Taxes were not the subject of a Downward Adjustment pursuant to Section 3.3A(iii) and (ii) allocable to Acquiring Party pursuant to Section 13.1 to the extent such Asset Taxes were the subject of an Upward Adjustment pursuant to Section 3.3B(iii).

H.All Retained Liabilities.

Section 12.4Survival. The representations and warranties of Transferring Party in Article V and Acquiring Party in Article VI (other than the Fundamental Representations and the Tax Representations) and the covenants and agreements of the Parties contained in this Agreement to be performed at or prior to the Closing shall, in each case, survive the Closing for a period of nine (9) months after the Closing Date. The Fundamental Representations of each Party shall survive the Closing indefinitely. The Tax Representations of each Party shall survive until the sixtieth (60^th) day after the expiration of the applicable statute of limitations. All covenants and agreements of the Parties contained in this Agreement to be performed after the Closing shall survive the Closing until performed. Representations, warranties, covenants and agreements shall be of no further force and effect after the date of their expiration; provided that there shall be no termination of any bona fide claim properly asserted pursuant to this Article XII with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

Section 12.5Indemnity Limitations.

A.An Indemnifying Party shall not have any liability for indemnification of any Losses under this Agreement unless (i) the amount of any Losses for any individual claim for which a Claim Notice is delivered by an Indemnified Party to an Indemnifying Party under this Article XII and for which an Indemnifying Party is liable exceeds $50,000, and (ii) the aggregate amount of all Losses for which an Indemnifying Party is liable under this Agreement exceeds two percent (2%) of the total Allocated Value of such Party’s Assets (the “Indemnity Deductible”), and then only to the extent such damages or costs exceed the Indemnity Deductible; provided, however, that (A) any adjustments to the Closing Amount under Section 3.3, (B) the indemnities under Section 12.2B or Section 12.3F for a breach of any Fundamental Representation or a breach of any Tax Representation, (C) the indemnity of Acquiring Party under Sections 12.2A, 12.2C and 12.2D and (D) the indemnity of Transferring Party under Sections 12.3A, 12.3B, 12.3C, 12.3D, 12.3E, 12.3G and 12.3H (such foregoing items (A) through (D), the “Limitation of Liability Exclusions”), in each case, shall not be limited by the provisions of this Section 12.5.

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B.Notwithstanding anything to the contrary contained in this Agreement, except with respect to the Limitation of Liability Exclusions, and Indemnifying Party shall not be required to indemnify an Indemnified Party for aggregate Losses in excess of twenty-five percent (25%) of the total Allocated Value of such Party’s Assets.

Section 12.6Indemnification Procedures. All claims for indemnification under this Agreement shall be asserted and resolved as follows:

A.For purposes of this Agreement, the term “Indemnifying Party” when used in connection with particular Losses shall mean the Party having an obligation to indemnify another Party or Person(s) with respect to such Losses pursuant to this Article XII, and the term “Indemnified Party” when used in connection with particular Losses shall mean the Party or Person(s) having the right to be indemnified with respect to such Losses by another Party pursuant to this Article XII.

B.To make a claim for indemnification under this Agreement, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 12.6, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). If the claim for indemnification is based upon a claim by a third party against the Indemnified Party (a “Third Party Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has Knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 12.6 shall not relieve the Indemnifying Party of its obligations under this Agreement except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. If the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

C.In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such thirty (30) day period, at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

D.If the Indemnifying Party admits its liability to defend the Indemnified Party against a Third Party Claim, it shall have the right and obligation to diligently defend, at its sole cost and expense, such Third Party Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Third Party Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, at its own expense, any defense or settlement of any Third Party Claim

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controlled by the Indemnifying Party pursuant to this Section 12.6D. An Indemnifying Party shall not, without the written consent of the Indemnified Party, (i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all Loss in respect of such Third Party Claim or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

E.If the Indemnifying Party does not admit its liability to defend, or admits its liability but fails to diligently defend, the Indemnified Party against the Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its liability to defend the Indemnified Party against the Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its liability to indemnify the Indemnified Party from and against the liability and consent to such settlement, (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability. Any failure to respond to such notice by the Indemnified Party shall be deemed to be an election under the preceding clause (i).

F.In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to (i) cure the Losses complained of, (ii) admit its liability for such Loss or (iii) dispute the claim for such Losses. If the Indemnifying Party does not notify the Indemnified Party within such thirty (30) day period that it has cured the Losses or that it disputes the claim for such Losses, the amount of such Losses shall conclusively be deemed a liability of the Indemnifying Party hereunder.

Section 12.7Non-Compensatory Damages. No Indemnified Parties shall be entitled to recover from an Indemnifying Party or its Affiliates in connection with this Article XII any indirect, special, incidental, consequential, punitive, exemplary, remote or speculative damages or damages for lost profits of any kind arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such Party suffers such damages to a Third Party, which damages (including costs of defense and reasonable attorneys’ fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder.

Section 12.8Waiver of Right to Rescission. LINN and ExxonMobil acknowledge that, from and after the Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As the payment of money shall be adequate compensation, following Closing, LINN and ExxonMobil waive any right to rescind this Agreement or any of the transactions contemplated hereby.

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Section 12.9Exclusive Remedy. As between an Acquiring Party and the Transferring Party Group, on the one hand, and the Transferring Party and the Acquiring Party Group, on the other, from and after the Closing, other than with respect to claims for fraud by or on behalf of Acquiring Party or Transferring Party, as the case may be, and without limiting a Party’s rights under Section 16.12 or any remedies related to the special warranty of title in the Assignment, the provisions set forth in Sections 4.8, 4.9,4.10,4.13, 7.3, 7.4, 12.2, 12.3 and 16.12 shall be the sole and exclusive rights, obligations and remedies of the Parties with respect to any claim for, related to or arising from any breach of or non-compliance with this Agreement, the consummation of the transactions contemplated hereby, the ownership, use or operation of the Assets prior to the Closing, or the condition, quality, status or nature of the Assets prior to the Closing.

Section 12.10Regardless of Fault. The phrase “REGARDLESS OF FAULT” means WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY CLAIM, WHETHER IN TORT, UNDER CONTRACT OR OTHERWISE AT LAW, INCLUDING, WITHOUT LIMITATION, EVEN THOUGH A CLAIM RESULTS FROM OR IS CAUSED IN WHOLE OR IN PART BY:

A.THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE, PASSIVE, GROSS OR OTHERWISE) WILLFUL MISCONDUCT, STRICT LIABILITY, OR OTHER FAULT OF THE ACQUIRING PARTY GROUP, THE TRANSFERRING PARTY GROUP, INVITEES AND/OR THIRD PARTIES; PROVIDED, HOWEVER, “REGARDLESS OF FAULT” SHALL NOT INCLUDE THE GROSS ENGLIGENCE OR WILLFUL MISCONDUCT OF ANY MEMBER OF THE ACQUIRING PARTY GROUP OR THE TRANSFERRING PARTY GROUP; AND/OR

B.A PRE-EXISTING DEFECT, WHETHER PATENT OR LATENT, OF THE PREMISES OF ACQUIRING PARTY’S PROPERTY OR TRANSFERRING PARTY’S PROPERTY (INCLUDING WITHOUT LIMITATION THE ASSETS), INVITEES AND/OR THIRD PARTIES; AND/OR MECHANICAL FAILURE OF ANY VEHICLE OF A PARTY WHETHER CHARTERED, LEASED, OWNED, OR FURNISHED OR PROVIDED BY ANY OF THE ACQUIRING PARTY GROUP, THE TRANSFERRING PARTY GROUP, INVITEES OR THIRD PARTIES.

Section 12.11Final Settlement Statement.

A.As soon as reasonably practicable after the Closing Date, but in no event longer than one hundred fifty (150) days after the Closing Date, each Party, as a Transferring Party shall prepare, in accordance with this Agreement, and deliver to Acquiring Party, a final statement (the “Final Settlement Statement”) in accordance with Section 3.3 setting forth the adjustments from zero, after giving effect to the adjustments made in the Closing Amount set forth in the Estimated Closing Settlement.

B.The Final Settlement Statement prepared by each Transferring Party shall be accompanied by reasonable supporting documentation. As soon as reasonably practicable, but in no event longer than thirty (30) days after receipt of the Final Settlement Statement,

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Acquiring Party shall deliver written notice (an “Objection Notice”) to Transferring Party of any objections that Acquiring Party has to the Final Settlement Statement. The Parties shall undertake to agree on the Final Settlement Statement no later than two hundred and ten (210) days after the Closing Date. The adjustments contained in the applicable Final Settlement Statement shall be conclusively deemed to be agreed to by the Parties as final unless challenged by an Acquiring Party within thirty (30) days of receipt of such Final Settlement Statement.

C.If the Parties are unable to resolve the matters addressed in an Objection Notice (if any) within fourteen (14) Business Days after the delivery of such Objection Notice, each of Transferring Party and Acquiring Party shall within Twenty-one (21) Business Days after the delivery of such Objection Notice, summarize its position with regard to such dispute in a written document of 20 pages or less and submit such summaries to the Dallas, Texas office of Ernst & Young, LLP or if Ernst & Young, LLP is unable or unwilling to serve as arbitrator and absent agreement by the Parties, to the Dallas, Texas office of the AAA (the “Accounting Arbitrator”), together with a copy of such Objection Notice, the applicable Final Settlement Statement and any other documentation such Party may desire to submit. Within twenty (20) Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision, choosing either Transferring Party’s position or Acquiring Party’s position with respect to each matter addressed in any Objection Notice, based on the materials described above. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on the Parties and will be enforceable against any of the Parties in any court of competent jurisdiction. The costs of such Accounting Arbitrator shall be borne one-half by LINN and one-half by ExxonMobil. The Final Settlement Statement as determined by the Accounting Arbitrator pursuant to this Section 12.11C shall be final and binding on the Parties (other than with respect to amounts not accounted for therein or settled thereby, which amounts shall be subject to the other provisions of this Section 12.11).

D.Once the adjustments to the Final Settlement Statement related to each Transferring Party’s Assets have been finally determined (by agreement of the Parties, deemed agreement of the Parties, or determination by the Accounting Arbitrator, in each case in accordance with this Section 12.11), the final calculation of the Final Settlement Statement shall be an amount (such amount, the “Final Settlement Amount”) equal to (X) the sum of (1) the aggregate amount of the Upward Adjustments attributable to the LINN Assets minus (2) the aggregate amount of the Downward Adjustments attributable to the LINN Assets (which may be a positive or a negative number) minus (Y) the sum of (1) the aggregate amount of the Upward Adjustments attributable to the ExxonMobil Assets minus (2) the aggregate amount of the Downward Adjustments attributable to the ExxonMobil Assets (which may be a positive or a negative number). If the Final Settlement Amount is greater than zero, ExxonMobil shall pay that amount to LINN. If the Final Settlement Amount is less than zero, LINN shall pay that amount, as a positive number, to ExxonMobil. Any amounts payable in connection with this Section 12.11D shall be paid by wire transfer of immediately available funds to the account designated by LINN or ExxonMobil, as applicable, no later than five (5) Business Days after the date the Final Settlement Amount has been determined.

Section 12.12Suspended Funds. Each Party, as a Transferring Party, shall provide to Acquiring Party at Closing a listing showing all net proceeds from production attributable to such Transferring Party’s Assets which are held in suspense at Closing because of lack of

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identity or address of owners, title defects, change of ownership, netting or over/under distributions, and the Final Settlement Statement shall be adjusted in respect of such amounts in accordance with Section 12.11. Transferring Party covenants to deliver to Acquiring Party, within ninety (90) days after Closing, in “Excel” format, to the extent available, the owner name, owner number, social security or federal ID number, reason for suspense, and the amount of suspense funds payable for each entry, together with monthly line item production detail including gross and net volumes and deductions for all suspense entries. Upon receipt of such information, Acquiring Party shall administer all such accounts and assume all payment obligations relating to the suspended funds in accordance with all applicable Laws, and shall be liable for the payment thereof to the proper parties (but only to the extent the Final Settlement Statement was adjusted in accordance with this Section 12.12); provided that, Transferring Party will retain all responsibility and liability for (i) statutory penalties and interest, if any, owing to any interest owner attributable to such suspended funds accruing prior to the Closing Date, (ii) penalties and interest, if any, attributable to the suspended funds accruing prior to the Closing Date, payable to any state under existing escheat or unclaimed property statutes and (iii) any other amounts payable to third parties attributable to any suspense fund accruing prior to the Closing Date to the extent the Final Settlement Statement was not adjusted in accordance with this Section 12.12. If Acquiring Party determines that any such penalties or interest or other amounts as described in the preceding proviso are due to the respective suspense account owner or any state under such statutes and Transferring Party fails to promptly reimburse such sums to Acquiring Party, then Acquiring Party shall return to Transferring Party the suspended funds in such account that existed as of the Closing Date, and Transferring Party shall thereupon assume all obligations for the final payment and settlement of any such claims and accompanying suspense funds.

Section 12.13Receipts and Credits. Following final adjustment of the Final Settlement Statement pursuant to Section 12.11 above, all monies, proceeds, receipts, credits and income attributable to Transferring Party’s Assets for all periods of time as of and after the Effective Time, shall be the sole property of Acquiring Party, and, to the extent received by Transferring Party, Transferring Party shall fully disclose, account for and transmit the same promptly to Acquiring Party. Following final adjustment of the Final Settlement Statement in accordance with Section 12.11 above, all monies, proceeds, receipts and income attributable to Transferring Party’s Assets, except as otherwise provided in this Agreement, for all periods of time prior to the Effective Time, shall be the sole property and entitlement of Transferring Party and, to the extent received by Acquiring Party, Acquiring Party shall fully disclose, account for and transmit the same promptly to Transferring Party. All costs, expenses, disbursements, obligations and liabilities attributable to a Transferring Party’s Assets other than those related to Assumed Obligations for periods of time prior to the Effective Time, regardless of when due or payable, shall be the sole obligation of such Transferring Party and such Transferring Party shall promptly pay, or if paid by Acquiring Party, promptly reimburse Acquiring Party for and hold harmless from and against the same. All costs, expenses, disbursements, obligations, and liabilities attributable to a Transferring Party’s Assets for periods of time as of and after the Effective Time, regardless of when due or payable, shall be the sole obligation of Acquiring Party and Acquiring Party shall promptly pay, or if paid by Transferring Party, promptly reimburse such Transferring Party for and hold such Transferring Party harmless from and against the same.

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Section 12.14Insurance. LINN acknowledge that ExxonMobil maintains a worldwide program of property and liability insurance coverage for itself and its Affiliates. This program has been designed to achieve a co-coordinated risk management package for the entire ExxonMobil corporate group and includes self-insurance. All of the insurance policies through which the worldwide program of coverage is presently or has previously been provided by or to ExxonMobil, its predecessors or Affiliates are herein referred to collectively as the “ExxonMobil Policies.” It is understood and agreed by LINN that from and after the Closing:

A.No insurance coverage shall be provided under the ExxonMobil Policies to LINN;

B.Any and all ExxonMobil Policies shall be deemed terminated, commuted and cancelled ab initio; and

C.No claims regarding any matter whatsoever, whether or not arising from events occurring prior to the Closing, shall be made by LINN against or with respect to any of the ExxonMobil Policies regardless of their date of issuance.

LINN shall have its insurers waive any subrogation rights that they might have against ExxonMobil under the ExxonMobil Policies.

LINN shall indemnify and defend ExxonMobil and its Affiliates against, and shall hold them harmless from, any claim made after the Closing with respect to the Assumed Obligations against any of the ExxonMobil Policies by LINN or any Person rightly claiming to be subrogated to LINN’s rights (or claiming to be subrogated to LINN’s rights as a result of an action or representation by LINN), including all costs and expenses (including attorneys’ fees) related thereto. Such indemnity shall cover, without limitation, any claim by an insurer for reinsurance, retrospective premium payments or prospective premium increases attributable to any such claim.

Section 12.15Recording. As soon as practicable after Closing, each Party, as an Acquiring Party, shall record the Assignment in the appropriate counties and provide the other Party with copies of the recorded Assignment, and all required documentary, filing and recording fees and expenses in connection with the filing and recording of the Assignment required to convey title to the Assets received by such Acquiring Party shall be borne by such Acquiring Party.

Section 12.16Records. Within sixty (60) days after the Closing Date, each Party, as a Transferring Party, will deliver to the other Party, at such other Party’s cost and request, copies of any files, records and data relating to Transferring Party’s Assets including title records (including abstracts of title, title opinions, title reports and title curative documents), contracts, correspondence and all related matters in the possession of such Transferring Party (but excluding corporate, financial, Tax and general accounting records, any document subject to the attorney-client privilege, and any document, data or other information where disclosure is restricted by agreement with a third party). If an Acquiring Party requests geophysical data relating to the Transferring Party’s Assets that is not otherwise acquired hereunder, and if a Transferring Party is not restricted from releasing such data to Acquiring Party, Acquiring

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Party’s execution of a license agreement satisfactory to Transferring Party will be a condition of Transferring Party’s delivering such data to Acquiring Party.

Section 12.17Cooperation. After Closing, each Party agrees to use its commercially reasonable efforts to take such further actions and to execute, acknowledge and deliver all such further documents that are necessary or useful in carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement, including using its commercially reasonable efforts to assist Acquiring Party in taking over as operator with respect to any of Transferring Party’s Assets in which Transferring Party operates. In addition, after Closing, if Acquiring Party reasonably requires the original of any document related to the Assets that have been retained by the Transferring Party, Acquiring Party may have access to them at reasonable times and upon reasonable notice during regular business hours for a period of six years following the Closing. Acquiring Party may, during this period and at its expense, make copies of such documents pursuant to a reasonable request. Without limiting the generality of the two preceding sentences, during such period Transferring Party agrees not to destroy or give up possession of any original or last-remaining copy of the documents without first offering Acquiring Party the opportunity, at Acquiring Party’s expense, to obtain the original or a copy thereof.

Section 12.18Non-Solicitation; No Hire. For the period beginning on the date of this Agreement and ending on the date that is one (1) year after the Closing Date, each Party will not, unless acting in accordance Section 7.9 or with the other Party’s prior written consent, solicit (a) a New Employee hired by the other Party as an Acquiring Party pursuant to Section 7.9; (b) an employee of the other Party or its Affiliates that is excluded from Exhibit I of the other Party but, at the time of the execution of this Agreement, his or her primary employment function was directly related to the Assets; or (c) an officer or executive level employee of the other Party (such employees, together, “Excluded Employees”), to leave the employment of the other Party or become an employee of such Party or its Affiliates. Notwithstanding the foregoing, the Parties will not be prohibited from hiring or contracting for the services of an Excluded Employee of the other Party who (i) has terminated his or her employment relationship with the other Party without solicitation or inducement from such Party, (ii) responds to a bona fide job advertisement of general circulation made by such Party or any of its Affiliates (whether posted on a public site on the internet or in a newspaper, magazine or other publication), or (iii) is submitted to such Party or any of its Affiliates by a third-party unaffiliated employment agency. A general advertisement by a Party for employment that is not targeted at any Excluded Employee or group of Excluded Employees shall not constitute a breach of the obligations of such Party under this Section 12.18.

Section 12.19LINN Drilling Contract. At Closing, ExxonMobil agrees to assume the obligations (and be entitled to the benefits) of that certain drilling contract listed on Schedule 12.19.

Section 12.20LINN Excluded Depths. No later than thirty (30) days following a written request by ExxonMobil or XTO, LINN shall convey:

A.to ExxonMobil (or its designee) all of the LINN Excluded Depths reserved by LINN in the Assignments delivered by LINN under this Agreement; and

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B.to XTO Energy, EMOC, MEPDC and ExxonMobil (each as defined in the Deal 1 Exchange Agreement) in the undivided percentages requested by ExxonMobil or XTO all of the LINN Excluded Depths reserved by LINN in the Assignments delivered by LINN pursuant to the Deal 1 Exchange Agreement,

using the form of Assignment attached as Exhibit C - LINN to this Agreement or the Deal 1 Exchange Agreement, as applicable.

ARTICLE XIII

TAX

Section 13.1Apportionment of Taxes.

A.Each Party shall solely bear and pay any and all income Taxes, franchise Taxes and similar Taxes (collectively, “Income Taxes”) imposed by Law on it or its Affiliates. Notwithstanding any other provision in this Agreement to the contrary, a Party will not assume or otherwise bear, pursuant to Section 3.3 or otherwise, any Income Taxes of the other Party.

B.All ad valorem Taxes, real property Taxes, personal property Taxes, and similar obligations relating to the Assets (collectively, “Property Taxes”) with respect to any tax period beginning before and ending after the Effective Time shall be prorated based on the number of days in such period that occur on or before the day that is immediately prior to the day on which the Effective Time occurs, on the one hand, and the number of days in such period that occur on or after the day on which the Effective Time occurs, on the other hand, the amount of such Property Taxes allocable to the portion of the period ending on the day immediately prior to the day on which the Effective Time occurs being the responsibility of Transferring Party and the remainder being the responsibility of Acquiring Party. For this purpose, the period for each such Property Tax shall begin on the date on which ownership of the applicable Assets gives rise to liability for such Property Tax and shall end on the day before the next such date. To the extent the actual amount of a Property Tax attributable to such period is not determinable at the time the Final Settlement Statement is determined, the Parties shall use the amount of such Property Tax that was assessed and paid for the immediately preceding tax period for purposes of preparing the Final Settlement Statement, as applicable. Property Taxes with respect to any tax period ending before the Effective Time shall be the responsibility of Transferring Party, and Property Taxes with respect to any tax period beginning on or after the Effective Time shall be the responsibility of Acquiring Party.

C.All production, severance, excise and similar Taxes relating to the production of oil, gas, condensate and other Hydrocarbons attributable to the Assets (“Production Taxes”) shall be allocated between Transferring Party and Acquiring Party using a closing of the books method as of the Effective Time, with (i) Transferring Party being liable for such Production Taxes attributable to production occurring prior to the Effective Time and (ii) Acquiring Party being liable for such Production Taxes attributable to production occurring on and after the Effective Time. All sales, use, and similar Taxes attributable to the Assets or the production of Hydrocarbons therefrom (“Sales Taxes” and together with Property Taxes and Production Taxes, “Asset Taxes”) shall be allocated between Transferring Party and Acquiring Party as of the Effective Time, with (i) Transferring Party being liable for such Sales Taxes

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attributable to transactions occurring prior to the Effective Time and (ii) Acquiring Party being liable for such Sales Taxes attributable to transactions occurring on and after the Effective Time. For purpose of this Section 13.1C, any exemption, deduction, credit or other item that is calculated on an annual basis will be allocated pro rata per day between the period ending immediately prior to the Effective Time and the period beginning on the Effective Time. For the avoidance of doubt, Asset Taxes shall not include any Income Taxes or any Taxes occurring as a result of the transactions effected pursuant to this Agreement.

Section 13.2Transfer Taxes. The Exchange Consideration is exclusive of any Sales Taxes, conveyance, transfer and recording fees, real estate transfer stamps and other similar fees and Taxes imposed in connection with the transfer of the Assets pursuant to this Agreement (collectively, “Transfer Taxes”). If any Transfer Taxes are assessed, the applicable Acquiring Party shall be solely responsible for the payment of such Transfer Taxes. The Parties shall reasonably cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes. The Parties shall cooperate to file all necessary Tax returns and other documentation with respect to all Transfer Taxes.

Section 13.3Cooperation. Each Party shall provide the other Party with reasonable information which may be required by the other Party for the purpose of preparing Tax returns, responding to any audit by any taxing jurisdiction, or establishing exemptions from Tax. Each Party shall cooperate with all reasonable requests of the other Party made in connection with contesting the imposition of Taxes. Notwithstanding anything to the contrary in this Agreement, neither Party shall be required at any time to disclose to the other Party any Tax returns or other confidential Tax information.

Section 13.4Like-Kind Exchange. The Parties agree to use reasonable efforts to cooperate in connection with the effectuation of a like-kind exchange, in whole or in part, as provided in Section 1031 of the Code (a “Like-Kind Exchange Transaction”), including, to the extent applicable, a Like-Kind Exchange Transaction subject to the procedures outlined in Treasury Regulation Section 1.1031(k)-1 and/or Internal Revenue Service Revenue Procedure 2000-37. Each Party consents to the other Party’s assignment of all or any portion of its rights under this Agreement to its Affiliate, an Affiliate and/or Qualified Intermediary (as that term is defined in Section 1.1031(k)-l(g)(4)(iii) of the Treasury Regulations) and/or a Qualified Exchange Accommodation Titleholder (as that term is defined in Rev. Proc. 2000-37 issued effective September 15, 2000). However, the Parties acknowledge and agree that neither an assignment of a Party’s rights pursuant to this Section 13.4 nor any other actions taken by a Party or any other Person in connection with the Like-Kind Exchange Transaction shall release any Party from, or modify, any of its respective liabilities and obligations (including indemnity obligations to each other) under this Agreement, and no Party makes any representations as to any particular tax treatment that may be afforded to any other Party by reason of such assignment or any other actions taken in connection with such Like-Kind Exchange Transaction. If a Like-Kind Exchange Transaction occurs, the Parties recognize that IRS Form 8824, Like-Kind Exchanges, will be required to be filed, and each Party consents to the filing of such Form and will fully cooperate, to the extent necessary, with the other Party in filing such form.

Section 13.5Responsibility for Filing Tax Returns and Remitting Taxes. With respect to the Assets, (i) Transferring Party shall be responsible for timely remitting all Asset

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Taxes due with respect to its Assets on or prior to the Closing Date and Acquiring Party shall be responsible for timely remitting all Assets Taxes due with respect to such Assets after the Closing Date, to the relevant Governmental Authority, and each Party shall reimburse the other Party for their portion of such Taxes paid in accordance with Section 13.1B and Section 13.1C; (ii) Transferring Party shall prepare and timely file any Tax return for Asset Taxes with respect to its Assets required to be filed on or before the Closing Date; (iii) except as required by applicable Law, Acquiring Party shall prepare and timely file all other Tax returns for Asset Taxes with respect to such Assets required to be filed after the Closing Date, including such Tax returns for any Tax period before the Effective Time or any Tax period that started before and ended after the Effective Time that are due after the Closing Date; and (iv) Acquiring Party shall prepare and timely file any Tax return described in clause (iii) for any Tax period before the Effective Time or Tax period that started before and ended after the Effective Time in a manner consistent with past practice (unless such past practice is no longer permissible by Law) and shall not file such Tax returns without Transferring Party’s written consent (not to be unreasonable withheld, conditioned or delayed) after providing Transferring Party a copy thereof reasonably in advance of the due date for filing such Tax returns.  If Transferring Party disputes any item on such Tax return, it shall notify Acquiring Party of such disputed item (or items) and the basis for its objection.  The Parties shall act in good faith to resolve any such dispute prior to the date on which the relevant Tax return for Asset Taxes with respect to the Assets is required to be filed.

ARTICLE XIV

DISCLAIMERS AND WAIVERS

Section 14.1Disclaimer by Transferring Party. EXCEPT AS OTHERWISE SPECIFICALLY PROVIDED FOR IN ARTICLE V, AND THE SPECIAL WARRANTY OF TITLE IN THE ASSIGNMENT, EACH PARTY, AS AN ACQUIRING PARTY, ACKNOWLEDGES AND AGREES THAT THE TRANSFERRING PARTY EXPRESSLY DISCLAIMS AND NEGATES, AND ACQUIRING PARTY ACKNOWLEDGES AND AGREES IT IS NOT RELYING UPON, ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, BY THE TRANSFERRING PARTY, AS TO (I) TITLE TO ANY OF TRANSFERRING PARTY’S ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO SUCH ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM SUCH ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF SUCH ASSETS OR FUTURE REVENUES GENERATED BY SUCH ASSETS, (V) THE ABILITY TO PRODUCE HYDROCARBONS FROM SUCH ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF SUCH ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY TRANSFERRING PARTY OR THIRD PARTIES WITH RESPECT TO SUCH ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO SUCH ACQUIRING PARTY OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS,

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REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS OTHERWISE SPECIFICALLY PROVIDED FOR IN ARTICLE V, AND THE SPECIAL WARRANTY OF TITLE IN THE ASSIGNMENT, TRANSFERRING PARTY FURTHER DISCLAIMS AND NEGATES, AND ACQUIRING PARTY ACKNOWLEDGES AND AGREES IT IS NOT RELYING UPON, ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF ITS ASSETS, RIGHTS OF AN ACQUIRING PARTY UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE EXCHANGE CONSIDERATION, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT, SUBJECT TO ACQUIRING PARTY’S RIGHTS UNDER ARTICLE XII, THE APPLICABLE ACQUIRING PARTY SHALL BE DEEMED TO BE OBTAINING TRANSFERRING PARTY’S ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT SUCH ACQUIRING PARTY HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS IT DEEMS APPROPRIATE.

Section 14.2Waiver of Trade Practices Act. Each Party, as an Acquiring Party, acknowledges that, but for the provisions in this Section 14.2, its rights and remedies with respect to this transaction and with respect to all acts or practices of Transferring Party, past, present or future, in connection with this transaction would otherwise be governed by legal principles other than the Texas Deceptive Trade Practices - Consumer Protection Act, Tex. Bus. & Com. Code Ann. § 17.41 et seq. (the “DTPA”). Notwithstanding the foregoing, as a condition to Transferring Party entering into this Agreement, such Acquiring Party hereby waives the applicability of the DTPA to this transaction and any and all duties, rights or remedies that might be imposed by the DTPA, whether such duties, rights and remedies are applied directly by the DTPA itself or indirectly in connection with other statutes; provided, however, such Acquiring Party does not waive § 17.555 of the DTPA. Each Party, as an Acquiring Party, acknowledges, represents and warrants that it is purchasing the goods and/or services covered by this Agreement for commercial or business use; that it has assets of $5 million or more according to its most recent financial statement prepared in accordance with generally accepted accounting principles; that it has knowledge and experience in financial and business matters that enable it to evaluate the merits and risks of a transaction such as this; and that it is not in a significantly disparate bargaining position with Transferring Party.

ARTICLE XV

TERMINATION

Section 15.1Right of Termination. This Agreement may be terminated at any time at or prior to the Closing Date:

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A.by mutual consent of the Parties in writing;

B.by either Party, by written notice to the other Party, if (i) such other Party has breached its representations, warranties or covenants hereunder and such breach would result in the failure of any condition to Closing of the terminating Party set forth in Articles IX or X, as applicable, or any such condition is not otherwise satisfied or waived, and (ii) in the case of a breach, such breach has not been cured within thirty (30) days following written notification of the same to such other Party;

C.by either Party, by written notice to the other Party, if Closing has not occurred on or before the Outside Date; provided that such failure to close is not caused by a breach of this Agreement by the terminating Party or its Affiliates; or

D.by either Party, by written notice to the other Party, if any Law or final order, award or judgment restrains, enjoins or otherwise prohibits or makes illegal the exchange contemplated by this Agreement.

Section 15.2Effect of Termination. If this Agreement is terminated pursuant to Section 15.1 above, this Agreement shall become void and of no further force or effect (except for the provisions of Section 8.1, Section 8.2, Article XIV, this Article XV, and Article XVI (other than Section 16.12, which will terminate), which shall continue in full force and effect); provided, however, that if either Party has knowingly and intentionally breached its obligations under this Agreement at the time this Agreement is so terminated, such breaching Party shall continue to be liable to the other Party for damages relating to such knowing and intentional breach (but not otherwise) and such liability shall not be affected by such termination. Notwithstanding anything to the contrary contained in this Agreement, upon any termination of this Agreement pursuant to Section 15.1 above, each Transferring Party shall be free immediately to enjoy all rights of ownership of its respective Assets and to sell, transfer, encumber or otherwise dispose of its Assets to any party without any restriction under this Agreement.

ARTICLE XVI

MISCELLANEOUS

Section 16.1Entire Agreement. This Agreement, including the Schedules, Exhibits and Annex attached hereto and incorporated herein, constitutes the entire agreement between the Parties as to the subject matter of this Agreement and supersedes all prior agreements, understandings, negotiations and discussions of the Parties, whether oral or written. No supplement, amendment, alteration, modification or waiver of this Agreement shall be binding unless executed in writing by the Parties.

Section 16.2References. All references in this Agreement to articles, sections and other subdivisions refer to corresponding articles, sections and other subdivisions of this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any of such subdivisions are for convenience only and shall not constitute part of such subdivisions and shall be disregarded in construing the language contained in such subdivisions. The words “this Agreement,” “this instrument,” “herein,” “hereof,” “hereby,” “hereunder,” and words of similar

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import refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited. Pronouns in masculine, feminine, and neuter genders shall be construed to include any other gender, and words in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Derivatives and other forms of the terms defined in this Agreement shall have meanings consistent with the definitions herein provided. The term “including” (or “included”) shall be deemed to be followed by the phrase “but not limited to.” Unless otherwise expressly provided herein, any reference herein to a “day” shall refer to a calendar day. The phrase “Business Day” shall mean a day (other than a Saturday or Sunday) on which commercial banks in Texas are generally open for business. Time is of the essence of this Agreement.

Section 16.3Assignment. Except pursuant to Section 13.4, no Party shall assign all or any part of this Agreement, nor shall any Party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other Party and any assignment made without such consent shall be void; provided, however, that (i) an Acquiring Party may assign its rights to acquire the Assets to an Affiliate of such Acquiring Party by providing notice of such assignment to the applicable Transferring Party by November 17, 2014. No assignment of any rights hereunder by a Party shall relieve such Party of its obligations (including indemnity obligations) and responsibilities hereunder. Subject to this Section 16.3, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective permitted successors, assigns and legal representatives.

Section 16.4Waiver. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provisions of this Agreement (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 16.5Governing Law; Jurisdiction. This Agreement (including all claims or causes of action (whether in contract or tort) that may be based upon, arise out of or relate to this Agreement, or the negotiation, execution or performance of this Agreement) and the legal relations among the Parties shall be governed and construed in accordance with the laws of the State of Texas, excluding any conflicts of law rule or principle that might refer construction of such provisions to the laws of another jurisdiction. Any dispute arising out of or relating to this Agreement which cannot be amicably resolved by the Parties, shall be brought in a federal or state court of competent jurisdiction of the State of Texas.

Section 16.6Notices. Any notice required or permitted by this Agreement shall be given in writing by personal service, overnight delivery service, facsimile, email or by certified mail, return receipt requested, postage prepaid, as follows:

If to ExxonMobil:

Exxon Mobil Corporation

c/o XTO Energy Inc.

810 Houston Street

Fort Worth, TX 76102

48

Attention: Monte Dobson

Fax: 817-885-1973

Email: monte_dobson@xtoenergy.com

With a copy to:

XTO Energy Inc.

810 Houston Street

Fort Worth, Texas 76102

Attention: J. Matthew Perkins, Sr.

Fax: 817-885-1752

Email: matthew_perkins@xtoenergy.com

If to LINN Holdings:

Linn Energy Holdings, LLC

600 Travis Street, Suite 5100

Houston, Texas 77002

Attention: General Counsel

Fax: 281-840-4001

Email: cwells@linnenergy.com

With a copy to:

Linn Energy Holdings, LLC

600 Travis Street, Suite 5100

Houston, Texas 77002

Attention: David Beathard

Fax: 832-426-5909

Email: dbeathard@linnenergy.com

If to Berry:

Berry Petroleum Company, LLC

600 Travis Street, Suite 5100

Houston, Texas 77002

Attention: General Counsel

Fax: 281-840-4000

Email: cwells@linnenergy.com

(or such other address as designated in writing by either Party to the other) and shall be deemed to have been given as of the date of receipt by the intended Party.

Section 16.7Publicity. In connection with the execution of this Agreement and the Closing, the Parties shall consult with each other before they or their Affiliates issue any press

49

release, make any other public statement or schedule any press conference or conference call with investors or analysts with respect to this Agreement or the transactions contemplated by this Agreement and, except to the extent any public statement or press release is required by Law, order of a court of competent jurisdiction, or any listing agreement with or rule of any national securities exchange or association, shall not issue any such press release, make any such other public statement or schedule any such press conference or conference call without the prior written approval of the other Party, which approval will not be unreasonably withheld or delayed. Once Closing occurs (and following the issuance of any agreed press releases made in connection therewith), the Parties may issue other releases or public statements regarding the transactions contemplated by this Agreement without the prior written approval of the other Party.

Section 16.8Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the contemplated transactions is not affected in any material adverse manner to either Party. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the contemplated transactions are fulfilled to the extent possible.

Section 16.9No Third Party Beneficiaries. Nothing in this Agreement shall entitle any party other than LINN and ExxonMobil to any claim, cause of action, remedy or right of any kind.

Section 16.10Conspicuousness. EACH PARTY ACKNOWLEGES THAT THE PROVISIONS OF THIS AGREEMENT THAT ARE PRINTED IN THE SAME MANNER AS THIS SECTION ARE CONSPICUOUS.

Section 16.11Execution in Counterparts. This Agreement may be executed in counterparts, and each such counterpart shall be deemed to be an original instrument, but all such counterparts together shall constitute for all purposes one agreement. Facsimiles or other electronic copies (e.g., PDFs) of executed counterparts shall be deemed to be original instruments.

Section 16.12Specific Performance. Each Party hereby acknowledges and agrees that the rights of each Party to consummate the transactions contemplated hereby (including the satisfaction of any condition to Closing) are special, unique and of extraordinary character and that, if any Party violates or fails or refuses to perform any covenant or agreement made by it herein, the non-breaching Party will be without an adequate remedy at law. If any Party violates or fails or refuses to perform any covenant or agreement made by such Party herein, the non-breaching Party subject to the terms hereof, may, except to the extent that this Agreement has been validly terminated, institute and prosecute an action in any court of competent jurisdiction to enforce specific performance of such covenant or agreement or seek any other equitable relief without the necessity of proving actual damages and without any requirement to post a bond.

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Section 16.13Expenses. Except as otherwise expressly provided in this Agreement, whether or not the transactions contemplated hereby are consummated, each Party will pay its own costs and expenses incurred in anticipation of, relating to and in connection with the negotiation and execution of this Agreement and the transactions contemplated hereby.

Section 16.14Schedules. The information in the Schedules of each Transferring Party constitutes exceptions, qualifications and/or supplements to particular representations or warranties of such Transferring Party as set forth in this Agreement. The Schedules shall not be construed as indicating that any disclosed information is required to be disclosed, and no disclosure shall be construed as an admission that such information is material to, outside the ordinary course of business of, or required to be disclosed by, such Transferring Party or constitutes a Material Adverse Effect. Capitalized terms used in the Schedules that are not defined therein and are defined in this Agreement shall have the meanings given to them in this Agreement. The captions contained in the Schedules are for the convenience of reference only, and shall not be deemed to modify or influence the interpretation of the information contained in the Schedules or this Agreement. The statements in each Schedule qualify and relate to the corresponding provisions in the Sections of this Agreement to which they expressly refer and to each other provision in this Agreement to which the applicability of à statement or disclosure in a particular Schedule is reasonably apparent on its face.

Section 16.15No Partnership. The Parties agree that there is no partnership or joint venture or special relationship, of any kind, or intent to create one, between the Parties in connection with the transactions contemplated by this Agreement, and that no conduct between them should be interpreted as creating such a relationship or intent, which must instead be documented and approved by the respective boards of the Parties.

[Signature Pages Follow]

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IN WITNESS WHEREOF, the Parties have executed and delivered this Agreement effective as of the date first written above.

LINN ENERGY HOLDINGS, LLC
By:	/s/ David B. Rottino
Name:	David B. Rottino
Title:	EVP Business Development & Chief Accounting Officer
BERRY PETROLEUM COMPANY, LLC d/b/a BERRY OIL COMPANY
By:	/s/ David B. Rottino
Name:	David B. Rottino
Title:	EVP Business Development & Chief Accounting Officer

SIGNATURE PAGE TO EXCHANGE AGREEMENT

IN WITNESS WHEREOF, the Parties have executed and delivered this Agreement effective as of the date first written above.

EXXON MOBIL CORPORATION
By:	/s/ Randy J. Cleveland
Name:	Randy J. Cleveland
Title:	Attorney-in-Fact

SIGNATURE PAGE TO EXCHANGE AGREEMENT

ANNEX A

DEFINED TERMS

As used in this Agreement, the following capitalized terms shall have the following meanings:

“AAA” shall mean the American Arbitration Association.

“Accounting Arbitrator” shall have the meaning given to such term in Section 12.11C.

“Acquiring Party” shall mean the Party acquiring Assets from Transferring Party and owning those Assets as of and after the Effective Time.

“Acquiring Party’s Environmental Assessment” shall have the meaning given to such term in Section 4.10(i).

“Acquiring Party Group” shall mean Acquiring Party, its Affiliates and their respective directors, officers, employees, agents and representatives.

“AFE” shall have the meaning given to such term in Section 5.10.

“Affiliate” shall mean, with respect to any Person, any other Person that directly, or indirectly through one or more intermediaries, Controls, or is Controlled by, or is under common Control with, such Person.

“Agreement” shall have the meaning given to such term in the introduction to this Agreement.

“Allocated Value Assets” shall have the meaning given such term in Section 4.5.

“Allocated Values” shall have the meaning given such term in Section 4.5.

“Allocation” shall have the meaning given to such term in Section 3.2.

“Asset Taxes” shall have the meaning given to such term in Section 13.1C.

“Assets” shall have the meaning given to such term in Section 2.2.

“Assignment” shall have the meaning given to such term in Section 4.17.

“Assumed Obligations” shall have the meaning given to such term in Section 12.1.

“Berry” shall have the meaning given to such term in the introduction to this Agreement.

“Business Day” shall have the meaning given to such term in Section 16.2.

“Casualty Defect” shall have the meaning given to such term in Section 4.15.

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“Claim Notice” shall have the meaning given to such term in Section 12.6B.

“Closing” shall have the meaning given to such term in Section 11.1.

“Closing Amount” shall have the meaning given such term in Section 3.3.

“Closing Date” shall have the meaning given to such term in Section 11.1.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Control” (including the terms “Controlling,” “Controlled by” and “under common Control with”) shall mean the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting shares, by contract, or otherwise.

“Deal 1 Exchange Agreement” shall mean that certain Exchange Agreement dated as of May 20, 2014 by and among LINN Energy Holdings, LLC, Berry Petroleum Company, LLC (d/b/a Berry Oil Company), XTO Energy Inc., ExxonMobil Oil Corporation, Mobil E&P U.S. Development Corporation, and Exxon Mobil Corporation.

“Defect Deadline” shall have the meaning given to such term in Section 4.4.

“Defect Deductible” shall have the meaning given to such term in Section 4.8B.

“Defensible Title” shall have the meaning given to such term in Section 4.2.

“Downward Adjustments” shall have the meaning given to such term in Section 3.3B.

“DTPA” shall have the meaning given to such term in Section 14.2.

“Effective Time” shall mean 7:00 a.m. local time where the Assets are located on June 1, 2014.

“Environmental Cure Period” shall have the meaning given to such term in Section 4.13.

“Environmental Defect” shall have the meaning given to such term in Section 4.11.

“Environmental Defect Amount” shall have the meaning given to such term in Section 4.12A.

“Environmental Defect Notice” shall have the meaning given to such term in Section 4.11.

“Environmental Laws” shall mean any and all applicable Laws, including principles of common law, pertaining to the safety, health or conservation or protection of the Assets, the environment, wildlife, or natural resources in effect in any and all jurisdictions in which the Assets are located, including, without limitation, the Clean Air Act, as amended, the Federal Water Pollution Control Act, as amended, the Safe Drinking Water Act, as amended, the

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Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), the Superfund Amendments and Reauthorization Act of 1986, as amended, the Resource Conservation and Recovery Act, as amended (“RCRA”), the Hazardous and Solid Waste Amendments Act of 1984, as amended, the Toxic Substances Control Act, as amended, the Occupational Safety and Health Act, as amended, and any applicable state, tribal, or local counterparts, but shall not include any applicable Law associated with plugging and abandonment of any of the wells. The terms “hazardous substance”, “release”, and “threatened release” shall have the meanings specified in CERCLA; provided, however, that to the extent the Laws of the state in which the Assets are located are applicable and have established a meaning for “hazardous substance”, “release”, “threatened release”, “solid waste”, “hazardous waste”, and “disposal” that is broader than that specified in CERCLA or RCRA, such broader meaning shall apply with respect to the matters covered by such Laws.

“Estimated Settlement Statement” shall have the meaning given to such term in Section 3.3C.

“Exchange Consideration” shall have the meaning given to such term in Section 3.1.

“Excluded Assets” shall have the meaning given to such term in Section 2.3.

“Excluded Employees” shall have the meaning given to such term in Section 12.18.

“Existing Contracts” shall mean, with respect to LINN as the Transferring Party, the LINN Existing Contracts and, with respect to ExxonMobil as the Transferring Party, the ExxonMobil Existing Contracts.

“ExxonMobil” shall have the meaning given to such term in the introduction to this Agreement.

“ExxonMobil Assets” means, excluding the Excluded Assets, all of ExxonMobil’s and any of its Affiliates’ interest right, title and interest in and to the following:

A.    The oil and gas and mineral fee interests leased pursuant to the ExxonMobil Royalty-Free Lease, royalties, overriding royalties and other interests that are described in Exhibit A-ExxonMobil to the extent related to the lands described in Exhibit A-ExxonMobil (the “ExxonMobil Leases”).

B.    To the extent they may be assigned (after using commercially reasonable efforts to obtain any consents), all contracts to the extent related to any of the items listed in subsections A, C and D of this definition, including operating agreements, pooling and unitization agreements, declarations of pooling or unitization, communitization agreements, pooling orders, farmout and farmin agreements, exploration agreements, participation agreements, area of mutual interest agreements, oil sales contracts, gas sales, gas processing, gas gathering, and transportation agreements, surface leases, the water rights agreement identified on Exhibit F, rights-of-way, easements, permits, licenses, and other instruments and agreements pertaining thereto (the “ExxonMobil Existing Contracts”).

Annex A - 3

C.    All producing wells, water wells, injection wells, disposal wells and other wells of any nature and kind located on the ExxonMobil Leases (or lands pooled or unitized therewith), including the wells set forth on Exhibit B-ExxonMobil (the “ExxonMobil Wells”), and all equipment, personal property and fixtures, to the extent they may be assigned (after using commercially reasonable efforts to obtain any consents), and pipelines, gathering lines and other facilities and appurtenances to the extent related to the operation of the ExxonMobil Leases or the ExxonMobil Wells.

D.    Without limiting the foregoing, but excluding the Excluded Assets, all other right, title and interest of ExxonMobil of whatever kind or character, whether legal or equitable, vested or contingent, in and to the oil, gas and other minerals in and under or that may be produced from or attributable to the ExxonMobil Wells, including oil and gas leases, overriding royalties, production payments, fee royalty interests and other interests in such ExxonMobil Wells whether such interests are specifically described in Exhibit A-ExxonMobil or Exhibit B-ExxonMobil, and even though ExxonMobil’s interest in such oil, gas or other minerals may be incorrectly described in or omitted from Exhibit A-ExxonMobil or Exhibit B-ExxonMobil.

E.    All Hydrocarbons produced from or allocated to the ExxonMobil Leases, the ExxonMobil Wells on and after the Effective Time.

F.    Copies of all files and records relating to the items described in subsections A through E above including title records (including abstracts of title, title opinions, title reports and title curative documents), contracts, correspondence, and all related matters assignable and in the possession of ExxonMobil (the “ExxonMobil Records”), and to the extent assignable without payment of fees or other penalties (unless LINN agrees to, and does, pay such fees and penalties), all geophysical data and other seismic and related technical data and information relating to the ExxonMobil Assets described in subsections A through E above.

“ExxonMobil Defect Amount” shall have the meaning given to such term in Section 4.8A.

“ExxonMobil Policies” shall have the meaning given to such term in Section 12.14.

“Final Settlement Amount” shall have the meaning given to such term in Section 12.11D.

“Final Settlement Statement” shall have the meaning given to such term in Section 12.11A.

“Financial Data” shall have the meaning given that term in Section 7.11.

“Fundamental Representations” shall mean the representations and warranties in (i) Section 5.1 (Existence and Power), (ii) Section 5.2 (Brokers), (iii) Section 6.1 (Existence and Power), and (iv) Section 6.2 (Brokers).

“Governmental Authority” shall mean any federal, state, local, municipal, tribal or other government, any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial,

Annex A - 4

legislative, belief, regulatory or taxing authority or power, and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

“Hire Date” shall have the meaning given to such term in Section 7.9.

“HSR Act” shall mean the Hart Scott Rodino Antitrust Improvements Act of 1976, as amended.

“Hydrocarbons” shall mean oil and gas and other hydrocarbons (including condensate) produced or processed in association therewith (whether or not such item is in liquid or gaseous form), or any combination thereof, carbon dioxide, water and any minerals produced in association therewith.

“Imbalances” shall mean over-production or under-production subject to an imbalance or make-up obligation with respect to Hydrocarbons produced from or allocated to the Assets, regardless of whether such over-production or under-production, imbalance or make-up obligation arises at the platform, wellhead, pipeline, gathering system, transportation or other location and regardless of whether the same arises under contract or by operation of Law.

“Income Taxes” shall have the meaning given to such term in Section 13.1A.

“Indemnified Party” shall have the meaning given to such term in Section 12.6A.

“Indemnifying Party” shall have the meaning given to such term in Section 12.6A.

“Interim Period” shall have the meaning given to such term in Section 7.1.

“IRS” shall mean the Internal Revenue Service.

“Joint Use Agreement” shall mean Exhibit E or such Exhibit as modified for Eddy County and Lea County, New Mexico, as applicable.

“Knowledge” shall mean with respect to (a) LINN, the actual knowledge (without investigation) of the Persons listed on Schedule 6-LINN and (b) ExxonMobil, the actual knowledge (without investigation) of the Persons listed on Schedule 6-ExxonMobil.

“Law” shall mean any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree, permit or other official act of or by any Governmental Authority.

“Leases” shall mean, with respect to LINN as the Transferring Party, the LINN Leases and, with respect to ExxonMobil as the Transferring Party, the ExxonMobil Leases

“Lien” shall mean any lien, mortgage, security interest, defect, irregularity, pledge, charge or encumbrance.

“Like-Kind Exchange Transaction” shall have the meaning given to such term in Section 13.4.

“LINN” shall have the meaning given to such term in the introduction to this Agreement.

Annex A - 5

“LINN Acreage Tract” shall mean each of the tracts of land described on Exhibits A-1, A-2, A-3 and A-4 – LINN.

“LINN Assets” means, excluding the Excluded Assets, all of LINN’s and any of its Affiliates’ rights, title and interest in the following rights and interests:

A.    The oil, gas, and/or mineral leases, and oil and gas and mineral fee interests leased pursuant to the LINN Royalty-Free Lease, royalties, overriding royalties and other interests that are described in Exhibit A-LINN to the extent related to lands described in Exhibits A-1, A-2, A-3, A-4, or A-5-LINN (the “LINN Leases”).

B.    To the extent they may be assigned (after using commercially reasonable efforts to obtain any consents), all contracts to the extent related to any of the items listed in subsections A, C and D of this definition, including operating agreements, pooling and unitization agreements, declarations of pooling or unitization, communitization agreements, pooling orders, farmout and farmin agreements, exploration agreements, participation agreements, area of mutual interest agreements, oil sales contracts, gas sales, gas processing, gas gathering, and transportation agreements, surface leases, rights-of-way, easements, permits, licenses, and other instruments and agreements pertaining thereto (the “LINN Existing Contracts”).

C.    All producing wells, water wells, injection wells, disposal wells and other wells of any nature and kind located on the LINN Leases (or lands pooled or unitized therewith), including the wells listed on Exhibit B-LINN (the “LINN Wells”), and all equipment, personal property and fixtures, to the extent they may be assigned (after using commercially reasonable efforts to obtain any consents), and pipelines, gathering lines and other facilities and appurtenances to the extent related to the operation of the LINN Leases or the LINN Wells.

D.    Without limiting the foregoing, but excluding the Excluded Assets, all other right, title and interest of LINN of whatever kind or character, whether legal or equitable, vested or contingent, in and to the oil, gas and other minerals in and under or that may be produced from or attributable to the LINN Wells, including oil and gas leases, overriding royalties, production payments, fee royalty interests and other interests in such LINN Wells whether such interests are specifically described in Exhibit A-LINN or Exhibit B-LINN, and even though LINN’s interest in such oil, gas or other minerals may be incorrectly described in or omitted from Exhibit A-LINN or Exhibit B-LINN.

E.    All Hydrocarbons produced from or allocated to the LINN Leases or the LINN Wells on and after the Effective Time.

F.    Copies of all files and records relating to the items described in subsections A through E above including title records (including abstracts of title, title opinions, title reports and title curative documents), contracts, correspondence, and all related matters assignable and in the possession of LINN (the “LINN Records”), and to the extent assignable without payment of fees or other penalties (unless ExxonMobil agrees to, and does, pay such fees and penalties), all geophysical data and other seismic and related technical data and information relating to the LINN Assets described in subsections A through E above.

“LINN Defect Amount” shall have the meaning given to such term in Section 4.8A.

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“LINN Excluded Depths” shall mean the top twenty (20) feet of the Clear Fork Formation being the stratigraphic equivalent of a true vertical depth of 6,865 feet to 6,885 feet, as such depths are found in the Houpt #1 Well (API No. 423293102900), said well being located in Midland County, Texas, Section 24, Township 2 South, Block 39, at 2,117 feet the North line, and 520 feet from the East line.

“LINN Excluded Producing Wells and Properties” shall mean

(i)    the wells listed on Schedule 2.3(xvii)-LINN, together with (A) the LINN Leases covering the lands upon which such Wells are located (or pooled therewith), insofar and only insofar as the interest in the Leases is directly related to the rights and obligations to use and produce such Wells, limited to the depths penetrated by the existing wellbore of such Wells, (B) the right of ingress and egress through the wellbore (“LINN Retained Wells”)

(ii)    all pipelines, gathering lines and other facilities and appurtenances to the extent related to the operation of the LINN Retained Wells (the “LINN Retained Facilities”);

(iii)    any of the LINN Existing Contracts to the extent and only to the extent same relate to the LINN Retained Wells or LINN Retained Facilities, provided that, if partially assignable, the portion of such LINN Existing Contract related to the LINN Assets but unrelated to the LINN Retained Well or LINN Retained Facility will be included in the LINN Assets;

(iv)    all Hydrocarbons produced from the LINN Retained Wells; and

(v)    a non-exclusive easement to access the surface of the lands covered by the LINN Leases but only to the extent necessary to access, maintain, repair or rework the LINN Retained Wells or LINN Retained Facilities.

(vi)    Notwithstanding the exclusion of the LINN Excluded Producing Wells and Properties or anything in this Agreement to the contrary, LINN shall operate the LINN Excluded Producing Wells and Properties only in accordance with the applicable Joint Use Agreement.

“LINN Holdings” shall have the meaning given to such term in the introduction to this Agreement.

“LINN Replacement Acreage Tract” shall mean those tracts of land described on Exhibit G.

“Losses” shall mean claims, liabilities, losses, costs and expenses (including court costs and reasonable attorneys’ fees).

“Material Adverse Effect” shall mean, with respect to any Party, any change, inaccuracy, effect, event, result, occurrence, condition or fact (for the purposes of this definition, each, an “event”) (whether foreseeable or not and whether covered by insurance or not) that has

Annex A - 7

had or would be reasonably likely to have, individually or in the aggregate with any other event or events, a material adverse effect on (a) the ownership, operation or financial condition of the Assets, taken individually or as a whole, as currently operated as of the date of this Agreement or (b) the ability of a Party to consummate the transactions contemplated by this Agreement; provided, however, that Material Adverse Effect shall not include such material adverse effects resulting from: (i) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (ii) changes in general market, economic, financial or political conditions (including changes in commodity prices (including Hydrocarbons), fuel supply or transportation markets, interest or rates) in the area in which the Assets are located, the United States or worldwide; (iii) changes in conditions or developments generally applicable to the oil and gas industry in the area where the Assets are located; (iv) acts of God, including hurricanes, storms or other naturally occurring events; (v) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (vi) matters that are cured or no longer exist by the earlier of the Closing Date and the termination of this Agreement; (vii) a change in Laws from and after the date of this Agreement; (viii) Casualty Defects; (ix) any reclassification or recalculation of reserves in the ordinary course of business; (x) actions taken by an Acquiring Party with respect to Transferring Party’s Assets; and (xi) natural declines in well performance.

“Material Contracts” shall mean, with respect to a Transferring Party, all Existing Contracts of the type described below:

(a)    any Existing Contract that can reasonably be expected to result in aggregate payments by Transferring Party of more than $500,000 during the current or any subsequent calendar year or $2,000,000 in the aggregate over the term of such Existing Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(b)    any Existing Contract that can reasonably be expected to result in aggregate revenues to Transferring Party of more than $500,000 during the current or any subsequent calendar year or $2,000,000 in the aggregate over the term of such Existing Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(c)    any Hydrocarbon purchase and sale, transportation, gathering, treating, processing or similar contract that is not terminable without penalty on ninety (90) days or less notice;

(d)    any indenture, mortgage, loan, credit or sale-leaseback, guaranty of any obligation, bonds, letters of credit or similar financial contract related to the Transferring Party’s Assets;

(e)    any Existing Contract that constitutes a lease under which Transferring Party is the lessor or the lessee of personal property which lease (A) cannot be terminated by Transferring Party without penalty upon sixty (60) days or less notice and (B) involves an annual base rental of more than $100,000;

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(f)    any Existing Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, Transferring Party conducts business, including area of mutual interest contracts;

(g)    any Existing Contract that contains calls upon or options to purchase production;

(h)    any Existing Contract that constitutes a partnership agreement, joint venture agreement or similar contract (in each case, excluding any tax partnership);

(i)    any Existing Contracts for the use or sharing of drilling rigs;

(j)    any executory Existing Contract that constitutes a pending farmout agreement, exploration agreement, participation agreement or other similar contract where the primary obligation thereunder has not fully been performed;

(k)    any Existing Contract that constitutes a joint operating agreement; and

(l)    any Existing Contract with any Affiliate of Transferring Party that will not be terminable by Acquiring Party without penalty upon sixty (60) days or less notice other than joint operating agreements.

“New Employees” shall have the meaning given to such term in Section 7.9.

“Net Acres” means the acres of land under an active oil and gas lease with the Transferring Party as the lessee, proportionately reduced for the percentage of 8/8ths of the oil and gas interests owned by the lessor and the leasehold interest owned by the Transferring Party.

“Net Closing Amount” shall have the meaning given to such term is Section 3.3C.

“Net Defect Amount” shall have the meaning given to such term in Section 4.8A.

“Net Environmental Defect Amount” shall have the meaning given to such term in Section 4.13D(i).

“NORM” shall have the meaning given to such term in Section 4.16.

“Objection Notice” shall have the meaning given to such term in Section 12.11B.

“Outside Date” shall have the meaning given to such term in Section 11.1.

“Parties” shall have the meaning given to such term in the introduction to this Agreement.

“Party” shall have the meaning given to such term in the introduction to this Agreement.

“Permitted Encumbrances” shall have the meaning given to such term in Section 4.3.

“Permitted Title Matters” shall mean: (i) defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate

Annex A - 9

proceedings, unless Acquiring Party provides affirmative evidence that such failure or omission results in another Person’s adverse claim of title to the relevant Lease or Well; (ii) defects arising out of lack of survey, unless a survey is expressly required by applicable Laws; (iii) defects arising out of lack of corporate or other entity authorization, unless such lack of authorization results in a third party’s actual and adverse claim of title to the relevant property; (iv) except for matters related to Section 4.2C, defects based solely on lack of information in Transferring Party’s files; (v) defects that have been cured by applicable Laws of limitations or prescription, including adverse possession, the doctrine of laches, and deemed marketable record title; (vi) defects arising from any change in Law after the Effective Time; (vii) defects arising from prior expired oil and gas leases that are not surrendered or released of record; (viii) defects based on a claim that Transferring Party does not have title to an Asset (other than a leasehold interest), if Transferring Party has a valid right to use such Asset for the purposes for which it is being used; (ix) defects arising as a result of actions taken by Acquiring Party or Acquiring Party’s failure to consent to any action pursuant to Section 7.1; (x) any Lease which does not provide for the ability to pool or unitize the applicable leased premises; (xi) a breach of a maintenance of uniform interest provision in a Lease or Existing Contract; (xii) in connection with the LINN Assets, failure of title in any depth below the top of the Strawn Formation; and (xiii) a continuous drilling obligation in any Lease or Existing Contract.

“Person” shall mean any individual, corporation, company, partnership, limited partnership, limited liability company, trust, estate, Governmental Authority or any other entity.

“Production Taxes” shall have the meaning given to such term in Section 13.1C.

“Property Taxes” shall have the meaning given to such term in Section 13.1B.

“Records” shall mean, with respect to LINN as the Transferring Party, the LINN Records and, with respect to ExxonMobil as the Transferring Party, the ExxonMobil Records.

“REGARDLESS OF FAULT” shall have the meaning given to such term in Section 12.10.

“Remediate” or “Remediation” shall mean the payment or other final resolution of any assessed fines, removal, excavation, capping, or other environmental remedies to the extent required by the Environmental Laws to remedy an Environmental Defect existing on or with respect to an Asset to a commercial/industrial standard using the least costly methods available, which may include bio-remediation, land-farming, or institutional or engineering controls.

“Retained Liabilities” shall mean (i) all liabilities (other than with respect to Asset Taxes) arising from, based upon or associated with Transferring Party’s Assets that are acquired by Acquiring Party pursuant to this Agreement that arose prior to the Effective Time other than those liabilities described in subsections A through D of Section 12.1, (ii) those matters described in Schedule 5.3-LINN or Schedule 5.3-ExxonMobil, as applicable for each Transferring Party, and (iii) all liabilities for Income Taxes imposed on or with respect to Transferring Party or its Affiliates. “Sales Taxes” shall have the meaning given to such term in Section 13.1C.

Annex A - 10

“Robbie Lease” shall mean, collectively, (i) that certain Oil and Gas Lease dated December 3, 2007 between James E. Barron, as lessor, and Henry Resources, LLC, as lessee, which is recorded as Document 660 in Volume 2981, Page 571 of the Real Property Records of Midland County, Texas, and (ii) that certain Oil and Gas Lease dated December 16, 2008 between James E. Barron, as lessor, and Henry Resources, LLC, as lessee, which is recorded as Document 3094 in Volume 3152, Page 326 of the Real Property Records of Midland County, Texas.

“Spraberry Trend Interval” shall mean all depths from the top of the Clearfork Formation, being the stratigraphic equivalent of a true vertical depth 6,865 feet, to the top of the Strawn Formation, being the stratigraphic equivalent of a true vertical depth of 10,605 feet, as such depths are found in the Houpt #1 Well (API No. 423293102900), said well being located in Midland County, Texas, Section 24, Township 2 South, Block 39, at 2,117 feet the North line, and 520 feet from the East line.

“Strawn Formation” shall mean all depths below the top of the Strawn Formation, being the stratigraphic equivalent of a true vertical depth of 10,605 feet, as such depths are found in the Houpt #1 Well (API No. 423293102900), said well being located in Midland County, Texas, Section 24, Township 2 South, Block 39, at 2,117 feet the North line, and 520 feet from the East line.

“Targeted Closing Date” shall have the meaning given to such term in Section 11.1.

“Tax” or “Taxes” shall mean all taxes, assessments, duties, levies, imposts and other similar charges imposed by a Governmental Authority, including all income, franchise, profits, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, ad valorem, property, excise, severance or production, windfall profit, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental (including taxes under Code Section 59A), alternative minimum, add-on, value-added and withholding (including backup withholding) taxes (in all cases, whether payable directly or by withholding and whether or not requiring the filing of a Tax return) and all estimated taxes, deficiency assessments, additions to tax, additional amounts imposed by any Governmental Authority, penalties and interest.

“Tax Representations” shall mean the representations and warranties in (i) Section 5.12 (Taxes) and (ii) Section 5.13 (Tax Partnerships).

“Third Party Claim” shall have the meaning given to such term in Section 12.6B.

“Title Arbitrator” shall have the meaning given to such term in Section 4.9.

“Title Benefit” shall have the meaning given to such term in Section 4.6.

“Title Benefit Notice” shall have the meaning given to such term in Section 4.6.

“Title Benefit Value” shall have the meaning given to such term in Section 4.6.

“Title Cure Period” shall have the meaning given to such term in Section 4.8.

Annex A - 11

“Title Defect” shall have the meaning given to such term in Section 4.4.

“Title Defect Value” shall have the meaning given to such term in Section 4.5.

“Title Defect Notice” shall have the meaning given to such term in Section 4.4.

“Transfer Taxes” shall have the meaning given to such term in Section 13.2.

“Title Disputes” shall have the meaning given to such term in Section 4.9.

“Transferring Party” shall mean the Party transferring ownership of Assets to Acquiring Party as of the Effective Time.

“Transferring Party Group” shall mean Transferring Party, its Affiliates and their respective directors, officers, employees, agents and representatives.

“Upward Adjustments” shall have the meaning given to such term in Section 3.3A.

Annex A - 12

EXHIBITS AND SCHEDULES

EXHIBIT A- LINN – Leases

EXHIBIT A-1 – LINN – Pkgs 1: Acreage Tract (Production Included)

EXHIBIT A-2 – LINN – Pkg 2: Acreage Tracts (Production Retained)

EXHIBIT A-3 – LINN – Pkg 3: Acreage Tract (Production Retained)

EXHIBIT A-4 – LINN – Delaware Basin: Acreage Tracts (Production Retained)

EXHIBIT A-5 – LINN – Pkgs 6&8 Leases Only (Production Only)

EXHIBIT A – ExxonMobil – ExxonMobil Assets

EXHIBIT B – LINN - Wells

EXHIBIT B – ExxonMobil – Wells

EXHIBIT C – LINN – Assignment and Bill of Sale

EXHIBIT C – ExxonMobil – Assignment and Bill of Sale

EXHIBIT D-1 – Transition Services Agreement Form – Hill

EXHIBIT D-2 – Transition Services Agreement Form – Permian/Delaware

EXHIBIT E – Joint Use Agreement Form -- Permian

EXHIBIT F – Water Rights Agreement

EXHIBIT G – LINN Replacement Acreage Tracts

EXHIBIT H – LINN - LINN Royalty-Free Oil and Gas Lease

EXHIBIT H – ExxonMobil – ExxonMobil Royalty-Free Oil and Gas Lease

EXHIBIT I – LINN – Impacted Employees

EXHIBIT I – ExxonMobil – Impacted Employees

EXHIBIT J – LINN – Severance Plan

SCHEDULE 2.3(vii)-LINN – Personal Property Exceptions to Excluded Assets

SCHEDULE 2.3(vii)-ExxonMobil – Personal Property Exceptions to Excluded Assets

SCHEDULE 2.3(xv) – LINN – Excluded Assets

SCHEDULE 2.3(xv) – ExxonMobil – Excluded Assets

SCHEDULE 2.3(xvi) - LINN – Field Offices

SCHEDULE 2.3(xvi) – ExxonMobil – Field Offices

SCHEDULE 2.3(xvii) – LINN - LINN Excluded Producing Wells and Properties

SCHEDULE 5.3 – LINN – Claims and Litigation

SCHEDULE 5.3 – ExxonMobil – Claims and Litigation

SCHEDULE 5.6 – LINN – Material Contracts

SCHEDULE 5.6 – ExxonMobil – Material Contracts

SCHEDULE 5.7 – LINN – Imbalances

SCHEDULE 5.7 – ExxonMobil – Imbalances

SCHEDULE 5.9 – LINN – Preferential Purchase Rights and Consents to Assign

SCHEDULE 5.9 – ExxonMobil – Preferential Purchase Rights and Consents to Assign

SCHEDULE 5.10 – LINN – AFEs

SCHEDULE 5.10 – ExxonMobil – AFEs

SCHEDULE 5.11 – LINN – Environmental Claims

SCHEDULE 5.11 – ExxonMobil – Environmental Claims

SCHEDULE 5.12 – LINN – Taxes

Annex A - 13

SCHEDULE 5.12 – ExxonMobil – Taxes

SCHEDULE 5.14 – LINN – Payout Status

SCHEDULE 5.14 – ExxonMobil – Payout Status

SCHEDULE 5.16 – LINN – Transactions with Affiliates

SCHEDULE 5.16 – ExxonMobil – Transactions with Affiliates

SCHEDULE 5.18 – LINN – Plugging & Abandonment

SCHEDULE 5.18 – ExxonMobil – Plugging & Abandonment

SCHEDULE 6.0 – LINN – Knowledge

SCHEDULE 6.0 – ExxonMobil – Knowledge

SCHEDULE 12.19 – LINN Drilling Contract

Annex A - 14

EX-2.2

Exhibit 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

TABLE OF CONTENTS

Page

Article I DEFINITIONS AND INTERPRETATION		1
1.1	Defined Terms	1
1.2	References and Rules of Construction	1
Article II PURCHASE AND SALE		2
2.1	Purchase and Sale	2
2.2	Excluded Assets	4
2.3	Revenues and Expenses.	4
Article III Purchase Price		5
3.1	Purchase Price	5
3.2	Deposit	5
3.3	Adjustment to Purchase Price	5
3.4	Adjustment Methodology	7
3.5	Preliminary Settlement Statement	8
3.6	Final Settlement Statement	8
3.7	Disputes	9
3.8	Allocation of Purchase Price / Allocated Values	9
3.9	Allocation for Imbalances at Closing	10
Article IV ACCESS / DISCLAIMERS		10
4.1	Access.	10
4.2	Confidentiality	13
4.3	Disclaimers.	13
Article V TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS		14
5.1	General Disclaimer of Title Warranties and Representations	14
5.2	Special Warranty	15
5.3	Notice of Title Defects; Defect Adjustments.	15
5.4	Casualty or Condemnation Loss.	20
5.5	Preferential Purchase Rights and Consents to Assign.	21
5.6	Acknowledged Title Defects	23
Article VI ENVIRONMENTAL MATTERS		23
6.1	Environmental Defects.	23
6.2	NORM, Asbestos, Wastes and Other Substances	26
Article VII REPRESENTATIONS AND WARRANTIES OF Seller		27
7.1	Organization, Existence and Qualification	27
7.2	Authorization, Approval and Enforceability	28
7.3	No Conflicts	28
7.4	Consents	28
7.5	Bankruptcy	28

i

7.6	Litigation	28
7.7	Material Contracts.	29
7.8	No Violation of Laws	30
7.9	Preferential Rights	30
7.10	Payment of Burdens	30
7.11	Imbalances	30
7.12	Current Commitments	30
7.13	Tax Matters	30
7.14	Brokers’ Fees	31
7.15	Equipment	31
7.16	Payouts	31
7.17	Condemnation	31
7.18	Employee Benefits	31
7.19	Midstream Assets	32
7.20	Midstream Environmental Matters	32
7.21	Permits	32
7.22	Wells	32
7.23	Foreign Person	33
7.24	Labor Matters	33
Article VIII REPRESENTATIONS AND WARRANTIES OF BUYER		33
8.1	Organization, Existence and Qualification	33
8.2	Authorization, Approval and Enforceability	34
8.3	No Conflicts	34
8.4	Consents	34
8.5	Bankruptcy	34
8.6	Litigation	34
8.7	Regulatory	34
8.8	Financing	35
8.9	Independent Evaluation	35
8.10	Brokers’ Fees	35
8.11	Accredited Investor	35
Article IX CERTAIN AGREEMENTS		35
9.1	Conduct of Business	35
9.2	Successor Operator	37
9.3	Governmental Bonds	37
9.4	Records Retention	38
9.5	Guarantees	38
9.6	Digital Records	38
9.7	Amendment to Schedules	38
9.8	Regulatory Matters	39
9.9	Suspense Accounts	39
9.10	Transition Services	40
Article X BUYER’S CONDITIONS TO CLOSING		40
10.1	Representations	40

ii

10.2	Performance	40
10.3	No Legal Proceedings	40
10.4	Title Defects and Environmental Defects	40
10.5	HSR Approval	41
10.6	Casualty Loss	41
10.7	Closing Deliverables	41
Article XI SELLER’S CONDITIONS TO CLOSING		41
11.1	Representations	41
11.2	Performance	41
11.3	No Legal Proceedings	41
11.4	Title Defects and Environmental Defects	41
11.5	Closing Deliverables	42
11.6	HSR Approval	42
Article XII CLOSING		42
12.1	Date of Closing	42
12.2	Place of Closing	42
12.3	Closing Obligations	42
12.4	Records	43
Article XIII ASSUMPTION; INDEMNIFICATION; SURVIVAL		43
13.1	Assumption by Buyer; Specified Obligations.	43
13.2	Indemnities of Seller	45
13.3	Indemnities of Buyer	45
13.4	Limitation on Liability.	46
13.5	Express Negligence	46
13.6	Exclusive Remedy	46
13.7	Indemnification Procedures	47
13.8	Survival.	48
13.9	Non-Compensatory Damages	49
13.10	Waiver of Right to Rescission	49
13.11	Insurance	49
13.12	Disclaimer of Application of Anti-Indemnity Statutes	50
Article XIV Employment Matters		50
14.1	Seller Benefit Plans	50
14.2	Pre-Employee Start Date Claims under Seller Benefit Plans	50
14.3	Available Employees’ Offers and Post- Employee Start Date Employment and Benefits	50
14.4	Savings Plans	52
14.5	Post- Employee Start Date Employment Claims	52
14.6	COBRA	52
14.7	WARN Act	52
14.8	No Third Party Beneficiary Rights	53
14.9	Non-Solicitation of Employees	53

iii

Article XV TERMINATION, DEFAULT AND REMEDIES		54
15.1	Right of Termination	54
15.2	Effect of Termination	54
15.3	Return of Documentation and Confidentiality	54
15.4	Distribution of Deposit Upon Termination	54
Article XVI MISCELLANEOUS		55
16.1	Appendices, Exhibits and Schedules	55
16.2	Expenses and Taxes	55
16.3	Assignment	57
16.4	Preparation of Agreement	57
16.5	Publicity	57
16.6	Notices	57
16.7	Further Cooperation	59
16.8	Filings, Notices and Certain Governmental Approvals	59
16.9	Entire Agreement; Non-Reliance; Conflicts	60
16.10	Successors and Permitted Assigns	60
16.11	Parties in Interest	60
16.12	Amendment	61
16.13	Waiver; Rights Cumulative	61
16.14	Governing Law; Jurisdiction; Venue; Jury Waiver	61
16.15	Severability	62
16.16	Removal of Name	62
16.17	Counterparts	62
16.18	Like-Kind Exchange	62
16.19	Specific Performance	63
16.20	Buyer Liability	63

iv

LIST OF APPENDICES, EXHIBITS AND SCHEDULES

Appendices
Appendix I	―	Definitions
Exhibits
Exhibit A	―	Leases
Exhibit A-1	―	Fee Minerals
Exhibit A-2	―	Midstream Assets
Exhibit A-3	―	Easements
Exhibit A-4	―	Surface Fee Interests
Exhibit A-5	―	Field Office and Other Real Property
Exhibit B	―	Wells and Well Locations
Exhibit C	―	Personal Property
Exhibit D	―	Form of Assignment and Bill of Sale
Exhibit E	―	Excluded Assets
Exhibit F	―	Salt Water Disposal Wells and Evaporation Pits
Exhibit G	―	Allocated Values
Exhibit H	―	[Intentionally Omitted]
Exhibit I	―	Form of Mineral Deed
Exhibit J	―	Form of Surface Deed
Exhibit K	―	Severance Plans
Exhibit L	―	Form of Transition Services Agreement
Exhibit M	―	Buyer Proportionate Shares
Exhibit N	―	Target Formations
Exhibit O	―	Deposit Escrow Agreement
Exhibit P	―	Title and Environmental Defects Escrow Agreement
Schedules
Schedule 2.3(a)	―	Pre-Effective Time Costs
Schedule 7.4	―	Seller Consents
Schedule 7.6	―	Litigation
Schedule 7.7	―	Material Contracts
Schedule 7.8	―	Violation of Laws
Schedule 7.9	―	Preferential Rights
Schedule 7.10	―	Royalties
Schedule 7.11	―	Imbalances
Schedule 7.12	―	Current Commitments
Schedule 7.13	―	Tax Matters
Schedule 7.15	―	Certain Equipment Matters
Schedule 7.16	―	Payout Information
Schedule 7.17	―	Condemnation Proceedings

v

Schedule 7.18	―	Seller Benefit Plans
Schedule 9.1	―	Conduct of Business
Schedule 9.5	―	Guarantees

vi

PURCHASE AND SALE AGREEMENT

THIS PURCHASE AND SALE AGREEMENT (as the same may be amended, restated, supplemented or otherwise modified from time to time in accordance herewith, this “Agreement”) is entered into this second day of October, 2014 (the “Execution Date”), between Linn Energy Holdings, LLC, a Delaware limited liability company (“LEH”), Linn Midstream, LLC, a Delaware limited liability company (“LINN Midstream”), Linn Exploration Mid-Continent, LLC a Delaware limited liability company (“Linn Exploration”), Mid-Continent II, LLC, Delaware limited liability company (“MidCon II”), and Linn Operating, Inc., a Delaware corporation (“LOI” and, collectively with LEH, Linn Exploration, MidCon II, and LINN Midstream, “Seller”), and EnerVest Energy Institutional Fund XIII-A, L.P., a Delaware limited partnership (“EnerVest XIII-A”), EnerVest Energy Institutional Fund XIII-WIB, L.P., a Delaware limited partnership (“EnerVest XIII‑WIB”), EnerVest Energy Institutional Fund XIII-WIC, L.P., a Delaware limited partnership (“EnerVest XIII-WIC,” and collectively with EnerVest XIII-A and EnerVest XIII-WIB, “EnerVest”), and FourPoint Energy, LLC, a Colorado limited liability company (“FourPoint,” and collectively with EnerVest, “Buyer”). Buyer and Seller may be referred to collectively as the “Parties” or individually as a “Party.”

Recitals

Seller desires to sell and assign, and each of EnerVest and FourPoint desires to purchase and pay for, to the extent of the undivided percentage interest set forth opposite the name of such Party in Exhibit M hereto (such undivided percentage interest, the “Proportionate Share”), all of the Conveyed Interests (as defined hereinafter) effective as of the Effective Time (as defined hereinafter).

NOW, THEREFORE, for and in consideration of the mutual agreements herein contained, the benefits to be derived by each Party, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

ARTICLE I

DEFINITIONS AND INTERPRETATION

1.1    Defined Terms. Capitalized terms used herein shall have the meanings given such terms in Appendix I, unless the context otherwise requires.

1.2    References and Rules of Construction. All references in this Agreement to Exhibits, Appendices, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding Exhibits, Appendices, Schedules, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Exhibits, Appendices, Schedules, Articles, Sections, subsections and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder,” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection or other

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HOU:3475670.13

subdivision unless expressly so limited. The words “this Article,” “this Section,” and “this subsection,” and words of similar import, refer only to the Article, Section or subsection hereof in which such words occur. The word “including” (in its various forms) means including without limitation. All references to “$” or “dollars” shall be deemed references to United States dollars. Each accounting term not defined herein, and each accounting term partly defined herein, to the extent not defined, will have the meaning given to it under GAAP. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. References to any agreement (including this Agreement) shall mean such agreement as it may be amended, supplemented or otherwise modified from time to time. References to any date shall mean such date in Houston, Texas and for purposes of calculating the period of time in which any notice or action is to be given or undertaken hereunder, such period shall be deemed to begin at 12:01 A.M. on the applicable date in Houston, Texas.

ARTICLE II

PURCHASE AND SALE

2.1    Purchase and Sale. Subject to the terms and conditions of this Agreement, Seller agrees to sell to Buyer, and Buyer agrees to purchase and pay for, as of the Effective Time, all of Seller’s right, title and interest in and to the interests and properties described in Section 2.1(a) through Section 2.1(r) (such right, title and interest, less and except the Excluded Assets, collectively, the “Conveyed Interests”):

(a)    all of the oil and gas leases described in Exhibit A, together with any and all other right, title and interest of Seller in and to the leasehold estates created thereby subject to the terms, conditions, covenants and obligations set forth in such leases and/or Exhibit A (such interest in such leases, the “Leases”), and all rights and interests in the lands covered by the Leases and any lands pooled or unitized therewith (such lands, the “Lands”);

(b)    all wells located on any of the Oil and Gas Properties (such interest in such wells, including the wells set forth inExhibit B, the “Wells”), and all Hydrocarbons produced therefrom or allocated thereto from and after the Effective Time;

(c)    all rights and interests in, under or derived from all unitization and pooling agreements, declarations and orders in effect with respect to any of the Leases or Wells and the units created thereby (the “Units”);

(d)    all fee mineral interests that are part of producing Units, including those described in Exhibit A-1 (such interest, the “Fee Minerals”) (the Leases, the Lands, the Wells, the Units, and the Fee Minerals being collectively referred to hereinafter as the “Oil and Gas Properties”);

(e)    the gas processing plants and gas gathering systems, including all pipelines, meters and measurement facilities, treating and separation facilities, compression equipment, Hydrocarbon terminals, water systems, collection and storage facilities, and all

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HOU:3475670.13

appurtenant facilities to provide processing, gathering and related midstream services, including those facilities described on Exhibit A-2 (collectively, the “Midstream Facilities”);

(f)    all permits, licenses, servitudes, easements, rights-of-way, surface leases, other surface interests and surface rights to the extent appurtenant to or used primarily in connection with the ownership, operation, production, gathering, treatment, processing, storing, sale or disposal of Hydrocarbons or produced water from the Oil and Gas Properties and the Midstream Facilities, including those described on Exhibit A-3 (the “Easements”);

(g)    the surface fee interests described in Exhibit A-4 (the “Surface Fee Interests”);

(h)    all equipment, machinery, fixtures and other personal, movable and mixed property, operational or nonoperational, known or unknown, located on or used or held for use in connection with any of the Oil and Gas Properties, Surface Fee Interests, or the Midstream Facilities, including those items listed in Exhibit C, and including well equipment, casing, tubing, pumps, motors, machinery, platforms, rods, tanks, boilers, fixtures, compression equipment, flowlines, pipelines, gathering systems associated with the Wells, manifolds, all processing, separation and treating facilities, pads, structures, buildings, materials, and other items used in the operation thereof (collectively, the “Personal Property”) (the Midstream Facilities and the related Easements, Surface Fee Interests and Personal Property being collectively referred to herein as the “Midstream Assets”);

(i)    the field offices and other real property described on Exhibit A-5 and any Personal Property located thereon;

(j)    the salt water disposal wells, fresh water wells, water lines, frac pits and evaporation pits that are located on, used, or held for use in connection with the Oil and Gas Properties or the Surface Fee Interests, including those described on Exhibit F;

(k)    to the extent assignable, all Applicable Contracts and all rights thereunder insofar and only insofar as they relate to the Conveyed Interests;

(l)    all Imbalances relating to the Conveyed Interests;

(m)    all of the files, records, information and data, whether written or electronically stored, primarily relating to the Conveyed Interests in Seller’s or its Affiliates’ possession, including: (i) land and title records (including abstracts of title, title opinions and title curative documents); (ii) Applicable Contract files; (iii) correspondence; (iv) operations, environmental, production and accounting records and (v) facility and well records (collectively, “Records”);

(n)    all of Seller’s right, title and interest in and to all claims and causes of action (including claims for adjustments or refunds) to the extent attributable to (i) the Conveyed Interests insofar as initially accruing from and after the Effective Time, and (ii) any of the Assumed Obligations;

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(o)    all SCADA and measurement technology used solely in connection with the Conveyed Interests;

(p)    all Hydrocarbons in storage or existing at the Effective Time in stock tanks, pipelines and/or plants (including inventory);

(q)    all information technology assets, including desktop computers, laptop computers, servers, networking equipment and any associated peripherals and other computer hardware, all radio and telephone equipment, smartphones, tablets and other mobility devices, well communication devices, and any other information technology systems to extent (i) solely used by Seller’s field personnel in connection with the operation of the Oil and Gas Properties or the Midstream Assets or (ii) located in a field office included in the Conveyed Interests, but in any case excluding any software or data related to assets other than the Conveyed Interests and data related to the Excluded Assets; and

(r)    all geophysical or other seismic or related technical data or information relating to the Conveyed Interests, together with all interpretations thereto, other than such data, information, or interpretations that cannot be transferred due to restrictions with third parties without payment of a fee or other penalties (unless Buyer agrees to, and does, pay such fees and penalties).

2.2    Excluded Assets. Seller shall reserve and retain all of the Excluded Assets.

2.3    Revenues and Expenses.

(a)    Except as expressly provided otherwise in this Agreement, Seller shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production, and other proceeds) and shall remain responsible (by payment, through the adjustments to the Purchase Price under this Agreement or otherwise) for all Operating Expenses, in each case attributable to the Conveyed Interests for the period of time prior to the Effective Time. Except as expressly provided otherwise in this Agreement, and subject to the occurrence of Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production, and other proceeds), and shall be responsible for (by payment, through the adjustments to the Purchase Price under this Agreement or otherwise) (i) all Operating Expenses, in each case attributable to the Conveyed Interests for the period of time commencing at the Effective Time, and (ii) the expenses shown as “Completion Costs” on Schedule 2.3(a) for each Well listed on Schedule 2.3(a) that has not been completed and placed on production prior to the Effective Time, whether or not such completion expenses were incurred before or after the Effective Time (and Seller will remain responsible for all other expenses shown on Schedule 2.3(a)) (the “Designated Well Costs”). Such amounts which are received or paid prior to Closing shall be accounted for in the Preliminary Settlement Statement or Final Settlement Statement, as applicable; provided, however, that the Preliminary Settlement Statement may contain estimated amounts. Such amounts which are received or paid after Closing but prior to the date of the Final Settlement Statement shall be accounted for in the Final Settlement Statement.

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(b)    Subject to Section 3.6(b), after the Parties’ agreement upon the Final Settlement Statement, (i) if either Party receives monies belonging to the other Party, including proceeds of production, then such amount shall, within 30 days after the end of the calendar month in which such amounts were received, be paid over to the proper Party, (ii) if either Party pays monies for Operating Expenses which are the obligation of the other Party, then such other Party shall, within 30 days after the end of the calendar month in which the applicable invoice and proof of payment of such invoice were received, reimburse the Party which paid such Operating Expenses, (iii) if a Party receives an invoice of an expense or obligation (other than an invoice of an expense or obligation with respect to Asset Taxes or Income Taxes) which is owed by the other Party, such Party receiving the invoice shall promptly forward such invoice to the Party obligated to pay the same, and (iv) if an invoice or other evidence of an obligation (other than an obligation with respect to Asset Taxes or Income Taxes) is received by a Party, which is partially an obligation of both Seller and Buyer, then the Parties shall consult with each other, and each shall promptly pay its portion of such obligation to the obligee thereof.

(c)    Each of Seller and Buyer shall be permitted to offset any Operating Expenses owed by such Party to the other Party pursuant to this Section 2.3 against amounts owing by the second Party to the first Party pursuant to this Section 2.3, but not otherwise.

ARTICLE III

PURCHASE PRICE

3.1    Purchase Price. The purchase price for the transfer of the Conveyed Interests and the transactions contemplated hereby shall be One Billion Nine Hundred Fifty Million Dollars ($1,950,000,000) (the “Purchase Price”), as adjusted pursuant to this Agreement and payable by Buyer to Seller at Closing by wire transfer in immediately available funds to a bank account of Seller (the details of which shall be provided by Seller to Buyer in the Preliminary Settlement Statement).

3.2    Deposit. Within five (5) Business Days following the Execution Date, Buyer shall deliver a deposit equal to five percent (5%) of the Purchase Price to assure Buyer’s performance of its obligations hereunder (the “Deposit”), by means of a federal fund wire transfer to Wells Fargo Bank, N.A. (the “Escrow Agent”) to be held pursuant to the Deposit Escrow Agreement. The Deposit shall be applied against the Purchase Price if the Closing occurs or shall otherwise be distributed in accordance with the terms of Section 15.4.

3.3    Adjustment to Purchase Price. The Purchase Price shall be adjusted as follows (without duplication), and the resulting amount shall be herein called the “Adjusted Purchase Price”:

(a)    The Purchase Price shall be adjusted upward by the following amounts:

(i)    an amount equal to the value of all Hydrocarbons attributable to the Conveyed Interests in storage or existing in stock tanks, pipelines and/or plants (including inventory, but excluding tank bottoms and BS&W) in each case that are, as of the Effective Time, (A) upstream of the pipeline connection or (B) upstream of the sales meter, if any, the value to be based upon the contract price in effect as of the Effective

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Time (or the price paid to Seller in connection with the sale of such Hydrocarbons, if there is no contract price, during the Interim Period), net of (i) amounts payable as Burdens on such production and (ii) any Asset Taxes on such Hydrocarbons economically borne by Buyer but not taken into account pursuant to Section 3.3(b)(ii);

(ii)    an amount equal to all Operating Expenses and all other costs and expenses that are attributable to the Conveyed Interests (other than Asset Taxes and Income Taxes) incurred by Seller during the period of time commencing at the Effective Time, whether paid before or after the Effective Time, including (A) Burdens, (B) bond and insurance premiums paid by or on behalf of Seller with respect to the period of time commencing at the Effective Time, and (C) rentals and other lease maintenance payments;

(iii)    an amount equal to all of the Designated Well Costs paid by Seller, whether paid before or after the Effective Time;

(iv)    the Title Benefit Amounts of any Title Benefits for which the Title Benefit Amounts have been determined prior to Closing;

(v)    the amount of all Asset Taxes allocated to Buyer in accordance with Section 16.2 but that are paid or otherwise economically borne by Seller;

(vi)    subject to Section 3.8(a), to the extent that Seller is underproduced as shown with respect to the net Well Imbalances set forth in Schedule 7.11, as complete and final settlement of all Well Imbalances attributable to the Conveyed Interests, the sum of $6,450,807.00, which is an amount equal to the product of the underproduced volumes times $3.00/MMBtu for gaseous Hydrocarbons or $90.00/Bbl for liquid Hydrocarbons;

(vii)    subject to Section 3.8(a), to the extent that Seller has overdelivered any Hydrocarbons as of the Effective Time as shown with respect to the net Pipeline Imbalances set forth in Schedule 7.11, as complete and final settlement of all Pipeline Imbalances attributable to the Conveyed Interests, the sum of $0, which is an amount equal to the product of the overdelivered volumes times $3.00/MMBtu for gaseous Hydrocarbons or $90.00/Bbl for liquid Hydrocarbons; and

(viii)    any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

(b)    The Purchase Price shall be adjusted downward by the following amounts:

(i)    an amount equal to all proceeds actually received by Seller attributable to the sale of Hydrocarbons (A) produced from or allocable to the Conveyed Interests during the period of time commencing at the Effective Time or (B) contained in storage or existing in stock tanks, pipelines and/or plants (including inventory, but excluding tank bottoms and BS&W) as of the Effective Time for which an upward Purchase Price adjustment was made pursuant to Section 3.3(a)(i), (in each case) net of expenses (other than Operating Expenses and other expenses taken into account pursuant

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to Section 3.3(a), Income Taxes and Asset Taxes) directly incurred in earning or receiving such proceeds;

(ii)    the amount of all Asset Taxes allocated to Seller in accordance with Section 16.2 but that are paid or otherwise economically borne by Buyer;

(iii)    if Seller makes the election under Section 5.3(d)(i) with respect to a Title Defect, the Title Defect Amount with respect to such Title Defect if the Title Defect Amount has been determined prior to Closing;

(iv)    if Seller makes the election under Section 6.1(b)(i) with respect to an Environmental Defect, the Remediation Amount with respect to such Environmental Defect if the Remediation Amount has been determined prior to Closing;

(v)    the Allocated Value of the Conveyed Interests excluded from the transactions contemplated hereby pursuant to Sections 4.1(b)), 5.3(d)(ii), 5.4(b), 5.5(b)(i), 5.5(b)(ii) or 6.1(b)(ii);

(vi)    an amount equal to all proceeds from sales of any of the Conveyed Interests (other than asset swap transactions made by Seller in accordance with Section 9.1(a)(iii)) during the Interim Period; provided that Buyer pays Seller the Allocated Value (as the same may be adjusted pursuant to the terms of this Agreement) for such Conveyed Interests at Closing;

(vii)    subject to Section 3.8(a), to the extent that Seller is overproduced as shown with respect to the net Well Imbalances set forth in Schedule 7.11, as complete and final settlement of all Well Imbalances attributable to the Conveyed Interests, the sum of $2,551,575.00, which is an amount equal to the product of the overproduced volumes times $3.00/MMBtu for gaseous Hydrocarbons or $90.00/Bbl for liquid Hydrocarbons;

(viii)    subject to Section 3.8(a), to the extent that Seller has underdelivered any Hydrocarbons as of the Effective Time as shown with respect to the net Pipeline Imbalances set forth in Schedule 7.11, as complete and final settlement of all Pipeline Imbalances attributable to the Conveyed Interests, the sum of $2,073.00, which is an amount equal to the product of the underdelivered volumes times $3.00/MMBtu for gaseous Hydrocarbons or $90.00/Bbl for liquid Hydrocarbons;

(ix)    an amount equal to all proceeds from sales of Hydrocarbons relating to the Conveyed Interests and payable to owners of Working Interests, royalties, overriding royalties and other similar interests (in each case) that are held by Seller in suspense as of the Closing Date; and

(x)    any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

3.4    Adjustment Methodology. When available, actual figures will be used for the adjustments to the Purchase Price at Closing. To the extent actual figures are not available,

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estimates will be used subject to final adjustments in accordance with Section 3.6 and Section 3.7.

3.5    Preliminary Settlement Statement. Not less than five Business Days prior to Closing, Seller shall prepare and submit to Buyer for review a draft settlement statement (the “Preliminary Settlement Statement”) that shall set forth the Adjusted Purchase Price, reflecting each adjustment made in accordance with this Agreement as of the date of preparation of such Preliminary Settlement Statement and the calculation of the adjustments used to determine such amount, together with the designation of Seller’s accounts for the wire transfers of funds as set forth in Section 3.1 and Section 12.3(d). Within two Business Days after receipt of the Preliminary Settlement Statement, Buyer will deliver to Seller a written report containing all changes, with explanation therefor, that Buyer proposes to be made to the Preliminary Settlement Statement, if any. The Parties shall in good faith attempt to agree on the Preliminary Settlement Statement as soon as possible after Seller’s receipt of Buyer’s written report. The Preliminary Settlement Statement, as agreed upon by the Parties, will be used to adjust the Purchase Price at Closing; provided that if the Parties do not agree on an adjustment set forth in the Preliminary Settlement Statement prior to the Closing, the amount of such adjustment set forth in the Preliminary Settlement Statement as presented by Seller will be used to adjust the Purchase Price at Closing.

3.6    Final Settlement Statement.

(a)    On or before 150 daysafter the Closing, Seller shall deliver to Buyer a final settlement statement (the “Final Settlement Statement”) prepared by Seller based on actual income and expenses during the Interim Period and which takes into account all final adjustments made to the Purchase Price and shows the resulting final Adjusted Purchase Price (the “Final Price”). The Final Settlement Statement shall set forth the actual proration of the amounts required by this Agreement. As soon as practicable, and in any event within 30 days after receipt of the Final Settlement Statement, Buyer will deliver to Seller a written report containing any proposed changes to the Final Settlement Statement and an explanation of any such changes and the reasons therefor (the “Dispute Notice”). Any changes not so specified in the Dispute Notice shall be deemed waived and Seller’s determinations with respect to all such elements of the Final Settlement Statement that are not addressed specifically in the Dispute Notice shall prevail. If Buyer fails to timely deliver a Dispute Notice to Seller containing changes Buyer proposes to be made to the Final Settlement Statement, the Final Settlement Statement as delivered by Seller will be deemed to be correct and mutually agreed upon by the Parties, and will be final and binding on the Parties and not subject to further audit or arbitration. If the Final Price set forth in the Final Settlement Statement is mutually agreed upon by Seller and Buyer, the Final Settlement Statement and the Final Price shall be final and binding on the Parties, subject to the provisions of Section 2.3(b). Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Price shall be paid by the owing Party to the owed Party within 10 days after final determination of such owed amounts in accordance herewith. All amounts paid pursuant to this Section 3.6 shall be delivered in United States currency by wire transfer of immediately available funds to the account specified in writing by the relevant Party.

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(b)    Should any adjustment provided for in Section 3.3be required after such adjustments under Section 3.6(a) are concluded, such adjustments shall be made by appropriate payments from Buyer to Seller or from Seller to Buyer, as provided under Section 2.3(b). The obligations of the Parties to the payments described in the preceding sentence shall terminate on the later of September 30, 2015 or the date that a decision is rendered pursuant to the Accounting Arbitrator in Section 3.7 and any payments required by such decisions have been made.

3.7    Disputes. If Seller and Buyer are unable to resolve the matters addressed in the Dispute Notice (if any), each of Buyer and Seller shall within 14 Business Days after the delivery of such Dispute Notice, summarize its position with regard to such dispute in a written document of 20 pages or less and submit such summaries to the Houston office of PricewaterhouseCoopers, LLP (the “Accounting Arbitrator”), together with the Dispute Notice, the Final Settlement Statement and any other documentation such Party may desire to submit. If PricewaterhouseCoopers, LLP is unable or unwilling to serve as Accounting Arbitrator under this Section 3.7, the Houston office of Ernst & Young LLP, or such other Person as the Parties may mutually select shall serve as Accounting Arbitrator. Within 20 Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision choosing either Seller’s position or Buyer’s position with respect to each matter addressed in any Dispute Notice, based on the materials submitted to the Accounting Arbitrator as described above. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and will be enforceable against the Parties in any court of competent jurisdiction. The costs of the Accounting Arbitrator shall be borne pro rata between the Parties with each Party being responsible for the Accounting Arbitrator’s costs to the extent the Accounting Arbitrator has not selected such Party’s position on an aggregate dollar basis with respect to all amounts submitted for resolution by the Accounting Arbitrator.

3.8    Allocation of Purchase Price/Allocated Values.

(a)    The “Allocated Values” for (i) the Wells and Well Locations as to the applicable Target Formation and (ii) the other Conveyed Interests are set forth on Exhibit G. The Allocated Value for a Well or a Well Location (as to the applicable Target Formation) is equal to the portion of the Unadjusted Purchase Price that is allocated to such Well or Well Location (as to the applicable Target Formation) on Exhibit G, increased or decreased by a share of each adjustment to the Unadjusted Purchase Price in accordance with Section 3.3. The share of each adjustment allocated to a particular Well or Well Location (as to the applicable Target Formation) shall be allocated to the particular Well or Well Location (as to the applicable Target Formation) to which such adjustment relates to the extent such adjustment relates to such Well or Well Location (as to the applicable Target Formation) and to the extent that it is, in the commercially reasonable discretion of Seller, possible to do so. Any adjustment not allocated to a specific Well or Well Location (as to the applicable Target Formation) pursuant to the immediately preceding sentence shall be allocated among the remaining Conveyed Interests on a pro-rata basis in proportion to the Unadjusted Purchase Price allocated to such Conveyed Interests on Exhibit G. Seller has accepted such Allocated Values for purposes of this Agreement and the transactions contemplated hereby, but makes no representation or warranty as to the accuracy of such values.

(b)    For purposes of Income Taxes, Asset Taxes, and other Taxes, Buyer and Seller shall use commercially reasonable efforts to agree to an allocation of the Purchase Price,

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in a manner consistent with Section 1060 of the Code, and Treasury Regulations thereunder (and, as adjusted hereunder, if applicable, in accordance with any other similar provision of state or local Law) within 30 days following the Closing Date. Such agreed allocation schedule shall be reasonably consistent with the Allocated Values, as adjusted pursuant to this Agreement. Buyer and Seller shall report the purchase and sale of the Conveyed Interests on all Tax Returns (including IRS Form 8594) consistently with such agreed allocation and shall not take any position that is inconsistent with any such agreed allocation schedule unless otherwise required by applicable Law. Such agreed allocation may be revised from time to time, upon the mutual written consent of Buyer and Seller, to take into account any matters that need updating (such as Purchase Price adjustments, if any).

3.9    Allocation for Imbalances at Closing. If, prior to Closing, either Party discovers an error in the Imbalances set forth inSchedule 7.11, then the Purchase Price shall be further adjusted at Closing pursuant toSections 3.3(a)(vi), 3.3(a)(vii), 3.3(b)(vii)or 3.3(b)(viii), as applicable, andSchedule 7.11 will be deemed amended immediately prior to Closing to reflect the Imbalances for which the Purchase Price is so adjusted.

ARTICLE IV

ACCESS / DISCLAIMERS

4.1    Access.

(a)    From and after the Execution Date and up to and including the Closing Date (or earlier termination of this Agreement pursuant to the terms herein) but subject to the other provisions of this Section 4.1 and obtaining of any required consents of Third Parties, including Third Party operators of the Oil and Gas Properties and the Midstream Assets (with respect to which consents Seller shall not be obligated to expend any monies), Seller shall afford to Buyer and its authorized representatives (“Buyer’s Representatives”) reasonable access, during normal business hours, to the Oil and Gas Properties and the Midstream Assets and all Records in Seller’s possession or control at such time to the extent necessary to conduct the title or environmental review described in Article V and Article VI. All investigations and due diligence conducted by Buyer or any Buyer’s Representative shall be conducted at Buyer’s sole cost, risk and expense and any conclusions made from any examination done by Buyer or any Buyer’s Representative shall result from Buyer’s own independent review and judgment.

(b)    From the Execution Date to the Defect Claim Date, Buyer’s inspection right with respect to the Environmental Condition of the Oil and Gas Properties and the Midstream Assets shall be limited to undertake a Phase I Environmental Site Assessment of the Oil and Gas Properties and the Midstream Assets conducted by E.Vironment, LLC, Kleinfelder or such other environmental consulting or engineering firm approved in advance in writing by Seller (such approval not to be unreasonably withheld), and may include only visual inspections and record reviews relating to the Properties. In conducting such inspection, Buyer shall not operate any equipment or conduct any testing or sampling of soil, groundwater or other materials (including any testing or sampling for Hazardous Substances, Hydrocarbons or NORM). If the Phase I Environmental Site Assessment reasonably recommends that any sampling or invasive activities be conducted on a Conveyed Interest for Buyer to estimate the Remediation Amount with respect to such Conveyed Interest, Buyer shall (i) furnish Seller with a written description

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of the proposed scope of such sampling or invasive activities, including a description of the specific activities to be conducted, and a description of the approximate location and expected timing of such activities and (ii) obtain the prior written consent of Seller (such consent not to be unreasonably withheld) and the Third Party operator of the affected Conveyed Interest to undertake such sampling or invasive activities. Seller shall respond to any request for such consent within three days of its receipt thereof. If any of the proposed sampling or invasive activities may unreasonably interfere with the normal operation of the affected Conveyed Interest, Seller may request an appropriate modification of the proposed sampling or invasive activities. Any sampling or invasive activities shall be conducted by a reputable environmental consulting or engineering firm, approved in advance by Seller (such approval not to be unreasonably withheld). Buyer shall obtain all permits necessary to conduct any approved sampling or invasive activities from any applicable Governmental Authorities; provided that, upon request, Seller shall provide Buyer with assistance as reasonably requested by Buyer that may be necessary to secure such permits. If Buyer reasonably requests access to conduct any sampling or invasive activities pursuant to this Section 4.1(b) and Seller denies Buyer consent to conduct such sampling or invasive activities, then Buyer may, at its sole election, elect to exclude such affected Conveyed Interest from the Conveyed Interests to be assigned to Buyer at Closing, and the Purchase Price shall be reduced by the Allocated Value of such Conveyed Interest. Buyer shall give Seller reasonable prior written notice before gaining physical access to any of the Conveyed Interests, and Seller or its designee shall have the right but not the obligation to accompany Buyer and Buyer’s Representatives whenever Buyer and/or Buyer’s Representative gain physical access to any Conveyed Interests. Notwithstanding anything contained herein to the contrary, Buyer shall not have access to, and shall not be permitted to conduct any inspections (including any Phase I Environmental Site Assessment) with respect to, any Conveyed Interests with respect to which Seller does not have the authority to grant access for such due diligence; provided that Seller shall request, and cooperate with Buyer’s efforts to obtain, access rights from Third Parties for Buyer to conduct such inspections (including any Phase I Environmental Site Assessment) with respect to, such Conveyed Interests.

(c)    Buyer shall coordinate its access rights, environmental property assessments and physical inspections of the Conveyed Interests with Seller and all Third Party operators, as applicable, to minimize any inconvenience to or interruption of the conduct of business by Seller or any such Third Party operator. Buyer shall abide by Seller’s, and any Third Party operator’s, safety rules, regulations and operating policies while conducting its due diligence evaluation of the Conveyed Interests, including any environmental or other inspection or assessment of the Conveyed Interests to the extent Buyer receives copies of such rules, regulations and policies in advance of entering upon the Conveyed Interests and, to the extent required by any Third Party operator, execute and deliver any access and bonding agreement required by any such Third Party operator, in each case before conducting Buyer’s assessment on such Conveyed Interest in accordance with this Section 4.1. Buyer hereby indemnifies, defends, and holds harmless each of the operators of the Conveyed Interests and each Seller Indemnified Party from and against any and all Liabilities arising out of, resulting from or relating to any field visit, environmental assessment or other due diligence activity conducted by Buyer or any Buyer’s Representative with respect to the Conveyed Interests, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF, OR THE VIOLATION OF LAW BY, A MEMBER OF THE

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SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES TO THE EXTENT ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SUCH OPERATOR OF THE CONVEYED INTERESTS OR A MEMBER OF THE SELLER INDEMNIFIED PARTIES.

(d)    Buyer acknowledges that any entry into Seller’s offices or onto the Conveyed Interests shall be at Buyer’s sole risk, cost and expense, and, subject to the terms hereof, that none of the Seller Indemnified Parties shall be liable in any way for any injury, loss or damage arising out of such entry that may occur to Buyer or any of Buyer’s Representatives pursuant to this Agreement. Buyer hereby fully waives and releases any and all Liabilities against all of the Seller Indemnified Parties for any injury, death, loss or damage to any of Buyer’s Representatives or their property in connection with Buyer’s due diligence activities, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF, OR THE VIOLATION OF LAW BY, A MEMBER OF THE SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES.

(e)    Upon written request, Buyer agrees to promptly provide Seller, but in no event less than five days after receipt or creation thereof by Buyer or any of Buyer’s Representatives (including Buyer’s environmental consulting or engineering firm), copies of all final reports prepared by Buyer and/or any of Buyer’s Representatives, which contain data collected or generated from Buyer’s and/or any of Buyer’s Representatives’ due diligence with respect to the Conveyed Interests, including all environmental and title reports. Seller shall not be deemed by its receipt of said documents or otherwise to have made any representation or warranty, express, implied or statutory, as to the condition of the Conveyed Interests or to the accuracy of said documents or the information contained therein.

(f)    Upon completion of Buyer’s due diligence, Buyer shall at its sole cost and expense and without any cost or expense to Seller or any of its Affiliates (i) repair all damage done to any Conveyed Interests in connection with Buyer’s and/or any of Buyer’s Representatives’ due diligence (including due diligence conducted by Buyer’s environmental consulting or engineering firm), (ii) restore the Conveyed Interests to the approximate same condition as, or better condition than, they were prior to commencement of any such due diligence, and (iii) remove all equipment, tools or other property brought onto the Conveyed Interests in connection with such due diligence. Any disturbance to the Conveyed Interests (including the leasehold associated therewith) resulting from such due diligence will be promptly corrected by Buyer at Buyer’s sole cost and expense.

(g)    During all periods that Buyer and/or any of Buyer’s Representatives (including Buyer’s environmental consulting or engineering firm) are on the Conveyed Interests, Buyer shall maintain, at its sole cost and expense, policies of insurance of the types and in the amounts reasonably necessary to support Buyer’s obligations under this Section 4.1.

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4.2    Confidentiality. Buyer acknowledges that, pursuant to its right of access to the Records or the Conveyed Interests, Buyer and/or Buyer’s Representatives (including Buyer’s environmental consulting or engineering firm) will become privy to confidential and other information of Seller and/or Seller’s Affiliates and Buyer shall ensure that such confidential information (a) shall not be used for any purpose other than in connection with the transactions contemplated by this Agreement and (b) shall be held confidential by Buyer and Buyer’s Representatives (including Buyer’s environmental consulting or engineering firm) in accordance with the terms of the Confidentiality Agreements. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreements, shall terminate as of the Closing Date (except as to (i) such portion of the Conveyed Interests that are not conveyed to Buyer pursuant to the provisions of this Agreement, (ii) the Excluded Assets, and (iii) information related to Seller, Seller’s Affiliates, or to any assets other than the Conveyed Interests).

4.3    Disclaimers.

(a)    EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE V AND ARTICLE VII AND IN THE TRANSACTION DOCUMENTS DELIVERED AT CLOSING (i) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (ii) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY A MEMBER OF THE SELLER INDEMNIFIED PARTIES).

(b)    EXCEPT AS AND TO THE LIMITED EXTENT REPRESENTED OTHERWISE IN ARTICLE V AND ARTICLE VII, AND IN THE TRANSACTION DOCUMENTS DELIVERED AT CLOSING AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (i) TITLE TO ANY OF THE CONVEYED INTERESTS, (ii) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE CONVEYED INTERESTS, (iii) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE CONVEYED INTERESTS, (iv) ANY ESTIMATES OF THE VALUE OF THE CONVEYED INTERESTS OR FUTURE REVENUES TO BE GENERATED BY THE CONVEYED INTERESTS, (v) THE PRODUCTION OF OR ABILITY TO PRODUCE HYDROCARBONS FROM THE CONVEYED INTERESTS, (vi) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE CONVEYED INTERESTS, (vii) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE CONVEYED INTERESTS, (viii) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR RESPECTIVE EMPLOYEES, AGENTS, CONSULTANTS,

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REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (ix) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT REPRESENTED OTHERWISE IN ARTICLE VII AND IN THE ASSIGNMENT AND THE DEEDS, SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE CONVEYED INTERESTS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT BUYER SHALL BE DEEMED TO BE OBTAINING THE CONVEYED INTERESTS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(c)    EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES SET FORTH IN SECTION7.20, (i) SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE CONVEYED INTERESTS, (ii) NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND (iii) SUBJECT TO BUYER’S RIGHTS UNDER ARTICLE VI, BUYER SHALL BE DEEMED TO BE TAKING THE CONVEYED INTERESTS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(d)    SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 4.3 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

ARTICLE V

TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS

5.1    General Disclaimer of Title Warranties and Representations. Except for the special warranty of title set forth in the Assignment and the Deeds, and without limiting Buyer’s remedies for Title Defects set forth in thisArticle V, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Conveyed Interests, and Buyer hereby acknowledges and agrees that Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Conveyed Interests (a) before Closing,

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shall be as set forth inSection 5.3 and (b) from and after Closing, shall be pursuant to the special warranty of title set forth in the Assignment and the Deeds.

5.2    Special Warranty. The Assignment and Mineral Deed delivered at Closing will contain a special warranty of title with regard to the Oil and Gas Properties and the Midstream Assets, as applicable, whereby Seller shall warrant title to the Oil and Gas Properties and the Midstream Assets, as applicable, unto Buyer against every Person whomsoever lawfully claiming or to claim the same or any part thereof by, through or under Seller, but not otherwise, subject, however, to the Permitted Encumbrances.

5.3    Notice of Title Defects; Defect Adjustments.

(a)    Title Defect Notices. On or before the Defect Claim Date, Buyer must deliver claim notices to Seller meeting the requirements of this Section 5.3(a) (collectively, the “Title Defect Notices” and, individually, a “Title Defect Notice”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Title Defects and which Buyer intends to assert as a Title Defect pursuant to this Section 5.3(a). For all purposes of this Agreement and notwithstanding anything herein to the contrary, Buyer shall be deemed to have waived, and Seller shall have no liability for, any Title Defect which Buyer fails to assert as a Title Defect by a properly delivered Title Defect Notice received by Seller on or before the Defect Claim Date; provided, however, that, for purposes of Seller’s special warranty of title set forth in the Assignment, such waiver shall not apply to any matter that, prior to the Defect Claim Date, is not discovered by any of Buyer’s or any of its Affiliates’ employees, title attorneys, landmen or other title examiners while conducting Buyer’s title due diligence with respect to the Conveyed Interests. To be effective, each Title Defect Notice shall be in writing, and shall include (i) a description of the alleged Title Defect and the Conveyed Interest (including the legal description of such Conveyed Interest and the Leases applicable to such Conveyed Interest, if applicable), or portion thereof (including by the Target Formation as applicable), affected by such alleged Title Defect (each a “Title Defect Property”), (ii) the Allocated Value of each Title Defect Property, (iii) supporting documents reasonably necessary for Seller to verify the existence of the alleged Title Defect, (iv) Buyer’s preferred manner of curing such Title Defect and (v) the amount by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by such alleged Title Defect and the computations upon which Buyer’s belief is based. To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer agrees to use reasonable efforts to give Seller, on or before the end of each calendar week prior to the Defect Claim Date, written notice of all alleged Title Defects (as well as any claims that would be claims under the special warranty set forth in the Assignment) discovered by Buyer during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Defect Claim Date; provided, however, that Buyer’s failure to deliver such notices shall not waive Buyer’s right to notify Seller of Title Defects prior to the Defect Claim Date. Buyer shall also, promptly upon discovery, furnish Seller with written notice of any Title Benefit which is discovered by any of Buyer’s or any of its Affiliates’ employees, title attorneys, landmen or other title examiners while conducting Buyer’s due diligence with respect to the Conveyed Interests prior to the Defect Claim Date.

(b)    Title Benefit Notices. Seller shall have the right, but not the obligation, to deliver to Buyer on or before the Defect Claim Date with respect to each Title Benefit a notice (a

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“Title Benefit Notice”) including (i) a description of the alleged Title Benefit and the Oil and Gas Property, or portion thereof, affected by such alleged Title Benefit (each a “Title Benefit Property”), and (ii) the amount by which Seller reasonably believes the Allocated Value of such Title Benefit Property is increased by such alleged Title Benefit, and the computations upon which Seller’s belief is based. Seller shall be deemed to have waived any Title Benefit which Seller fails to assert as a Title Benefit by a Title Benefit Notice delivered to Buyer on or before the Defect Claim Date. To give Buyer an opportunity to commence reviewing Title Benefits, Seller agrees to use reasonable efforts to give Buyer, on or before the end of each calendar week prior to the Defect Claim Date, written notice of all alleged Title Benefits discovered by Seller during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Defect Claim Date; provided, however, that Seller’s failure to deliver such notices shall not waive Seller’s right to notify Buyer of Title Benefits prior to the Defect Claim Date.

(c)    Seller’s Right to Cure. Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure any properly asserted Title Defects at any time prior to 120 days after the Closing Date (the “Cure Period”). During the period of time from Closing to the expiration of the Cure Period, Buyer agrees to afford Seller and its officers, employees and other authorized representatives reasonable access, during normal business hours, to the Oil and Gas Properties and all Records in Buyer’s or any of its Affiliates’ possession in order to facilitate Seller’s attempt to cure any such Title Defects. The Purchase Price shall be reduced by the amount set forth in Section 5.3(a)(v) with respect to any Title Defect for which Seller has provided notice to Buyer prior to or on the Closing Date that Seller intends to attempt to cure the Title Defect during the Cure Period. Buyer shall remit the amount set forth in the preceding sentence to the Escrow Agent on the Closing Date to be held pursuant to the Title and Environmental Defects Escrow Agreement. Such amount plus interest earned thereon shall be paid to Seller at the end of the Cure Period if the applicable Title Defect is cured. If the applicable Title Defect is not cured at the end of the Cure Period, then such amount plus interest earned thereon shall be paid to Buyer. Any disputes regarding the sufficiency of any attempted curative action by Seller shall be resolved in accordance with Section 5.3(j). An election by Seller to attempt to cure a Title Defect shall be without prejudice to its rights under Section 5.3(j) and shall not constitute an admission against interest or a waiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the alleged Title Defect.

(d)    Remedies for Title Defects. Subject to Seller’s continuing right to dispute the existence of a Title Defect and/or the Title Defect Amount asserted with respect thereto, and subject to the rights of the Parties pursuant to Section 15.1(e), in the event that any Title Defect timely asserted by Buyer in accordance with Section 5.3(a) is not waived in writing by Buyer or cured during the Cure Period, Seller shall, at its sole option, but subject to Buyer’s agreement in the case of the remedies described in Section 5.3(d)(ii) and Section 5.3(d)(iii), elect to:

(i)    subject to the Individual Title Defect Threshold and the Title Defect Deductible, reduce the Purchase Price or the Final Price, as applicable, by the Title Defect Amount determined pursuant to Section 5.3(g) or Section 5.3(j);

(ii)    with the written consent of Buyer, retain the entirety of the Title Defect Property that is subject to such Title Defect, together with all associated Conveyed

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Interests, or if the Title Defect Property has been assigned to Buyer, have Buyer reassign to Seller, with special warranty of title against claims by, through or under Buyer, but not otherwise, the Title Defect Property that is subject to such Title Defect, together with all associated Conveyed Interests, and, concurrently therewith, the Purchase Price or the Final Price, as applicable, shall be reduced by an amount equal to the Allocated Value of such Title Defect Property and such associated Conveyed Interests;

(iii)    if and only if Buyer agrees to this remedy in its sole discretion, indemnify Buyer against all Liability (up to the Allocated Value of the applicable Title Defect Property) resulting from such Title Defect with respect to such Title Defect Property pursuant to an indemnity agreement prepared by Seller in a form and substance reasonably acceptable to Buyer (a “Title Indemnity Agreement”); or

(iv)    if applicable, terminate this Agreement pursuant to Section 15.1(e).

(e)    Remedies for Title Benefits. With respect to each Title Benefit Property reported under Section 5.3(b), the Purchase Price shall be increased by an amount (the “Title Benefit Amount”) equal to the increase in the Allocated Value for such Title Benefit Property caused by such Title Benefit, as determined pursuant to Section 5.3(h) or Section 5.3(j); provided, however, that any such increase to the Purchase Price shall not exceed the absolute value of any downward adjustments to the Purchase Price attributable to Title Defects.

(f)    Exclusive Remedy. Except for Buyer’s rights arising under Seller’s representations and warranties in Section 7.20, Buyer’s rights under Seller’s special warranty of title in the Assignment and Deeds delivered at Closing and Buyer’s right to terminate this Agreement pursuant to Section 15.1(e), Section 5.3(d) shall be the exclusive right and remedy of Buyer with respect to Seller’s failure to have Defensible Title with respect to any Well, Well Location, or Lease or any other title matter with respect to any Oil and Gas Properties, and Buyer hereby waives any and all other rights or remedies with respect thereto.

(g)    Title Defect Amount. The amount by which the Allocated Value of a Title Defect Property is reduced as a result of the existence of a Title Defect shall be the “Title Defect Amount” for such Title Defect Property and shall be determined in accordance with the following terms and conditions (without duplication):

(i)    if Buyer and Seller agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

(ii)    if the Title Defect is an Encumbrance that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii)    if the Title Defect represents a discrepancy between (A) Seller’s Net Revenue Interest for any Title Defect Property and (B) the Net Revenue Interest set forth for such Title Defect Property in Exhibit G, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest set forth for such Title Defect Property inExhibit G;

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(iv)    if the Title Defect arises under clause (b)(ii) of the definition of Defensible Title, then the Title Defect Amount for that Title Defect Property shall be the product of the total length (measured in Rods) of the portion of the gathering pipelines affected by such Title Defect multiplied by an amount equal to $300.00 per Rod.

(v)    if the Title Defect represents an obligation or Encumbrance upon or other defect in title to the Title Defect Property of a type not described above, then the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation;

(vi)    the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(vii)    notwithstanding anything to the contrary in this Article V, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(h)    Title Benefit Amount. The Title Benefit Amount resulting from a Title Benefit shall be determined in accordance with the following methodology, terms and conditions (without duplication):

(i)    if Buyer and Seller agree on the Title Benefit Amount, then that amount shall be the Title Benefit Amount;

(ii)    if the Title Benefit represents a discrepancy between (A) Seller’s Net Revenue Interest for any Title Benefit Property and (B) the Net Revenue Interest set forth for such Title Benefit Property in Exhibit G, then the Title Benefit Amount shall be the product of the Allocated Value of such Title Benefit Property multiplied by a fraction, the numerator of which is the Net Revenue Interest increase and the denominator of which is the Net Revenue Interest set forth for such Title Benefit Property in Exhibit G; and

(iii)    if the Title Benefit is of a type not described above, then the Title Benefit Amounts shall be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of such Title Benefit Property affected by such Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of such Title Benefit Property, the values placed upon the Title Benefit by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation.

(i)    Title Defect Threshold and Deductible. Notwithstanding anything herein to the contrary, subject to Section 5.6, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller hereunder for any individual Title Defect for

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which the Title Defect Amount does not exceed $50,000 (“Individual Title Defect Threshold”); and (ii) in no event shall there be any adjustment to the Purchase Price or other remedies provided by Seller hereunder for any Title Defect for which the Title Defect Amount exceeds the Individual Title Defect Threshold unless (A) the amount of the sum of the aggregate Title Defect Amounts of all such Title Defects that exceed the Individual Title Defect Threshold (but excluding any Title Defect Amounts attributable to Title Defects cured by Seller or Title Defect Properties retained by or reassigned to Seller, as applicable, pursuant to Section 5.3(d)(ii)), exceeds (B) the Title Defect Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other applicable remedies available hereunder, but only to the extent that the amount by which the aggregate amount of such Title Defect Amounts exceeds the Title Defect Deductible. For the avoidance of doubt, if Seller elects to retain any Title Defect Property or to have Buyer reassign any Title Defect Property pursuant to Section 5.3(d)(ii), the Title Defect Amount relating to the Conveyed Interest attributable to such Title Defect Property will not be counted towards the Title Defect Deductible and will not be considered for purposes of Section 10.4 or Section 11.4.

(j)    Title Dispute Resolution. Seller and Buyer shall attempt to agree on matters regarding (i) all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts, and (ii) the adequacy of any curative materials provided by Seller to cure any alleged Title Defect (collectively “Title Disputes”) prior to Closing. If Seller and Buyer are unable to agree by Closing (or by the Title Dispute Date if Seller elects to attempt to cure an alleged Title Defect after Closing), the Title Disputes shall be exclusively and finally resolved pursuant to this Section 5.3(j). There shall be a single arbitrator, who shall be a title attorney with at least 10 years’ experience in oil and gas or midstream titles, as applicable, involving properties in any of the regional areas in which the Title Defect Properties or Title Benefit Properties, as applicable, are located, in each case as selected by the mutual agreement of Buyer and Seller within 15 days after Closing or the Title Dispute Date, as applicable (the “Title Arbitrator”). If the Parties do not mutually agree upon the Title Arbitrator in accordance with this Section 5.3(j), a tenured professor of oil and gas law at the University of Texas at Austin School of Law shall appoint the Title Arbitrator under such conditions as he in his sole discretion deems necessary or advisable; provided that he must appoint someone (1) with at least 10 years’ experience in oil and gas or midstream titles, as applicable, involving properties in any of the regional areas in which the Title Defect Properties or Title Benefit Properties, as applicable, are located, (2) who has not been employed by either Party (or their Affiliate) in the past ten years, and (3) who has no ethical conflict in serving as the Title Arbitrator. If such tenured professor is unable or unwilling to appoint the Title Arbitrator, a tenured professor of oil and gas law at the Southern Methodist University Dedman School of Law shall appoint the Title Arbitrator, subject to the foregoing limitations. The place of arbitration shall be Houston, and the arbitration shall be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of this Section 5.3(j). The Title Arbitrator’s determination shall be made within 30 days after submission of Title Disputes and shall be final and binding upon both Parties, without right of appeal. In making his determination with respect to any Title Dispute, the Title Arbitrator shall be bound by the rules set forth in Section 5.3(g) and Section5.3(h) and, subject to the foregoing, may consider such other matters as, in the opinion of the Title Arbitrator, are necessary to make a proper determination. The Title Arbitrator, however, (i) may not award Buyer a greater Title Defect Amount than the Title Defect Amount claimed by Buyer in its applicable Title Defect Notice and (ii) may not award Seller a greater Title Benefit Amount than the Title Benefit

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Amount claimed by Seller in its applicable Title Benefit Notice. The Title Arbitrator shall act as an expert for the limited purpose of determining the specific Title Disputes submitted by either Party, and the Title Arbitrator may not award damages, interest or penalties to either Party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Title Arbitrator. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Title Arbitrator. To the extent the award of the Title Arbitrator with respect to any Title Defect Amount or Title Benefit Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 3.5 or Section 3.6, then within 10 days after the Title Arbitrator delivers written notice to Buyer and Seller of his award with respect to a Title Dispute, and, subject to Section 5.3(d)(i), (i) Buyer shall pay to Seller the amount, if any, so awarded by the Title Arbitrator to Seller and (ii) Seller shall pay to Buyer the amount, if any, so awarded by the Title Arbitrator to Buyer. Nothing herein shall operate to cause Closing to be delayed on account of any arbitration that may be conducted pursuant to this Section 5.3(j), and, to the extent any adjustments are not agreed upon by the Parties as of Closing, the Purchase Price shall not be adjusted therefor at Closing and subsequent adjustments to the Purchase Price, if any, will be made pursuant to Section 3.7 or this Section 5.3(j).

5.4    Casualty or Condemnation Loss.

(a)    Notwithstanding anything herein to the contrary, from and after the Effective Time, if Closing occurs, Buyer shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well) and the depreciation of Personal Property due to ordinary wear and tear, in each case, with respect to the Conveyed Interests, and Buyer shall not assert such matters as Casualty Losses or Title Defects hereunder. Until Closing, Seller shall maintain its current insurance policies relative to the Conveyed Interests in all respects.

(b)    If after the Execution Date but prior to the Closing Date, (i) any portion of the Conveyed Interests is damaged or destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain (each, a “Casualty Loss”), (ii) the Closing thereafter occurs and (iii) the estimated cost to repair such Conveyed Interest (with equipment of similar utility) is greater than $100,000, then Buyer shall not be obligated to purchase such Conveyed Interest. If Buyer declines to purchase such Conveyed Interest, the Purchase Price shall be reduced by the Allocated Value of such Conveyed Interest. If Buyer elects to purchase such Conveyed Interest, the Purchase Price shall be reduced by the estimated cost to repair such Conveyed Interest (with equipment of similar utility), less all insurance proceeds which Seller causes to be paid or pays to Buyer, up to the Allocated Value thereof. Seller, at its sole option, may elect to cure such Casualty Loss to Buyer’s reasonable satisfaction and, in such event, Seller shall be entitled to all insurance proceeds. If Seller elects to cure such Casualty Loss, Seller may replace any Personal Property that is the subject of a Casualty Loss with equipment of similar grade, function, quality and utility. If Seller cures the Casualty Loss to Buyer’s reasonable satisfaction, Buyer shall purchase the affected Conveyed Interest at Closing for the Allocated Value thereof.

(c)    If after the Execution Date but prior to the Closing Date, (i) a Casualty Loss occurs, (ii) the Closing thereafter occurs and (iii) the estimated cost to repair such Conveyed Interest (with equipment of similar utility) is less than $100,000, Seller, at Closing,

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shall pay to Buyer all sums actually paid to Seller by Third Parties by reason of any Casualty Loss insofar as with respect to the Conveyed Interests and shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s right, title and interest (if any) in insurance claims, unpaid awards, and other rights against Third Parties (excluding any Liabilities, other than insurance claims, of or against any Seller Indemnified Party) arising out of such Casualty Loss insofar as with respect to the Conveyed Interests; provided, however, that Seller shall reserve and retain (and Buyer shall assign to Seller) all right, title, interest and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to Closing in repairing such Casualty Loss and/or pursuing or asserting any such insurance claims or other rights against Third Parties.

5.5    Preferential Purchase Rights and Consents to Assign.

(a)    With respect to each Preferential Purchase Right set forth in Schedule 7.9, not later than 10 days after the Execution Date (and, with respect to each Preferential Purchase Right that is not set forth in Schedule 7.9 but is discovered by either Party after the Execution Date and before the Closing Date, not later than five days after the discovery thereof), Seller shall send to the holder of each such Preferential Purchase Right a notice in material compliance with the contractual provisions applicable to such Preferential Purchase Right.

(i)    If, prior to Closing, any holder of a Preferential Purchase Right notifies Seller that it intends to consummate the purchase of the Conveyed Interest to which its Preferential Purchase Right applies, then the Conveyed Interest subject to such Preferential Purchase Right shall be excluded from the Oil and Gas Properties to be assigned to Buyer at Closing (but only to the extent of the portion of such Conveyed Interest affected by the Preferential Purchase Right), and the Purchase Price shall be reduced by the Allocated Value of the Conveyed Interest (or portion thereof) so excluded. Seller shall be entitled to all proceeds paid by any Person exercising a Preferential Purchase Right prior to Closing. If such holder of such Preferential Purchase Right thereafter fails to consummate the purchase of the Conveyed Interest (or portion thereof) covered by such Preferential Purchase Right on or before the end of the period of time for closing such sale but no later than 120 days following the Closing Date, (A) Seller shall so notify Buyer, (B) Buyer shall purchase, on or before 10 days following receipt of such notice, such Conveyed Interest (or portion thereof) that was so excluded from the Conveyed Interests to be assigned to Buyer at Closing, under the terms of this Agreement and for a price equal to the amount by which the Purchase Price was reduced at Closing with respect to such excluded Conveyed Interest (or portion thereof), and (C) Seller shall assign to Buyer the Conveyed Interest (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment. If, as of Closing, the time for exercising a Preferential Purchase Right has not expired and such Preferential Purchase Right has not been exercised or waived, then the Conveyed Interest subject to such Preferential Purchase Right shall be included in the Conveyed Interests to be assigned to Buyer at Closing, and Buyer shall be solely responsible for complying with the terms of such Preferential Purchase Right and shall be entitled to the proceeds, if any, associated with the exercise of such Preferential Purchase Right.

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(ii)    All Oil and Gas Properties for which any applicable Preferential Purchase Right has been waived, or as to which the period to exercise the applicable Preferential Purchase Right has expired, in each case, prior to Closing, shall be sold to Buyer at Closing pursuant to the provisions of this Agreement.

(b)    With respect to each Consent set forth in Schedule 7.4, Seller, not later than 10 days after the Execution Date (and, with respect to each Consent that is not set forth in Schedule 7.4 but is discovered by either Party after the Execution Date and before the Closing Date, not later than five days after the discovery thereof), shall send to the holder of each such Consent a notice in material compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby.

(i)    If (A) Seller fails to obtain a Consent set forth in Schedule 7.4 (or any Consent that is not set forth in Schedule 7.4 but is discovered by either Party after the Execution Date and before the Closing Date) prior to Closing and the failure to obtain such Consent would cause (1) the assignment of the Conveyed Interests affected thereby to Buyer to be void or voidable under the terms thereof, (2) the termination of a Lease or other Conveyed Interest under the express terms thereof or (3) the payment of liquidated damages under a Lease or a Contract for assignment without obtaining consent or (B) a Consent requested by Seller is denied in writing, then, in each case, the Conveyed Interest (or portion thereof) affected by such un-obtained Consent shall be excluded from the Conveyed Interests to be assigned to Buyer at Closing, and the Purchase Price shall be reduced by the Allocated Value of such Conveyed Interest (or portion thereof) so excluded. In the event that any such Consent (with respect to a Conveyed Interest excluded pursuant to this Section 5.5(b)(i)) that was not obtained prior to Closing is obtained within 180 days following the Closing Date, then, within 10 Business Days after such Consent is obtained, (x) Buyer shall purchase the Conveyed Interest (or portion thereof) that was so excluded as a result of such previously un-obtained Consent and pay to Seller the amount by which the Purchase Price was reduced at Closing with respect to the Conveyed Interest (or portion thereof) so excluded and (y) Seller shall assign to Buyer the Conveyed Interest (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment.

(ii)    If Seller fails to obtain a Consent set forth in Schedule 7.4 (or any Consent that is not set forth in Schedule 7.4 but is discovered by either Party after the Execution Date and before the Closing Date) prior to Closing and (A) the failure to obtain such Consent would not cause (1) the assignment of the Conveyed Interest (or portion thereof) affected thereby to Buyer to be void, (2) the termination of a Lease under the express terms thereof or (3) the payment of liquidated damages under a Lease or a Contract for assignment without obtaining consent and (B) such Consent requested by Seller is not denied in writing by the holder thereof, then the Conveyed Interest (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by Seller to Buyer at Closing as part of the Conveyed Interests and Buyer shall have no claim against, and Seller shall have no Liability for, the failure to obtain such Consent.

(iii)    Prior to Closing, Seller shall use its commercially reasonable efforts to obtain all Consents listed in Schedule 7.4 (and any Consent that is not set forth

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in Schedule 7.4 but is discovered by either Party after the Execution Date and before the Closing Date); provided, however, that Seller shall not be required to incur any Liability or pay any money in order to obtain any such Consent. Subject to the foregoing, Buyer agrees to provide Seller with any information or documentation that may be reasonably requested by Seller and/or the Third Party holder(s) of such Consents in order to facilitate the process of obtaining such Consents.

5.6    Acknowledged Title Defects

(a)    Notwithstanding anything to the contrary herein, Seller acknowledges that the matters listed on Schedule 7.8 Part 2 (the “RRC Matters”) constitute Title Defects.

(b)    To the extent Seller is unable to cure the Title Defect arising from the RRC Matters fully prior to Closing, the Oil and Gas Property associated with each uncured RRC Matter will be excluded from the Oil and Gas Properties to be assigned to Buyer at Closing, and the Purchase Price will be reduced by the Allocated Value of the Oil and Gas Property so excluded. This Purchase Price reduction will be without regard to the Individual Title Defect Threshold or the Title Defect Deductible and any Purchase Price reduction will not count toward the Title Defect Deductible.

ARTICLE VI

ENVIRONMENTAL MATTERS

6.1    Environmental Defects.

(a)    Assertions of Environmental Defects. Buyer must deliver claim notices to Seller meeting the requirements of this Section 6.1(a) (collectively the “Environmental Defect Notices” and individually an “Environmental Defect Notice”) not later than the Defect Claim Date setting forth any matters which, in Buyer’s reasonable opinion, constitute Environmental Defects and which Buyer intends to assert as Environmental Defects pursuant to this Section 6.1. For all purposes of this Agreement except for Buyer’s rights prior to Closing with respect to breaches of the representations and warranties set forth in Section 7.20, Buyer shall be deemed to have waived, and Seller shall have no liability for, any Environmental Defect which Buyer fails to assert as an Environmental Defect by a properly delivered Environmental Defect Notice received by Seller on or before the Defect Claim Date, with such liabilities being “Buyer’s Environmental Liabilities.” To be effective, each Environmental Defect Notice shall be in writing and shall include (i) a description of the matter constituting the alleged Environmental Condition (including the applicable Environmental Law violated or implicated thereby) and the Conveyed Interests affected by such alleged Environmental Condition, (ii) the Allocated Value of the Conveyed Interests (or portions thereof) affected by such alleged Environmental Condition, (iii) supporting documents reasonably necessary for Seller to verify the existence of such alleged Environmental Condition, and (iv) a calculation of the Remediation Amount (itemized in reasonable detail) that Buyer asserts is attributable to such alleged Environmental Condition. Buyer’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the alleged Environmental Condition that gives rise to the asserted Environmental Defect and identify all assumptions used by Buyer in calculating the Remediation Amount, including the standards that Buyer asserts must

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be met to comply with Environmental Laws. Seller shall have the right, but not the obligation, to cure any asserted Environmental Defect on or before the expiration of the Cure Period. The Purchase Price shall be reduced by the amount set forth in Section 6.1(b)(iv) with respect to any asserted Environmental Defect for which Seller has provided notice to Buyer prior to or on the Closing Date that Seller intends to attempt to cure the asserted Environmental Defect during the Cure Period. Buyer shall remit the amount set forth in the preceding sentence to the Escrow Agent on the Closing Date to be held pursuant to the Title and Environmental Defects Escrow Agreement. Such amount plus interest earned thereon shall be paid to Seller at the end of the Cure Period if the applicable Environmental Defect is cured. If the applicable Environmental Defect is not cured at the end of the Cure Period, then such amount plus interest earned thereon shall be paid to Buyer. Any disputes regarding the sufficiency of any attempted curative action by Seller shall be resolved in accordance with Section 6.1(e). To give Seller an opportunity to commence reviewing and curing Environmental Defects, Buyer agrees to use reasonable efforts to give Seller, on or before the end of each calendar week prior to the Defect Claim Date, written notice of all alleged Environmental Defects discovered by Buyer during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Defect Claim Date; provided, however, that Buyer’s failure to deliver such notices shall not waive Buyer’s right to notify Seller of Environmental Defects prior to the Defect Claim Date.

(b)    Remedies for Environmental Defects. Subject to Seller’s continuing right to dispute the existence of an Environmental Defect and/or the Remediation Amount asserted with respect thereto, and subject to the rights of the Parties pursuant to Section 15.1(e), in the event that any Environmental Defect timely asserted by Buyer in accordance with Section 6.1(a) is not waived in writing by Buyer or cured during the Cure Period, Seller shall, at its sole option but subject to Buyer’s agreement in the case of the remedy described in Section 6.1(b)(ii) or Section 6.1(b)(iii), elect to:

(i)    subject to the Individual Environmental Threshold and the Aggregate Deductible, reduce the Purchase Price by the Remediation Amount;

(ii)    with the written consent of Buyer, retain the entirety of the Conveyed Interest that is subject to such Environmental Defect, together with all associated Conveyed Interests, or if the Environmental Defect Property has been assigned to Buyer, have Buyer reassign to Seller, with special warranty of title against claims by, through or under Buyer, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Conveyed Interest and such associated Conveyed Interests;

(iii)    if and only if Buyer agrees to this remedy in its sole discretion, to indemnify Buyer against all Liability resulting from such Environmental Defect with respect to the Conveyed Interests pursuant to an indemnity agreement prepared by Seller in a form and substance reasonably acceptable to Buyer (each, an “Environmental Indemnity Agreement”); or

(iv)    if applicable, terminate this Agreement pursuant to Section 15.1(e).

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If Seller elects the option set forth in clause (i) above, Buyer shall be deemed to have assumed responsibility for all of the costs and expenses attributable to the Remediation of the Environmental Condition attributable to such Environmental Defect and for all Liabilities with respect thereto and Buyer’s obligations with respect to the foregoing shall be deemed to constitute Assumed Obligations.

(c)    Exclusive Remedy. Except for Seller’s representations in Section 7.20 and Buyer’s rights to terminate this Agreement pursuant to Section 15.1(e), the provisions set forth in Section 6.1(b) shall be the exclusive right and remedy of Buyer with respect to any Environmental Defect with respect to any Conveyed Interest or other environmental matter.

(d)    Environmental Deductibles. Notwithstanding anything herein to the contrary, (i) in no event shall there be any adjustment to the Purchase Price or other remedies provided by Seller for any individual Environmental Defect for which the Remediation Amount does not exceed $100,000 (the “Individual Environmental Threshold”); and (ii) in no event shall there be any adjustment to the Purchase Price or other remedies provided by Seller for any Environmental Defect for which the Remediation Amount exceeds the Individual Environmental Threshold unless (A) the amount of the aggregate Remediation Amounts of all such Environmental Defects that exceed the Individual Environmental Threshold (but excluding any Remediation Amounts attributable to any Environmental Defects cured by Seller and Conveyed Interests retained by Seller pursuant to Section 6.1(b)(ii)), exceeds (B) the Environmental Defect Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other applicable remedies available hereunder, but only with respect to the amount by which the aggregate amount of such Remediation Amounts exceeds the Environmental Defect Deductible. For the avoidance of doubt, if Seller elects to retain any Conveyed Interest related to any Environmental Defect pursuant to Section 6.1(b)(ii), then (x) the Purchase Price shall be reduced by the Allocated Value of such retained Conveyed Interest and (y) the Remediation Amount for the Environmental Defect relating to such retained Conveyed Interest will not be counted towards the Environmental Defect Deductible.

(e)    Environmental Dispute Resolution. Seller and Buyer shall attempt to agree on all Environmental Defects and Remediation Amounts prior to Closing. If Seller and Buyer are unable to agree by Closing, the Environmental Defects and/or Remediation Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 6.1(e). There shall be a single arbitrator, who shall be an environmental attorney with at least 10 years’ experience in environmental matters involving oil and gas producing properties or midstream properties, as applicable, in any of the regional areas in which the affected Conveyed Interests are located, as selected by the mutual agreement of Buyer and Seller within 15 days after the Closing Date (the “Environmental Arbitrator”). If the Parties do not mutually agree upon the Environmental Arbitrator in accordance with this Section 6.1(e), a tenured professor of oil and gas law at the University of Texas at Austin School of Law shall appoint the Environmental Arbitrator under such conditions as he in his sole discretion deems necessary or advisable; provided however that he must appoint someone (1) who is an environmental attorney with at least 10 years’ experience in environmental matters involving oil and gas producing properties or midstream properties, as applicable, in any of the regional areas in which the affected Conveyed Interests are located (2) who has not been employed by either Party (or their Affiliate) in the past ten years, and (3) who has no ethical conflict in serving as the Title Arbitrator. If such tenured

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professor is unable or unwilling to appoint the Environmental Arbitrator, a tenured professor of oil and gas law at the Southern Methodist University Dedman School of Law shall appoint the Environmental Arbitrator. The place of arbitration shall be Houston, and the arbitration shall be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of this Section 6.1(e). The Environmental Arbitrator’s determination shall be made within 30 days after submission of the matters in dispute and shall be final and binding upon both Parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section 6.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary or helpful to make a proper determination. The Environmental Arbitrator, however, may not award Buyer a greater Remediation Amount than the Remediation Amount claimed by Buyer in its applicable Environmental Defect Notice. The Environmental Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Environmental Defects and/or Remediation Amounts submitted by either Party and may not award damages, interest or penalties to either Party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Environmental Arbitrator. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Environmental Arbitrator. To the extent that the award of the Environmental Arbitrator with respect to any Remediation Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 3.5 or Section 3.6, then within ten 10 days after the Environmental Arbitrator delivers written notice to Buyer and Seller of his award with respect to any Remediation Amount, and, subject to Section 6.1(d), (i) Buyer shall pay to Seller the amount, if any, so awarded by the Environmental Arbitrator to Seller and (ii) Seller shall pay to Buyer the amount, if any, so awarded by the Environmental Arbitrator to Buyer. Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section 6.1(e), and, to the extent any adjustments are not agreed upon by the Parties as of Closing, the Purchase Price shall not be adjusted therefor at Closing and subsequent adjustments to the Purchase Price, if any, will be made pursuant to Section 3.7 or this Section 6.1(e).

6.2    NORM, Asbestos, Wastes and Other Substances. Buyer acknowledges that the Conveyed Interests have been used for exploration, development, and production of oil and gas and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under the Conveyed Interests or associated with the Conveyed Interests. Equipment and sites included in the Conveyed Interests may contain asbestos, NORM or other Hazardous Substances. NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms. The wells, materials, and equipment located on the Conveyed Interests or included in the Conveyed Interests may contain asbestos, NORM and other wastes or Hazardous Substances. NORM containing material and/or other wastes or Hazardous Substances may have come in contact with various environmental media, including water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of any affected environmental media, wastes, asbestos, NORM and other Hazardous Substances from the Conveyed Interests. Notwithstanding anything herein to the contrary, Buyer shall not be permitted to claim any Environmental Defect on the account of the presence of NORM or asbestos-containing materials that are non-friable, unless and only to the extent such presence of NORM or asbestos-containing materials that are non‑friable constitutes an Environmental Condition resulting in a violation of Environmental

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Laws or to the extent such NORM or asbestos-containing material is present on out of service surface equipment included in the Conveyed Interests.

ARTICLE VII

REPRESENTATIONS AND WARRANTIES OF SELLER

Seller represents and warrants to Buyer as follows:

7.1    Organization, Existence and Qualification.

(a)    LEH is a limited liability company duly formed and validly existing under the Laws of the State of Delaware. LEH has all requisite power and authority to own and operate its property (including its interests in the Conveyed Interests) and to carry on its business as now conducted. LEH is duly licensed or qualified to do business as a foreign limited liability company in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law, except where the failure to be so qualified would not have a Material Adverse Effect.

(b)    LOI is a corporation duly formed and validly existing under the Laws of the State of Delaware. LOI has all requisite power and authority to own and operate its property (including its interests in the Conveyed Interests) and to carry on its business as now conducted. LOI is duly licensed or qualified to do business as a foreign corporation in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law, except where the failure to be so qualified would not have a Material Adverse Effect.

(c)    LINN Midstream is a single member limited liability company duly formed and validly existing under the Laws of the State of Delaware. Linn Midstream has all requisite power and authority to own and operate its property (including its interests in the Conveyed Interests) and to carry on its business as now conducted. Linn Midstream is duly licensed or qualified to do business as a foreign limited liability company in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law, except where the failure to be so qualified would not have a Material Adverse Effect.

(d)    Linn Exploration is a single member limited liability company duly formed and validly existing under the Laws of the State of Delaware. Linn Exploration has all requisite power and authority to own and operate its property (including its interests in the Conveyed Interests) and to carry on its business as now conducted. Linn Exploration is duly licensed or qualified to do business as a foreign limited liability company in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law, except where the failure to be so qualified would not have a Material Adverse Effect.

(e)    MidCon II is a single member limited liability company duly formed and validly existing under the Laws of the State of Delaware. MidCon II has all requisite power and authority to own and operate its property (including its interests in the Conveyed Interests) and to carry on its business as now conducted. MidCon II is duly licensed or qualified to do business as a foreign limited liability company in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law, except where the failure to be so qualified would not have a Material Adverse Effect.

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7.2    Authorization, Approval and Enforceability. Seller has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Seller of this Agreement have been duly and validly authorized and approved by all necessary limited partnership action on the part of Seller. Assuming the due authorization, execution and delivery by the other parties to such documents, this Agreement is, and the Transaction Documents to which Seller is a party when executed and delivered by Seller will be, the valid and binding obligations of Seller and enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

7.3    No Conflicts. Assuming the receipt of all Consents and the waiver of, or compliance with, all Preferential Purchase Rights applicable to the transactions contemplated hereby, the execution, delivery, and performance by Seller of this Agreement and the Transaction Documents to which it is a party and the consummation of the transactions contemplated herein and therein will not (a) conflict with or result in a breach of any provisions of the organizational documents of Seller or (b) except for Permitted Encumbrances, result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation, or acceleration under any of the terms, conditions, or provisions of any note, bond, mortgage, indenture, or Material Contract to which Seller is a party or by which Seller or the Conveyed Interests may be bound or (c) violate, in any material respect, any Law applicable to Seller or any of the Conveyed Interests.

7.4    Consents. Except (a) as set forth in Schedule 7.4, (b) for Customary Post-Closing Consents, (c) under Contracts that are terminable without payment of any fee upon not greater than 90 days’ notice, (d) for any Preferential Purchase Rights applicable to the transactions contemplated by this Agreement that are set forth in Schedule 7.9, and (e) as described in Section 9.8, there are no restrictions to assignment, including requirements for consents from Third Parties to any assignment (in each case), that Seller is required to obtain in connection with the transfer of the Conveyed Interests by Seller to Buyer or the consummation of the transactions contemplated by this Agreement by Seller (each, a “Consent”).

7.5    Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened in writing against Seller.

7.6    Litigation. Except as set forth in Schedule 7.6, there is no suit, action, litigation or arbitration by any Person or before any Governmental Authority pending or, to Seller’s Knowledge, threatened in writing against Seller with respect to the Conveyed Interests or otherwise relating to the Conveyed Interests. There is no investigation, lawsuit, action, litigation or arbitration by any Person or before any Governmental Authority pending, or to Seller’s Knowledge, threatened against Seller or any of its Affiliates that has or would have a material adverse effect upon the ability of Seller to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

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7.7    Material Contracts.

(a)    Schedule 7.7 sets forth as of the Execution Date all Applicable Contracts of the type described below (collectively, the “Material Contracts”):

(i)    any Applicable Contract that can reasonably be expected to result in aggregate payments by Seller of more than $200,000 during the remainder of the current or any subsequent fiscal year (based solely on the terms thereof and current volumes, without regard to any expected increase in volumes or revenues);

(ii)    any Applicable Contract that can reasonably be expected to result in aggregate revenues to Seller of more than $200,000 during the remainder of the current or any subsequent fiscal year (based solely on the terms thereof and current volumes, without regard to any expected increase in volumes or revenues);

(iii)    any Hydrocarbon purchase and sale, exchange, or similar Applicable Contract that is not terminable without penalty on 60 days’ or less notice;

(iv)    any indenture, mortgage, loan, credit or sale-leaseback or similar Applicable Contract relating to or burdening the Conveyed Interests that can reasonably be expected to result in aggregate payments by Seller during the current or any subsequent fiscal year of more than $200,000;

(v)    any guarantee by Seller or by an Affiliate of Seller provided to a Third Party under an Applicable Contract for an amount reasonably expected to be in excess of $200,000;

(vi)    any Applicable Contract that constitutes a lease under which Seller is the lessor or the lessee of real or personal property which lease (A) cannot be terminated by Seller without penalty upon 60 days’ or less notice and (B) involves an annual base rental of more than $200,000;

(vii)    any Applicable Contract with any Affiliate of Seller which will be binding on Buyer after the Closing Date;

(viii)    any farmout agreement, area of mutual interest agreement, exploration agreement, participation agreement, joint operating agreement or similar Applicable Contract where the primary obligation and thereunder have not fully been performed;

(ix)    any Applicable Contract relating to the storage, gathering, processing, compression, treating, fractionation, transportation, sale, or purchase of Hydrocarbons, or the provision of services related thereto; and

(x)    any Applicable Contract for the purchase or sale of Hydrocarbons containing a take-or-pay, advance payment, prepayment or similar provision or requiring Hydrocarbons to be gathered, delivered, processed or transported without then or thereafter receiving full payment therefor.

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(b)    Except as set forth in Schedule 7.7, there exists no material default under any Material Contract by Seller or, to Seller’s Knowledge, by any other Person that is a party to such Material Contract, and no event has occurred that with notice or lapse of time or both would constitute any default under any such Material Contract by Seller or, to Seller’s Knowledge, any other Person who is a party to such Material Contract.

7.8    No Violation of Laws. Except as set forth in Schedule 7.8, Seller is not in violation in any material respect as to the Conveyed Interests as a whole of any applicable Laws (other than Environmental Laws and Tax Laws, which are addressed in Article VI, Section 7.13 and Section 7.20) with respect to its ownership and operation of the Conveyed Interests. For the avoidance of doubt, this Section 7.8 does not include any matters with respect to Environmental Laws or Tax Laws, which shall be addressed in Article VI, Section 7.13 and Section 7.20.

7.9    Preferential Rights. Except as set forth inSchedule 7.9, there are no preferential purchase rights, rights of first refusal or other similar rights that are applicable to the transfer of the Conveyed Interests in connection with the transactions contemplated hereby (each a “Preferential Purchase Right”).

7.10    Payment of Burdens. Except as would not have a Material Adverse Effect, except for such items that are not yet due or are being held in suspense for which the Purchase Price will be adjusted in accordance herewith pursuant toSection 3.3(b)(ix) and except as set forth onSchedule 7.10, Seller has properly and timely paid, in accordance with the applicable Lease and all applicable Laws, all Burdens due by Seller with respect to the Conveyed Interests, or if not paid, is contesting such Burdens described inSchedule 7.10 in good faith in the normal course of business.

7.11    Imbalances. To Seller’s Knowledge, Schedule 7.11 sets forth all material Imbalances associated with the Conveyed Interests as of the Effective Time.

7.12    Current Commitments.Schedule 7.12 sets forth, as of the Execution Date, all approved authorizations for expenditures and other approved capital commitments, individually equal to or greater than $200,000 (net to Seller’s interest) (the “AFEs”) relating to the Conveyed Interests to drill or rework any Wells or for other capital expenditures pursuant to any of the Material Contracts for which all of the activities anticipated in such AFEs have not been completed by the Execution Date.

7.13    Tax Matters. Except as set forth inSchedule 7.13, during the period of Seller’s ownership of the Conveyed Interests, all material Asset Taxes that have become due and payable by Seller have been properly paid, other than any Asset Taxes that are being contested in good faith and all Tax Returns required to have been filed with respect to such Asset Taxes have been timely filed (taking into account applicable filing extensions). Except as set forth onSchedule 7.13, Seller has not received written notice nor, to Seller’s Knowledge, is there any pending or threatened claim against or audit of Seller from or by any applicable Taxing Authority for the assessment of any material Asset Taxes. All Taxes imposed on Seller that could result in a lien or other claim against any of the Conveyed Interests that have become due and payable have been properly paid, unless contested in good faith by appropriate proceeding. Except as set forth

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inSchedule 7.13, no transfer of any part of the Conveyed Interests pursuant to this Agreement will be treated as a transfer of an interest in a partnership for Tax purposes. Each partnership listed on Schedule 7.13 (if any) has in effect a valid election under Section 754 of the Code. All of the Conveyed Interests have been properly listed and described on the property Tax rolls for all periods prior to and including the Closing Date and no portion of the Conveyed Interests constitute omitted property for property Tax purposes.

7.14    Brokers’ Fees. Seller has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer or any Affiliate of Buyer shall have any responsibility.

7.15    Equipment. To Seller's Knowledge, except as set forth in Schedule 7.15, the Personal Property has been maintained in operable repair, working order and operating condition and are adequate for normal operation of the Conveyed Interests consistent with current practices, ordinary wear and tear excepted.

7.16    Payouts. To Seller's Knowledge, Schedule 7.16 contains a complete and accurate list of the status of any “payout” balance, as of the Effective Time, for the Seller operated Wells subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

7.17    Condemnation. Except as set forth in Schedule 7.17, there is no actual or threatened taking (whether permanent, temporary, whole or partial) of any part of the Conveyed Interests by reason of condemnation or the threat of condemnation.

7.18    Employee Benefits.

(a)    Schedule 7.18 contains a true and complete list of each “employee benefit plan,” as defined in Section 3(3) of ERISA, and all other retirement, pension, deferred compensation, bonus, incentive, severance, executive life insurance, vacation, paid time off, stock purchase, stock option, phantom stock, equity, equity-based, employment, consulting, profit sharing, retention, stay bonus, change of control, welfare, health, disability, fringe benefit and other benefit plans, programs, agreements or arrangements maintained, sponsored or contributed to by Seller or any of its ERISA Affiliates for the benefit of any Available Employee (collectively, the “Seller Benefit Plans”).

(b)    Neither Seller nor its ERISA Affiliates (a) participate in nor have they in the past six years participated in or had a contribution obligation or Liability to (i) any “multiemployer plan” as defined in Section 3(37)(A) or Section 4001(a)(3) of ERISA, (ii) any “multiple employer plan” subject to Sections 4063 or 4064 of ERISA or Section 413 of the Code, or (iii) any “defined benefit plan” within the meaning of Section 3(35) of ERISA, or any “pension plan” as defined in Section 3(2) of ERISA that is or was subject to Title IV of ERISA, Section 302 of ERISA, or Section 412 of the Code, whether or not terminated, nor (b) sponsor or participate in a “welfare plan” within the meaning of Section 3(1) of ERISA that is a “multiple employer welfare arrangement” as such term is defined in Section 3(40) of ERISA. No Seller Benefit Plan is funded through a trust that is intended to be exempt from federal income taxation pursuant to Section 501(c)(9) of the Code.

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(c)    Seller and its Affiliates do not have any obligations under any Seller Benefit Plan or otherwise for any post-employment or post-retirement health or life insurance with respect to the Available Employees, except as required to avoid an excise tax under Section 4980B of the Code or as required pursuant to other similar applicable law.

7.19    Midstream Assets. Seller operates the Midstream Assets (to the extent Seller is the operator for such Midstream Asset) in a manner that does not violate the terms of the Easements in any material respect. To Seller’s Knowledge, none of the Midstream Assets is operated in a manner that would subject Seller to regulation under the Natural Gas Act and the Interstate Commerce Act or the rules and regulations of the Federal Energy Regulatory Commission.

7.20    Midstream Environmental Matters.

(a)    There are no unresolved notices or actions pending, or, to Seller’s Knowledge, threatened by a Governmental Authority with respect to the Midstream Assets which allege a material violation of or liability under any Environmental Law.

(b)    The ownership and operation of the Midstream Assets operated by Seller (or one of its Affiliates) is in compliance in all material respects with all Environmental Laws and to Seller’s Knowledge, the ownership and operation of the Midstream Assets not operated by Seller (or one of its Affiliates) also is in compliance in all material respects with all Environmental Laws.

7.21    Permits.

(a)    Seller has all material permits, certificates, licenses, approvals, registrations, and authorizations under applicable Laws necessary for its ownership and operation of the Conveyed Interests as currently conducted except to the extent failure to have any of the foregoing would not have a material impact on the ownership or operation of the Conveyed Interests as a whole.

(b)    To Seller’s Knowledge, Seller is in compliance in all material respects with and has not violated in any material respect the terms of such permits, certificates, licenses, approvals, registrations, and authorizations except to the extent failure to have any of the foregoing would not have a material impact on the ownership or operation of the Conveyed Interests as a whole.

7.22    Wells.

(a)    During the period of Seller’s ownership of the Oil and Gas Properties, and to Seller’s Knowledge prior to Seller’s ownership, there are no wells located on the Oil and Gas Properties that: (a) Seller is obligated by Law or contract to currently plug and abandon; or (b) to the extent plugged and abandoned, have not been plugged in accordance with applicable material requirements of each Governmental Authority having jurisdiction over the Oil and Gas Properties.

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(b)    Except pursuant to the Material Contracts, no Person has any call upon, option to purchase or similar rights with respect to the production from the Oil and Gas Properties, production from the Oil and Gas Properties is not bound by any gas dedications or subject to any monetary or in-kind throughput fees or charges in connection with gathering or transportation, and the Oil and Gas Properties are not bound by any Hedge Contract that will continue after Closing.

7.23    Foreign Person. Seller is not a “foreign person” within the meaning of Section 1445 of the Code.

7.24    Labor Matters.

(a)    There are no, and have not been in the last four years any, pending or, to Seller’s Knowledge, threatened labor organizing activities, election petitions or similar proceedings;

(b)    Seller has not experienced in the last four years any strike, work stoppage or lockout;

(c)    Seller has no collective bargaining, union, or labor agreements, contracts, or other arrangements with any group of its employees, labor union, or employee representative; and

(d)    there is no pending or, to Seller’s Knowledge, threatened charge, complaint, lawsuit, investigation, or proceeding in any forum or before any court, tribunal or Governmental Authority by or on behalf of any Available Employee alleging breach of any express or implied contract of employment, any Law governing employment, employment practices, or the termination thereof or other discriminatory, retaliatory, wrongful, or tortious conduct in connection with the employment relationship against Seller or its Affiliates.

ARTICLE VIII

REPRESENTATIONS AND WARRANTIES OF BUYER

Each of EnerVest and FourPoint, severally and not jointly, represents and warrants to Seller the following:

8.1    Organization, Existence and Qualification. Each of EnerVest XIII-A, EnerVest XIII-WIB and EnerVest XIII-WIC is a limited partnership duly formed, validly existing and in good standing under the Laws of the State of Delaware and has all requisite power and authority to own and operate its property and to carry on its business as now conducted. FourPoint is a limited liability company duly formed, validly existing and in good standing under the Laws of the State of Delaware and has all requisite power and authority to own and operate its property and to carry on its business as now conducted. Buyer is duly licensed or qualified to do business as a foreign limited liability company in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law except where the failure to be so qualified would not have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

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8.2    Authorization, Approval and Enforceability. Buyer has full power and authority to enter into and perform this Agreement, the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Buyer of this Agreement and the Transaction Documents have been duly and validly authorized and approved by all necessary limited partnership or limited liability company action on the part of Buyer. This Agreement is, and the Transaction Documents to which Buyer is a party, when executed and delivered by Buyer, will be the valid and binding obligations of Buyer and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

8.3    No Conflicts. The execution, delivery, and performance by Buyer of this Agreement and the Transaction Documents to which it is a party and the consummation of the transactions contemplated herein and therein will not (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of Buyer or (b) result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or other agreement to which Buyer is a party or by which Buyer or any of its property may be bound or (c) violate any Law applicable to Buyer or any of its property, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not, individually or in the aggregate, have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

8.4    Consents. Except as described in Section 9.8, there are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment, in each case, that Buyer is required to obtain in connection with the consummation of the transactions contemplated by this Agreement by Buyer.

8.5    Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s Knowledge, threatened against Buyer or any Affiliate of Buyer. Buyer is not insolvent.

8.6    Litigation. There is no investigation, lawsuit, action, litigation or arbitration by any Person or before any Governmental Authority pending, or to Buyer’s Knowledge, threatened against Buyer or any of its Affiliates that has or would have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

8.7    Regulatory. Buyer (or, if applicable, Buyer’s operating Affiliate) is qualified under Law to own and assume operatorship of the Conveyed Interests in all jurisdictions where the Conveyed Interests are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer to be disqualified as such an owner or operator. To the extent required by any Laws, Buyer has maintained and currently has lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, all Laws governing the ownership and operation of the Conveyed Interests and has filed any and all

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reports necessary for such ownership and/or operation with all Governmental Authorities having jurisdiction over such ownership and/or operation. To Buyer’s knowledge, there is no fact or condition with respect to Buyer or its obligations hereunder that may cause any Governmental Authority to withhold its unconditional approval of the transactions contemplated hereby to the extent approval by such Governmental Authority is required by Law.

8.8    Financing. Buyer shall have, as of the Closing Date, sufficient cash in immediately available funds with which to pay the Purchase Price, consummate the transactions contemplated by this Agreement and perform its obligations under this Agreement and the Transaction Documents. Buyer expressly acknowledges that the failure to have sufficient funds shall in no event be a condition to the performance of its obligations hereunder, and in no event shall the Buyer’s failure to perform its obligations hereunder be excused by failure to receive funds from any source.

8.9    Independent Evaluation. Buyer (a) is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities, (b) is capable of evaluating, and hereby acknowledges that it has so evaluated, the merits and risks of the Conveyed Interests, Buyer’s acquisition, ownership, and operation thereof, and its obligations hereunder, and (c) is able to bear the economic risks associated with the Conveyed Interests, Buyer’s acquisition, ownership, and operation thereof, and its obligations hereunder. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer (i) has relied or shall rely solely on its own independent investigation and evaluation of the Conveyed Interests and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and the express provisions of this Agreement and not on any comments, statements, projections or other materials made or given by any representatives or consultants or advisors of Seller or any Affiliates of Seller, and (ii) has satisfied or shall satisfy itself through its own due diligence as to the environmental and physical condition of and contractual arrangements and other matters affecting the Conveyed Interests.

8.10    Brokers’ Fees. None of Buyer or Buyer’s Affiliates has incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement or the Transaction Documents for which Seller or any of Seller’s Affiliates has or shall have any responsibility.

8.11    Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Conveyed Interests for its own account and not with a view to a sale, distribution, or other disposition thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

ARTICLE IX

CERTAIN AGREEMENTS

9.1    Conduct of Business. Except (x) for the operations covered by the AFEs and other capital commitments described inSchedule 7.12, (y) for actions taken in connection with emergency situations or to maintain a Lease, and/or (z) as expressly contemplated by this

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Agreement or as expressly consented to by Buyer in writing (which consent shall not be unreasonably delayed, withheld or conditioned),

(a)    Seller shall, from and after the Execution Date until Closing:

(i)    maintain or cause its Affiliates to maintain, and if Seller or one of its Affiliates is the operator thereof, operate, the Conveyed Interests in the usual and ordinary manner consistent with its past practice, including completing prior to Closing the repair of the saltwater disposal well and the backfill and seeding of the reserve pits described in Schedule 9.1;

(ii)    maintain the books of account and Records relating to the Conveyed Interests in the usual and ordinary manner, in accordance with its usual accounting practices;

(iii)    use commercially reasonable efforts to maintain in full force and effect all Leases, except for immaterial swaps of equivalent acreage and except where any such Lease terminates pursuant to its existing terms or where a reasonably prudent operator would not maintain the same;

(iv)    maintain insurance coverage on the Conveyed Interests in the amounts and types currently in force;

(v)    give written notice to Buyer as soon as is practicable of any written notice received or given by Seller with respect to any alleged material breach by Seller of any Lease or Material Contract;

(vi)    keep Buyer reasonably informed as to material events involving the Conveyed Interests; and

(vii)    consult with Buyer regarding operations involving the Assets and elections to be made under any Material Contract.

(b)    Seller shall not, from and after the Execution Date until Closing:

(i)    except in the case of any Contracts that are crude oil, condensate, and natural gas purchase and sale, gathering, transportation, and marketing arrangements entered into in the ordinary course of business that are terminable without penalty upon 60 days’ or less notice, enter into an Applicable Contract that, if entered into on or prior to the Execution Date, would be required to be listed in Schedule 7.7, or materially amend the terms of any Material Contract;

(ii)    terminate (unless such Material Contract terminates pursuant to its stated terms) or materially amend the terms of any Material Contract;

(iii)    not propose any operation reasonably expected to cost Seller in excess of $300,000;

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(iv)    consent to any operation proposed by a Third Party that is reasonably expected to cost Seller in excess of $300,000;

(v)    settle any suit or litigation or waive any material claims or rights of material value in each case attributable to the Conveyed Interests and affecting the period after the Effective Time;

(vi)    transfer, sell, mortgage, pledge or dispose of the Conveyed Interests (or permit any Affiliate to do any of the foregoing), other than (A) the transfer, sale, or disposal of Hydrocarbons in the ordinary course of business, (B) sales of equipment that is no longer necessary or desirable in the operation of the Conveyed Interests or for which replacement equipment has been, or will be on or prior to Closing, obtained, and (C) immaterial acreage trades or swaps for acreage of approximately equivalent value; and

(vii)    commit to do any of the foregoing.

(c)    Buyer acknowledges that Seller owns undivided interests in certain of the properties comprising the Conveyed Interests with respect to which it is not the operator, and Buyer agrees that the acts or omissions of any other Working Interest owner (including any operator) or any other Person who is not Seller or an Affiliate of Seller shall not constitute a breach of the provisions of this Section 9.1, and no action required by a vote of Working Interest owners shall constitute such a breach so long as Seller has voted its interest in a manner that complies with the provisions of this Section 9.1.

9.2    Successor Operator. Buyer acknowledges that it desires to succeed Seller as operator of those Conveyed Interests or any portion thereof that Seller may presently operate. Buyer further acknowledges and agrees that Seller does not covenant or warrant that Buyer shall become successor operator of such Conveyed Interests. Seller agrees, however, that, as to the Conveyed Interests it operates, it shall use its commercially reasonable efforts to designate, to the extent legally possible and permitted under any applicable joint operating agreement, Buyer (or one of its Affiliates) as successor operator of such Conveyed Interests effective as of Closing.

9.3    Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by Seller or its Affiliates with any Governmental Authority and/or relating to the Conveyed Interests are transferable to Buyer. On or before the Closing Date, Buyer shall use it commercially reasonable efforts to obtain, or cause to be obtained in the name of Buyer (or, if applicable, Buyer’s operating Affiliate), replacements for such bonds, letters of credit and guarantees to the extent such replacements are necessary (a) for Buyer’s ownership of the Conveyed Interests, and (b) to permit the cancellation of the bonds, letters of credit and guarantees posted by Seller and/or any Affiliate of Seller with respect to the Conveyed Interests. In addition, at or prior to Closing, Buyer shall deliver to Seller evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements of such Governmental Authorities to own and, if applicable, operate the Conveyed Interests.

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9.4    Records Retention. Buyer shall and shall cause its successors and assigns to, for a period of seven years following Closing (or, in the case of Records related to Tax matters, until the expiration of the period of time set forth in the applicable statute of limitations), (a) retain the Records, (b) provide Seller, its Affiliates and its and their respective officers, employees and representatives with access to the Records during normal business hours for review and copying at Seller’s expense, and (c) provide Seller, its Affiliates and its and their respective officers, employees and representatives with access, during normal business hours, to materials received or produced after Closing relating to any indemnity claim made under Section 13.2 for review and copying at Seller’s expense. At the end of such seven-year period and prior to destroying any of the Records, Buyer shall notify Seller in writing in advance of such destruction and provide Seller a reasonable opportunity to copy any or all of such Records at Seller’s expense.

9.5    Guarantees. Buyer shall cooperate with Seller in order to cause Seller and its Affiliates to be released, as of the Closing Date, from the guarantees set forth in Schedule 9.5 (the “Guarantees”). Without limiting the foregoing, if required by a counterparty to any Guarantee, Buyer shall, and, if applicable, shall cause its Affiliates to, use commercially reasonable efforts to provide, effective as of the Closing Date or such later date as may be required by such counterparty, substitute guarantee or similar arrangements for all periods covered by the Guarantees, which guarantee or similar arrangements shall (a) constitute a type of security, and (b) be provided by a party whose creditworthiness is, in each case, equivalent to or better than that required by the counterparty to such Guarantee. In the event that any counterparty to any such Guarantee does not release Seller or any of its Affiliates, then, from and after Closing, Buyer shall indemnify Seller or any Affiliate of Seller, as applicable, against all amounts incurred by Seller or any Affiliate of Seller, as applicable, under such Guarantee (and all costs incurred in connection with such Guarantee) if applicable to the Conveyed Interests acquired by Buyer. Notwithstanding anything to the contrary contained in this Agreement, any cash placed in escrow by Seller or any Affiliate of Seller pursuant to the Guarantees must be returned to Seller as soon as practicable and shall be deemed an Excluded Asset for all purposes hereunder.

9.6    Digital Records. After the Execution Date and within ten (10) Business Days prior to the Closing Date, Seller will use commercially reasonable efforts to deliver to Buyer any requested Records available in digital format (the “Digital Records”) upon such request by Buyer so that Buyer may prepare to take over physical operations on the Closing Date as well as to prepare for taking over administrative functions for operated and non-operated Assets.  Any Digital Records delivered to Buyer prior to Closing will be subject to the provisions of the Confidentiality Agreements.  If this Agreement is terminated prior to the Closing, then Buyer will return the Digital Records to Seller in their entirety and shall destroy any copies of the same that may have been created by Buyer.

9.7    Amendment to Schedules. Buyer agrees that, with respect to the representations and warranties of Seller contained in this Agreement, Seller shall have the continuing right until the Closing Date to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereafter arising or discovered which, if existing or known on the Execution Date or thereafter, would have been required to be set forth or described in such Schedules. Notwithstanding the foregoing, for all purposes of this Agreement, including for purposes of determining whether the conditions set forth inArticle X have been fulfilled and

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whether Seller owes Buyer an indemnity underArticle XIII, the Schedules to Seller’s representations and warranties contained in this Agreement shall be deemed to include only that information contained therein on the Execution Date and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto;provided, however, that if Closing shall occur, then all matters disclosed pursuant to any such addition, supplement or amendment at or prior to the Closing Date that arose in the ordinary course of business shall be waived and Buyer shall not be entitled to make a claim with respect thereto pursuant to the terms of this Agreement or otherwise.

9.8    Regulatory Matters. Seller and Buyer shall (a) make or cause to be made an appropriate filing of a Notification and Report Form pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”) with respect to the transactions contemplated hereby as promptly as practicable, but in no event later than 10 Business Days, after the Execution Date, Seller and Buyer shall request early termination of the HSR Act waiting period on the Notification and Report Form, and Seller and Buyer shall bear their own costs and expenses incurred in connection with such filings, provided that Buyer shall pay any filing fees in connection therewith, and (b) each use its commercially reasonable efforts (i) to respond at the earliest practicable date to any requests for additional information made by the Antitrust Division of the Department of Justice (the “DOJ”), the Federal Trade Commission (the “FTC”) or any other Governmental Authority, (ii) to take all actions reasonably necessary to cause the waiting periods under the HSR Act and any other Laws to terminate or expire at the earliest possible date, (iii) to resist in good faith, at each of their respective cost and expense, any assertion that the transactions contemplated hereby constitute a violation of Laws, and (iv) to eliminate any impediment under any Laws that may be asserted by any Governmental Authority so as to enable the Closing to occur as soon as reasonably possible in accordance herewith, all to the end of expediting consummation of the transactions contemplated hereby. In connection with thisSection 9.8, the Parties shall, to the extent permitted by Laws, (A) cooperate in all respects with each other in connection with any filing, submission, investigation or inquiry, (B) promptly inform the other Party of any communication received by such Party from, or given by such Party to, the DOJ or the FTC or any other Governmental Authority and of any material communication received or given in connection with any proceeding by a private party, in each case, regarding the transactions contemplated hereby, (C) have the right to review in advance, and to the extent practicable each shall consult the other on, any filing made with, or written materials to be submitted to, the DOJ, the FTC or any other Governmental Authority or, in connection with any proceeding by a private party, any other Person, in connection with the transactions contemplated hereby, and (D) consult with each other in advance of any meeting, discussion, telephone call or conference with the DOJ, the FTC or any other Governmental Authority or, in connection with any proceeding by a private party, with any other Person, and to the extent not expressly prohibited by the DOJ, the FTC or any other Governmental Authority or person, give the other Party the opportunity to attend and participate in such meetings and conferences, in each case, regarding the transactions contemplated hereby.

9.9    Suspense Accounts. Seller shall, prior to Closing, pay to the States of Texas and Oklahoma or other applicable jurisdictions those suspended royalties that, as of the Execution Date, have escheated or are escheatable to the States of Texas and Oklahoma or other applicable jurisdictions to the extent that such payments are required to be made prior to Closing under applicable Laws.  Seller shall transfer to Buyer pursuant to a downward adjustment to the

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Purchase Price as set forth inSection 3.3(b) only those monies held in suspense by Seller at Closing that relate to suspended royalties as to which Buyer shall be responsible for distribution after Closing (which shall not include such escheatable monies).  Seller agrees to provide to Buyer any information reasonably requested by Buyer regarding all of Seller’s accounts holding monies in suspense that will be transferred to Buyer together with a written explanation (to the extent contained in Seller’s files) of why such monies are held in suspense or other information identifying the proper disposition of such monies.

9.10    Transition Services. Exhibit A to the Transition Services Agreement lists the transition services to be provided by Seller to Buyer thereunder after Closing. Buyer shall have the right, by providing written notice to Seller not later than five (5) Business Days prior to Closing, to remove one or more of such transition services from Exhibit A to the Transition Services Agreement. If Buyer provides such notice, then the Parties shall revise Exhibit A to the Transition Services Agreement executed and delivered at Closing to remove such transition services.

ARTICLE X

BUYER’S CONDITIONS TO CLOSING

The obligations of Buyer to consummate the transactions provided for herein are subject, at the option of Buyer, to the fulfillment by Seller or waiver by Buyer, on or prior to Closing of each of the following conditions precedent:

10.1    Representations. The representations and warranties of Seller set forth in Article VII shall be true and correct in all respects (without regard to materiality or Material Adverse Effect qualifiers) on and as of the Closing Date as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that individually or in the aggregate would not have a Material Adverse Effect.

10.2    Performance. Seller shall have materially performed or complied with all obligations, agreements, and covenants contained in this Agreement as to which performance or compliance by Seller is required prior to or at the Closing Date.

10.3    No Legal Proceedings. No material suit, action, litigation or other proceeding instituted by any Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit, enjoin, or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement.

10.4    Title Defects and Environmental Defects. In each case subject to the Individual Title Threshold, the Individual Environmental Threshold and the Aggregate Deductible, as applicable, the sum of (a) all Title Defect Amounts determined underSection 5.3(d)(i) prior to the Closing or if not so determined prior to the Closing, as determined by Buyer in its reasonable opinion, and the sum of all Purchase Price adjustments pursuant to Section 5.3(d)(ii) prior to the Closing, less the sum of all Title Benefit Amounts determined underSection 5.3(e) prior to the Closing, plus (b) all Remediation Amounts for Environmental Defects determined under

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Section 6.1(b)(i) prior to the Closing or if not so determined prior to the Closing, as determined by Buyer in its reasonable opinion, shall be less than 20% of the Purchase Price.

10.5    HSR Approval. The waiting period under the HSR Act applicable to the transactions contemplated hereunder shall have expired or been terminated.

10.6    Casualty Loss. No Casualty Losses shall have occurred with respect to the Conveyed Interests that are reasonably expected to exceed, in the aggregate, Fifty Million Dollars ($50,000,000) to remedy or repair.

10.7    Closing Deliverables. Seller shall have delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Seller underSection 12.3.

ARTICLE XI

SELLER’S CONDITIONS TO CLOSING

The obligations of Seller to consummate the transactions provided for herein are subject, at the option of Seller, to the fulfillment by Buyer or waiver by Seller, on or prior to Closing of each of the following conditions precedent:

11.1    Representations. The representations and warranties of Buyer set forth in Article VIII shall be true and correct in all respects (without regard to materiality qualifiers) on and as of the Closing, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that individually or in the aggregate would not have a Material Adverse Effect.

11.2    Performance. Buyer shall have materially performed or complied with all obligations, agreements, and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or at the Closing Date.

11.3    No Legal Proceedings. No material suit, action, litigation or other proceeding instituted by any Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit, or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement.

11.4    Title Defects and Environmental Defects. In each case subject to the Individual Title Threshold, the Individual Environmental Threshold and the Aggregate Deductible, as applicable, the sum of (a) all Title Defect Amounts determined underSection 5.3(d)(i) prior to the Closing or if not so determined prior to the Closing, as determined by Seller in its reasonable opinion, and the sum of all Purchase Price adjustments pursuant to Section 5.3(d)(ii) prior to the Closing, less the sum of all Title Benefit Amounts determined underSection 5.3(e) prior to the Closing, plus (b) all Remediation Amounts for Environmental Defects determined under Section 6.1(b)(i) prior to the Closing or if not so determined prior to the Closing, as determined by Seller in its reasonable opinion, shall be less than 20% of the Purchase Price.

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11.5    Closing Deliverables. Buyer shall have delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items required to be delivered by Buyer underSection 12.3.

11.6    HSR Approval. The waiting period under the HSR Act applicable to the transactions contemplated hereunder shall have expired or been terminated.

ARTICLE XII

CLOSING

12.1    Date of Closing. Subject to the conditions stated in this Agreement, the sale by Seller and the purchase by Buyer of the Conveyed Interests pursuant to this Agreement (the “Closing”) shall occur on or before December 15, 2014, or such other date as Buyer and Seller may agree upon in writing. The date on which the Closing actually occurs shall be the “Closing Date.”

12.2    Place of Closing. Closing shall be held at the offices of Seller at 600 Travis Street, Suite 5100, Houston, Texas 77002 or such other location as Buyer and Seller may agree upon in writing.

12.3    Closing Obligations. At Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a)    Seller and Buyer shall execute and deliver the Assignment, in sufficient counterparts to facilitate recording in the applicable counties, covering the Conveyed Interests;

(b)    Seller and Buyer shall execute and deliver assignments, on appropriate forms, of federal Leases, state Leases and Indian Leases comprising portions of the Conveyed Interests, if any, in sufficient counterparts to facilitate filing with the applicable Governmental Authority;

(c)    Seller and Buyer shall execute and deliver the Preliminary Settlement Statement;

(d)    Buyer shall deliver to Seller, to the accounts designated in the Preliminary Settlement Statement, by direct bank or wire transfer in same day funds, the Adjusted Purchase Price less the amount of the Deposit plus interest earned thereon;

(e)    Seller and Buyer shall execute and deliver the Deeds, in sufficient counterparts to facilitate recording in the applicable counties;

(f)    Seller and Buyer shall execute and deliver the Transition Services Agreement;

(g)    Seller shall deliver, on forms supplied by Buyer and reasonably acceptable to Seller, transfer orders or letters in lieu thereof directing all purchasers of production to make

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payment to Buyer of proceeds attributable to production from the Conveyed Interests from and after the Effective Time, for delivery by Buyer to the purchaser of production;

(h)    Seller shall deliver an executed certificate of non-foreign status that meets the requirements set forth in Treasury Regulation § 1.1445-2(b)(2);

(i)    To the extent required under any Law or Governmental Authority for any federal or state Lease, Seller and Buyer shall deliver federal and state change of operator forms designating Buyer as the operator of the Wells and the Leases currently operated by Seller;

(j)    An authorized officer of Seller shall execute and deliver a certificate, dated as of Closing Date, certifying that the conditions set forth in Section 10.1 and Section 10.2 have been fulfilled and, if applicable, any exceptions to such conditions that have been waived by Buyer;

(k)    An authorized officer of Buyer shall execute and deliver a certificate, dated as of Closing, certifying that the conditions set forth in Section 11.1 and Section 11.2 have been fulfilled and, if applicable, any exceptions to such conditions that have been waived by Seller;

(l)    Buyer shall deliver any instruments and documents required by Sections 9.3 and/or 9.5;

(m)    Seller, Buyer, and the Escrow Agent shall execute and deliver the Title and Environmental Escrow Agreement if required under Article V;

(n)    Seller and Buyer shall deliver joint written instructions to the Escrow Agent, authorizing the disbursement of the Deposit plus interest earned thereon to Seller; and

(o)    Seller and Buyer shall execute and deliver any other agreements, instruments and documents that are required by other terms of this Agreement to be executed and/or delivered at Closing.

12.4    Records. In addition to the obligations set forth underSection 9.6 and Section 12.3 above, but notwithstanding anything herein to the contrary, no later than 30 days following the Closing Date, Seller shall make available to Buyer the Records for pickup from Seller’s offices during normal business hours.

ARTICLE XIII

ASSUMPTION; INDEMNIFICATION; SURVIVAL

13.1    Assumption by Buyer; Specified Obligations.

(a)    Without limiting Buyer’s rights to indemnity under this Article XIII and Buyer’s rights under any Title Indemnity Agreement or Environmental Indemnity Agreement, from and after Closing, each Buyer, severally and not jointly, assumes and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) its Proportionate Share of all obligations and Liabilities, known or unknown, arising from, based

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upon, related to or associated with the Conveyed Interests, regardless of whether such obligations or Liabilities arose prior to, at or after the Effective Time, including obligations and Liabilities relating in any manner to the use, ownership or operation of the Conveyed Interests, including obligations:

(i)    to furnish makeup gas and/or settle Imbalances according to the terms of applicable gas sales, processing, gathering or transportation Contracts,

(ii)    to pay Working Interests, royalties, overriding royalties and other interest owners’ revenues or proceeds attributable to sales of Hydrocarbons after the Effective Time, (including those held in suspense (including those amounts for which the Purchase Price was adjusted pursuant to Section 3.3(b)(ix) even if such suspense amounts are attributable to sales of Hydrocarbons before the Effective Time),

(iii)    to decommission the Conveyed Interests (the “Decommissioning Obligations”),

(iv)    subject to Seller’s obligations under Article VI, to clean up, restore and/or Remediate the premises covered by or related to the Conveyed Interests in accordance with applicable Contracts and Laws,

(v)    to perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and the Applicable Contracts, or as required by any Law,

(vi)    subject to Article VI, arising from or related to Environmental Conditions, Environmental Defects and Buyer’s Environmental Liabilities, and

(vii)    the matters set forth on Schedule 7.6 – PART A

(all of said obligations and Liabilities, subject to the following exclusion, herein being referred to as the “Assumed Obligations”); provided that Buyer does not assume any obligations or Liabilities of Seller to the extent that they are Specified Obligations or attributable to or arise out of the ownership, use or operation of the Excluded Assets.

(b)    Upon Closing, with respect to specific Claims for the following for which a valid Claim Notice is given within the applicable survival period as set forth in Section 13.8, each Seller, severally but not jointly, retains and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) all obligations and Liabilities, arising from, based upon, related to or associated with (i) Seller’s failure to properly, timely and legally pay, in accordance with the terms of any Lease and applicable Laws, all Burdens with respect to the Conveyed Interests due by Seller and attributable to Seller’s ownership of the Conveyed Interests prior to the Effective Time (other than for amounts held in suspense for which the Purchase Price was adjusted pursuant to Section3.3(b)(ix)); (ii) personal injury or wrongful death attributable to Seller’s operation of the Conveyed Interests prior to the Closing Date; (iii) Operating Expenses for which Seller is responsible pursuant to Section 2.3, (iv) the Excluded Assets, (v) Asset Taxes for which Seller is responsible pursuant to Section 16.2(b) (taking into account, and without duplication of, (A) such Asset Taxes effectively

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borne by Seller as a result of Purchase Price adjustments made pursuant to Section 3.3 and (B) any payments made from one Party to the other in respect of Asset Taxes pursuant to Section 16.2(d)), (vi) all Income Taxes imposed by any applicable Laws on Seller, any of its direct or indirect owners or affiliates, or any combined, unitary, or consolidated group of which any of the foregoing is or was a member, (vii) the matters set forth on Schedule 7.6 – PART B, (viii) the disposal or transport of any Hydrocarbons or Hazardous Substances to or at an off-site waste disposal location, which Hydrocarbons or Hazardous Substances were produced or generated by or resulted from operations on the Conveyed Interests prior to the Effective Time, and (ix) the employment relationship between Seller and any of its past, present or future employees (all of said Liabilities herein being referred to as the “Specified Obligations”).

13.2    Indemnities of Seller. Effective as of Closing, subject to the limitations set forth in Section 13.4 andSection 13.8, each Seller, severally but not jointly, shall be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Buyer and its Affiliates, and all of its and their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, consultants, agents and representatives (collectively, the “Buyer Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party claims or incurred in the investigation or defense of any of the same or in asserting, preserving or enforcing any of their respective rights hereunder, arising from, based upon, related to or associated with:

(a)    any breach by Seller of its representations or warranties contained in Article VII other than Section 7.20;

(b)    any breach by Seller of its covenants and agreements under this Agreement (including those pursuant to Section 16.2 and taking into account adjustments to the purchase price pursuant to Sections 3.3, 3.5 and 3.6); or

(c)    the Specified Obligations.

13.3    Indemnities of Buyer. Effective as of Closing, each Buyer, severally and not jointly, and its successors and assigns shall assume and be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Seller and its Affiliates, and all of their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, consultants, agents and representatives (collectively, the “Seller Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party claims or incurred in the investigation or defense of any of the same or in asserting, preserving or enforcing any of their respective rights hereunder arising from, based upon, related to or associated with:

(a)    any breach by Buyer of its representations or warranties contained in Article VIII;

(b)    any breach by Buyer of its covenants and agreements under this Agreement (including those pursuant to Section 16.2 and taking into account adjustments to the purchase price pursuant to Sections 3.3, 3.5 and 3.6); or

(c)    its Proportionate Share of the Assumed Obligations.

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13.4    Limitation on Liability.

(a)    Seller shall not have any liability for any indemnification under Section 13.2 of this Agreement (i) for any individual Liability unless the amount with respect to such Liability exceeds $100,000, and (ii) until and unless the aggregate amount of all Liabilities exceeding the threshold described in clause (i) above and for which Claim Notices are delivered by Buyer exceeds the Indemnity Deductible, and then only to the extent such Liabilities exceed the Indemnity Deductible; provided that (x) the adjustments to the Purchase Price under Sections 3.3, 3.5, 3.6 or 3.7 and any payments in respect thereof, (y) any breach of Sections 7.1, 7.2, 7.13 or 7.14, or (z) any indemnity owed for Specified Obligations shall not be limited by this Section 13.4(a).

(b)    Notwithstanding anything to the contrary contained in this Agreement, Seller shall not be required to indemnify Buyer for aggregate Liabilities in excess of an amount equal to 20% of the Purchase Price; provided that (x) the adjustments to the Purchase Price under Sections 3.3, 3.5, 3.6 or 3.7 and any payments in respect thereof, (y) any breach of Sections7.1, 7.2, 7.13 or 7.14, or (z) any indemnity owed for Specified Obligations shall not be limited by this Section 13.4(b).

13.5    Express Negligence. EXCEPT AS OTHERWISE PROVIDED IN SECTIONS 4.1(c), 4.1(d), 4.3 AND9.5, THE DEFENSE, INDEMNIFICATION, HOLD HARMLESS, RELEASE, ASSUMED OBLIGATIONS AND LIMITATION OF LIABILITY PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE GROSS, SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS “CONSPICUOUS.”

13.6    Exclusive Remedy. Notwithstanding anything to the contrary contained in this Agreement, from and after Closing,Sections 4.1(c), 9.5, 13.2 and 13.3, the Assignment and any Title Indemnity Agreement or Environmental Indemnity Agreement entered into by the Parties contain the Parties’ exclusive remedies against each other with respect to the transactions contemplated hereby, including breaches of the representations, warranties, covenants and agreements of the Parties contained in this Agreement or in any document or certificate delivered pursuant to this Agreement. Except as specified in Section 4.1(c), Section 13.2 and any Title Indemnity Agreement or Environmental Indemnity Agreement entered into by the Parties, effective as of Closing, Buyer, on its own behalf and on behalf of the Buyer Indemnified Parties, hereby releases, remises and forever discharges Seller and its Affiliates and all of such Persons’ equityholders, partners, members, directors, officers, employees, agents, advisors, and representatives from any and all suits, legal or administrative proceedings, claims, demands, damages, losses, costs, Liabilities, interest or causes of action whatsoever, at Law or in equity, known or unknown, which Buyer or the Buyer Indemnified Parties might now or subsequently have, based on, relating to or arising out of this Agreement, the transactions contemplated by this

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Agreement, the ownership, use or operation of any of the Conveyed Interests prior to Closing or the condition, quality, status or nature of any of the Conveyed Interests prior to Closing, including rights to contribution under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, and any similar Environmental Law, breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common law rights of contribution and rights under insurance maintained by Seller or any of its Affiliates (except as provided inSection 5.4).

13.7    Indemnification Procedures. All claims for indemnification under Sections 4.1(c), 9.5, 13.2 and 13.3 shall be asserted and resolved as follows:

(a)    For purposes of Section 4.1(c), Section 9.5 and this Article XIII, the term “Indemnifying Party” when used in connection with particular Liabilities shall mean the Party or Parties having an obligation to indemnify another Party and/or other Person(s) with respect to such Liabilities pursuant to Section 4.1(c), Section 9.5 or this Article XIII, and the term “Indemnified Party” when used in connection with particular Liabilities shall mean the Party and/or other Person(s) having the right to be indemnified with respect to such Liabilities by the Indemnifying Party pursuant to Section 4.1(c), Section9.5 or this Article XIII.

(b)    To make a claim for indemnification under Sections 4.1(c), 9.5, 13.2 or 13.3, an Indemnified Party shall notify the Indemnifying Party in writing of its claim under this Section 13.7, including the specific details of and specific basis under this Agreement for its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “Third Party Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 13.7(b) shall not relieve the Indemnifying Party of its obligations under Sections 4.1(c), 9.5, 13.2 or 13.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(c)    In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its obligation to defend and indemnify the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such 30-day period, at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

(d)    If the Indemnifying Party admits its obligation to defend and indemnify the Indemnified Party against a Third Party Claim, it shall have the right and obligation to

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diligently defend and indemnify, at its sole cost and expense, the Indemnified Party against such Third Party Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Third Party Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, at its own expense, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 13.7(d). An Indemnifying Party shall not, without the written consent of the Indemnified Party, (i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all Liability in respect of such Third Party Claim or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e)    If the Indemnifying Party does not admit its obligation or admits its obligation to defend and indemnify the Indemnified Party against a Third Party Claim, but fails to diligently prosecute, indemnify against or settle such Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its obligation to defend and indemnify the Indemnified Party against a Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for 10 days following receipt of such notice to (i) admit in writing its obligation to indemnify the Indemnified Party from and against the liability and consent to such settlement, (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability. Any failure by the Indemnifying Party to respond to such notice shall be deemed to be an election under subsection (i) above.

13.8    Survival.

(a)    SELLER’S REPRESENTATIONS AND WARRANTIES IN SECTION 7.20 WILL NOT SURVIVE CLOSING AND BUYER RECOGNIZES THAT IT WILL HAVE NO REMEDY OR RECOURSE WITH RESPECT TO SECTION 7.20 AFTER CLOSING.

(b)    Except for the Specified Representations, the representations and warranties set forth in Section 7.20, the representations and warranties set forth in Section 7.13 and the special warranty of title included in the Assignment and Deeds, the representations and warranties of Seller in Article VII and Buyer in Article VIII and the covenants and agreements of the Parties in Section 9.1 and Section 12.4, shall in each case terminate on the date that is 12 calendar months from the Closing Date. The Specified Representations shall survive Closing without time limit. The representations and warranties set forth in Sections 7.13 and 7.18 shall survive until 30 days after the expiration of the period of time set forth in the applicable statute of limitations. The special warranty of title included in the Assignment shall survive for the period set forth in the Assignment. Subject to the foregoing and as set forth in Section 13.8(c), the remainder of this Agreement shall survive Closing without time limit. Representations, warranties, covenants and agreements shall be of no further force or effect after the date of their

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expiration, provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

(c)    The indemnities in Sections 13.2(a), 13.2(b), 13.3(a) and 13.3(b) shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification. Seller’s indemnities set forth in Section 13.2(c) shall survive the Closing for a period of five years from the Closing Date; provided, however, that (i) Seller’s indemnities set forth in Section 13.2(c) relating to the portions of the Specified Obligations defined in items (v) and (vi) of Section 13.1(b) shall survive until 30 days after the expiration of the period of time set forth in the statute of limitations regarding same and Seller’s indemnities set forth in Section 13.2(c) relating to the portions of the Specified Obligations defined in items (i), (iv), (vii), and (viii) of Section 13.1(b) shall survive without time limit. Buyer’s indemnity set forth in Sections 4.1(c), 9.5 and 13.3(c) shall survive the Closing without time limit and shall be deemed covenants running with the Conveyed Interests (provided that each Buyer and its successors and assigns shall not be released from any of, and shall remain severally and not jointly liable to the Seller Indemnified Parties for, the obligations and Liabilities of Buyer under such Sections of this Agreement upon any transfer or assignment of any Conveyed Interest). Notwithstanding the foregoing, there shall be no termination of any bona fide claim asserted pursuant to the indemnities in Sections 13.2(a) and 13.2(b) or Sections 13.3(a) through 13.3(c) prior to the date of termination for such indemnity.

13.9    Non-Compensatory Damages. None of the Buyer Indemnified Parties nor Seller Indemnified Parties shall be entitled to recover from Seller or Buyer, or their respective Affiliates, any indirect, consequential, punitive, exemplary, remote or speculative damages or damages for lost profits of any kind arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such Party suffers such damages to a Third Party, which damages (including costs of defense and reasonable attorneys’ fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder. Subject to the preceding sentence, Buyer, on behalf of each of the Buyer Indemnified Parties, and Seller, on behalf of each of the Seller Indemnified Parties, waive any right to recover punitive, special, indirect, exemplary, or consequential damages, remote or speculative, or damages for lost profits of any kind, arising in connection with or with respect to this Agreement or the transactions contemplated hereby.

13.10    Waiver of Right to Rescission. Seller and Buyer acknowledge that, following Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As the payment of money shall be adequate compensation, following Closing, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

13.11    Insurance. The amount of any Liabilities for which any of the Buyer Indemnified Parties is entitled to indemnification under this Agreement or in connection with or with respect to the transactions contemplated by this Agreement shall be reduced by any corresponding insurance proceeds from insurance policies carried by Buyer actually realized or

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that could reasonably be expected to be actually realized by Buyer if a claim were properly pursued under the relevant insurance arrangements.

13.12    Disclaimer of Application of Anti-Indemnity Statutes. The Parties acknowledge and agree that the provisions of any anti-indemnity statute relating to oilfield services and associated activities shall not be applicable to this Agreement and/or the transactions contemplated hereby.

ARTICLE XIV

EMPLOYMENT MATTERS

14.1    Seller Benefit Plans. Buyer shall not assume any of the Seller Benefit Plans. From and after the Employee Start Date, Seller and its ERISA Affiliates shall retain and shall be solely responsible for all obligations and liabilities under the Seller Benefit Plans, and neither Buyer nor its Affiliates shall have any obligation, liability or responsibility from and after the Employee Start Date to or under the Seller Benefit Plans, whether such obligation, liability or responsibility arose before, on or after the Employee Start Date. Seller shall indemnify and hold harmless Buyer and its Affiliates with respect to all claims and Liabilities relating to or arising out of the Seller Benefit Plans.

14.2    Pre-Employee Start Date Claims under Seller Benefit Plans. To the extent that an Available Employee was a participant in a Seller Benefit Plan, Seller shall ensure that the Seller Benefit Plans are responsible for providing welfare benefits (including medical, hospital, dental, accidental death and dismemberment, life, disability and other similar benefits) to all participating Available Employees and their dependents and beneficiaries for all claims incurred prior to the Employee Start Date, subject to the generally applicable terms and conditions of such plans. For purposes of thisSection 14.2, a claim is incurred with respect to (i) accidental death and dismemberment, disability, life and other similar benefits when the event giving rise to such claim occurred and (ii) medical, hospital, dental and other similar benefits when the services with respect to such claim are rendered. Seller shall pay out all accrued and unused vacation balances of the Continuing Employees, and all other compensation or remuneration due under applicable Law within thirty (30) days of the Employee Start Date in accordance with Seller’s applicable policies in effect at that time or sooner if required by applicable Law.

14.3    Available Employees’ Offers and Post- Employee Start Date Employment and Benefits. No later than fifteen (15) Business Days following the Execution Date, Seller shall deliver to Buyer (i) a letter that includes a list of all Available Employees (the “Employee Letter”) and (ii) a letter that includes a list of all independent contractors who provide significant services with respect to the Conveyed Interests. Buyer shall have thirty (30) days after receipt of the Employee Letter within which to interview Available Employees for possible employment with Buyer or its Affiliate. Buyer shall have no obligation under this Agreement or otherwise to offer to employ any Available Employee. The Employee Letter shall include the Available Employee Information with respect to each Available Employee. Buyer shall:

(a)    Within ten (10) Business Days before the anticipated Closing Date, make written offers of employment to each of the Available Employees selected for hire by Buyer in its sole discretion (the “Offered Employees”), with such offers providing such Available Employees

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at least five (5) Business Days to either accept or reject such offers, provided, however, that any such written offers of employment to Available Employees at the Wheeler, Texas location of Seller shall be made by no later than October 24, 2014;

(b)    no later than the date that is three (3) Business Days prior to the anticipated Closing Date, Buyer shall notify Seller as to each Offered Employee who, as of such date, has accepted employment with Buyer or any of its Affiliates (the “Continuing Employees”), which acceptance shall be conditioned upon the occurrence of the Closing and effective as of the Employee Start Date and may be conditioned on other typical hiring policies, and each Offered Employee who, as of such date, has rejected Buyer’s offer of employment;

(c)    indemnify and hold harmless Seller and its Affiliates with respect to all claims and Liabilities relating to or arising solely out of Buyer’s employee selection and employment offer process described in this Section 14.3 (including any claim of discrimination or other illegality in such selection and offer process);

(d)    (i) initially provide to each Continuing Employee base salary/wage rate and cash bonus opportunities that are substantially comparable in the aggregate to the base salary and cash bonus opportunities provided to similarly situated employees of Buyer or its Affiliate; provided that nothing in this Agreement shall affect the right of Buyer and its Affiliates to terminate the employment of a Continuing Employee for any reason or at any time; and provided further that neither Buyer nor its Affiliateshall be required to provide compensation or benefits in the form of defined benefit pension benefits, retiree medical benefits, or equity compensation, and (ii) provide severance benefits for each Continuing Employee who is terminated by Buyer or its Affiliate without cause (as defined in Exhibit K) during the twelve (12) month period immediately following the Employee Start Date equivalent to the severance benefits available under Exhibit K; provided, however, that no such severance shall be payable unless such Continuing Employee whose employment has been so terminated timely signs and does not revoke as permitted by applicable Law a general release agreement in a form provided by Buyer or its Affiliate;

(e)    make reasonable efforts to cause the waiver of all limitations as to pre‑existing conditions, exclusions and waiting periods with respect to participation and coverage requirements applicable to the Continuing Employees under the group health plans of Buyer or its Affiliates; and

(f)    provide full service credit for purposes of eligibility and vesting (other than to the extent that such credit would result in duplication of benefits with respect to the same period of service, and excepting credit for Buyer’s long term equity compensation plan) under all vacation, incentive, compensation and employee benefit plans, policies and arrangements made available to Continuing Employees by Buyer or any of its Affiliates on or after the Employee Start Date to the same extent such Continuing Employee’s service was recognized under the corresponding type of benefit plans in which such Continuing Employee participated immediately prior to the Employee Start Date, including the severance benefit determinations.

14.4    Savings Plans. Buyer shall cause the defined contribution pension plan (or plans) and trust (or trusts) intended to qualify under Sections 401(a) and 501(a) of the Code maintained

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by Buyer in which the Continuing Employees are eligible to participate to accept the direct rollover of electing Continuing Employees’ benefits in cash and, if applicable and subject to the terms of such Buyer plans, promissory notes from the Seller Savings Plan; provided that such direct rollover qualifies as an “eligible rollover distribution” under Section 402(c) of the Code.

14.5    Post- Employee Start Date Employment Claims. Buyer shall indemnify, defend and hold Seller and its Affiliates harmless from and against any and all Liability of any kind or nature involving or related to the employment of the Continuing Employees by Buyer, including any Liability related to any employee benefit plan sponsored or maintained by Buyer or its Affiliates.  Seller shall indemnify, defend and hold Buyer and its Affiliates harmless from and against any and all Liability of any kind or nature or related to the employment of any Available Employee who does not become a Continuing Employee. Any Offered Employee who rejects Buyer’s offer of employment as set forth in Section 14.3 shall remain an employee of LOI. All Continuing Employees shall remain employed by LOI between the Closing Date until the Employee Start Date.

14.6    COBRA. Seller acknowledges and agrees that Seller shall be solely liable, and that Buyer and its Affiliates shall have no obligation, responsibility or Liability, for providing continuation coverage under and complying with Section 4980B of the Code, Sections 601 through 608 of ERISA, and any state health care continuation coverage laws with respect to any individual who either prior to, on or after the Closing Date experienced a loss of coverage under any group health plan contributed to or maintained by Seller or its ERISA Affiliates, or who will otherwise be an “M&A Qualified Beneficiary” (as such phrase is defined in Section 54.4980B-9, Q&A-4 of the Treasury Regulations) in connection with the transaction contemplated by this Agreement. Seller agrees to provide continuing health benefit coverage as described in Section 4980B of the Code and Sections 601 through 608 of ERISA (hereinafter referred to as “COBRACoverage”) to all employees who are M&A Qualified Beneficiaries with respect to the transactions contemplated in this Agreement (hereinafter referred to as “COBRA Beneficiaries”). Specifically, Seller agrees that all obligations to provide COBRA Coverage to COBRA Beneficiaries are being allocated to and shall remain with Seller, as permitted by Q&A-7 of the Treasury Regulation Section 54.4980B-9. If Seller and its ERISA Affiliates ceases to maintain a group health plan and Seller’s obligation to provide COBRA Coverage to COBRA Beneficiaries shifts to Buyer or its Affiliate as a result of Treasury Regulation Section 54.4980B-9, Q&A-8(b) or (c), then, notwithstanding any other provision of this Agreement to the contrary, Seller shall reimburse Buyer for any and all costs and expenses which Buyer or its Affiliate incurs in providing or otherwise making available COBRA Coverage to COBRA Beneficiaries (including, but not limited to, claims, administrative costs, fees, insurance premiums, insurance premium increases, etc.). Buyer will invoice Seller monthly with respect to such expenses and Seller shall be obligated to make full payment of each such invoice within fifteen (15) business days of the date of such invoice and, if Seller shall fail to timely pay the amounts of such invoices, Seller shall also be obligated to pay interest with respect to the unpaid amounts at the rate of ten percent (10%) per annum.

14.7    WARN Act. From the date of this Agreement until the Employee Start Date, Seller shall not and shall cause its Affiliates not to terminate the employment of any Available Employees such that a “plant closing” or “mass layoff” (as those terms are defined in the WARN Act or any similar state Law) occurs prior to the Employee Start Date without complying with

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the WARN Act. Buyer agrees to provide any notice required under the WARN Act or any similar state Law with respect to any “plant closing” or “mass layoff” affecting Continuing Employees that may occur on or after the Employee Start Date. Buyer shall indemnify, defend and hold Seller harmless from and against any liability, damages, fines or costs (including reasonable attorneys’ fees) under the WARN Act or any similar state Law for any “plant closing” or “mass layoff” affecting any Continuing Employee on or after the Employee Start Date or arising, in whole or in part, from the actions (or inactions) of Buyer on or after the Employee Start Date. Seller shall indemnify, defend and hold Buyer harmless from and against any liability, damages, fines or costs (including reasonable attorneys’ fees) under the WARN Act or any similar state Law for any “plant closing” or “mass layoff” occurring prior to the Employee Start Date or arising, in whole or in part, from the actions (or inactions) of Seller prior to the Employee Start Date.

14.8    No Third Party Beneficiary Rights. Nothing herein, expressed or implied, shall confer upon any Available Employees (or any of their beneficiaries or alternate payees) any rights or remedies (including any right to employment or continued employment, or any right to compensation or benefits for any period) of any nature or kind whatsoever, under or by reason of this Agreement or otherwise. In addition, the provisions of this Article XIV, are for the sole benefit of the Parties and are not for the benefit of any Third Party. Nothing in this Article XIV, express or implied, shall be deemed to create any employee benefit plan or amend any employee benefit plan, or be construed to prevent Buyer, Seller, or any of their respective Affiliates from terminating or modifying to any extent or in any respect any employee benefit plan. Nothing in this Article XIV shall: (i) grant any rights or benefits to any Person other than Buyer, Seller, and their respective Affiliates or (ii) amend, or may be construed as amending, any employee benefit plan.

14.9    Non-Solicitation of Employees. Beginning on the Closing Date and until the date that is one (1) year from the Closing Date, (i) Buyer shall not solicit for hire, and shall cause its Affiliates not to solicit for hire (without Seller’s prior written consent) any Available Employee to whom Buyer does not make an offer of employment as described in Section 14.3; and (ii) Buyer shall not solicit for hire, and shall cause its Affiliates not to solicit for hire (without Seller’s prior written consent) any LOI employee whose employment location is at Seller’s headquarters or Seller’s Oklahoma City office and whose principal responsibility prior to Closing related to the Conveyed Interests or who are or were directly or indirectly engaged the negotiation or the Closing of the transactions contemplated by this Agreement. Beginning on the applicable Employee Start Date and until the date that is one (1) year from such Employee Start Date, Seller shall not employ, and shall cause its Affiliates not to employ (without Buyer’s prior written consent) any Continuing Employee. Notwithstanding the foregoing, this Section 14.9 shall not prohibit (x) any solicitation that consists of a general advertisement or solicitation by Buyer or Seller, as applicable, through the use of media advertisements, the Internet, or professional search firms that is not targeted at employees of LOI or Buyer or their respective Affiliates, as applicable, or (y) any hiring of any person who is no longer employed by LOI or Buyer or their respective Affiliates, as applicable.

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ARTICLE XV

TERMINATION, DEFAULT AND REMEDIES

15.1    Right of Termination. This Agreement and the transactions contemplated herein may be terminated at any time prior to Closing:

(a)    by the mutual prior written consent of Seller and Buyer;

(b)    by either Seller or Buyer if Closing has not occurred on or before December 31, 2014 (or such later date as agreed to in writing by Seller and Buyer);

(c)    by Seller, at Seller’s option, if any of the conditions set forth in Article XI (other than the conditions set forth in Sections 11.4 and 11.6) have not been satisfied on or before the Closing Date and, following written notice thereof from Seller to Buyer specifying the reason such condition is unsatisfied (including any breach by Buyer of this Agreement), such condition remains unsatisfied for a period of 10 Business Days after Buyer’s receipt of written notice thereof from Seller;

(d)    by Buyer, at Buyer’s option, if any of the conditions set forth in Article X (other than the condition set forth in Sections 10.4 and 10.5) have not been satisfied on or before Closing Date and, following written notice thereof from Buyer to Seller specifying the reason such condition is unsatisfied (including any breach by Seller of this Agreement), such condition remains unsatisfied for a period of 10 Business Days after Seller’s receipt of written notice thereof from Buyer; or

(e)    by Buyer if the condition set forth in Section 10.4 has not been satisfied on or before the Closing Date or by Seller if the condition set forth in Section 11.4 is not satisfied on or before the Closing Date provided, however, that neither Party shall be entitled to terminate this Agreement pursuant to Sections 15.1(b) through (d) aboveif such Party or its Affiliates are, at such time, in material breach of this Agreement.

15.2    Effect of Termination. If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 15.1 hereof, then, except for the provisions of Article I, Sections 4.1(c) through 4.1(g), 4.2, 4.3, 13.9, 14.9, this Section 15.2, and Section 15.3, Article XVI (other than Sections 16.2(b), 16.7 and 16.8) and such of the defined terms in Appendix I to give context to the surviving provisions, this Agreement shall forthwith become void and the Parties shall have no liability or obligation hereunder.

15.3    Return of Documentation and Confidentiality. Upon termination of this Agreement, Buyer shall destroy or return to Seller all title, engineering, geological and geophysical data, environmental assessments and/or reports, maps and other information furnished by or no behalf of Seller to Buyer or prepared by or on behalf of Buyer in connection with its due diligence investigation of the Conveyed Interests, in each case, in accordance with the Confidentiality Agreements and, if Buyer elects to destroy any such information, an officer of Buyer shall certify the destruction of such information to Seller in writing.

15.4    Distribution of Deposit Upon Termination

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(a)    If Seller terminates this Agreement under Section 15.1(c), and the Closing has not occurred (i) because Buyer has materially breached its covenants and agreements hereunder, or (ii) because Buyer is in material breach of its representations and warranties hereunder, then Seller shall be entitled to retain the Deposit, free of any claims by Buyer or any other Person with respect thereto. In such event, Seller shall be free to enjoy immediately all rights of ownership of the Conveyed Interests and to sell, transfer, encumber or otherwise dispose of the Conveyed Interests to any party without any restriction under this Agreement.

(b)    If the Closing does not occur and Seller is entitled to retain the Deposit under the foregoing Section 15.4(a), then the Seller’s sole and exclusive remedy for Buyer’s failure to perform hereunder shall be the retention of the Deposit as agreed and liquidated damages. In such event, Buyer will promptly instruct the Escrow Agent to release the Deposit to Seller, together with any interest earned thereon.

(c)    If this Agreement is terminated for any reason other than the reasons set forth in Section 15.4(a), Seller will promptly instruct the Escrow Agent to return the Deposit to Buyer, together with any interest earned thereon, free of any claims by Seller or any other Person with respect thereto.

ARTICLE XVI

MISCELLANEOUS

16.1    Appendices, Exhibits and Schedules. All of the Appendices, Exhibits and Schedules referred to in this Agreement are hereby incorporated into this Agreement by reference and constitute a part of this Agreement. Each Party to this Agreement and its counsel has received a complete set of Appendices, Exhibits and Schedules prior to and as of the execution of this Agreement.

16.2    Expenses and Taxes.

(a)    Except as otherwise specifically provided herein, all fees, costs and expenses incurred by the Parties in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including legal and accounting fees, costs and expenses.

(b)    Seller shall be allocated and bear all Asset Taxes attributable to (A) any Tax period ending prior to the Effective Time and (B) the portion of any Straddle Period ending immediately prior to the date on which the Effective Time occurs. Buyer shall be allocated and bear all Asset Taxes attributable to (A) any Tax period or portion thereof beginning on or after the Effective Time and (B) the portion of any Straddle Period beginning on the date on which the Effective Time occurs. Each Party shall be responsible for its own Income Taxes.

(c)    For purposes of Section 16.2 (i) Asset Taxes that are attributable to the severance or production of Hydrocarbons shall be allocated to the period in which the severance or production giving rise to such Asset Taxes occurred, (ii) Asset Taxes that are based upon or related to income or receipts or imposed on a transactional basis (other than such Asset Taxes described in clause (i)), shall be allocated to the period in which the transaction giving rise to such Asset Taxes occurred, and (iii) Asset Taxes that are ad valorem, property or other Asset

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Taxes imposed on a periodic basis pertaining to a Straddle Period shall be allocated between the portion of such Straddle Period ending immediately prior to the date on which the Effective Time occurs and the portion of such Straddle Period beginning on the date on which the Effective Time occurs by prorating each such Asset Tax based on the number of days in the applicable Straddle Period that occur before the date on which the Effective Time occurs, on the one hand, and the number of days in such Straddle Period that occur on or after the date on which the Effective Time occurs, on the other hand. For purposes of clause (iii) of the preceding sentence, the period for such Asset Taxes shall begin on the date on which ownership of the applicable Conveyed Interests gives rise to liability for the particular Asset Tax and shall end on the day before the next such date.

(d)    To the extent the actual amount of an Asset Tax is not determinable at the Closing or at the time of the determination of the Final Settlement Statement pursuant to Section 3.6, as applicable, (i) the Parties shall utilize the most recent information available in estimating the amount of such Asset Tax for purposes of such adjustment, and (ii) upon the later determination of the actual amount of such Asset Tax, timely payments will be made from one Party to the other to the extent necessary to cause each Party to bear the amount of such Asset Tax that is allocable to such Party under Section 16.2(b).Buyer shall be responsible for the preparation and timely filing of any Tax Returns and the payment to the applicable Taxing Authority of all Asset Taxes that become due and payable on or after the Closing Date, and Buyer shall indemnify and hold Seller harmless for any failure to file such Tax Returns and to make such payments.

(e)    All required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Conveyed Interests to Buyer shall be borne by Buyer. Any and all sales, use, transfer, stamp, documentary, registration or similar Taxes incurred or imposed with respect to the transactions described in this Agreement (collectively, “Transfer Taxes”) shall be borne by Buyer, provided that Seller shall pay or cause to be paid to the applicable Governmental Authorities any Transfer Taxes that it is required by law to collect and remit. Buyer shall indemnify and hold Seller harmless from and against such Transfer Taxes within thirty (30) days of Seller's written demand therefor. If Seller (not Buyer) is required by applicable law to appeal or protest the assessment of Transfer Taxes, the appeal or protest of such proposed assessment shall be treated as an item for which Seller is entitled to indemnification and if Buyer provides a written request and instructs Seller to do so, Seller shall prosecute the protest or appeal; in such event Buyer shall pay all out-of-pocket expenses of Seller (including attorneys’ fees) incurred by Seller in connection with such appeal or protest. Seller and Buyer shall reasonably cooperate in good faith to minimize, to the extent permissible under applicable law, the amount of any such Transfer Taxes.

(f)    The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns and any audit, litigation, or other proceeding with respect to Taxes relating to the Conveyed Interests. Such cooperation shall include the retention and (upon another Party’s request) the provision of records and information that are relevant to any such Tax Return or audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided under this Agreement. The Parties agree to retain all books

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and records with respect to Tax matters pertinent to the Conveyed Interests relating to any Tax period beginning before the Closing Date until the expiration of the statute of limitations of the respective Tax periods and to abide by all record retention agreements entered into with any Governmental Authority.

16.3    Assignment. Subject to the provisions of Section 16.18, this Agreement may not be assigned by Buyer without the prior written consent of Seller; provided, however, at any time prior to three Business Days prior to the Closing Date, Buyer may, by written notice to Seller, direct Seller to assign Buyer’s interest in this Agreement or all or a portion of the Conveyed Interests and Assumed Obligations to one or more Affiliates of Buyer. Such assignment shall not relieve Buyer of any obligations and responsibilities hereunder, including obligations and responsibilities arising following such assignment. Any assignment or other transfer by Buyer or its successors and assigns of any of the Conveyed Interests shall not relieve Buyer or its successors or assigns of any of their obligations (including indemnity obligations) hereunder, as to the Conveyed Interests so assigned or transferred.

16.4    Preparation of Agreement. Both Seller and Buyer and their respective counsel participated in the preparation of this Agreement. In the event of any ambiguity in this Agreement, no presumption shall arise based on the identity of the draftsman of this Agreement.

16.5    Publicity. Seller and Buyer shall promptly consult with each other with regard to all press releases or other public or private announcements issued or made at or prior to Closing concerning this Agreement or the transactions contemplated herein, and, except as may be required by applicable Laws or the applicable rules and regulations of any Governmental Authority or stock exchange, neither Buyer nor Seller shall issue any such press release or other public or private announcement without the prior written consent of the other Party, which shall not be unreasonably withheld or delayed.

16.6    Notices. All notices and communications required or permitted to be given hereunder shall be given in writing and shall be delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail, Federal Express or United Parcel Service Express Delivery or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), or sent by electronic mail (“email”) transmission (provided that receipt of such email is requested and received, excluding automatic receipts) addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:

If to Seller:

Linn Energy Holdings, LLC

Linn Operating, Inc.

Linn Midstream, LLC

Linn Exploration Mid-Continent, LLC

Mid-Continent II, LLC, and
Linn Midstream, LLC

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600 Travis Street, Suite 5100

Houston, Texas 77064

Attention: Candice Wells

   Vice President, General Counsel and Corporate Secretary

Fax: (832) 426-5956

Email: CWells@linnenergy.com

With a copy to:

Linn Energy Holdings, LLC

Linn Operating, Inc.

Linn Midstream, LLC

Linn Exploration Mid-Continent, LLC

Mid-Continent II, LLC, and
Linn Midstream, LLC

600 Travis Street, Suite 5100

Houston, Texas 77064

Attention: David Beathard,

   VP Business Development, Strategy & Planning

Fax: (832) 426-5909

Email: DBeathard@linnenergy.com

If to Buyer:

EnerVest:

EnerVest, Ltd.

1001 Fannin, Suite 800

Houston, TX 77002

Attention: Mr. Phil DeLozier

Fax: (713) 659-3556

Email: pdelozier@enervest.net

with a copy to:

EnerVest, Ltd.

1001 Fannin, Suite 800

Houston, TX 77002

Attention: Mr. Philip B. Berry

Fax: (713) 615-7799

Email: pberry@enervest.net

with a copy to:

Thompson & Knight LLP

One Arts Plaza, 1722 Routh Street, Suite 1500

Dallas, Texas 75201-2533

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Attention: Arthur Wright

Fax: (214) 999-1695

Email: Arthur.Wright@tklaw.com

FourPoint:

FourPoint Energy, LLC

8450 E. Crescent Parkway, Suite 400,

Greenwood Village, Colorado 80111

Attention: Mr. Frank W. Nessinger

Telephone: (303) 785-1549

Facsimile: (303) 290-9997

Email: fnessinger@fourpointenergy.com

Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile or email transmission during normal business hours on a Business Day (or if delivered or transmitted after normal business hours on a Business Day or on a day other than a Business Day, then on the next Business Day), or upon actual receipt by the addressee during normal business hours on a Business Day after such notice has either been delivered to an overnight courier or deposited in the United States Mail or with Federal Express or United Parcel Service, as the case may be (or if delivered after normal business hours on a Business Day or on a day other than a Business Day, then on the next Business Day). Either Party may change their contact information for notice by giving written notice to the other Party in the manner provided in this Section 16.6. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

16.7    Further Cooperation. From and after Closing, Buyer and Seller shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer, and shall take such other actions as either Party may reasonably request, to convey and deliver the Conveyed Interests to Buyer, to perfect Buyer’s title thereto, and to accomplish the orderly transfer of the Conveyed Interests to Buyer in the manner contemplated by this Agreement.

16.8    Filings, Notices and Certain Governmental Approvals. Promptly after Closing, Buyer shall (a) record all assignments executed at Closing in the records of the applicable Governmental Authority (including any federal or state agencies, if applicable), (b) if applicable, send notices to vendors supplying goods and services for the Conveyed Interests and to the operator of such Conveyed Interests of the assignment of such Conveyed Interests to Buyer, (c) actively pursue the unconditional approval of all applicable Governmental Authorities of the assignment of the Conveyed Interests to Buyer and (d) actively pursue all other consents and approvals that may be required in connection with the assignment of the Conveyed Interests to Buyer and the assumption of the Liabilities assumed by Buyer hereunder, in each case, that shall not have been obtained prior to Closing. Buyer obligates itself to take any and all action required

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by any Governmental Authority in order to obtain such unconditional approval, including the posting of any and all bonds or other security that may be required in excess of its existing lease, pipeline or area-wide bond.

16.9    Entire Agreement; Non-Reliance; Conflicts. THIS AGREEMENT, THE APPENDICES, EXHIBITS AND SCHEDULES HERETO, THE TRANSACTION DOCUMENTS AND THE CONFIDENTIALITY AGREEMENTS COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT BETWEEN THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS, AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF THE PARTIES PERTAINING TO THE SUBJECT MATTER OF THIS AGREEMENT. THERE ARE NO WARRANTIES, REPRESENTATIONS, OR OTHER AGREEMENTS BETWEEN THE PARTIES RELATING TO THE SUBJECT MATTER OF THIS AGREEMENT EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT OR THE TRANSACTION DOCUMENTS, AND NEITHER PARTY SHALL BE BOUND BY OR LIABLE FOR ANY ALLEGED REPRESENTATION, PROMISE, INDUCEMENT, OR STATEMENTS OF INTENTION NOT SO SET FORTH. EACH PARTY ACKNOWLEDGES THAT, IN ENTERING INTO THIS AGREEMENT, IT HAS RELIED SOLELY ON THE PROMISES, AGREEMENTS, STATEMENTS OR REPRESENTATIONS THAT ARE EXPRESSLY SET FORTH IN THIS AGREEMENT AND THE TRANSACTION DOCUMENTS AND THAT NEITHER PARTY HAD ANY DUTY TO MAKE ANY PROMISES, AGREEMENTS, STATEMENTS OR REPRESENTATIONS THAT ARE NOT EXPRESSLY SET FORTH IN THIS AGREEMENT OR IN THE TRANSACTION DOCUMENTS. EACH PARTY ALSO ACKNOWLEDGES THAT, IN ENTERING THIS AGREEMENT, IT HAS NOT RELIED ON ANY PROMISES, AGREEMENTS, STATEMENTS OR REPRESENTATIONS THAT ARE NOT EXPRESSLY SET FORTH IN THIS AGREEMENT OR IN THE TRANSACTION DOCUMENTS. IN THE EVENT OF A CONFLICT BETWEEN: (A) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY SCHEDULE OR EXHIBIT HERETO; OR (B) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY TRANSACTION DOCUMENT, THE TERMS AND PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL,PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE SCHEDULES OR EXHIBITS HERETO OR ANY TRANSACTION DOCUMENT OF TERMS AND PROVISIONS NOT ADDRESSED IN THIS AGREEMENT SHALL NOT BE DEEMED A CONFLICT, AND ALL SUCH ADDITIONAL PROVISIONS SHALL BE GIVEN FULL FORCE AND EFFECT, SUBJECT TO THE PROVISIONS OF THISSECTION 16.9.

16.10    Successors and Permitted Assigns. This Agreement shall be binding upon and inure to the benefit of Buyer and Seller and their respective successors and permitted assigns.

16.11    Parties in Interest. Notwithstanding anything contained in this Agreement, nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Parties or their respective successors and permitted assigns, or the Parties’ respective related Indemnified Parties hereunder any rights, remedies, obligations or Liabilities under or by reason of this Agreement.

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16.12    Amendment. This Agreement may be amended, restated, supplemented or otherwise modified only by an instrument in writing executed by all of the Parties and expressly identified as an amendment, restatement, supplement or modification.

16.13    Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties, or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of either Party, or their respective officers, employees, agents, or representatives, and no failure by a Party to exercise any of its rights under this Agreement, shall, in any such case, operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by either Party of any condition, or any breach of any term, covenant, representation, or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation, or warranty. The rights of the Parties under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

16.14    Governing Law; Jurisdiction; Venue; Jury Waiver. THIS AGREEMENT AND ANY CLAIM, CONTROVERSY OR DISPUTE ARISING UNDER OR RELATED TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THE RIGHTS, DUTIES AND THE LEGAL RELATIONS AMONG THE PARTIES HERETO AND THERETO SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS (EXCEPT THAT, WITH RESPECT TO ISSUES RELATING TO REAL PROPERTY FOR PROPERTIES LOCATED IN A SPECIFIC STATE, THE LAWS OF SUCH STATE SHALL GOVERN), EXCLUDING ANY CONFLICTS OF LAW RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF SUCH PROVISIONS TO THE LAWS OF ANOTHER JURISDICTION. ALL OF THE PARTIES HERETO CONSENT TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE FEDERAL COURTS OF THE UNITED STATES LOCATED IN HOUSTON, TEXAS OR THE STATE COURTS LOCATED IN HOUSTON, TEXAS FOR ANY ACTION ARISING OUT OF THIS AGREEMENT, THE TRANSACTION DOCUMENTS, OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY. ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM THIS AGREEMENT, THE TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY SHALL BE EXCLUSIVELY LITIGATED IN SUCH COURTS DESCRIBED ABOVE HAVING SITES IN HOUSTON, TEXAS AND EACH PARTY IRREVOCABLY SUBMITS TO THE JURISDICTION OF SUCH COURTS SOLELY IN RESPECT OF ANY PROCEEDING ARISING OUT OF OR RELATED TO THIS AGREEMENT. EACH PARTY HERETO VOLUNTARILY, INTENTIONALLY AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY. THE PARTIES FURTHER AGREE, TO THE EXTENT PERMITTED BY LAW, THAT A FINAL AND NONAPPEALABLE JUDGMENT AGAINST A PARTY IN ANY ACTION OR PROCEEDING CONTEMPLATED ABOVE SHALL BE CONCLUSIVE AND MAY BE

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ENFORCED IN ANY OTHER JURISDICTION WITHIN OR OUTSIDE THE UNITED STATES BY SUIT ON THE JUDGMENT, A CERTIFIED OR EXEMPLIFIED COPY OF WHICH SHALL BE CONCLUSIVE EVIDENCE OF THE FACT AND AMOUNT OF SUCH JUDGMENT. TO THE EXTENT THAT EITHER PARTY OR ANY OF ITS AFFILIATES HAS ACQUIRED, OR HEREAFTER MAY ACQUIRE, ANY IMMUNITY FROM JURISDICTION OF ANY COURT OR FROM ANY LEGAL PROCESS (WHETHER THROUGH SERVICE OR NOTICE, ATTACHMENT PRIOR TO JUDGMENT, ATTACHMENT IN AID OF EXECUTION, EXECUTION OR OTHERWISE) WITH RESPECT TO ITSELF OR ITS PROPERTY, SUCH PARTY (ON ITS OWN BEHALF AND ON BEHALF OF ITS AFFILIATES) HEREBY IRREVOCABLY (I) WAIVES SUCH IMMUNITY IN RESPECT OF ITS OBLIGATIONS WITH RESPECT TO THIS AGREEMENT AND (II) SUBMITS TO THE PERSONAL JURISDICTION OF ANY COURT DESCRIBED IN THIS SECTION 16.14.

16.15    Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to either Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

16.16    Removal of Name. As promptly as practicable, but in any case within 60 days after the Transition Period or such earlier time as may be required by applicable Law, Buyer shall eliminate the names “Seller” and any variants thereof from the Conveyed Interests and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

16.17    Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile or other electronic transmission shall be deemed an original signature hereto.

16.18    Like-Kind Exchange. Buyer and Seller agree that either or both of Seller and Buyer may elect to treat the acquisition or sale of the Conveyed Interests as an exchange of like‑kind property under Section 1031 of the Code (an “Exchange”) by providing written notice prior to the Closing Date, provided that the Closing shall not be delayed by reason of the Exchange.  Each Party agrees to use reasonable efforts to cooperate with the other Party in the completion of such an Exchange including an Exchange subject to the procedures outlined in Treasury Regulation § 1.1031(k)-1 and/or Internal Revenue Service Revenue Procedure 2000-37.  Each of Seller and Buyer shall have the right at any time prior to Closing to assignall or a part of its rights under this Agreement to a qualified intermediary (as that term is defined in Treasury Regulation § 1.1031(k)-1(g)(4)(iii)) or an exchange accommodation titleholder (as that term is defined in Internal Revenue Service Revenue Procedure 2000-37) to effect an Exchange.  In connection with any such Exchange, any exchange accommodation titleholder

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shall have taken all steps necessary to own the Conveyed Interests under applicable Law.  Each Party acknowledges and agrees that neither an assignment of a Party’s rights under this Agreement nor any other actions taken by a Party or any other Person in connection with the Exchange shall release either Party from, or modify, any of its liabilities and obligations (including indemnity obligations to the other Party) under this Agreement, and neither Party makes any representations as to any particular Tax treatment that may be afforded to any other Party by reason of such assignment or any other actions taken in connection with the Exchange.  Either Party electing to treat the acquisition or sale of the Conveyed Interests as an Exchange shall be obligated to pay all additional costs incurred hereunder as a result of the Exchange, and in consideration for the cooperation of the other Party, the Party electing Exchange treatment shall agree to pay all costs associated with the Exchange and to indemnify and hold the other Party, its Affiliates, and their respective former, current and future partners, members, shareholders, owners, officers, directors, managers, employees, agents and representatives harmless from and against any and all liabilities and Taxes arising out of, based upon, attributable to or resulting from the Exchange or transactions or actions taken in connection with the Exchange that would not have been incurred by the other Party but for the electing Party’s Exchange election.

16.19    Specific Performance. The Parties agree that if any of the provisions of this Agreement are not performed by Seller in accordance with their specific terms, Buyer shall be entitled to specific performance of the terms hereof, in addition to any other remedy available at law or in equity.

16.20    Buyer Liability. Notwithstanding anything to the contrary in this Agreement, the Parties agree that each Buyer shall be severally, but not jointly, liable (each for its Proportionate Share) for Buyer’s obligations and liabilities under this Agreement.

[Remainder of page intentionally left blank. Signature page follows.]

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IN WITNESS WHEREOF, Seller and Buyer have executed this Agreement on the date first above written.

Seller:
LINN ENERGY HOLDINGS, LLC
By:	/s/ David R. Beathard
Name:	David R. Beathard
Title:	Vice President – Business Development, Strategy & Planning
LINN OPERATING, INC.
By:	/s/ David R. Beathard
Name:	David R. Beathard
Title:	Vice President – Business Development, Strategy & Planning
LINN EXPLORATION MID-CONTINENT, LLC
By:	/s/ David R. Beathard
Name:	David R. Beathard
Title:	Vice President – Business Development, Strategy & Planning
MID-CONTINENT II, LLC
By:	/s/ David R. Beathard
Name:	David R. Beathard
Title:	Vice President – Business Development, Strategy & Planning
LINN MIDSTREAM, LLC
By:	/s/ David R. Beathard
Name:	David R. Beathard
Title:	Vice President – Business Development, Strategy & Planning

SIGNATURE PAGE TO PURCHASE AND SALE AGREEMENT

HOU:3475670.13

Buyer:
ENERVEST ENERGY INSTITUTIONAL FUND XIII–A, L.P. ENERVEST ENERGY INSTITUTIONAL FUND XIII–WIB, L.P.
By:	EnerVest, Ltd., its Managing General Partner
By:	EnerVest Management GP, L.C., its General Partner
By:	/s/ Kenneth Mariani
Name:	Kenneth Mariani
Title:	President
ENERVEST ENERGY INSTITUTIONAL FUND XIII–WIC, L.P.
By:	EnerVest Holding XIII, LLC, its General Partner
By:	EnerVest, Ltd., its Sole Member
By:	EnerVest Management GP, L.C., its General Partner
By:	/s/ Kenneth Mariani
Name:	Kenneth Mariani
Title:	President

SIGNATURE PAGE TO PURCHASE AND SALE AGREEMENT

HOU:3475670.13

FOURPOINT ENERGY, LLC (doing business in Texas as 4P Energy Texas, LLC)
By:	/s/ George H. Solich
Name:	George H. Solich
Title:	President and Chief Executive Officer

SIGNATURE PAGE TO PURCHASE AND SALE AGREEMENT

HOU:3475670.13

APPENDIX I

Definitions

Capitalized terms used in this Agreement shall have the meanings set forth in this Appendix I unless the context requires otherwise.

“AAA” means the American Arbitration Association.

“AAA Rules” means the Commercial Arbitration Rules of the AAA.

“Accounting Arbitrator” has the meaning set forth in Section 3.7.

“Adjusted Purchase Price” has the meaning set forth in Section 3.3.

“AFEs” has the meaning set forth in Section 7.12.

“Affiliate” means, with respect to any Person, any other Person that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, another Person. The term “control” and its derivatives with respect to any Person mean the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” has the meaning set forth in the first paragraph herein.

“Allocated Values” has the meaning set forth in Section 3.8(a).

“Applicable Contracts” means all Contracts to which Seller is a party or is bound relating to any of the Conveyed Interests and (in each case) that will be binding on Buyer after the Closing, including, without limitation: communitization agreements; net profits agreements; production payment agreements; area of mutual interest agreements; joint venture agreements; confidentiality agreements; farmin and farmout agreements; bottom hole agreements; crude oil, condensate, and natural gas purchase and sale, gathering, transportation, and marketing agreements; hydrocarbon storage agreements; acreage contribution agreements; operating agreements; balancing agreements; pooling declarations or agreements; unitization agreements; processing agreements; saltwater disposal agreements; facilities or equipment leases; and other similar contracts and agreements, but exclusive of any master service agreements and Contracts relating to the Excluded Assets.

“Asset Taxes” means ad valorem, property, excise, severance, production, sales, use, or similar Taxes (excluding, for the avoidance of doubt, any Income Taxes and Transfer Taxes) based upon or measured by the ownership or operation of the Conveyed Interests or the production of Hydrocarbons therefrom or the receipt of proceeds therefrom.

“Assignment” means the Assignment and Bill of Sale from Seller to Buyer, pertaining to the Conveyed Interests, substantially in the form attached to this Agreement as Exhibit D.

“Assumed Obligations” has the meaning set forth in Section 13.1(a).

ANNEX I

PAGE 1

“Available Employee” means certain employees of LOI who are providing services with respect to the Conveyed Interests and are identified on the Employee Letter, which will include all field employees of LOI who provide services solely in connection with the Conveyed Interests as of the Effective Time.

“Available Employee Information” means, with respect to an Available Employee, (a) his or her name; (b) his or her title or position; (c) location of employment; (d) start date or seniority date (if different); (e) his annualized base salary or hourly wage, as applicable; (f) a description of commission, bonus or other incentive-based compensation arrangement applicable to such Available Employee, including, but not limited to, the target payment amount for the current year, the amount payable during the one-year period immediately preceding the date hereof, and the amount accrued and paid in the current year as of the date hereof; (g) the number of years of service credit under each Seller Benefit Plan in which an Available Employee participates or with respect to which an Available Employee or dependent or beneficiary thereof may be entitled to any compensation or benefits; (h) whether or not such Available Employee is currently active at work and, if not, the date that absence began, whether such absence is permitted and, if so, the policy permitting such absence, the nature of such absence and the date upon which such Available Employee is currently expected to return to work; (i) the accrued but untaken vacation and other paid leave credited to the Available Employee; (j) whether such person is classified as exempt or non-exempt; and (k) whether such person is full-time or part-time.

“BP Farmout Agreements”means those certain farmout agreements between BP American Production Company and Linn Energy Holdings, LLC, dated January 15, 2014 and November 13, 2013.

“Burden” means any and all royalties (including lessor’s royalty), overriding royalties, production payments, net profits interests and other burdens upon, measured by or payable out of production (excluding, for the avoidance of doubt, any Taxes).

“Business Day” means any day (other than Saturday or Sunday) on which commercial banks in Houston, Texas are generally open for business.

“Buyer” has the meaning set forth in the first paragraph herein.

“Buyer Indemnified Parties” has the meaning set forth in Section 13.2.

“Buyer’s Environmental Liabilities” has the meaning set forth in Section 6.1(a).

“Buyer’s Representatives” has the meaning set forth in Section 4.1(a).

“Casualty Loss” has the meaning set forth in Section 5.4(b).

“Claim Notice” has the meaning set forth in Section 13.7(b).

“Closing” has the meaning set forth in Section 12.1.

“Closing Date” has the meaning set forth in Section 12.1.

ANNEX I

PAGE 2

“COBRA Beneficiaries” has the meaning set forth in Section 14.6.

“COBRA Coverage” has the meaning set forth in Section 14.6.

“Code” means the Internal Revenue Code of 1986, as amended, and any successor statute, and the regulations and administrative guidance promulgated thereunder.

“Confidentiality Agreements” shall mean (i) that certain Confidentiality Agreement, dated as of July 31, 2014, by and between LEH and EnerVest, and (ii) that certain Confidentiality Agreement, dated as of August 6, 2014, by and between LEH and FourPoint.

“Consent” has the meaning set forth in Section 7.4.

“Contract” means any written or oral contract, agreement or any other legally binding arrangement, but excluding, however, any Lease, easement, right-of-way, permit or other instrument creating or evidencing an interest in the Conveyed Interests or any real or immovable property related to or used in connection with the operations of any Conveyed Interests.

“Continuing Employees” is defined in Section 14.3(b).

“Conveyed Interests” has the meaning set forth in Section 2.1.

“Cure Period” has the meaning set forth in Section 5.3(c).

“Customary Post-Closing Consents” means the consents and approvals from Governmental Authorities for the assignment of the Conveyed Interests to Buyer that are customarily obtained after the assignment of properties similar to the Conveyed Interests.

“Decommissioning Obligations” has the meaning set forth in Section 13.1(a).

“Deeds” means, collectively, the Oil, Gas, and Mineral Deed from Seller to Buyer, pertaining to the Fee Minerals, substantially in the form attached to this Agreement as Exhibit I (the “Mineral Deed”)and the Special Warranty Deed from Seller to Buyer, pertaining to the applicable Surface Fee Interests included in the Conveyed Interests, substantially in the form attached to this Agreement as Exhibit J (the “Surface Deed”).

“Defect Claim Date” means on or before 5:00 P.M. (Central Time) on the date that is 60 days after the Execution Date.

“Defensible Title” means:

(a)    with respect to the Oil and Gas Properties, as of the Effective Time, and subject to Permitted Encumbrances:

(i)    that Seller’s title to the Leases, Wells, and Well Locations, with respect to each applicable Target Formation set forth in Exhibit G for a Well or each applicable Target Formation set forth in Exhibit G for a Well Location (in each case, subject to any reservations, limitations or depth restrictions described in Exhibit G),

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entitles Seller to receive, without reduction, suspension or termination throughout the productive life of such Well or the well to be drilled on such Well Location, not less than the Net Revenue Interest set forth in Exhibit G for such applicable Target Formation, except for (i) decreases in connection with those operations in which Seller or its successors or assigns may from and after the Execution Date elect to be a non-consenting co-owner, (ii) decreases resulting from the establishment or amendment from and after the Execution Date of pools or units in accordance with this Agreement, and (iii) decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries; and

(ii)    that Seller’s title to the Leases, Wells, and Well Locations, with respect to each applicable Target Formation set forth in Exhibit G for a Well or each applicable Target Formation set forth in Exhibit G for a Well Location (in each case, subject to any reservations, limitations or depth restrictions described in Exhibit G), obligates Seller to bear, throughout the productive life of such Well or the well drilled on such Well Location, not more than the Working Interest set forth in Exhibit G for such applicable Target Formation, except (i) increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements, or (ii) increases to the extent that such increases are accompanied by a proportionate increase in Seller’s Net Revenue Interest; and

(iii)    that the Wells have been or are being drilled, completed, and operated within the boundaries of the applicable Leases or within the limits otherwise permitted or prescribed by contract, pooling, or unit agreement and by Law; and

(iv)    that the Oil and Gas Properties are free and clear of all Encumbrances.

(b)    with respect to the Midstream Assets, as of the Effective Time, and subject to Permitted Encumbrances:

(i)    that Seller has good and valid title to the Midstream Facilities and Personal Property included in the Midstream Assets; and

(ii)    (that Seller has good and marketable fee title to the Surface Fee Interests; and

(iii)    that the continuous length of the Off Lease Pipelines is located within a recorded right-of-way, easement, or license from the owner of the land covered thereby which grants to Seller and Seller’s successors and assigns (or to Seller’s predecessor in title and its successors and assigns) the right to construct, operate, replace, repair and maintain the applicable portion of such Off Lease Pipeline in, over, under, and across such land, but the failure to record a license from any county or highway department shall not give rise to a claim under this clause (iii); and

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(iv)    that the continuous length of the On Lease Pipelines is located within the boundaries of the applicable Lease and has been constructed, operated, replaced, repaired and maintained in accordance with the terms of such Lease; and

(v)    that the Midstream Assets are free and clear of all Encumbrances.

“Deposit” is defined in Section 3.2.

“DepositEscrow Agreement” means that certain Deposit Escrow Agreement dated as of the Execution Date between Buyer, Seller and Escrow Agent, in substantially the same form as Exhibit O.

“Designated Well Costs” has the meaning set forth in Section 2.3(a).

“Digital Records” has the meaning set forth in Section 9.6.

“Dispute Notice” has the meaning set forth in Section 3.6(a).

“DOJ” has the meaning set forth in Section 9.8.

“Easements” has the meaning set forth in Section 2.1(f).

“Effective Time” means 7:00 A.M. (Central Time) on September 1, 2014.

“email” has the meaning set forth in Section 16.6.

“Employee Letter” is defined in Section 14.3.

“Employee Start Date” means January 1, 2015.

“Encumbrance” means any lien, mortgage, security interest, pledge, charge or similar encumbrance.

“EnerVest” has the meaning set forth in the first paragraph herein.

“EnerVest XIII-A” has the meaning set forth in the first paragraph herein.

“EnerVest XIII-WIB” has the meaning set forth in the first paragraph herein.

“EnerVest XIII-WIC” has the meaning set forth in the first paragraph herein.

“Environmental Arbitrator” has the meaning set forth in Section 6.1(e).

“Environmental Condition” means (a) a condition existing on the Execution Date or Closing Date with respect to the air, soil, subsurface, surface waters, ground waters and/or sediments that causes a Conveyed Interest (or Seller with respect to a Conveyed Interest) not to be in compliance with any Environmental Law, or (b) the existence on the Execution Date or Closing Date with respect to the Conveyed Interests or the operation thereof of any

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environmental pollution, contamination or degradation where remedial or corrective action is presently required (or if known, would be presently required) under Environmental Laws.

“Environmental Defect” means an Environmental Condition with respect to a Conveyed Interest.

“Environmental Defect Deductible” means one percent (1%) of the Purchase Price.

“Environmental Defect Notice” has the meaning set forth in Section 6.1(a).

“Environmental Indemnity Agreement” has the meaning set forth in Section 6.1(b)(iii).

“Environmental Laws” means all Laws in effect as of the Execution Date, including common law, relating to the protection of the environment, including those Laws relating to the storage, handling, and use of Hazardous Substances and those Laws relating to the generation, processing, treatment, storage, transportation, disposal or other management thereof. The term “Environmental Laws” does not include (a) good or desirable operating practices or standards that may be employed or adopted by other oil and gas well operators or recommended by a Governmental Authority, or (b) the Occupational Safety and Health Act of 1970, 29 U.S.C. § 651 et seq., as amended, or any other Law governing worker safety or workplace conditions.

“ERISA” means the Employee Retirement Security Act of 1974, as amended, and the regulations and administrative guidance promulgated thereunder.

“ERISA Affiliate” means, with respect to any entity, any other entity, trade or business that is or at any relevant time was a member of a group described in Section 414(b), (c), (m) or (o) of the Code or Section 4001(b)(1) of ERISA that includes such first entity, or that is a member of the same “controlled group” as such first entity pursuant to Section 4001(a)(14) of ERISA.

“Escrow Agent” has the meaning set forth in Section 3.2.

“Exchange” has the meaning set forth in Section 16.18.

“Excluded Assets” means (a) all of Seller’s corporate minute books, financial records and other business records that relate to Seller’s business generally; (b) to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all trade credits, all accounts, all receivables of Seller and all other proceeds, income or revenues of Seller attributable to the Conveyed Interests and attributable to any period of time prior to the Effective Time; (c) to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all claims and causes of action of Seller arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds); (d) subject to Section 5.4 and to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all rights and interests of Seller (i) under any policy or agreement of insurance or indemnity, (ii) under any bond, or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events or damage to or destruction of property; (e) Seller’s rights with respect to all Hydrocarbons produced and sold from the

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Conveyed Interests with respect to all periods prior to the Effective Time; (f) all claims of Seller or any of its Affiliates for refunds of, rights to receive funds from any Governmental Authority, or loss carry forwards or credits with respect to (i) Asset Taxes attributable to any period (or portion thereof) prior to the Effective Time, (ii) Income Taxes, or (iii) any Taxes attributable to the Excluded Assets; (g) all information technology assets, including desktop computers, laptop computers, servers, networking equipment and any associated peripherals and other computer hardware, computer software, all radio and telephone equipment, smartphones, tablets and other mobility devices, well communication devices, and any other information technology systems, except as provided in Section 2.1(q); (h) all of Seller’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property; (i) all documents and instruments of Seller that are protected by an attorney-client privilege or any attorney work product doctrine; (j) all data that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties; (k) all audit rights or obligations of Seller arising under any of the Applicable Contracts or otherwise with respect to any period prior to the Effective Time or to any of the Excluded Assets, except for any Imbalances assumed by Buyer; (l) documents prepared or received by Seller or its Affiliates with respect to (i) lists of prospective purchasers for such transactions compiled by Seller, (ii) bids submitted by other prospective purchasers of the Conveyed Interests, (iii) analyses by Seller or its Affiliates of any bids submitted by any prospective purchaser, (iv) correspondence between or among Seller, its representatives, and any prospective purchaser other than Buyer, and (v) correspondence between Seller or any of its representatives with respect to any of the bids, the prospective purchasers or the transactions contemplated by this Agreement; (m) except for field offices described on Exhibit A-5, any offices, office leases and any personal property located in or on such offices or office leases; (n) any leases, rights and other assets specifically listed in Exhibit E; (o) any Hedge Contracts; (p) any debt instruments; and (q) any assets described in Section 2.1(i) that are not assignable.

“Execution Date” has the meaning set forth in the first paragraph herein.

“FeeMinerals” has the meaning set forth in Section 2.1(d).

“Final Price” has the meaning set forth in Section 3.6(a).

“Final Settlement Statement” has the meaning set forth in Section 3.6(a).

“FourPoint” has the meaning set forth in the first paragraph herein.

“FTC” has the meaning set forth in Section 9.8.

“GAAP” means generally accepted accounting principles in the United States as interpreted as of the Execution Date.

“Governmental Authority” means any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or Taxing Authority or power; and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

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“Guarantees” has the meaning set forth in Section 9.5.

“Hazardous Substances” means any pollutants, contaminants, toxins or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds, or chemicals that are regulated by, or may form the basis of liability under, any Environmental Laws, including NORM and other substances referenced in Section 6.2.

“Hedge Contract” means any Contract to which Seller or any of its Affiliatesis a party with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions.

“HSR Act” has the meaning set forth in Section 9.8.

“Hydrocarbons” means oil and gas and other hydrocarbons (including condensate) produced or processed in association therewith (whether or not such item is in liquid or gaseous form), or any combination thereof, and any minerals produced in association therewith.

“Imbalances” means all Well Imbalances and Pipeline Imbalances.

“Income Taxes” means any income, franchise and similar Taxes.

“Indemnified Party” has the meaning set forth in Section 13.7(a).

“Indemnifying Party” has the meaning set forth in Section 13.7(a).

“Indemnity Deductible” means one percent (1%) of the Purchase Price.

“Individual Environmental Threshold” has the meaning set forth in Section 6.1(d).

“Individual Title Defect Threshold” has the meaning set forth in Section 5.3(i).

“Interim Period” means that period of time commencing at the Effective Time and ending at 7:00 A.M. (Central Time) on the Closing Date.

“Knowledge” means with respect to Seller, the actual knowledge of the following Persons: Mark Ellis, Arden Walker, Jr., Kolja Rockov, David B. Rottino, Thomas Emmons, and David R. Beathard, Don Davis, Mark Owen and Justin Vick.

“Lands” has the meaning set forth in Section 2.1(a).

“Law” means any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

“Leases” has the meaning set forth in Section 2.1(a).

“LEH” has the meaning set forth in the first paragraph herein.

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“Liabilities” means any and all claims, obligations, causes of action, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines, costs, and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith, including liabilities, costs, losses and damages for personal injury, death, property damage, environmental damage, or Remediation.

“Linn Exploration” has the meaning set forth in the first paragraph herein.

“Linn Midstream” has the meaning set forth in the first paragraph herein.

“LOI” has the meaning set forth in the first paragraph herein.

“Material Adverse Effect” means any change, event, circumstance, development or occurrence that, individually or in the aggregate with all other changes, events, circumstances, developments or occurrences, is or would reasonably be expected to be adverse to the ownership, operation, or financial condition of the Conveyed Interests, taken as a whole, in an amount in excess of Fifty Million Dollars ($50,000,000); provided, however, that the term “Material Adverse Effect” shall not include any material adverse effect resulting from: (a) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (b) any action or omission of Seller taken in accordance with the terms of this Agreement or with the prior consent of Buyer; (c) changes in general market, economic, financial, or political conditions (including changes in commodity prices, fuel supply or transportation markets, interests or rates), regardless of location; (d) changes in conditions or developments generally applicable to the oil and gas industry; (e) acts of God, including hurricanes, storms or other naturally occurring events; (f) acts or failures to act of a Governmental Authority; (g) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (h) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement; (i) any reclassification or recalculation of reserves in the ordinary course of business; (j) changes in the prices of any Hydrocarbons; (k) a change in Laws and any interpretations thereof from and after the Execution Date; and (l) natural declines in well performance.

“Material Contracts” has the meaning set forth in Section 7.7(a).

“Midstream Assets” has the meaning set forth in Section 2.1(h).

“Midstream Facilities” has the meaning set forth in Section 2.1(e).

“Net Revenue Interest” means, with respect to any Well or Well Location set forth in Exhibit G, the interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Well or Well Location (in each case, limited to the applicable currently producing formation or Target Formation as described in the definition of “Defensible Title” and subject to any reservations, limitations or depth restrictions described in Exhibit G), after giving effect to all Burdens.

“NORM” means naturally occurring radioactive material.

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“Off Lease Pipeline” means any Midstream Facility which is (i) not located on a Lease, or (ii) if located on a Lease, is used to transport, process, measure, collect, store or separate Hydrocarbons produced from properties other than or in addition to the Lease on which such Midstream Facility is located or lands pooled therewith.

“Offered Employees” has the meaning set forth in Section 14.3(a).

“Oil and Gas Properties” has the meaning set forth in Section 2.1(d).

“On Lease Pipeline” means any Midstream Facility used to transport, process, measure, collect, store or separate Hydrocarbons produced solely from the Lease on which such Midstream Facility is located or lands pooled therewith.

“Operating Expenses” means (other than the Designated Well Costs) all operating expenses (including costs of insurance) and all capital expenditures incurred in the ownership and operation of the Conveyed Interests in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to the Conveyed Interests under the relevant operating agreement or unit agreement, if any, but excluding Liabilities attributable to (a) personal injury or death, property damage, or violation of any Law, (b) Decommissioning Obligations, (c) environmental matters, including obligations to remediate any contamination of water or Personal Property under applicable Environmental Laws, (d) obligations with respect to Imbalances, (e) obligations to pay Working Interests, royalties, overriding royalties or other interest owners revenues or proceeds attributable to sales of Hydrocarbons relating to the Conveyed Interests, including those held in suspense, and (f) Asset Taxes.

“Party” and “Parties” has the meaning set forth in the first paragraph herein.

“Permitted Encumbrances” means:

(a)    as to the Oil and Gas Properties, the terms and conditions of all Leases and all Burdens if the net cumulative effect of such Leases and Burdens does not (i) have the potential to negatively affect the cash flow or increase the costs to operate or use any of the Conveyed Interests (as currently operated and used), (ii) operate to reduce the Net Revenue Interest of Seller with respect to any Well or Well Location to an amount less than the Net Revenue Interest set forth in Exhibit G for such Well or Well Location, and (iii) does not obligate Seller to bear a Working Interest with respect to any Well or Well Location in any amount greater than the Working Interest set forth in Exhibit G for such Well or Well Location (unless the Net Revenue Interest for such Well or Well Location is greater than the Net Revenue Interest set forth in Exhibit G in the same or greater proportion as any increase in such Working Interest);

(b)    preferential rights to purchase and required consents to assignment and similar agreements (but only as applicable to the transfer to Buyer);

(c)    liens for Taxes not yet due or delinquent or, if delinquent, that are being contested in good faith;

(d)    Customary Post-Closing Consents;

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(e)    conventional rights of reassignment;

(f)    as to the Oil and Gas Properties, such Title Defects as Buyer may have waived or is deemed to have waived pursuant to the terms of this Agreement;

(g)    all Laws and all rights reserved to or vested in any Governmental Authority (i) to control or regulate any Conveyed Interest in any manner; (ii) by the terms of any right, power, franchise, grant, license or permit, or by any provision of Law, to terminate such right, power, franchise, grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any of the Conveyed Interests; (iii) to use such property in a manner which does not materially impair the use of such property for the purposes for which it is currently owned and operated; or (iv) to enforce any obligations or duties affecting the Conveyed Interests to any Governmental Authority with respect to any right, power, franchise, grant, license or permit;

(h)    rights of a common owner of any interest in rights-of-way, permits or easements held by Seller and such common owner as tenants in common or through common ownership;

(i)    easements, conditions, covenants, restrictions, servitudes, permits, rights‑of-way, surface leases, and other rights in the Conveyed Interests for the purpose of operations, facilities, roads, alleys, highways, railways, pipelines, transmission lines, transportation lines, distribution lines, power lines, telephone lines, removal of timber, grazing, logging operations, canals, ditches, reservoirs and other like purposes, or for the joint or common use of real estate, rights-of-way, facilities and equipment, which, in each case, do not have the potential to negatively affect the cash flow or increase the costs to operate or use the Conveyed Interests as currently operated and used;

(j)    vendors, carriers, warehousemen’s, repairmen’s, mechanics’, workmen’s, materialmen’s, construction or other like liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due or which are being contested in good faith by appropriate proceedings by or on behalf of Seller;

(k)    liens created under the Conveyed Interests or operating agreements or by operation of Law in respect of obligations that are not yet due or that are being contested in good faith by appropriate proceedings by or on behalf of Seller;

(l)    with respect to any interest in the Conveyed Interests acquired through compulsory pooling, failure of the records of any Governmental Authority to reflect Seller as the owner of any Conveyed Interests;

(m)    any Encumbrance affecting the Conveyed Interests that is discharged by Seller at or prior to Closing;

(n)    any matters referenced in Schedule 7.6, if the net cumulative effect of such matters (i) does not materially interfere with the operation or use of any of the Conveyed Interests (as currently operated and used or projected to be operated or used), (ii) does not

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reduce the Net Revenue Interest of Seller with respect to any Well or Well Location to an amount less than the Net Revenue Interest set forth in Exhibit G for such Well or Well Location, and (iii) does not obligate Seller to bear a Working Interest in any amount greater than the Working Interest set forth in Exhibit G for such Well or Well Location (unless the Net Revenue Interest for such Lease, Well or Well Location is greater than the Net Revenue Interest set forth in Exhibit G in the same or greater proportion as any increase in such Working Interest);

(o)    any mortgage lien on the fee estate or mineral fee estate from which title to the relevant Lease is derived which (i) was created after the date of the Lease or (ii) has been subordinated to the applicable Lease, in each case only to the extent that such mortgage lien is not currently subject to foreclosure or other enforcement proceedings by the holder of the mortgage lien; and

(p)    the terms and conditions of all Contracts (including the Applicable Contracts) if the net cumulative of such Contracts (i) do not have the potential to negatively affect the cash flow or increase the costs to operate or use any of the Conveyed Interests (as currently operated and used), (ii) do not reduce the Net Revenue Interest of Seller with respect to any Well or Well Location to an amount less than the Net Revenue Interest set forth in Exhibit G for such Well or Well Location, and (iii) do not obligate Seller to bear a Working Interest in any amount greater than the Working Interest set forth in Exhibit G for such Well or Well Location (unless the Net Revenue Interest for such Lease, Well or Well Location is greater than the Net Revenue Interest set forth in Exhibit G in the same or greater proportion as any increase in such Working Interest); and

(q)    all other Encumbrances, instruments, obligations, defects and irregularities affecting the Conveyed Interests that individually or in the aggregate (i) do not have the potential to negatively affect the cash flow or increase the costs to operate or use any of the Conveyed Interests (as currently operated and used or projected to be operated or used), (ii) do not reduce the Net Revenue Interest of Seller with respect to any Well or Well Location to an amount less than the Net Revenue Interest set forth in Exhibit G for such Well or Well Location, and (iii) do not obligate Seller to bear a Working Interest in any amount greater than the Working Interest set forth in Exhibit G for such Well or Well Location (unless the Net Revenue Interest for such Lease, Well or Well Location is greater than the Net Revenue Interest set forth in Exhibit G in the same or greater proportion as any increase in such Working Interest).

Notwithstanding the foregoing, a Permitted Encumbrance shall not include any Encumbrance arising under or with respect to a Seller Benefit Plan.

“Person” means any individual, firm, corporation, company, partnership (general and limited), limited liability company, joint venture, association, trust, estate, unincorporated organization, Governmental Authority or any other entity.

“Personal Property” has the meaning set forth in Section 2.1(h).

“Phase I Environmental Site Assessment” means an environmental site assessment performed pursuant to ASTM Standard E1527, or any similar environmental assessment that does not involve any invasive, sampling or testing activities.

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“Pipeline Imbalance” means any marketing imbalance between the quantity of Hydrocarbons attributable to the Conveyed Interests required to be delivered by Seller under any Contract relating to the purchase and sale, gathering, transportation, storage, processing (including any production handling and processing at a separation facility) or marketing of Hydrocarbons and the quantity of Hydrocarbons attributable to the Conveyed Interests actually delivered by Seller pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility.

“Preferential Purchase Right” has the meaning set forth in Section 7.9.

“Preliminary Settlement Statement” has the meaning set forth in Section 3.5.

“Proportionate Share” has the meaning set forth in the Recitals.

“Purchase Price” has the meaning set forth in Section 3.1.

“Records” has the meaning set forth in Section 2.1(m).

“Release” shall mean any depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, injecting, escaping, leaching, dumping or disposing of any Hazardous Substances into the environment.

“Remediation” means, with respect to an Environmental Condition, the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions, including monitoring, to the extent but only to the extent required under Environmental Laws to correct or remove such Environmental Condition.

“Remediation Amount” means, with respect to an Environmental Condition, the present value as of the Closing Date (using an annual discount rate of 10%) of the cost (net to Seller’s interest prior to the consummation of the transactions contemplated by this Agreement) of the most cost-effective Remediation of such Environmental Condition considering the circumstances and generally accepted industry practices and methods.

“Rod” means a unit of length equal to 51⁄2 yards, 161⁄2 feet, or 1⁄320th of a statute mile.

“RRC” has the meaning set forth in Section 5.6(a).

“Seller” has the meaning set forth in the first paragraph herein.

“Seller Benefit Plans” has the meaning set forth in Section 7.18.

“Seller Indemnified Parties” has the meaning set forth in Section 13.3.

“Specified Obligations” has the meaning set forth in Section 13.1(b).

“Specified Representations” means the representations and warranties in Sections 7.1, 7.2, 7.3, 7.5, 7.10, 7.14, 8.1, 8.2, 8.10, and 8.11.

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“Straddle Period” means any Tax period beginning before and ending on or after the date on which the Effective Time occurs.

“Target Formations” has the meaning set forth in Exhibit N.

“Taxes” means (a) any taxes, assessments, unclaimed property or escheat obligations and other governmental charges imposed by any Governmental Authority, including gross income, net income profits, gross receipts, license, employment, stamp, occupation, premium, alternative or add-on minimum, ad valorem, real property, personal property, transfer, real property transfer, value added, sales, use, customs, duties, capital stock, franchise, excise, withholding, social security (or similar), unemployment, disability, payroll, windfall profit, severance, production, environmental (including taxes under Code Section 59A) estimated or other tax, including any interest, penalty or addition thereto, whether disputed or not, and (b) any liability in respect of any item described in clause (a) above, that arises by reason of a contract, assumption, transferee or successor liability, operation of Law (including by reason of participation in a consolidated, combined or unitary Tax Return) other otherwise.

“Taxing Authority” means, with respect to any Tax, the governmental entity or political subdivision thereof that imposes such Tax, and the agency (if any) charged with the collection of such Tax for such entity or subdivision, including any governmental or quasi-governmental entity or agency that imposes, or is charged with collecting, social security or similar charges or premiums.

“Tax Return” means any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto, and including any amendment thereof.

“Third Party” means any Person other than a Party or an Affiliate of a Party.

“Third PartyClaim” has the meaning set forth in Section 13.7(b).

“Title and Environmental DefectsEscrow Agreement” means that certain Title and Environmental Defects Escrow Agreement dated as of the Closing Date between Buyer, Seller and Escrow Agent, in substantially the same from as Exhibit P.

“Title Arbitrator” has the meaning set forth in Section 5.3(j).

“Title Benefit” means, with respect to each Well and Well Location shown in Exhibit G, any right, circumstance or condition that operates (a) to increase the Net Revenue Interest of Seller above that shown for such Well or Well Location in Exhibit G to the extent the same does not cause a greater than proportionate increase in Seller’s Working Interest therein above that shown in Exhibit G, or (b) to decrease the Working Interest of Seller in any Well or Well Location below that shown for such Well or Well Location in Exhibit G to the extent the same causes a decrease in Seller’s Working Interest that is proportionately greater than the decrease in Seller’s Net Revenue Interest therein below that shown in Exhibit G.

“Title Benefit Amount” has the meaning set forth in Section 5.3(e).

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“Title Benefit Notice” has the meaning set forth in Section 5.3(b).

“Title Benefit Property” has the meaning set forth in Section 5.3(b).

“Title Defect” means any Encumbrance, defect or other matter that causes Seller not to have Defensible Title in and to Wells and Well Locations included in the Oil and Gas Properties or in and to the Midstream Assets, as applicable, as of the Effective Time, without duplication; provided that the following shall not be considered Title Defects:

(a)    defects arising out of the lack of corporate or other entity authorization unless Buyer provides affirmative evidence that such corporate or other entity action was not authorized and results in another Person’s actual and superior claim of title to the relevant Conveyed Interest;

(b)    defects based upon the failure to record any federal or state Leases or any assignments of interests in such Leases in any applicable public records;

(c)    defects based on the failure to recite marital status in a document or omission of successors or heirship or estate proceedings;

(d)    defects that have been cured by applicable Laws of limitations or prescription;

(e)    any Encumbrance or loss of title resulting from Seller’s conduct of business in compliance with this Agreement;

(f)    defects based upon the exercise of any Preferential Purchase Rights or failure to obtain any Consents but only in connection with the proposed transfer to Buyer;

(g)    defects arising from any change in applicable Law after the Execution Date, including changes that would raise the minimum landowner royalty;

(h)    defects arising from any prior oil and gas lease taken more than fifteen (15) years prior to the Effective Time relating to the lands covered by a Lease not being surrendered of record, unless Buyer provides affirmative evidence that such prior oil and gas lease is still in effect and results in another Person’s actual and superior claim of title to the relevant Lease or Well;

(i)    defects or irregularities resulting from or related to probate proceedings or the lack thereof, which defects or irregularities have been outstanding for ten years or more;

(j)    defects that affect only which Person has the right to receive royalty payments rather than the amount or the proper payment of such royalty payment;

(k)    defects based solely on (i) lack of information in Seller’s files, or (ii) references to an unrecorded document(s) to which neither Seller nor any Affiliate of Seller is a party, if such document is dated earlier than January 1, 1960 and is not in Seller’s files;

ANNEX I

PAGE 15

(i)    defects arising from or relating to the outcome of any litigation set forth in Schedule 7.6;

(l)    with respect to the Oil and Gas Properties, defects or irregularities that would customarily be waived by a reasonable owner or operator of similar oil and gas properties;

(m)    defects based on an interest that has not yet been earned under the BP Farmout Agreements; and

(n)    defects arising out of lack of survey, unless a survey is expressly required by applicable Laws.

“Title Defect Amount” has the meaning set forth in Section 5.3(g).

“Title Defect Deductible” means one percent (1%) of the Purchase Price.

“Title Defect Notice” has the meaning set forth in Section 5.3(a).

“Title Defect Property” has the meaning set forth in Section 5.3(a).

“Title Disputes” has the meaning set forth in Section 5.3(j).

“TitleDispute Date” means on or before 5:00 P.M. (Central Time) on the date that is 30 days after the expiration of the Cure Period.

“Title Indemnity Agreement” has the meaning set forth in Section 5.3(d)(iii).

“Transaction Documents” means those documents executed pursuant to or in connection with this Agreement.

“Transition Period” shall mean the period of time for which certain transition services are provided by Seller pursuant to the Transition Services Agreement covering three production months after Closing.

“Transition Services Agreement” shall mean a transition services agreement pertaining to the Conveyed Interests in substantially the same form as Exhibit L.

“Transfer Taxes” has the meaning set forth in Section 16.2(e).

“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed or final Treasury Regulations.

“Units” has the meaning set forth in Section 2.1(c).

“Well Imbalance” means any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to the interests of Seller therein and the shares

ANNEX I

PAGE 16

of production from the relevant Well to which Seller is entitled, together with any appurtenant rights and obligations concerning future in kind and/or cash balancing at the wellhead.

“Wells” has the meaning set forth in Section 2.1(b).

“Well Location” means each well location set forth in Exhibit G.

“Working Interest” means, with respect to any Well or Well Location set forth in Exhibit G, the interest in and to such Well or Well Location that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Well or Well Location (in each case, limited to the applicable currently producing formation or Target Formation as described in the definition of “Defensible Title” and subject to any reservations, limitations or depth restrictions described in Exhibit G), but without regard to the effect of any Burdens.

ANNEX I

PAGE 17

EX-10.1

EXHIBIT 10.1

FOURTH AMENDMENT

TO

SIXTH AMENDED AND RESTATED CREDIT AGREEMENT

DATED AS OF AUGUST 6, 2014

AMONG

LINN ENERGY, LLC,
AS BORROWER,

THE GUARANTORS,

WELLS FARGO BANK, NATIONAL ASSOCIATION,
AS ADMINISTRATIVE AGENT,

AND

THE LENDERS PARTY HERETO

______________________________________________________________________________

JOINT BOOK RUNNERS AND JOINT LEAD ARRANGERS

Wells Fargo Securities, LLC RBC Capital Markets

FOURTH AMENDMENT TO SIXTH AMENDED AND RESTATED CREDIT AGREEMENT

THIS FOURTH AMENDMENT TO SIXTH AMENDED AND RESTATED CREDIT AGREEMENT (this “Fourth Amendment”) dated as of August 6, 2014, among LINN ENERGY, LLC, a Delaware limited liability company (the “Borrower”); the Guarantors signatory hereto, each of the Lenders party to the Credit Agreement referred to below that are signatory hereto; and WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

R E C I T A L S

A.    The Borrower, the Administrative Agent, the Lenders and the other Agents party thereto entered into that certain Sixth Amended and Restated Credit Agreement dated as of April 24, 2013 as amended by that certain First Amendment dated as of October 30, 2013, that certain Second Amendment dated as of December 13, 2013, and that certain Third Amendment dated as of April 30, 2014 (the “Credit Agreement”), pursuant to which the Lenders have made certain credit and other financial accommodations available to and on behalf of the Borrower and its Subsidiaries.

B.    The Borrower has requested and the Administrative Agent and the Majority Lenders have agreed to amend certain provisions of the Credit Agreement.

C.    NOW, THEREFORE, to induce the Administrative Agent and the Majority Lenders to enter into this Fourth Amendment and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Fourth Amendment. Unless otherwise indicated, all section or article references in this Fourth Amendment refer to sections or articles of the Credit Agreement.

Amendments to Credit Agreement.

2.1    Amendment to Section 1.02. Section 1.02 is hereby amended by (a) with respect to each defined term below that is defined in Section 1.02 of the Credit Agreement, deleting such defined term from such Section 1.02 and replacing it with the analogous term below and (b) with respect to each defined term below that is not in Section 1.02 of the Credit Agreement, adding such defined term to such Section 1.02 in the appropriate alphabetical order thereto:

“‘Accommodator’ means Petroleum Strategies Inc., or such other agent selected by the Borrower to arrange the Reverse 1031 Exchange.

‘Acquisition Term Debt’ means the Debt incurred by the Section 1031 Counterparty or an Unrestricted Subsidiary, as applicable, for the purpose of acquiring the Target Properties in a principal amount not to exceed $1.3 billion.

‘Affiliate’ means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified. For the avoidance of doubt, the Section 1031 Counterparty and any direct or indirect subsidiary or parent entity of the Section 1031 Counterparty (including without limitation, the Accommodator) are not “Affiliates” of the Borrower.

‘Agreement’ means this Credit Agreement, as amended by the First Amendment dated as of October 30, 2013, the Second Amendment dated as of December 13, 2013, the Third Amendment dated as of April 30, 2014, and the Fourth Amendment dated as of August 6, 2014, as the same may from time to time be further amended, modified, supplemented or restated.

‘Debt’ means, for any Person, the sum of the following (without duplication): (a) all obligations of such Person for borrowed money or evidenced by bonds, bankers’ acceptances, debentures, notes or other similar instruments; (b) all obligations of such Person (whether contingent or otherwise) in respect of letters of credit, surety or other bonds and similar instruments; (c) all accounts payable, accrued expenses, liabilities or other obligations of such Person, in each such case to pay the deferred purchase price of Property or services (other than (i) accrued pension costs and other employee benefit and compensation obligations arising in the ordinary course of business and (ii) accounts payable incurred in the ordinary course of business which are either (A) not overdue by more than 60 days or (B) being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP); (d) all obligations under Capital Leases; (e) all obligations under Synthetic Leases; (f) all Debt (as defined in the other clauses of this definition) of others secured by (or for which the holder of such Debt has an existing right, contingent or otherwise, to be secured by) a Lien on any Property of such Person, whether or not such Debt is assumed by such Person (other than any Lien on the Equity Interests of an Unrestricted Subsidiary owned by such Person or a Restricted Subsidiary of such Person to secure any Non-Recourse Debt of such Unrestricted Subsidiary), provided that the amount of Debt for purposes of this clause (f) shall be an amount equal to the lesser of the unpaid amount of such Debt and the fair market value of the encumbered Property; (g) all Debt (as defined in the other clauses of this definition) of others guaranteed by such Person or with respect to which such Person otherwise assures a creditor against loss of the Debt (howsoever such assurance shall be made) to the extent of the lesser of the amount of such Debt and the maximum stated amount of such guarantee or assurance against loss; (h) all obligations or undertakings of such Person to maintain or cause to be maintained the financial position or covenants of others or to purchase the Debt of others; (i) obligations to deliver commodities, goods or services, including, without limitation, Hydrocarbons, in consideration of one or more advance payments, other than gas balancing arrangements in the ordinary course of business (but only to the extent of such advance payments); (j) obligations under “take or pay” or similar agreements (other than obligations under firm transportation or drilling contracts); (k) any Debt of a partnership for which such

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Person is liable either by agreement, by operation of law or by a Governmental Requirement but only to the extent of such liability; (l) Disqualified Capital Stock of such Person; and (m) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment. The Debt of any Person shall include all obligations of such Person of the character described above to the extent such Person remains legally liable in respect thereof notwithstanding that any such obligation is not included as a liability of such Person under GAAP.

‘Non-Recourse Debt’ means any Debt of any Unrestricted Subsidiary, in each case in respect of which: (a) the holder or holders thereof (i) shall have recourse only to, and shall have the right to require the obligations of such Unrestricted Subsidiary to be performed, satisfied, and paid only out of, the Property of such Unrestricted Subsidiary and/or one or more of its Subsidiaries (but only to the extent that such Subsidiaries are Unrestricted Subsidiaries) and/or any other Person (other than Borrower and/or any Restricted Subsidiary except to the extent of any Equity Interests of such Unrestricted Subsidiary owned by the Borrower or any Restricted Subsidiary) and (ii) shall have no direct or indirect recourse (including by way of guaranty, support or indemnity) to the Borrower or any Restricted Subsidiary or to any of the Property of Borrower or any Restricted Subsidiary (other than to the extent of any Equity Interests of such Unrestricted Subsidiary owned by the Borrower or any Restricted Subsidiary), whether for principal, interest, fees, expenses or otherwise; and (b) the terms and conditions relating to the non-recourse nature of such Debt are in form and substance reasonably acceptable to the Administrative Agent.

‘Reverse 1031 Exchange’ means, a transaction intended to qualify for non-recognition of gain or loss under Section 1031 of the Code pursuant to which (a) the Section 1031 Counterparty receives funds from the Borrower and/or a Restricted Subsidiary and/or third party financing to acquire Properties owned by one or more third parties, in return for a Section 1031 Note from the Borrower and/or such Restricted Subsidiary and secured financing from the third party financing source, (b) such acquired Properties are ‘parked’ with the Section 1031 Counterparty, (c) the Borrower and/or any of its Restricted Subsidiaries conveys Properties to one or more third parties directly or through the Section 1031 Counterparty, (d) proceeds from such conveyance of Properties referenced in clause (c) above are received by the Section 1031 Counterparty and are used by the Section 1031 Counterparty to repay such Section 1031 Note and the secured third party financing (if the Equity Interests of the Section 1031 Counterparty are not transferred to the Borrower as referenced in clause (e) below), and (e) the Properties ‘parked’ with the Section 1031 Counterparty or the Equity Interests in the Section 1031 Counterparty are transferred to the Borrower and/or any of its Restricted Subsidiaries, in each case, subject to changes recommended by counsel to the Borrower and reasonably acceptable to the Administrative Agent (such acceptance not to be unreasonably withheld or delayed).

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‘Section 1031 Exchange’ means a Reverse 1031 Exchange and any other analogous transaction intended to qualify for non-recognition of gain or loss under Section 1031 of the Code pursuant to which the Borrower and/or any of its Restricted Subsidiaries exchange Properties owned by them for Properties owned by a third party.

‘Section 1031 Counterparty’ means the entity formed by the Accommodator to serve as the qualified intermediary or exchange accommodation titleholder with respect to the Reverse 1031 Exchange and any subsidiary thereof.

‘Section 1031 Note’ means any promissory note or similar instrument issued by a Section 1031 Counterparty in favor of the Borrower and/or a Restricted Subsidiary in connection with a Reverse 1031 Exchange, evidencing any loan or advance made to the Section 1031 Counterparty by the Borrower and/or a Restricted Subsidiary; provided that such note or other instrument is in form and substance reasonably acceptable to the Administrative Agent.

‘Target Properties’ means those Oil and Gas Properties to be acquired pursuant to the Target Purchase and Sale Agreement.

‘Target Purchase and Sale Agreement’ means that certain purchase and sale agreement dated as of June 27, 2014 by and between Devon Energy Production Company, L.P. and Devon Uinta Basin Corporation, as seller, and Linn Energy Holdings, LLC, as buyer.

‘UR Note’ means any promissory note or similar instrument issued by the Unrestricted Subsidiary acquiring the Target Assets in favor of the Borrower and/or a Restricted Subsidiary in connection with the acquisition of the Target Assets, evidencing any loan or advance made to such Unrestricted Subsidiary by the Borrower and/or a Restricted Subsidiary; provided that such note or other instrument is in form and substance reasonably acceptable to the Administrative Agent.”

2.2    Amendment to Section 8.19. Section 8.19 is hereby amended by deleting such Section in its entirety and replacing it with the following:

“Section 8.19    Berry Matters. The Borrower covenants and agrees to cause Berry and each of its Subsidiaries to become Restricted Subsidiaries pursuant to Section 9.18(c) and to repay the Berry Revolver, each within 90 days of the redemption or refinancing of the Berry Senior Debt.”

2.3    Amendment to Section 9.02. Section 9.02 is hereby amended by:

(a)    deleting clause (f) thereof in its entirety and replacing it with the following:

“(f)    Funded Debt and any guarantees thereof incurred after the Effective Date, provided that (i) at the time such Debt is incurred (A), no Default

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has occurred and is then continuing and (B) no Default would result from the incurrence of such Debt after giving effect to the incurrence thereof (and any concurrent repayment of Debt with the proceeds of such incurrence), (ii) immediately after the incurrence of such Debt, the Borrowing Base shall be adjusted in accordance with Section 2.07(e) and prepayment shall be made to the extent required by Section 3.04(c)(iii), (iii) at the time such Debt is incurred, such Debt does not have any scheduled amortization prior to one year after the Maturity Date, (iv) at the time such Debt is incurred, such Debt does not mature sooner than one year after the Maturity Date, (v) such Debt and any guarantees thereof are on market terms for issuers of similar size and credit quality given the then prevailing market conditions and (vi) such Debt does not have any mandatory prepayment or redemption provisions (other than customary change of control or asset sale tender offer provisions) which would require a mandatory prepayment or redemption in priority to the Indebtedness (it being understood and agreed that any Funded Debt constituting unsecured bridge loans incurred by the Borrower in an aggregate principal amount of up to $1,000,000,000 satisfy the conditions described in the foregoing clauses (iii) through (vi)) ; and any Permitted Refinancing Debt in respect thereof.” and

(b)     adding the following to the end of clause (i) thereof: “or Section 9.05(s)”.

2.4    Amendment to Section 9.03. Section 9.03 is hereby amended by:

(a)    adding the phrase “and clause (g)” after the phrase “clauses (a) through (e)” in clause (f) thereof; and

(b)    adding the following Section 9.03(g) thereto:

“(g)    Liens on the Equity Interests of any Unrestricted Subsidiary owned by the Borrower or any Restricted Subsidiary to secure any Non-Recourse Debt of such Unrestricted Subsidiary.”

2.5    Amendment to Section 9.05. Section 9.05 is hereby amended by (a) adding the following to the end of clause (g)(iv)(A)(II) thereof: “(excluding the amount of Investments permitted under Section 9.05(s)) and (b) adding the following Section 9.05(s) thereto:

“(s)    Investments (including any UR Note, any Section 1031 Note and the transfer of any Oil and Gas Properties) made by the Borrower or any Restricted Subsidiary in either the Section 1031 Counterparty or an Unrestricted Subsidiary in an aggregate outstanding amount not to exceed $2,400,000,000 (any Property so Invested valued as of the date such Investment was made) to facilitate the acquisition and development of the Target Properties, the servicing of any Debt incurred by such Section 1031 Counterparty or Unrestricted Subsidiary, as applicable and the Section 1031 Exchange; provided that promptly after the earlier of (i) the receipt by the Borrower or any of its Restricted Subsidiaries of sufficient net cash proceeds in respect of any sale of its Oil and Gas Properties (or Equity Interests in any Restricted Subsidiary owning Oil and Gas Properties) to

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pay off in full the Acquisition Term Debt of such Section 1031 Counterparty or Unrestricted Subsidiary, as applicable, or (ii) the termination and repayment of the Acquisition Term Debt of such Section 1031 Counterparty or Unrestricted Subsidiary, as applicable, the Target Properties (directly or indirectly) become assets of the Borrower and/or a Restricted Subsidiary and any Investments in the Section 1031 Counterparty are extinguished (if such Section 1031 Counterparty does not become a Restricted Subsidiary).”

2.6    Amendments to Section 9.18. Section 9.18 is hereby amended by (a) deleting clause (b) thereof in its entirety and replacing it with the following clause (b) and (b) deleting clause (d) thereof in its entirety and replacing it with the following clause (d):

“(b)    The Borrower may designate by written notification thereof to the Administrative Agent, any Restricted Subsidiary, including a newly formed or newly acquired Subsidiary, as an Unrestricted Subsidiary if either (X) (i) prior, and immediately after giving effect, to such designation, neither a Default nor a Borrowing Base deficiency would exist and (ii) such designation is deemed to be an Investment in an Unrestricted Subsidiary in an amount equal to the fair market value as of the date of such designation of the Borrower’s direct and indirect ownership interest in such Subsidiary and such Investment would be permitted to be made at the time of such designation under Section 9.05(g) or (Y) such Unrestricted Subsidiary is the entity formed or acquired in respect of the Investment permitted under Section 9.05(s). Except as provided in this Section 9.18(b), no Restricted Subsidiary may be redesignated as an Unrestricted Subsidiary;”

“(d)    After the date Berry becomes a Restricted Subsidiary, and other than the Non-Recourse Debt of any Unrestricted Subsidiary that acquires the Target Assets as set forth in Section 9.05(s), the Borrower shall not permit the aggregate principal amount of all other Non-Recourse Debt outstanding at any one time to exceed $25,000,000.”

Conditions Precedent. This Fourth Amendment shall become effective on the date (such date, the “Fourth Amendment Effective Date”), when each of the following conditions is satisfied (or waived in accordance with Section 12.02 of the Credit Agreement):

3.1    The Administrative Agent shall have received (a) all fees and other amounts due and payable on or prior to the Fourth Amendment Effective Date and all other fees the Borrower has agreed to pay in connection with this Fourth Amendment and (b) to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.

3.2    The Administrative Agent shall have received from Lenders constituting the Majority Lenders, the Borrower and the Guarantors, counterparts (in such number as may be requested by the Administrative Agent) of this Fourth Amendment signed on behalf of such Person.

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3.3    The Administrative Agent shall be reasonably satisfied (a) with the terms and conditions of the Qualified Exchange Agreement among the Accommodator, any Section 1031 Counterparty, the Borrower and any of the other parties thereto and (b) the terms of any Section 1031 Note.

3.4    No Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this Fourth Amendment.

The Administrative Agent is hereby authorized and directed to declare this Fourth Amendment to be effective when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3 or the waiver of such conditions as permitted in Section 12.02 of the Credit Agreement. Such declaration shall be final, conclusive and binding upon all parties to the Agreement for all purposes.

Miscellaneous.

4.1    Confirmation. The provisions of the Credit Agreement, as amended by this Fourth Amendment, shall remain in full force and effect following the effectiveness of this Fourth Amendment.

4.2    Ratification and Affirmation; Representations and Warranties. Each of the Borrower and the Guarantors hereby (a) acknowledges the terms of this Fourth Amendment; (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect as expressly amended hereby and (c) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this Fourth Amendment:

(i)    all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects (except those which have a materiality qualifier, which shall be true and correct as so qualified), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct as of such specified earlier date,

(ii)    no Default or Event of Default has occurred and is continuing, and

(iii)    no event or events have occurred which individually or in the aggregate could reasonably be expected to have a Material Adverse Effect.

4.3    Loan Document. This Fourth Amendment is a Loan Document.

4.4    Counterparts. This Fourth Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Fourth Amendment by facsimile transmission or other electronic delivery shall be effective as delivery of a manually executed counterpart hereof.

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4.5    NO ORAL AGREEMENT. THIS FOURTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.

4.6    GOVERNING LAW. THIS FOURTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

4.7    Payment of Expenses. In accordance with Section 12.03 of the Credit Agreement, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable out-of- pocket costs and reasonable expenses incurred in connection with this Fourth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

4.8    Severability. Any provision of this Fourth Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

4.9    Successors and Assigns. This Fourth Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[SIGNATURES BEGIN NEXT PAGE]

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IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to be duly executed as of the date first written above.

BORROWER:	LINN ENERGY, LLC
	By:	/s/ Kolja Rockov
		Kolja Rockov
		Executive Vice President and Chief Financial Officer

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GUARANTORS:	LINN ENERGY HOLDINGS, LLC
	LINN OPERATING, INC.
	MID-CONTINENT HOLDINGS I, LLC
	MID-CONTINENT HOLDINGS II, LLC
	MID-CONTINENT I, LLC
	MID-CONTINENT II, LLC
	LINN MIDSTREAM, LLC (formerly Linn Gas Marketing, LLC)
	LINN EXPLORATION & PRODUCTION MICHIGAN LLC
	LINN MIDWEST ENERGY LLC
	By:		/s/ Kolja Rockov
			Kolja Rockov
			Executive Vice President and Chief Financial Officer
	LINN EXPLORATION MIDCONTINENT, LLC
	By: Mid-Continent Holdings II, LLC, its sole member, as Member/Manager
	By:	/s/ Kolja Rockov
	Name:	Kolja Rockov
	Title:	Executive Vice President and Chief Financial Officer

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LENDERS:	WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent and a Lender
	By:	/s/ Betsy Jocher
	Name:	Betsy Jocher
	Title:	Director

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ROYAL BANK OF CANADA
By:	/s/ Don J. McKinnerney
Name:	Don J. McKinnerney
Title:	Authorized Signatory

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BARCLAYS BANK PLC
By:	/s/ Vanessa A. Kurbatskiy
Name:	Vanessa A. Kurbatskiy
Title:	Vice President

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CITIBANK, N.A.
By:	/s/ Phillip Ballard
Name:	Phillip Ballard
Title:	Vice-President

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CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK
By:	/s/ Darrell Stanley
Name:	Darrell Stanley
Title:	Managing Director
By:	/s/ Ting Lee
Name:	Ting Lee
Title:	Director

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CREDIT SUISSE AG, CAYMAN ISLAND BRANCH
By:	/s/ Nupur Kumar
Name:	NUPUR KUMAR
Title:	AUTHORIZED SIGNATORY
By:	/s/ Samuel Miller
Name:	Samuel Miller
Title:	Authorized Signatory

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THE ROYAL BANK OF SCOTLAND PLC
By:	/s/ Steve Ray
Name:	Steve Ray
Title:	Director

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THE BANK OF NOVA SCOTIA
By:	/s/ Alan Dawson
Name:	Alan Dawson
Title:	Director

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BANK OF MONTREAL
By:	/s/ James V. Ducote
Name:	James V. Ducote
Title:	Managing Director

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CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH
By:	/s/ Trudy Nelson
Name:	Trudy Nelson
Title:	Authorized Signatory
By:	/s/ Richard Antl
Name:	Richard Antl
Title:	Authorized Signatory

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UBS AG, STAMFORD BRANCH
By:	/s/ Lana Gifas
Name:	Lana Gifas
Title:	Director
By:	/s/ Jennifer Anderson
Name:	Jennifer Anderson
Title:	Associate Director

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COMERICA BANK
By:	/s/ William Robinson
Name:	William Robinson
Title:	Vice President

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ING CAPITAL LLC
By:	/s/ Charles Hall
Name:	Charles Hall
Title:	Managing Director
By:	/s/ Juli Bieser
Name:	Juli Bieser
Title:	Director

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SOCIETE GENERALE
By:	/s/ Graeme Bullen
Name:	Graeme Bullen
Title:	Managing Director

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U.S. BANK NATIONAL ASSOCIATION
By:	/s/ Ben J. Leonard
Name:	Ben J. Leonard
Title:	Vice President

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ABN AMRO CAPITAL USA LLC
By:	/s/ Urvashi Zutshi
Name:	Urvashi Zutshi
Title:	Managing Director
By:	/s/ Elizabeth Johnson
Name:	Elizabeth Johnson
Title:	Director

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COMPASS BANK
By:	/s/ Ann Van Wagener
Name:	Ann Van Wagener
Title:	Senior Vice President

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DNB CAPITAL LLC
By:	/s/ Cathleen Buckley
Name:	Cathleen Buckley
Title:	Senior Vice President
By:	/s/ Stian Lovseth
Name:	Stian Lovseth
Title:	First Vice President

Signature Page to Fourth Amendment

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MUFG UNION BANK, N.A. (f/k/a Union Bank, N.A.)
By:	/s/ Stacy A. Goldstein
Name:	Stacy A. Goldstein
Title:	Vice President

Signature Page to Fourth Amendment

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CAPITAL ONE, N.A.
By:	/s/ Matthew L. Molero
Name:	Matthew L. Molero
Title:	Sr. Vice President

Signature Page to Fourth Amendment

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SUNTRUST BANK
By:	/s/ John Kovarik
Name:	John Kovarik
Title:	Vice President

Signature Page to Fourth Amendment

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BANK OF AMERICA, N.A.
By:	/s/ Joseph Scott
Name:	Joseph Scott
Title:	Director

Signature Page to Fourth Amendment

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JPMORGAN CHASE BANK, N.A.
By:	/s/ Ryan Aman
Name:	Ryan Aman
Title:	Authorized Officer

Signature Page to Fourth Amendment

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DEUTSCHE BANK AG NEW YORK BRANCH
By:	/s/ Michael Shannon
Name:	Michael Shannon
Title:	Vice President
By:	/s/ Michael Winters
Name:	Michael Winters
Title:	Vice President

Signature Page to Fourth Amendment

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GOLDMAN SACHS BANK USA
By:	/s/ Michelle Latzoni
Name:	Michelle Latzoni
Title:	Authorized Signatory

Signature Page to Fourth Amendment

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MACQUARIE BANK LIMITED
By:	/s/ Bob Kapp
Name:	Bob Kapp
Title:	Executive Director
By:	/s/ Andrew Mitchell
Name:	Andrew Mitchell
Title:	Division Director

Signature Page to Fourth Amendment

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MORGAN STANLEY BANK, N.A.
By:	/s/ Matthew T. Meyers
Name:	Matthew T. Meyers
Title:	Authorized Signatory

Signature Page to Fourth Amendment

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BP ENERGY COMPANY
By:	/s/ Ryan McGeachie
Name:	Ryan McGeachie
Title:	Attorney-in-Fact

Signature Page to Fourth Amendment

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BNP PARIBAS
By:	/s/ Sriram Chandrasekaran
Name:	Sriram CHANDRASEKARAN
Title:	Director
By:	/s/ Julien Pecoud-Bouvet
Name:	Julien PECOUD-BOUVET
Title:	Vice President

Signature Page to Fourth Amendment

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BRANCH BANKING AND TRUST COMPANY
By:	/s/ James Giordano
Name:	James Giordano
Title:	Vice President

Signature Page to Fourth Amendment

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SUMITOMO MITSUI BANKING CORPORATION
By:	/s/ Shuji Yabe
Name:	Shuji Yabe
Title:	Managing Director

Signature Page to Fourth Amendment

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WHITNEY BANK
By:	/s/ Liana Tchernysheva
Name:	Liana Tchernysheva
Title:	Senior Vice President

Signature Page to Fourth Amendment

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ASSOCIATED BANK, N.A.
By:	/s/ Farhan Iqbal
Name:	FARHAN IQBAL
Title:	Senior Vice President

Signature Page to Fourth Amendment

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KEYBANK NATIONAL ASSOCIATION
By:	/s/ John Dravenstott
Name:	John Dravenstott
Title:	Vice President

Signature Page to Fourth Amendment

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THE HUNTINGTON NATIONAL BANK
By:	/s/ Margaret Niekrash
Name:	Margaret Niekrash
Title:	Vice President

Signature Page to Fourth Amendment

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FIFTH THIRD BANK
By:	/s/ Justin B. Crawford
Name:	Justin B. Crawford
Title:	Director

Signature Page to Fourth Amendment

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NATIXIS
By:	/s/ Louis P. Laville, III
Name:	Louis P. Laville, III
Title:	Managing Director
By:	/s/ Stuart Murray
Name:	Stuart Murray
Title:	Managing Director

Signature Page to Fourth Amendment

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TORONTO DOMINION (NEW YORK) LLC
By:	/s/ Marie Fernandes
Name:	Marie Fernandes
Title:	Authorized Signatory

Signature Page to Fourth Amendment

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MIZUHO BANK LTD.
By:	/s/ Raymond Ventura
Name:	Raymond Ventura
Title:	Deputy General Manager

Signature Page to Fourth Amendment

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CARGILL, INCORPORATED
By:	/s/ Marc D. Rubenstein
Name:	Marc D. Rubenstein
Title:	Credit Manager, Authorized Signatory Cargill, Incorporated

Signature Page to Fourth Amendment

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PNC BANK NATIONAL ASSOCIATION
By:	/s/ Jonathan Luchansky
Name:	Jonathan Luchansky
Title:	Assistant Vice President

Signature Page to Fourth Amendment

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NEXTERA ENERGY POWER MARKETING, LLC
By:	/s/ Mark Maisto
Name:	Mark Maisto
Title:	President

Signature Page to Fourth Amendment

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EX-10.2

EXHIBIT 10.2

FIFTH AMENDMENT

TO

SIXTH AMENDED AND RESTATED CREDIT AGREEMENT

DATED AS OF SEPTEMBER 10, 2014

AMONG

LINN ENERGY, LLC,
AS BORROWER,

THE GUARANTORS,

WELLS FARGO BANK, NATIONAL ASSOCIATION,
AS ADMINISTRATIVE AGENT,

AND

THE LENDERS PARTY HERETO

______________________________________________________________________________

JOINT BOOK RUNNERS AND JOINT LEAD ARRANGERS

Wells Fargo Securities, LLC RBC Capital Markets

FIFTH AMENDMENT TO SIXTH AMENDED AND RESTATED CREDIT AGREEMENT

THIS FIFTH AMENDMENT TO SIXTH AMENDED AND RESTATED CREDIT AGREEMENT (this “Fifth Amendment”) dated as of September 10, 2014, among LINN ENERGY, LLC, a Delaware limited liability company (the “Borrower”); the Guarantors signatory hereto, each of the Lenders party to the Credit Agreement referred to below that are signatory hereto; and WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

R E C I T A L S

A.The Borrower, the Administrative Agent, the Lenders and the other Agents party thereto entered into that certain Sixth Amended and Restated Credit Agreement dated as of April 24, 2013 as amended by that certain First Amendment dated as of October 30, 2013, that certain Second Amendment dated as of December 13, 2013, that certain Third Amendment dated as of April 30, 2014 and that certain Fourth Amendment dated as of August 6, 2014 (the “Credit Agreement”), pursuant to which the Lenders have made certain credit and other financial accommodations available to and on behalf of the Borrower and its Subsidiaries.

B.The Borrower has requested and the Administrative Agent and the Majority Lenders have agreed to amend certain provisions of the Credit Agreement.

C.NOW, THEREFORE, to induce the Administrative Agent and the Majority Lenders to enter into this Fifth Amendment and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Fifth Amendment. Unless otherwise indicated, all section or article references in this Fifth Amendment refer to sections or articles of the Credit Agreement.

Section 2.Amendments to Credit Agreement.

2.1Amendment to Section 1.02. Section 1.02 is hereby amended by (a) with respect to each defined term below that is defined in Section 1.02 of the Credit Agreement, deleting such defined term from such Section 1.02 and replacing it with the analogous term below and (b) with respect to each defined term below that is not in Section 1.02 of the Credit Agreement, adding such defined term to such Section 1.02 in the appropriate alphabetical order thereto:

“‘Agreement’ means this Credit Agreement, as amended by the First Amendment dated as of October 30, 2013, the Second Amendment dated as of December 13, 2013, the Third Amendment dated as of April 30, 2014, the Fourth Amendment dated as of August 6, 2014 and the Fifth Amendment dated as of September 10, 2014, as the same may from time to time be further amended, modified, supplemented or restated.

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‘Pioneer Properties’ means those Oil and Gas Properties to be acquired pursuant to the Pioneer Purchase and Sale Agreement.

‘Pioneer Purchase and Sale Agreement’ means that certain purchase and sale agreement dated as of July 18, 2014 by and between Pioneer Natural Resources USA, Inc., as seller, and Linn Energy Holdings, LLC, as buyer.

‘UR Note’ means any promissory note or similar instrument issued by the Unrestricted Subsidiary acquiring the Target Properties and/or the Pioneer Properties in favor of the Borrower and/or a Restricted Subsidiary in connection with the acquisition of the Target Properties and/or the Pioneer Properties, evidencing any loan or advance made to such Unrestricted Subsidiary by the Borrower and/or a Restricted Subsidiary; provided that such note or other instrument is in form and substance reasonably acceptable to the Administrative Agent.”

2.2Amendments to Section 9.05. Section 9.05 is hereby amended by (a) adding the following inside the second parenthetical at the end of clause (g)(iv)(A)(II) thereof: “and Section 9.05(t) and (b) adding the following Section 9.05(t) thereto:

“(t)Investments (including any UR Note, any Section 1031 Note and the transfer of any Oil and Gas Properties) made by the Borrower or any Restricted Subsidiary in either the Section 1031 Counterparty or an Unrestricted Subsidiary to facilitate the acquisition and development of the Pioneer Properties and the Section 1031 Exchange; provided that (i) such Unrestricted Subsidiary or Section 1031 Counterparty, as applicable, that directly holds the Pioneer Properties shall not incur any Debt (it being understood that any UR Note or Section 1031 Note, as applicable, shall not be considered Debt of such Unrestricted Subsidiary or Section 1031 Counterparty) and (ii) promptly after completion or unwinding of the Section 1031 Exchange, as applicable, the Pioneer Properties (directly or indirectly) become assets of the Borrower and/or a Restricted Subsidiary and any Investments in the Section 1031 Counterparty are extinguished (if such Section 1031 Counterparty does not become a Restricted Subsidiary).”

2.3Amendments to Section 9.18. Section 9.18 is hereby amended by (a) deleting clause (b) thereof in its entirety and replacing it with the following clause (b) and (b) deleting clause (d) thereof in its entirety and replacing it with the following clause (d):

“(b)The Borrower may designate by written notification thereof to the Administrative Agent, any Restricted Subsidiary, including a newly formed or newly acquired Subsidiary, as an Unrestricted Subsidiary if either (X) (i) prior, and immediately after giving effect, to such designation, neither a Default nor a Borrowing Base deficiency would exist and (ii) such designation is deemed to be an Investment in an Unrestricted Subsidiary in an amount equal to the fair market value as of the date of such designation of the Borrower’s direct and indirect ownership interest in such Subsidiary and such Investment would be permitted to

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be made at the time of such designation under Section 9.05(g) or (Y) such Unrestricted Subsidiary is the entity formed or acquired in respect of the Investment permitted under Section 9.05(s) or Section 9.05(t). Except as provided in this Section 9.18(b), no Restricted Subsidiary may be redesignated as an Unrestricted Subsidiary;”

“(d)After the date Berry becomes a Restricted Subsidiary, and other than the Non-Recourse Debt of any Unrestricted Subsidiary that acquires the Target Properties as set forth in Section 9.05(s) or the Pioneer Properties as set forth in Section 9.05(t), the Borrower shall not permit the aggregate principal amount of all other Non-Recourse Debt outstanding at any one time to exceed $25,000,000.”

Section 3.Conditions Precedent. This Fifth Amendment shall become effective on the date (such date, the “Fifth Amendment Effective Date”), when each of the following conditions is satisfied (or waived in accordance with Section 12.02 of the Credit Agreement):

3.1The Administrative Agent shall have received (a) all fees and other amounts due and payable on or prior to the Fifth Amendment Effective Date and all other fees the Borrower has agreed to pay in connection with this Fifth Amendment and (b) to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.

3.2The Administrative Agent shall have received from Lenders constituting the Majority Lenders, the Borrower and the Guarantors, counterparts (in such number as may be requested by the Administrative Agent) of this Fifth Amendment signed on behalf of such Person.

3.3The Administrative Agent shall be reasonably satisfied (a) with the terms and conditions of the Qualified Exchange Agreement among the Accommodator, any Section 1031 Counterparty, Linn Energy Holdings, LLC and any of the other parties thereto with respect to the Pioneer Properties and (b) the terms of any Section 1031 Note with respect to the Pioneer Properties.

3.4No Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this Fifth Amendment.

The Administrative Agent is hereby authorized and directed to declare this Fifth Amendment to be effective when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3 or the waiver of such conditions as permitted in Section 12.02 of the Credit Agreement. Such declaration shall be final, conclusive and binding upon all parties to the Agreement for all purposes.

Section 4.Miscellaneous.

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4.1Confirmation. The provisions of the Credit Agreement, as amended by this Fifth Amendment, shall remain in full force and effect following the effectiveness of this Fifth Amendment.

4.2Ratification and Affirmation; Representations and Warranties. Each of the Borrower and the Guarantors hereby (a) acknowledges the terms of this Fifth Amendment; (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect as expressly amended hereby and (c) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this Fifth Amendment:

(i)all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects (except those which have a materiality qualifier, which shall be true and correct as so qualified), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct as of such specified earlier date,

(ii)no Default or Event of Default has occurred and is continuing, and

(iii)no event or events have occurred which individually or in the aggregate could reasonably be expected to have a Material Adverse Effect.

4.3Loan Document. This Fifth Amendment is a Loan Document.

4.4Counterparts. This Fifth Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Fifth Amendment by facsimile transmission or other electronic delivery shall be effective as delivery of a manually executed counterpart hereof.

4.5NO ORAL AGREEMENT. THIS FIFTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.

4.6GOVERNING LAW. THIS FIFTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

4.7Payment of Expenses. In accordance with Section 12.03 of the Credit Agreement, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable out-of- pocket costs and reasonable expenses incurred in connection with this Fifth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby,

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including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

4.8Severability. Any provision of this Fifth Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

4.9Successors and Assigns. This Fifth Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[SIGNATURES BEGIN NEXT PAGE]

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IN WITNESS WHEREOF, the parties hereto have caused this Fifth Amendment to be duly executed as of the date first written above.

BORROWER:	LINN ENERGY, LLC
	By:	/s/ Kolja Rockov
		Kolja Rockov
		Executive Vice President and Chief Financial Officer

Signature Page to Fifth Amendment

GUARANTORS:	LINN ENERGY HOLDINGS, LLC
	LINN OPERATING, INC.
	MID-CONTINENT HOLDINGS I, LLC
	MID-CONTINENT HOLDINGS II, LLC
	MID-CONTINENT I, LLC
	MID-CONTINENT II, LLC
	LINN MIDSTREAM, LLC (formerly Linn Gas Marketing, LLC)
	LINN EXPLORATION & PRODUCTION MICHIGAN LLC
	LINN MIDWEST ENERGY LLC
	By:		/s/ Kolja Rockov
			Kolja Rockov
			Executive Vice President and Chief Financial Officer
	LINN EXPLORATION MIDCONTINENT, LLC
	By: Mid-Continent Holdings II, LLC, its sole member, as Member/Manager
	By:	/s/ Kolja Rockov
	Name:	Kolja Rockov
	Title:	Executive Vice President and Chief Financial Officer

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LENDERS:	WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent and a Lender
	By:	/s/ Patrick J. Fults
	Name:	Patrick J. Fults
	Title:	Vice President

Signature Page to Fifth Amendment

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ROYAL BANK OF CANADA
By:	/s/ Don J. McKinnerney
Name:	Don J. McKinnerney
Title:	Authorized Signatory

Signature Page to Fifth Amendment

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BARCLAYS BANK PLC
By:	/s/ May Huang
Name:	May Huang
Title:	Assistant Vice President

Signature Page to Fifth Amendment

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CITIBANK, N.A.
By:	/s/ Eamon Baqui
Name:	Eamon Baqui
Title:	Vice President

Signature Page to Fifth Amendment

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CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK
By:	/s/ Darrell Stanley
Name:	Darrell Stanley
Title:	Managing Director
By:	/s/ Michael Willis
Name:	Michael Willis
Title:	Managing Director

Signature Page to Fifth Amendment

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CREDIT SUISSE AG, CAYMAN ISLAND BRANCH
By:	/s/ Nupur Kumar
Name:	Nupur Kumar
Title:	Authorized Signatory
By:	/s/ Whitney Gaston
Name:	Whitney Gaston
Title:	Authorized Signatory

Signature Page to Fifth Amendment

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THE ROYAL BANK OF SCOTLAND PLC
By:	/s/ James L. Moyes
Name:	James L. Moyes
Title:	Managing Director

Signature Page to Fifth Amendment

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THE BANK OF NOVA SCOTIA
By:	/s/ Alan Dawson
Name:	Alan Dawson
Title:	Director

Signature Page to Fifth Amendment

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BANK OF MONTREAL
By:	/s/ James V. Ducote
Name:	James V. Ducote
Title:	Managing Director

Signature Page to Fifth Amendment

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CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH
By:	/s/ Trudy Nelson
Name:	Trudy Nelson
Title:	Authorized Signatory
By:	/s/ Richard Antl
Name:	Richard Antl
Title:	Authorized Signatory

Signature Page to Fifth Amendment

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UBS AG, STAMFORD BRANCH
By:	/s/ Lana Gifas
Name:	Lana Gifas
Title:	Director
By:	/s/ Jennifer Anderson
Name:	Jennifer Anderson
Title:	Associate Director

Signature Page to Fifth Amendment

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COMERICA BANK
By:	/s/ William Robinson
Name:	William Robinson
Title:	Vice President

Signature Page to Fifth Amendment

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ING CAPITAL LLC
By:	/s/ Juli Bieser
Name:	Juli Bieser
Title:	Director
By:	/s/ Michael Price
Name:	Michael Price
Title:	Director

Signature Page to Fifth Amendment

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SOCIETE GENERALE
By:	/s/ Graeme Bullen
Name:	Graeme Bullen
Title:	Managing Director

Signature Page to Fifth Amendment

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U.S. BANK NATIONAL ASSOCIATION
By:	/s/ Benjamin J. Leonard
Name:	Benjamin J. Leonard
Title:	Vice President

Signature Page to Fifth Amendment

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ABN AMRO CAPITAL USA LLC
By:	/s/ Vincent E. Lisanti
Name:	Vincent E. Lisanti
Title:	Managing Director
By:	/s/ Casey Lowary
Name:	Casey Lowary
Title:	Executive Director

Signature Page to Fifth Amendment

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COMPASS BANK
By:	/s/ Kathleen J. Bowen
Name:	Kathleen J. Bowen
Title:	Senior Vice President

Signature Page to Fifth Amendment

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DNB CAPITAL LLC
By:	/s/ Kelton Glasscok
Name:	Kelton Glasscok
Title:	Senior Vice President
By:	/s/ Joe Hykle
Name:	Joe Hykle
Title:	Senior Vice President

Signature Page to Fifth Amendment

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MUFG UNION BANK, N.A. (f/k/a Union Bank, N.A.)
By:	/s/ Stacy A. Goldstein
Name:	Stacy A. Goldstein
Title:	Vice President

Signature Page to Fifth Amendment

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CAPITAL ONE, N.A.
By:	/s/ Matthew L. Molero
Name:	Matthew L. Molero
Title:	Sr. Vice President

Signature Page to Fifth Amendment

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SUNTRUST BANK
By:	/s/ Chulley Bogle
Name:	Chulley Bogle
Title:	Vice President

Signature Page to Fifth Amendment

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BANK OF AMERICA, N.A.
By:	/s/ Joseph Scott
Name:	Joseph Scott
Title:	Director

Signature Page to Fifth Amendment

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JPMORGAN CHASE BANK, N.A.
By:	/s/ Michael A. Kamauf
Name:	Michael A. Kamauf
Title:	Authorized Officer

Signature Page to Fifth Amendment

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DEUTSCHE BANK AG NEW YORK BRANCH
By:	/s/ Lisa Wong
Name:	Lisa Wong
Title:	Vice President
By:	/s/ Peter Cucchiara
Name:	Peter Cucchiara
Title:	Vice President

Signature Page to Fifth Amendment

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GOLDMAN SACHS BANK USA
By:	/s/ Michelle Latzoni
Name:	Michelle Latzoni
Title:	Authorized Signatory

Signature Page to Fifth Amendment

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MACQUARIE BANK LIMITED

By:

Name:

Title:

By:

Name:

Title:

Signature Page to Fifth Amendment

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MORGAN STANLEY BANK, N.A.
By:	/s/ Matthew T. Meyers
Name:	Matthew Meyers
Title:	Authorized Signatory

Signature Page to Fifth Amendment

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BP ENERGY COMPANY
By:	/s/ Ryan McGeachie
Name:	Ryan McGeachie
Title:	Attorney-in-Fact

Signature Page to Fifth Amendment

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BNP PARIBAS
By:	/s/ Ann Rhoads
Name:	Ann Rhoads
Title:	Managing Director
By:	/s/ Sriram Chandrasekaran
Name:	Sriram CHANDRASEKARAN
Title:	Director

Signature Page to Fifth Amendment

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BRANCH BANKING AND TRUST COMPANY
By:	/s/ James Giordano
Name:	James Giordano
Title:	Vice President

Signature Page to Fifth Amendment

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SUMITOMO MITSUI BANKING CORPORATION
By:	/s/ James D. Weinstein
Name:	James D. Weinstein
Title:	Managing Director

Signature Page to Fifth Amendment

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WHITNEY BANK
By:	/s/ David E. Sisler
Name:	David E. Sisler
Title:	Senior Vice President

Signature Page to Fifth Amendment

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ASSOCIATED BANK, N.A.
By:	/s/ Brian Caddell
Name:	Brian Caddell
Title:	Senior Vice President

Signature Page to Fifth Amendment

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KEYBANK NATIONAL ASSOCIATION
By:	/s/ John Dravenstott
Name:	John Dravenstott
Title:	Vice President

Signature Page to Fifth Amendment

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THE HUNTINGTON NATIONAL BANK
By:	/s/ Margaret Niekrash
Name:	Margaret Niekrash
Title:	Vice President

Signature Page to Fifth Amendment

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FIFTH THIRD BANK
By:	/s/ Justin B. Crawford
Name:	Justin B. Crawford
Title:	Director

Signature Page to Fifth Amendment

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NATIXIS
By:	/s/ Louis P. Laville, III
Name:	Louis P. Laville, III
Title:	Managing Director
By:	/s/ Stuart Murray
Name:	Stuart Murray
Title:	Managing Director

Signature Page to Fifth Amendment

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TORONTO DOMINION (NEW YORK) LLC
By:	/s/ Masood Fikree
Name:	Masood Fikree
Title:	Authorized Signatory

Signature Page to Fifth Amendment

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MIZUHO BANK, LTD.

By:

Name:

Title:

Signature Page to Fifth Amendment

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CARGILL, INCORPORATED
By:	/s/ Marc D. Rubenstein
Name:	Marc D. Rubenstein
Title:	Credit Manager, Authorized Signatory Cargill, Incorporated

Signature Page to Fifth Amendment

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PNC BANK NATIONAL ASSOCIATION
By:	/s/ Jonathan Luchansky
Name:	Jonathan Luchansky
Title:	Assistant Vice President

Signature Page to Fifth Amendment

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NEXTERA ENERGY POWER MARKETING, LLC
By:	/s/ Lawrence Silverstein
Name:	Lawrence Silverstein
Title:	Managing Director Nextera Energy Power Marketing, LLC

Signature Page to Fifth Amendment

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EX-31.1

Exhibit 31.1

I, Mark E. Ellis, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 4, 2014

/s/ Mark E. Ellis

Mark E. Ellis

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

I, Kolja Rockov, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 4, 2014

/s/ Kolja Rockov

Kolja Rockov

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

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

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Linn Energy, LLC (the “Company”) on Form 10-Q for the quarter ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mark E. Ellis, Chairman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: November 4, 2014	/s/ Mark E. Ellis
	Mark E. Ellis
	Chairman, President and Chief Executive Officer

EX-32.2

Exhibit 32.2

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

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Linn Energy, LLC (the “Company”) on Form 10-Q for the quarter ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kolja Rockov, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: November 4, 2014	/s/ Kolja Rockov
	Kolja Rockov
	Executive Vice President and Chief Financial Officer

XML

Unit-Based Compensation (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	1,457,677
Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	214,875
Share Based Compensation Arrangement Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate fair value of grants issued to employees	$ 56
Vesting period of grants issued to employees	3 years
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	212,524
Aggregate fair value of grants issued to employees	$ 5
Share-based Compensation Award, Tranche One [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	50.00%
Vesting period of grants issued to employees	2 years
Share-based Compensation Award, Tranche Two [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	50.00%
Vesting period of grants issued to employees	3 years

XML

Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 59,161	$ 52,171	$ 27,480	$ 1,243
Accounts receivable – trade, net	522,633	488,202
Accounts receivable – affiliates	0	0
Derivative instruments	337,244	176,130
Assets held for sale	1,865,040	0
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)
Oil and natural gas properties, successful efforts method, net	15,036,848	14,342,275
Other property and equipment	635,410	647,882
Less accumulated depreciation	(148,815)	(110,939)
Other property and equipment, net	486,595	536,943
Derivative instruments	305,274	682,002
Notes receivable – affiliates	0	0
Advance to related party	0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	148,687	127,804
Noncurrent assets, excluding property, total	453,961	809,806
Total noncurrent assets	15,977,404	15,689,024
Total assets	18,926,994	16,504,964
Current liabilities:
Accounts payable and accrued expenses	826,976	849,624
Accounts payable – affiliates	0	0
Advance from related party	0
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
Notes payable – affiliates	0	0
Derivative instruments	80	4,649
Other noncurrent liabilities	527,613	397,497
Total noncurrent liabilities	11,537,839	9,360,804
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)
Total unitholders' capital	4,932,133	5,891,427
Total liabilities and unitholders’ capital	18,926,994	16,504,964
Reportable Legal Entities [Member] | Parent Company [Member]
Current assets:
Cash and cash equivalents	48	52	(3,436)	107
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	3,805,769	4,212,348
Derivative instruments	0	0
Assets held for sale	0
Other current assets	18	330
Total current assets	3,805,835	4,212,730
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	0	0
Oil and natural gas properties, successful efforts method, net	0	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Notes receivable – affiliates	121,500	86,200
Advance to related party	1,285,000
Investments in consolidated subsidiaries	8,654,255	8,433,290
Other noncurrent assets	122,046	108,785
Noncurrent assets, excluding property, total	10,182,801	8,628,275
Total noncurrent assets	10,182,801	8,628,275
Total assets	13,988,636	12,841,005
Current liabilities:
Accounts payable and accrued expenses	3,656	14,529
Accounts payable – affiliates	0	0
Advance from related party	0
Derivative instruments	0	0
Other accrued liabilities	138,877	75,071
Current portion of long-term debt	0	0
Total current liabilities	142,533	89,600
Noncurrent liabilities:
Credit facilities	2,510,000	1,560,000
Term loan	500,000	500,000
Senior notes, net	5,912,739	4,809,055
Notes payable – affiliates	0	0
Derivative instruments	0	0
Other noncurrent liabilities	0	0
Total noncurrent liabilities	8,922,739	6,869,055
Unitholders’ capital:
331,820,379 units and 329,661,161 units issued and outstanding at September 30, 2014, and December 31, 2013, respectively	5,621,068	6,282,747
Accumulated deficit	(697,704)	(400,397)
Total unitholders' capital	4,923,364	5,882,350
Total liabilities and unitholders’ capital	13,988,636	12,841,005
Reportable Legal Entities [Member] | Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	11,858	1,078	30,916	1,136
Accounts receivable – trade, net	343,207	365,347
Accounts receivable – affiliates	16,451	16,950
Derivative instruments	313,954	170,534
Assets held for sale	1,485,270
Other current assets	75,817	68,274
Total current assets	2,246,557	622,183
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	10,738,434	13,074,900
Less accumulated depletion and amortization	(2,880,850)	(3,535,890)
Oil and natural gas properties, successful efforts method, net	7,857,584	9,539,010
Other property and equipment	508,485	564,756
Less accumulated depreciation	(142,511)	(110,706)
Other property and equipment, net	365,974	454,050
Derivative instruments	302,959	679,491
Notes receivable – affiliates	0	0
Advance to related party	1,285,000
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	11,416	10,968
Noncurrent assets, excluding property, total	1,599,375	690,459
Total noncurrent assets	9,822,933	10,683,519
Total assets	12,069,490	11,305,702
Current liabilities:
Accounts payable and accrued expenses	545,494	587,774
Accounts payable – affiliates	3,805,769	4,212,348
Advance from related party	1,285,000
Derivative instruments	1,686	7,783
Other accrued liabilities	171,314	59,311
Current portion of long-term debt	0	0
Total current liabilities	5,809,263	4,867,216
Noncurrent liabilities:
Credit facilities	0	0
Term loan	0	0
Senior notes, net	0	0
Notes payable – affiliates	121,500	86,200
Derivative instruments	80	0
Other noncurrent liabilities	207,082	205,406
Total noncurrent liabilities	328,662	291,606
Unitholders’ capital:
331,820,379 units and 329,661,161 units issued and outstanding at September 30, 2014, and December 31, 2013, respectively	4,833,046	4,833,354
Accumulated deficit	1,098,519	1,313,526
Total unitholders' capital	5,931,565	6,146,880
Total liabilities and unitholders’ capital	12,069,490	11,305,702
Reportable Legal Entities [Member] | Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	6,576	51,041	0	0
Accounts receivable – trade, net	133,775	122,855
Accounts receivable – affiliates	0	0
Derivative instruments	23,290	5,596
Assets held for sale	379,770
Other current assets	45,110	30,833
Total current assets	588,521	210,325
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	4,807,794	4,813,659
Less accumulated depletion and amortization	(208,367)	(10,394)
Oil and natural gas properties, successful efforts method, net	4,599,427	4,803,265
Other property and equipment	102,496	83,126
Less accumulated depreciation	(6,024)	(233)
Other property and equipment, net	96,472	82,893
Derivative instruments	2,315	2,511
Notes receivable – affiliates	0	0
Advance to related party	0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	15,225	8,051
Noncurrent assets, excluding property, total	17,540	10,562
Total noncurrent assets	4,713,439	4,896,720
Total assets	5,301,960	5,107,045
Current liabilities:
Accounts payable and accrued expenses	248,181	247,321
Accounts payable – affiliates	11,228	16,950
Advance from related party	0
Derivative instruments	911	20,393
Other accrued liabilities	17,031	28,993
Current portion of long-term debt	0	211,558
Total current liabilities	277,351	525,215
Noncurrent liabilities:
Credit facilities	1,173,175	1,173,175
Term loan	0	0
Senior notes, net	914,232	916,428
Notes payable – affiliates	0	0
Derivative instruments	0	4,649
Other noncurrent liabilities	200,123	192,091
Total noncurrent liabilities	2,287,530	2,286,343
Unitholders’ capital:
331,820,379 units and 329,661,161 units issued and outstanding at September 30, 2014, and December 31, 2013, respectively	2,483,181	2,315,460
Accumulated deficit	253,898	(19,973)
Total unitholders' capital	2,737,079	2,295,487
Total liabilities and unitholders’ capital	5,301,960	5,107,045
Reportable Legal Entities [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Current assets:
Cash and cash equivalents	40,679	0	0	0
Accounts receivable – trade, net	45,651	0
Accounts receivable – affiliates	0	0
Derivative instruments	0	0
Assets held for sale	0
Other current assets	44,567	0
Total current assets	130,897	0
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	2,590,257	0
Less accumulated depletion and amortization	(10,420)	0
Oil and natural gas properties, successful efforts method, net	2,579,837	0
Other property and equipment	24,429	0
Less accumulated depreciation	(280)	0
Other property and equipment, net	24,149	0
Derivative instruments	0	0
Notes receivable – affiliates	0	0
Advance to related party	0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	0	0
Noncurrent assets, excluding property, total	0	0
Total noncurrent assets	2,603,986	0
Total assets	2,734,883	0
Current liabilities:
Accounts payable and accrued expenses	29,645	0
Accounts payable – affiliates	5,223	0
Advance from related party	1,285,000
Derivative instruments	0	0
Other accrued liabilities	227	0
Current portion of long-term debt	1,300,000	0
Total current liabilities	2,620,095	0
Noncurrent liabilities:
Credit facilities	0	0
Term loan	0	0
Senior notes, net	0	0
Notes payable – affiliates	0	0
Derivative instruments	0	0
Other noncurrent liabilities	120,408	0
Total noncurrent liabilities	120,408	0
Unitholders’ capital:
331,820,379 units and 329,661,161 units issued and outstanding at September 30, 2014, and December 31, 2013, respectively	0	0
Accumulated deficit	(5,620)	0
Total unitholders' capital	(5,620)	0
Total liabilities and unitholders’ capital	2,734,883	0
Consolidation, Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	0	0
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	(3,822,220)	(4,229,298)
Derivative instruments	0	0
Assets held for sale	0
Other current assets	0	0
Total current assets	(3,822,220)	(4,229,298)
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	0	0
Oil and natural gas properties, successful efforts method, net	0	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Notes receivable – affiliates	(121,500)	(86,200)
Advance to related party	(2,570,000)
Investments in consolidated subsidiaries	(8,654,255)	(8,433,290)
Other noncurrent assets	0	0
Noncurrent assets, excluding property, total	(11,345,755)	(8,519,490)
Total noncurrent assets	(11,345,755)	(8,519,490)
Total assets	(15,167,975)	(12,748,788)
Current liabilities:
Accounts payable and accrued expenses	0	0
Accounts payable – affiliates	(3,822,220)	(4,229,298)
Advance from related party	(2,570,000)
Derivative instruments	0	0
Other accrued liabilities	0	0
Current portion of long-term debt	0	0
Total current liabilities	(6,392,220)	(4,229,298)
Noncurrent liabilities:
Credit facilities	0	0
Term loan	0	0
Senior notes, net	0	0
Notes payable – affiliates	(121,500)	(86,200)
Derivative instruments	0	0
Other noncurrent liabilities	0	0
Total noncurrent liabilities	(121,500)	(86,200)
Unitholders’ capital:
331,820,379 units and 329,661,161 units issued and outstanding at September 30, 2014, and December 31, 2013, respectively	(7,307,458)	(7,139,737)
Accumulated deficit	(1,346,797)	(1,293,553)
Total unitholders' capital	(8,654,255)	(8,433,290)
Total liabilities and unitholders’ capital	$ (15,167,975)	$ (12,748,788)

XML

Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Future inflation factor used in the calculation of the asset retirement obligations	2.00%
Credit adjusted risk-free interest rate for the calculation of the asset retirement obligations	5.30%
Asset retirement obligations rollforward
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

XML

Subsidiary Guarantors Condensed Consolidating Statements of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
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
Total revenues	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
Total expenses	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)
Interest expense – affiliates	0	0	0	0
Interest income – affiliates	0	0	0	0
Loss on extinguishment of debt	0	(1,117)	0	(5,304)
Equity in earnings from consolidated subsidiaries	0	0	0	0
Other, net	(1,847)	(2,475)	(6,699)	(6,300)
Total other income and (expenses)	(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
Reportable Legal Entities [Member] | Parent Company [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales	0	0	0	0
Gains (losses) on oil and natural gas derivatives	0	0	0	0
Marketing revenues	0	0	0	0
Other revenues	0	0	0	0
Total revenues	0	0	0	0
Expenses:
Lease operating expenses	0	0	0	0
Transportation expenses	0	0	0	0
Marketing expenses	0	0	0	0
General and administrative expenses	0	0	0	0
Exploration costs	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
Impairment of long-lived assets	0	0	0	0
Taxes, other than income taxes	40	0	40	0
(Gains) losses on sale of assets and other, net	0	0	0	724
Total expenses	40	0	40	724
Other income and (expenses):
Interest expense, net of amounts capitalized	(129,129)	(103,252)	(350,382)	(307,316)
Interest expense – affiliates	0	0	0	0
Interest income – affiliates	2,218	1,588	5,627	4,142
Loss on extinguishment of debt		(1,117)		(5,304)
Equity in earnings from consolidated subsidiaries	124,435	75,133	53,244	408,602
Other, net	(1,584)	(2,412)	(5,756)	(6,188)
Total other income and (expenses)	(4,060)	(30,060)	(297,267)	93,936
Income (loss) before income taxes	(4,100)	(30,060)	(297,307)	93,212
Income tax expense (benefit)	0	0	0	0
Net income (loss)	(4,100)	(30,060)	(297,307)	93,212
Reportable Legal Entities [Member] | Guarantor Subsidiaries [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales	542,535	537,671	1,755,766	1,488,610
Gains (losses) on oil and natural gas derivatives	406,712	(63,931)	(221,472)	154,432
Marketing revenues	26,518	13,484	60,088	40,558
Other revenues	5,874	7,338	19,154	18,847
Total revenues	981,639	494,562	1,613,536	1,702,447
Expenses:
Lease operating expenses	97,613	87,076	293,162	259,381
Transportation expenses	36,531	35,637	111,539	92,118
Marketing expenses	23,871	9,962	47,511	26,696
General and administrative expenses	52,580	45,431	126,901	150,302
Exploration costs	7,850	1,588	10,492	4,632
Depreciation, depletion and amortization	199,360	208,892	595,212	604,962
Impairment of long-lived assets	603,250	(4,240)	603,250	37,962
Taxes, other than income taxes	38,598	36,457	126,334	108,525
(Gains) losses on sale of assets and other, net	(93,257)	827	(92,828)	2,316
Total expenses	966,396	421,630	1,821,573	1,286,894
Other income and (expenses):
Interest expense, net of amounts capitalized	757	(554)	1,384	(696)
Interest expense – affiliates	(2,218)	(1,588)	(5,627)	(4,142)
Interest income – affiliates	0	0	0	0
Loss on extinguishment of debt		0		0
Equity in earnings from consolidated subsidiaries	0	0	0	0
Other, net	(84)	(63)	(130)	(112)
Total other income and (expenses)	(1,545)	(2,205)	(4,373)	(4,950)
Income (loss) before income taxes	13,698	70,727	(212,410)	410,603
Income tax expense (benefit)	(1,192)	(4,406)	2,597	2,001
Net income (loss)	14,890	75,133	(215,007)	408,602
Reportable Legal Entities [Member] | Non-Guarantor Subsidiaries [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales	350,863	0	1,044,359	0
Gains (losses) on oil and natural gas derivatives	44,990	0	22,893	0
Marketing revenues	13,318	0	40,567	0
Other revenues	245	0	238	0
Total revenues	409,416	0	1,108,057	0
Expenses:
Lease operating expenses	83,684	0	267,069	0
Transportation expenses	13,326	0	28,802	0
Marketing expenses	7,703	0	28,409	0
General and administrative expenses	16,566	0	88,379	0
Exploration costs	0	0	0	0
Depreciation, depletion and amortization	79,725	0	226,109	0
Impairment of long-lived assets	0	0	0	0
Taxes, other than income taxes	24,830	0	71,338	0
(Gains) losses on sale of assets and other, net	49,011	0	56,635	0
Total expenses	274,845	0	766,741	0
Other income and (expenses):
Interest expense, net of amounts capitalized	(19,068)	0	(66,555)	0
Interest expense – affiliates	0	0	0	0
Interest income – affiliates	0	0	0	0
Loss on extinguishment of debt		0		0
Equity in earnings from consolidated subsidiaries	0	0	0	0
Other, net	(179)	0	(813)	0
Total other income and (expenses)	(19,247)	0	(67,368)	0
Income (loss) before income taxes	115,324	0	273,948	0
Income tax expense (benefit)	159	0	77	0
Net income (loss)	115,165	0	273,871	0
Reportable Legal Entities [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales	44,060	0	44,060	0
Gains (losses) on oil and natural gas derivatives	0	0	0	0
Marketing revenues	0	0	0	0
Other revenues	0	0	0	0
Total revenues	44,060	0	44,060	0
Expenses:
Lease operating expenses	10,333	0	10,333	0
Transportation expenses	3,555	0	3,555	0
Marketing expenses	0	0	0	0
General and administrative expenses	6,238	0	6,238	0
Exploration costs	0	0	0	0
Depreciation, depletion and amortization	11,202	0	11,202	0
Impairment of long-lived assets	0	0	0	0
Taxes, other than income taxes	3,302	0	3,302	0
(Gains) losses on sale of assets and other, net	8,443	0	8,443	0
Total expenses	43,073	0	43,073	0
Other income and (expenses):
Interest expense, net of amounts capitalized	(6,607)	0	(6,607)	0
Interest expense – affiliates	0	0	0	0
Interest income – affiliates	0	0	0	0
Loss on extinguishment of debt		0		0
Equity in earnings from consolidated subsidiaries	0	0	0	0
Other, net	0	0	0	0
Total other income and (expenses)	(6,607)	0	(6,607)	0
Income (loss) before income taxes	(5,620)	0	(5,620)	0
Income tax expense (benefit)	0	0	0	0
Net income (loss)	(5,620)	0	(5,620)	0
Consolidation, Eliminations [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales	0	0	0	0
Gains (losses) on oil and natural gas derivatives	0	0	0	0
Marketing revenues	0	0	0	0
Other revenues	0	0	0	0
Total revenues	0	0	0	0
Expenses:
Lease operating expenses	0	0	0	0
Transportation expenses	0	0	0	0
Marketing expenses	0	0	0	0
General and administrative expenses	0	0	0	0
Exploration costs	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
Impairment of long-lived assets	0	0	0	0
Taxes, other than income taxes	0	0	0	0
(Gains) losses on sale of assets and other, net	0	0	0	0
Total expenses	0	0	0	0
Other income and (expenses):
Interest expense, net of amounts capitalized	0	0	0	0
Interest expense – affiliates	2,218	1,588	5,627	4,142
Interest income – affiliates	(2,218)	(1,588)	(5,627)	(4,142)
Loss on extinguishment of debt		0		0
Equity in earnings from consolidated subsidiaries	(124,435)	(75,133)	(53,244)	(408,602)
Other, net	0	0	0	0
Total other income and (expenses)	(124,435)	(75,133)	(53,244)	(408,602)
Income (loss) before income taxes	(124,435)	(75,133)	(53,244)	(408,602)
Income tax expense (benefit)	0	0	0	0
Net income (loss)	$ (124,435)	$ (75,133)	$ (53,244)	$ (408,602)

XML

Derivatives (Gains (Losses) On Derivatives) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014 MBbls MMMBTU	Sep. 30, 2013 MBbls MMMBTU	Sep. 30, 2014 MBbls MMMBTU	Sep. 30, 2013 MMMBTU MBbls
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Volume Of Natural Gas Production On Settled Derivatives	44,621	43,729	132,408	129,760
Gains (losses) on oil and natural gas derivatives	$ 451,702	$ (63,931)	$ (198,579)	$ 154,432
Cash settlements	$ 10,000	$ 45,000	$ (12,507)	$ 190,368
Average Contract Price On Natural Gas Settled Derivatives Per Unit	5.14	5.29
Volume Of Oil On Settled Derivatives	6,299	3,775	18,690	11,201
Average Contract Price On Oil Settled Derivatives Per Unit	92.39	95.57

XML

Subsidiary Guarantors (Tables)

9 Months Ended

Sep. 30, 2014

Condensed Financial Information [Abstract]

Condensed Consolidating Balance Sheets

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

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

Condensed Consolidating Statements of Operations

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	)

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

Condensed Consolidating Statements of Cash Flows

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

	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

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

	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

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Subsidiary Guarantors Details (Details)	9 Months Ended
	Sep. 30, 2014
Condensed Financial Information [Abstract]
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions	100.00%

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Oil and Natural Gas Properties (Tables)

9 Months Ended

Sep. 30, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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

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

	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

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Earnings Per Unit (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]
Net income (loss)	$ (4,100)	$ (30,060)	$ (297,307)	$ 93,212
Allocated to participating securities	(2,097)	(1,266)	(6,289)	(3,796)
Net income (loss) available to common unitholders, basic	$ (6,197)	$ (31,326)	$ (303,596)	$ 89,416
Earnings per share reconciliation
Basic loss per unit (in usd per unit)	$ (0.02)	$ (0.13)	$ (0.92)	$ 0.38
Diluted loss per unit (in usd per unit)	$ (0.02)	$ (0.13)	$ (0.92)	$ 0.38
Weighted average units outstanding
Basic weighted average units outstanding	329,168,000	233,552,000	328,783,000	233,393,000
Dilutive effect of unit equivalents	0	0	0	372,000
Diluted weighted average units outstanding	329,168,000	233,552,000	328,783,000	233,765,000
Unit options and warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)	6,000,000	4,000,000	6,000,000	3,000,000

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Debt Schedule of Long Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Credit facilities	$ 3,683,175		$ 2,733,175
Term loans	1,800,000		500,000
Senior Notes	6,826,971		5,937,041
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
Senior Notes [Member]
Debt Instrument [Line Items]
Net unamortized discounts and premiums	(22,162)		(18,216)
Linn Energy, LLC [Member] | Line of Credit
Debt Instrument [Line Items]
Credit facilities	2,510,000	[1]	1,560,000	[1]
Linn Energy, LLC [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Term loans	500,000	[2]	500,000	[2]
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Senior Notes	1,200,000	[3]	750,000	[3]
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Senior Notes	1,800,000		1,800,000
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior Notes	1,300,000		1,300,000
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due September 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	650,000	[3]	0	[3]
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due February 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	1,000,000		1,000,000
Variable Interest Entity, Primary Beneficiary [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Term loans	1,300,000	[4]	0	[4]
Berry [Member] | Line of Credit
Debt Instrument [Line Items]
Credit facilities	1,173,175	[2]	1,173,175	[2]
Berry [Member] | Senior Notes [Member] | Senior Notes Due 2014 [Member]
Debt Instrument [Line Items]
Senior Notes	0		205,257
Berry [Member] | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior Notes	299,970		300,000
Berry [Member] | Senior Notes [Member] | Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 599,163		$ 600,000

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

[4] Variable interest rate of 3.15% at September 30, 2014. Incurred on August 29, 2014.

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Unitholders' Capital (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended		1 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Oct. 31, 2014 Dividend Declared [Member] Subsequent Event [Member]	Oct. 31, 2014 Dividend Paid [Member] Subsequent Event [Member]
Subsequent Event [Line Items]
Per unit cash dividend declared (in usd per unit)	$ 0.725	$ 0.725	$ 2.175	$ 2.175	$ 0.725
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit					$ 0.2416
Distributions to unitholders			$ 721,235	$ 511,686		$ 80,000

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Cash Flows) (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Supplemental Cash Flow Information [Abstract]
Cash payments for interest, net of amounts capitalized	$ 345,687,000	$ 240,261,000
Cash payments for income taxes	0	14,000
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	2,743,611,000	47,901,000
Cash paid	(2,577,180,000)	(28,524,000)
Gain (Loss) on Disposition of Oil and Gas Property	48,333,000	0
Receivables from sellers	42,621,000	3,654,000
Payables to sellers	0	(6,854,000)
Liabilities assumed	160,719,000	16,177,000
Joint-venture funding	25,000,000	112,000,000
Net Outstanding Checks	$ 85,000,000

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Fair Value Measurements on a Recurring Basis (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Assets:
Commodity derivatives	$ 783,056		$ 1,048,212
Commodity derivatives	(140,538)	[1]	(190,080)	[1]
Commodity derivatives	642,518		858,132
Liabilities:
Commodity derivatives	143,215		222,905
Commodity derivatives	(140,538)	[1]	(190,080)	[1]
Commodity derivatives	$ 2,677		$ 32,825

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

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Unitholders' Capital

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Unitholders' Capital

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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Debt Debt Fair Value Disclosure (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Credit facilities	$ 3,683,175	$ 2,733,175
Credit Facilities, Fair Value Disclosure	3,683,175	2,733,175
Term loans	1,800,000	500,000
Term Loans, Fair Value Disclosure	1,800,000	500,000
Senior Notes, net	6,826,971	5,937,041
Senior Notes, Fair Value	6,821,718	6,162,402
Total debt, net	12,310,146	9,170,216
Total Debt, Fair Value	$ 12,304,893	$ 9,395,577

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Fair Value Measurements on a Recurring Basis (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements, Recurring Basis

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

	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.

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

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	$	—

	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		$	—		$	—		$	—

	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”).

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

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

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

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Subsidiary Guarantors Condensed Consolidating Statements of Cash Flow (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flow from operating activities:
Net 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	0	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
Equity in earnings from consolidated subsidiaries	0	0
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 accounts receivable – affiliates	0	0
Decrease in other assets	3,284	9,177
Increase in accounts payable and accrued expenses	112,235	29,445
Decrease in accounts payable and accrued expenses – affiliates	0	0
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)
Investment in affiliates	0
Change in notes receivable with affiliate	0	0
Advance to related party	0
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)
Change in notes payable with affiliate	0	0
Advance from related party	0
Capital contributions – affiliates	0
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
Reportable Legal Entities [Member] | Parent Company [Member]
Cash flow from operating activities:
Net loss	(297,307)	93,212
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	0	0
Impairment of long-lived assets	0	0
Unit-based compensation expenses	0	0
Loss on extinguishment of debt		5,304
Amortization and write-off of deferred financing fees	31,564	16,392
(Gains) losses on sale of assets and other, net	0	0
Equity in earnings from consolidated subsidiaries	(53,244)	(408,602)
Deferred income taxes	0	0
Derivatives activities:
Total (gains) losses	0	0
Cash settlements	0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	0	0
Decrease in accounts receivable – affiliates	469,499	341,730
Decrease in other assets	312	(330)
Increase in accounts payable and accrued expenses	18	0
Decrease in accounts payable and accrued expenses – affiliates	0	0
Increase in other liabilities	63,806	51,069
Net cash provided by operating activities	214,648	98,775
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	0
Development of oil and natural gas properties	0	0
Purchases of other property and equipment	0	0
Investment in affiliates	(167,721)
Change in notes receivable with affiliate	(35,300)	(38,200)
Advance to related party	(1,285,000)
Proceeds from sale of properties and equipment and other	(13,188)	(9,044)
Net cash used in investing activities	(1,501,209)	(47,244)
Cash flow from financing activities:
Proceeds from borrowings	4,000,024	1,260,000
Repayments of debt	(1,950,000)	(789,898)
Distributions to unitholders	(721,235)	(511,686)
Financing fees and other, net	(46,263)	(13,490)
Change in notes payable with affiliate	0	0
Advance from related party	0
Capital contributions – affiliates	0
Excess tax benefit from unit-based compensation	4,031	0
Net cash provided by (used in) financing activities	1,286,557	(55,074)
Net increase in cash and cash equivalents	(4)	(3,543)
Cash and cash equivalents:
Beginning	52	107
Ending	48	(3,436)
Reportable Legal Entities [Member] | Guarantor Subsidiaries [Member]
Cash flow from operating activities:
Net loss	(215,007)	408,602
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	595,212	604,962
Impairment of long-lived assets	603,250	37,962
Unit-based compensation expenses	43,692	29,261
Loss on extinguishment of debt		0
Amortization and write-off of deferred financing fees	0	0
(Gains) losses on sale of assets and other, net	(81,492)	18,744
Equity in earnings from consolidated subsidiaries	0	0
Deferred income taxes	2,542	731
Derivatives activities:
Total (gains) losses	221,472	(154,432)
Cash settlements	5,623	190,368
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(1,343)	22,877
Decrease in accounts receivable – affiliates	16,950	0
Decrease in other assets	(10,723)	9,507
Increase in accounts payable and accrued expenses	107,673	29,445
Decrease in accounts payable and accrued expenses – affiliates	(468,896)	(341,730)
Increase in other liabilities	(18,053)	(14,561)
Net cash provided by operating activities	800,900	841,736
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	(76,627)	(192,871)
Development of oil and natural gas properties	(750,450)	(767,604)
Purchases of other property and equipment	(41,822)	(76,987)
Investment in affiliates	0
Change in notes receivable with affiliate	0	0
Advance to related party	(1,285,000)
Proceeds from sale of properties and equipment and other	5,447	219,341
Net cash used in investing activities	(2,148,452)	(818,121)
Cash flow from financing activities:
Proceeds from borrowings	0	0
Repayments of debt	0	0
Distributions to unitholders	0	0
Financing fees and other, net	38,032	(32,195)
Change in notes payable with affiliate	35,300	38,200
Advance from related party	1,285,000
Capital contributions – affiliates	0
Excess tax benefit from unit-based compensation	0	160
Net cash provided by (used in) financing activities	1,358,332	6,165
Net increase in cash and cash equivalents	10,780	29,780
Cash and cash equivalents:
Beginning	1,078	1,136
Ending	11,858	30,916
Reportable Legal Entities [Member] | Non-Guarantor Subsidiaries [Member]
Cash flow from operating activities:
Net loss	273,871	0
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	226,109	0
Impairment of long-lived assets	0	0
Unit-based compensation expenses	0	0
Loss on extinguishment of debt		0
Amortization and write-off of deferred financing fees	(5,174)	0
(Gains) losses on sale of assets and other, net	48,357	0
Equity in earnings from consolidated subsidiaries	0	0
Deferred income taxes	77	0
Derivatives activities:
Total (gains) losses	(22,893)	0
Cash settlements	(18,130)	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(10,611)	0
Decrease in accounts receivable – affiliates	0	0
Decrease in other assets	4,551	0
Increase in accounts payable and accrued expenses	(10,619)	0
Decrease in accounts payable and accrued expenses – affiliates	(5,722)	0
Increase in other liabilities	(36,626)	0
Net cash provided by operating activities	443,190	0
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	(3,912)	0
Development of oil and natural gas properties	(426,028)	0
Purchases of other property and equipment	(8,316)	0
Investment in affiliates	0
Change in notes receivable with affiliate	0	0
Advance to related party	0
Proceeds from sale of properties and equipment and other	256	0
Net cash used in investing activities	(438,000)	0
Cash flow from financing activities:
Proceeds from borrowings	0	0
Repayments of debt	(206,124)	0
Distributions to unitholders	0	0
Financing fees and other, net	(11,252)	0
Change in notes payable with affiliate	0	0
Advance from related party	0
Capital contributions – affiliates	167,721
Excess tax benefit from unit-based compensation	0	0
Net cash provided by (used in) financing activities	(49,655)	0
Net increase in cash and cash equivalents	(44,465)	0
Cash and cash equivalents:
Beginning	51,041	0
Ending	6,576	0
Reportable Legal Entities [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Cash flow from operating activities:
Net loss	(5,620)	0
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	11,202	0
Impairment of long-lived assets	0	0
Unit-based compensation expenses	0	0
Loss on extinguishment of debt		0
Amortization and write-off of deferred financing fees	2,846	0
(Gains) losses on sale of assets and other, net	0	0
Equity in earnings from consolidated subsidiaries	0	0
Deferred income taxes	0	0
Derivatives activities:
Total (gains) losses	0	0
Cash settlements	0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(44,060)	0
Decrease in accounts receivable – affiliates	0	0
Decrease in other assets	9,144	0
Increase in accounts payable and accrued expenses	15,163	0
Decrease in accounts payable and accrued expenses – affiliates	(11,831)	0
Increase in other liabilities	228	0
Net cash provided by operating activities	(22,928)	0
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	(2,521,393)	0
Development of oil and natural gas properties	0	0
Purchases of other property and equipment	0	0
Investment in affiliates	0
Change in notes receivable with affiliate	0	0
Advance to related party	0
Proceeds from sale of properties and equipment and other	0	0
Net cash used in investing activities	(2,521,393)	0
Cash flow from financing activities:
Proceeds from borrowings	1,300,000	0
Repayments of debt	0	0
Distributions to unitholders	0	0
Financing fees and other, net	0	0
Change in notes payable with affiliate	0	0
Advance from related party	1,285,000
Capital contributions – affiliates	0
Excess tax benefit from unit-based compensation	0	0
Net cash provided by (used in) financing activities	2,585,000	0
Net increase in cash and cash equivalents	40,679	0
Cash and cash equivalents:
Beginning	0	0
Ending	40,679	0
Consolidation, Eliminations [Member]
Cash flow from operating activities:
Net loss	(53,244)	(408,602)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	0	0
Impairment of long-lived assets	0	0
Unit-based compensation expenses	0	0
Loss on extinguishment of debt		0
Amortization and write-off of deferred financing fees	0	0
(Gains) losses on sale of assets and other, net	0	0
Equity in earnings from consolidated subsidiaries	53,244	408,602
Deferred income taxes	0	0
Derivatives activities:
Total (gains) losses	0	0
Cash settlements	0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	0	0
Decrease in accounts receivable – affiliates	(486,449)	(341,730)
Decrease in other assets	0	0
Increase in accounts payable and accrued expenses	0	0
Decrease in accounts payable and accrued expenses – affiliates	486,449	341,730
Increase in other liabilities	0	0
Net cash provided by operating activities	0	0
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	0
Development of oil and natural gas properties	0	0
Purchases of other property and equipment	0	0
Investment in affiliates	167,721
Change in notes receivable with affiliate	35,300	38,200
Advance to related party	2,570,000
Proceeds from sale of properties and equipment and other	0	0
Net cash used in investing activities	2,773,021	38,200
Cash flow from financing activities:
Proceeds from borrowings	0	0
Repayments of debt	0	0
Distributions to unitholders	0	0
Financing fees and other, net	0	0
Change in notes payable with affiliate	(35,300)	(38,200)
Advance from related party	(2,570,000)
Capital contributions – affiliates	(167,721)
Excess tax benefit from unit-based compensation	0	0
Net cash provided by (used in) financing activities	(2,773,021)	(38,200)
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents:
Beginning	0	0
Ending	$ 0	$ 0

XML

Derivatives (Commodity Derivatives) (Details)	Sep. 30, 2014 MMMBTU
2014 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	24,550
Average Price (in usd per energy unit)	5.25
2014 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	20,071	[1]
Average Price (in usd per energy unit)	5.00	[1]
2014 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,242	[2]
Average Price (in usd per energy unit)	92.44	[2]
2014 | Oil Derivative Instruments | Crude Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	184	[2]
Derivative, Floor Price	90.00	[2]
Derivative, Cap Price	102.87	[2]
2014 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	998	[2]
Average Price (in usd per energy unit)	91.30	[2]
2014 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	782	[2]
2014 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	92	[2]
2014 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	20,010	[3]
Hedged Differential (in usd per energy unit)	(0.33)	[3]
2014 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	10,398	[3]
Hedged Differential (in usd per energy unit)	(0.20)	[3]
2014 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	2,392	[3]
Hedged Differential (in usd per energy unit)	0.08	[3]
2014 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	1,325	[3]
Hedged Differential (in usd per energy unit)	(0.10)	[3]
2014 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	1,233	[3]
Hedged Differential (in usd per energy unit)	(0.21)	[3]
2014 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	920
Hedged Differential (in usd per energy unit)	11.60
2014 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	2,289	[3]
Hedged Differential (in usd per energy unit)	0.24	[3]
2015 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	118,041
Average Price (in usd per energy unit)	5.19
2015 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	71,854	[1]
Average Price (in usd per energy unit)	5.00	[1]
2015 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	11,599	[2]
Average Price (in usd per energy unit)	96.23	[2]
2015 | Oil Derivative Instruments | Crude Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
2015 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	3,426	[2]
Average Price (in usd per energy unit)	90.00	[2]
2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	1,095	[2]
2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
2015 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	87,162	[3]
Hedged Differential (in usd per energy unit)	(0.33)	[3]
2015 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	43,292	[3]
Hedged Differential (in usd per energy unit)	(0.20)	[3]
2015 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	9,344	[3]
Hedged Differential (in usd per energy unit)	0.06	[3]
2015 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,891	[3]
Hedged Differential (in usd per energy unit)	(0.10)	[3]
2015 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	5,074	[3]
Hedged Differential (in usd per energy unit)	(0.21)	[3]
2015 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	2,920
Hedged Differential (in usd per energy unit)	11.60
2015 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,251	[3]
Hedged Differential (in usd per energy unit)	0.24	[3]
2016 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	121,841
Average Price (in usd per energy unit)	4.20
2016 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	76,269	[1]
Average Price (in usd per energy unit)	5.00	[1]
2016 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	11,465	[2]
Average Price (in usd per energy unit)	90.56	[2]
2016 | Oil Derivative Instruments | Crude Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
2016 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	3,271	[2]
Average Price (in usd per energy unit)	90.00	[2]
2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
2016 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	59,954	[3]
Hedged Differential (in usd per energy unit)	(0.32)	[3]
2016 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	46,294	[3]
Hedged Differential (in usd per energy unit)	(0.20)	[3]
2016 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,768	[3]
Hedged Differential (in usd per energy unit)	0.05	[3]
2016 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,575	[3]
Hedged Differential (in usd per energy unit)	(0.10)	[3]
2016 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,219	[3]
Hedged Differential (in usd per energy unit)	(0.20)	[3]
2016 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0
Hedged Differential (in usd per energy unit)	0.00
2016 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,446	[3]
Hedged Differential (in usd per energy unit)	0.25	[3]
2017 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	120,122
Average Price (in usd per energy unit)	4.26
2017 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	66,886	[1]
Average Price (in usd per energy unit)	4.88	[1]
2017 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,755	[2]
Average Price (in usd per energy unit)	89.02	[2]
2017 | Oil Derivative Instruments | Crude Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
2017 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	384	[2]
Average Price (in usd per energy unit)	90.00	[2]
2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
2017 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Average Price (in usd per energy unit)	100.00
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384
2017 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	59,138	[3]
Hedged Differential (in usd per energy unit)	(0.33)	[3]
2017 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	38,880	[3]
Hedged Differential (in usd per energy unit)	(0.19)	[3]
2017 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,437	[3]
Hedged Differential (in usd per energy unit)	0.05	[3]
2017 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	3,604	[3]
Hedged Differential (in usd per energy unit)	(0.08)	[3]
2017 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,819	[3]
Hedged Differential (in usd per energy unit)	(0.20)	[3]
2017 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0
Hedged Differential (in usd per energy unit)	0.00
2017 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	6,486	[3]
Hedged Differential (in usd per energy unit)	0.25	[3]
2018 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	36,500
Average Price (in usd per energy unit)	5.00
2018 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[1]
Average Price (in usd per energy unit)	0.00	[1]
2018 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
Average Price (in usd per energy unit)	0.00	[2]
2018 | Oil Derivative Instruments | Crude Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
2018 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
Average Price (in usd per energy unit)	0.00	[2]
2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
2018 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384
2018 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	16,425	[3]
Hedged Differential (in usd per energy unit)	(0.33)	[3]
2018 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	10,804	[3]
Hedged Differential (in usd per energy unit)	(0.19)	[3]
2018 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	2,044	[3]
Hedged Differential (in usd per energy unit)	0.05	[3]
2018 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	986	[3]
Hedged Differential (in usd per energy unit)	(0.08)	[3]
2018 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	1,314	[3]
Hedged Differential (in usd per energy unit)	(0.20)	[3]
2018 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0
Hedged Differential (in usd per energy unit)	0.00
2018 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[3]
Hedged Differential (in usd per energy unit)	0.00	[3]
2019 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Average Price (in usd per energy unit)	90.00
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384
Short [Member] | 2014 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	72.11	[2]
Derivative, Cap Price	109.79	[2]
Short [Member] | 2014 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00	[2]
Derivative, Cap Price	114.05	[2]
Short [Member] | 2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	70.00	[2]
Derivative, Cap Price	101.62	[2]
Short [Member] | 2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
Short [Member] | 2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
Short [Member] | 2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
Short [Member] | 2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
Short [Member] | 2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
Short [Member] | 2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
Short [Member] | 2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Derivative, Cap Price	0.00	[2]
Long [Member] | 2014 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	93.76	[2]
Long [Member] | 2014 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	100.00	[2]
Long [Member] | 2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	90.00	[2]
Long [Member] | 2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Long [Member] | 2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Long [Member] | 2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Long [Member] | 2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Long [Member] | 2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Long [Member] | 2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]
Long [Member] | 2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 2 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00	[2]

[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”).

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations Reconciliation

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

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Earnings Per Unit (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

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

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

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Acquisitions, Divestitures and Joint-Venture Funding

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Acquisitions, Divestitures and Joint-Venture Funding

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.

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.

	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.

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.

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

9 Months Ended

Sep. 30, 2014

Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]

Other Accrued Liabilities

“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 Conslidated Statements of Cash Flow

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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Unit-Based Compensation (Compensation Expenses) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated Share Based Compensation Expense	$ 11,109	$ 9,686	$ 43,692	$ 29,261
Income tax benefit	4,105	3,579	16,144	10,812
General and administrative expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated Share Based Compensation Expense	9,445	8,407	37,164	25,408
Lease operating expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated Share Based Compensation Expense	$ 1,664	$ 1,279	$ 6,528	$ 3,853

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Related Party Transactions (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Related Party Transaction [Line Items]
General and administrative expenses	$ 75,384,000	$ 45,431,000	$ 221,518,000	$ 150,302,000
Distributions to unitholders			721,235,000	511,686,000
LinnCo [Member]
Related Party Transaction [Line Items]
Ownership percentage	39.00%		39.00%
General and administrative expenses	644,000		2,100,000
General and Administrative Expenses and Offering Costs		1,000,000		15,000,000
Related Party Transaction, Expenses from Transactions with Related Party	470,000	403,000	1,400,000	1,000,000
Director [Member]
Related Party Transaction [Line Items]
Related party transaction, amounts of transaction	5,000,000	7,000,000	17,000,000	20,000,000
FY 2014 [Member] | LinnCo [Member]
Related Party Transaction [Line Items]
General and administrative expenses paid on behalf of LinnCo			1,900,000	9,000,000
FY 2013 [Member] | LinnCo [Member]
Related Party Transaction [Line Items]
General and administrative expenses paid on behalf of LinnCo			11,000,000
Business Acquisition, Berry [Member] | LinnCo [Member]
Related Party Transaction [Line Items]
General and Administrative Expenses and Offering Costs		125,000		13,000,000
Dividend Paid [Member] | LinnCo [Member]
Related Party Transaction [Line Items]
Distributions to unitholders	$ 94,000,000	$ 25,000,000	$ 280,000,000	$ 76,000,000

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
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	0
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)
Oil and natural gas properties, successful efforts method, net	15,036,848	14,342,275
Other property and equipment	635,410	647,882
Less accumulated depreciation	(148,815)	(110,939)
Other property and equipment, net	486,595	536,943
Derivative instruments	305,274	682,002
Other noncurrent assets	148,687	127,804
Noncurrent assets, excluding property, total	453,961	809,806
Total noncurrent assets	15,977,404	15,689,024
Total assets	18,926,994	16,504,964
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)
Total unitholders' capital	4,932,133	5,891,427
Total liabilities and unitholders’ capital	$ 18,926,994	$ 16,504,964

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Derivatives (Balance Sheet Presentation) (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 783,000,000
Assets:
Commodity derivatives	783,056,000	1,048,212,000
Liabilities:
Commodity derivatives	$ 143,215,000	$ 222,905,000

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Cash flow from operating activities:
Net income (loss)	$ (4,100)	$ (30,060)	$ (297,307)	$ 93,212
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
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
Unit-based compensation expenses			43,692	29,261
Loss on extinguishment of debt	0	1,117	0	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	(451,702)	63,931	198,579	(154,432)
Cash settlements	10,000	45,000	(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	$ 59,161	$ 27,480

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Acquisitions, Divestitures and Joint-Venture Funding Acquisition Purchase Price Allocation (Details) (Business Acquisition, Various [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
Business Acquisition, Various [Member]
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

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SEC Inquiry

9 Months Ended

Sep. 30, 2014

SEC Inquiry [Abstract]

SEC Inquiry

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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Acquisitions, Divestitures and Joint-Venture Funding Pro Forma Financial Information (Details) (USD $)	3 Months Ended		9 Months Ended				9 Months Ended	0 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2013 Business Acquisition Devon [Member] [Member]	Jun. 27, 2014 Business Acquisition Devon [Member] [Member]	Sep. 30, 2013 Business Acquisition, Berry [Member]	Dec. 17, 2013 Linn Energy, LLC [Member] Business Acquisition, Berry [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Business acquisition interim financing						$ 2,300,000,000
Property, Plant and Equipment, Useful Life					10 years		20 years
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares								93,756,674
Business Acquisition, Pro Forma Information [Abstract]
Total revenues and other	1,509,498,000	902,733,000	3,117,792,000	2,978,108,000
Total operating expenses	1,331,861,000	717,032,000	2,852,327,000	2,150,170,000
Net income	$ 3,000	$ 25,262,000	$ (257,158,000)	$ 334,272,000
Net income per unit:
Basic	$ 0.00	$ 0.08	$ (0.80)	$ 1.01
Diluted	$ 0.00	$ 0.08	$ (0.80)	$ 1.01

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Acquisitions, Divestitures and Joint-Venture Funding (Tables)

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

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

Schedule of Pro Forma Results of Business Combination

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.

	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.

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Basis of Presentation

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

Nature of Business

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical)	Sep. 30, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Unitholders' capital: Units issued	331,820,379	329,661,161
Unitholders' capital: Units outstanding	331,820,379	329,661,161

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Earnings Per Unit

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Unit

Earnings Per Unit

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

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net 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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Document And Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Amendment Flag	false
Entity Registrant Name	Linn Energy, LLC
Entity Central Index Key	0001326428
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		331,903,326
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3

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Income Taxes

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
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
Total revenues	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
Total expenses	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	0	(1,117)	0	(5,304)
Other, net	(1,847)	(2,475)	(6,699)	(6,300)
Total other income and (expenses)	(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 (in usd per unit)	$ (0.02)	$ (0.13)	$ (0.92)	$ 0.38
Diluted (in usd per unit)	$ (0.02)	$ (0.13)	$ (0.92)	$ 0.38
Weighted average units outstanding:
Basic (in units)	329,168	233,552	328,783	233,393
Diluted (in units)	329,168	233,552	328,783	233,765
Distributions declared per unit (in usd per unit)	$ 0.725	$ 0.725	$ 2.175	$ 2.175

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Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Debt

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.

⁽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.

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 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.

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 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.

Payment of Berry June 2014 Senior Notes

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

Senior Notes Covenants

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

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

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Unit-Based Compensation

9 Months Ended

Sep. 30, 2014

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

Unit-Based Compensation

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

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Principles of Consolidation and Reporting

Principles of Consolidation and Reporting

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 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

Use of Estimates

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

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In 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 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.

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

9 Months Ended

Sep. 30, 2014

Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]

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

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

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

	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

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.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the 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

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Derivatives

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

Commodity Derivatives

The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. The Company 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	$	—

	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		$	—		$	—		$	—

	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 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.”

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Fair Value Measurements on a Recurring Basis

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements on a Recurring Basis

Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those 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.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the 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.

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.

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.

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Acquisitions, Divestitures and Joint-Venture Funding Acquisitions, Divestitures and Joint-Venture Funding (Details) (USD $)	3 Months Ended				9 Months Ended				9 Months Ended	0 Months Ended	9 Months Ended		0 Months Ended		0 Months Ended			0 Months Ended		1 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Oct. 01, 2014 Permian Basin Divestiture [Member]	Sep. 30, 2014 XOM I Exchange [Member]	Apr. 03, 2012 Business Acquisition Anadarko [Member]	Sep. 30, 2014 Business Acquisition Anadarko [Member]	Sep. 30, 2014 Business Acquisition, Various [Member]	Dec. 17, 2013 Business Acquisition Devon [Member] [Member]	Jun. 27, 2014 Business Acquisition Devon [Member] [Member]	Dec. 17, 2013 Business Acquisition Pioneer [Member]	Dec. 17, 2013 Linn Energy, LLC [Member] Business Acquisition, Berry [Member]	Dec. 16, 2013 Linn Energy, LLC [Member] Business Acquisition, Berry [Member]	Dec. 17, 2013 LinnCo [Member] Business Acquisition, Berry [Member]	Oct. 02, 2014 Subsequent Event [Member] Granite Wash Divestiture [Member]	Oct. 31, 2014 Subsequent Event [Member] STACK acreage divestiture [Member]
Business Acquisition [Line Items]
Divestiture Contract Price								$ 350,000,000											$ 1,950,000,000
Gain (Loss) on Disposition of Assets									45,000,000
Future Funding Commitment Of Joint Venture Consideration Transferred											25,000,000
Future Funding Of Joint Venture Agreement										400,000,000
Business Combination, Consideration Transferred												9,000,000	2,240,000,000		328,000,000
Assets held for sale	1,865,040,000				1,865,040,000		0
Liabilities held for sale	110,241,000				110,241,000		0
Business acquisition interim financing														2,300,000,000
Business Acquisition, Equity Interest Issued or Issuable, Exchange Ratio																		168.00%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares																93,756,674		93,756,674
Business Acqusition, Preliminary Value																4,600,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents																	451,000,000
Impairment of Long-Lived Assets to be Disposed of		(4,000,000)	15,000,000	57,000,000		38,000,000
Impairment of long-lived assets	603,250,000	(4,240,000)			603,250,000	37,962,000
Proceeds from Sale of Property Held-for-sale		218,000,000																		44,000,000
Costs Associated With Sale of Oil and Gas Property and Equipment		$ 2,000,000							$ 3,000,000

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Balance Sheets) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Restricted cash	$ 6,000,000	$ 6,000,000
Net Outstanding Checks	85,000,000	48,000,000
Accrued Liabilities and Other Liabilities [Abstract]
Accrued compensation	43,952,000	55,257,000
Accrued interest	150,676,000	93,998,000
Asset retirement obligations	12,616,000	6,270,000
Liabilities held for sale	110,241,000	0
Other	9,964,000	7,850,000
Other accrued liabilities	$ 327,449,000	$ 163,375,000

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Subsidiary Guarantors

9 Months Ended

Sep. 30, 2014

Condensed Financial Information [Abstract]

Subsidiary Guarantors

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.

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

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

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	)

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	)

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	)

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

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

	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

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

	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

XML

Unit-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2014

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

Employee Service Share-Based Compensation Expense

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

	Three Months Ended 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

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Commitments and Contingencies (Details) (USD $)	1 Months Ended			9 Months Ended		29 Months Ended
	Apr. 30, 2014	Apr. 30, 2013	Mar. 31, 2011	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014
Loss Contingency, Estimate [Abstract]
Litigation Settlement, Amount				$ 2,400,000
Payments for Legal Settlements				0	0
General Unsecured Claims Amount From Termination Agreement			51,000,000
Distribution Under Termination Agreement	3,000,000	5,000,000				42,000,000
Pending Litigation [Member]
Loss Contingency, Estimate [Abstract]
Loss Contingency, Range of Possible Loss, Minimum				1,000,000		1,000,000
Loss Contingency, Range of Possible Loss, Maximum				$ 4,500,000		$ 4,500,000

XML

Debt (Details) (USD $)	9 Months Ended				3 Months Ended		9 Months Ended						3 Months Ended			3 Months Ended		3 Months Ended								9 Months Ended						3 Months Ended	9 Months Ended						1 Months Ended		9 Months Ended								9 Months Ended				9 Months Ended							3 Months Ended		9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Credit Facility	Dec. 31, 2013 Credit Facility	Mar. 31, 2012 Subordinated Debt [Member] Senior Notes Due November 2019	Sep. 30, 2014 Berry [Member] Line of Credit Credit Facility	Sep. 30, 2014 Berry [Member] Line of Credit Credit Facility Minimum	Sep. 30, 2014 Berry [Member] Line of Credit Credit Facility Maximum	Sep. 30, 2014 Berry [Member] Line of Credit Credit Facility London Interbank Offered Rate (LIBOR) [Member] Minimum	Sep. 30, 2014 Berry [Member] Line of Credit Credit Facility London Interbank Offered Rate (LIBOR) [Member] Maximum	Sep. 30, 2014 Berry [Member] Line of Credit Credit Facility ABR Minimum	Sep. 30, 2014 Berry [Member] Line of Credit Credit Facility ABR Maximum	Sep. 30, 2014 Berry [Member] Subordinated Debt [Member] Senior Notes Due 2014 [Member]	Sep. 30, 2013 Berry [Member] Subordinated Debt [Member] Senior Notes Due 2014 [Member]	Mar. 31, 2014 Berry [Member] Subordinated Debt [Member] Senior Notes Due 2014 [Member]	Sep. 30, 2014 Berry [Member] Subordinated Debt [Member] Senior Notes Due 2020	Dec. 16, 2013 Berry [Member] Subordinated Debt [Member] Senior Notes Due 2020	Sep. 30, 2014 Berry [Member] Subordinated Debt [Member] Senior Notes Due 2022 [Member]	Dec. 16, 2013 Berry [Member] Subordinated Debt [Member] Senior Notes Due 2022 [Member]	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit	Sep. 09, 2014 Linn Energy, LLC [Member] Line of Credit	Aug. 29, 2014 Linn Energy, LLC [Member] Line of Credit	Apr. 30, 2012 Linn Energy, LLC [Member] Line of Credit	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit Credit Facility	Dec. 31, 2013 Linn Energy, LLC [Member] Line of Credit Credit Facility	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit Credit Facility Minimum	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit Credit Facility Maximum	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit Credit Facility London Interbank Offered Rate (LIBOR) [Member] Minimum	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit Credit Facility London Interbank Offered Rate (LIBOR) [Member] Maximum	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit Credit Facility ABR Minimum	Sep. 30, 2014 Linn Energy, LLC [Member] Line of Credit Credit Facility ABR Maximum	Sep. 30, 2014 Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due September 2021 [Member]	Sep. 30, 2014 Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due September 2021 [Member]	Sep. 09, 2014 Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due September 2021 [Member]	Sep. 30, 2014 Linn Energy, LLC [Member] Loans Payable [Member]		Dec. 31, 2013 Linn Energy, LLC [Member] Loans Payable [Member]		Sep. 30, 2014 Linn Energy, LLC [Member] Loans Payable [Member] Credit Facility	Aug. 29, 2014 Linn Energy, LLC [Member] Loans Payable [Member] Credit Facility	Sep. 30, 2014 Linn Energy, LLC [Member] Loans Payable [Member] Credit Facility London Interbank Offered Rate (LIBOR) [Member]	Sep. 30, 2014 Linn Energy, LLC [Member] Loans Payable [Member] Credit Facility London Interbank Offered Rate (LIBOR) [Member] Maximum	Sep. 30, 2014 Linn Energy, LLC [Member] Loans Payable [Member] Credit Facility ABR	Sep. 30, 2014 Linn Energy, LLC [Member] Loans Payable [Member] Credit Facility ABR Maximum	Sep. 30, 2014 Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due May 2019	Sep. 30, 2014 Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due November 2019	Sep. 30, 2014 Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due 2020	Sep. 30, 2014 Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due 2021	Sep. 30, 2014 Variable Interest Entity, Primary Beneficiary [Member] Loans Payable [Member]		Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Loans Payable [Member]		Sep. 30, 2014 Variable Interest Entity, Primary Beneficiary [Member] Loans Payable [Member] London Interbank Offered Rate (LIBOR) [Member]	Sep. 30, 2014 Variable Interest Entity, Primary Beneficiary [Member] Loans Payable [Member] ABR	Aug. 29, 2014 Variable Interest Entity, Primary Beneficiary [Member] Loans Payable [Member] ABR	Sep. 30, 2014 2014 [Member] Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due September 2021 and May 2019 [Member]		Sep. 30, 2014 2014 [Member] Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due May 2019	Sep. 09, 2014 2014 [Member] Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due September 2021 and May 2019 [Member]	Sep. 30, 2014 2014 [Member] Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due May 2019	Sep. 09, 2014 2014 [Member] Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due May 2019	Sep. 30, 2014 After May 15, 2015 [Member] Linn Energy, LLC [Member] Subordinated Debt [Member] Senior Notes Due May 2019	Mar. 31, 2012 Prior to September 15, 2017 [Member] Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due September 2021 [Member]	Sep. 30, 2014 Prior to September 15, 2017 [Member] Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due September 2021 [Member]	Sep. 30, 2014 After September 15, 2017 [Member] Linn Energy, LLC [Member] Senior Notes [Member] Senior Notes Due September 2021 [Member]
Debt Instrument [Line Items]
Percent Reduction of Borrowing Base Under Credit Facility																						25.00%
Reduction of Borrowing Base Under Line of Credit																					$ 25,000,000	$ 250,000,000
Debt Instrument, Interest Rate at Period End (in hundredths)			2.66%	2.67%																				2.15%	1.92%																								3.15%
Line of Credit Facility, redetermined borrowing base						1,400,000,000														4,225,000,000	4,225,000,000	4,250,000,000
Reduction of Maximum Borrowing Capacity Under Line of Credit																					25,000,000	250,000,000
Line of Credit Facility, Maximum Borrowing Capacity						1,200,000,000														3,725,000,000			4,000,000,000
Term loans	1,800,000,000	500,000,000																																	500,000,000	[1]	500,000,000	[1]											1,300,000,000	[2]	0	[2]
Equity in Subsidiaries Pledged to Secure Debt																																																	100.00%
Line of Credit Facility, Remaining Borrowing Capacity						1,000,000														1,200,000,000
Letters of Credit Outstanding, Amount																				5,000,000
The percentage of properties that the company is required to maintain mortgages on (in hundredths)						80.00%																													80.00%				80.00%										80.00%
Line Of Credit Facility Collateral Coverage Ratio																				2.5																			2.5
Debt Instrument, Basis Spread on Variable Rate									1.50%	2.50%	0.50%	1.50%																1.50%	2.50%	0.50%	1.50%								0.00%		5.00%	2.50%	4.00%	1.50%									3.00%	2.00%
Initial Period																																																	180 days
Debt Instrument, Increase in Basis Spread on Variable Rate																																								0.50%															0.50%
Debt Instrument, Additional Increase in Basis Spread on Variable Rate																																																							0.25%
Cash proceeds required to be used to repay loans	100.00%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage							0.375%	0.50%																		0.375%	0.50%
Bridge Loan																																								1,000,000,000
Debt Instrument, Face Amount																300,000,000		599,000,000														650,000,000	650,000,000													1,800,000,000	1,300,000,000	1,000,000,000								1,100,000,000	[3]	450,000,000		450,000,000
Additional interest paid due to late registration																																														15,000,000
Debt instrument, interest rate, stated percentage (in hundredths)															10.25%	6.75%		6.375%														6.50%	6.50%												6.50%	6.25%	8.625%	7.75%
Long-term Debt, Fair Value	12,304,893,000	9,395,577,000															310,000,000		607,000,000
Maximum Percentage Of November 2019 Senior Notes Redeemable On Before 2017																																																															35.00%
Debt Instrument, redemption price																																																														103.25%		106.50%	103.25%
Redemption Price of Senior Notes for Change of Control																																	101.00%												101.00%
Issue Price Of Debt Instruments As Percentage Of Face Amount																																		98.619%																											102.00%
Proceeds from Debt, Net of Issuance Costs																																628,000,000																												450,000,000
Debt Instrument, Unamortized Discount																																		9,000,000
Number Of Days For Effective Registration Statement					400 days
Extinguishment of debt													321,000,000			30,000,000		837,000,000
Debt Instrument, Unamortized Premium																10,000,000		7,000,000																																											9,000,000
Debt Instrument Financing Fees And Expense Incurred Related To Issuing Long Term Debt																																		13,000,000																									22,000,000		9,000,000
Repayments of Long-term Debt														$ 205,000,000

[1] Variable interest rates of 2.66% and 2.67% at September 30, 2014, and December 31, 2013, respectively.

[2] Variable interest rate of 3.15% at September 30, 2014. Incurred on August 29, 2014.

[3] $450 million of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014.

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CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Increase (Decrease) in Unitholders' Capital
December 31, 2013		$ 5,891,427
Issuance of units		11,789
Distributions to unitholders		(721,235)
Unit-based compensation expenses		43,692
Excess tax benefit from unit-based compensation and other		3,767
Net loss	(4,100)	(297,307)
September 30, 2014	4,932,133	4,932,133
Units
Increase (Decrease) in Unitholders' Capital
December 31, 2013 (in units)		329,661
Issuance of units (in units)		2,159
September 30, 2014 (in units)	331,820	331,820
Unitholders' Capital
Increase (Decrease) in Unitholders' Capital
December 31, 2013		6,291,824
Issuance of units		11,789
Distributions to unitholders		(721,235)
Unit-based compensation expenses		43,692
Excess tax benefit from unit-based compensation and other		3,767
Net loss		0
September 30, 2014	5,629,837	5,629,837
Accumulated Deficit
Increase (Decrease) in Unitholders' Capital
December 31, 2013		(400,397)
Issuance of units		0
Distributions to unitholders		0
Unit-based compensation expenses		0
Excess tax benefit from unit-based compensation and other		0
Net loss		(297,307)
September 30, 2014	$ (697,704)	$ (697,704)

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Oil and Natural Gas Properties

9 Months Ended

Sep. 30, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Natural Gas Properties

Oil and Natural Gas Properties

Oil and Natural Gas Capitalized Costs

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

	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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Debt (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Summary of Outstanding 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.

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

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

	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

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Oil and Natural Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Impairment of long-lived assets	$ 603,250	$ (4,240)	$ 603,250	$ 37,962
Proved properties:
Leasehold acquisition	13,045,461		13,045,461		12,277,089
Development	3,047,527		3,047,527		3,660,277
Unproved properties	2,043,497		2,043,497		1,951,193
Oil and natural gas properties (successful efforts method)	18,136,485		18,136,485		17,888,559
Less accumulated depletion and amortization	(3,099,637)		(3,099,637)		(3,546,284)
Oil and natural gas properties, successful efforts method, net	$ 15,036,848		$ 15,036,848		$ 14,342,275

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Related Party Transactions

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions

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 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.