Edgar Filing: LINN ENERGY, LLC

form10qq32008.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the Quarterly Period Ended September 30, 2008

¨	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 is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one).

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

(Do not check if a 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, 2008, there were 115,154,653 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, 2008 and December 31, 2007	1
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2007	2
	Condensed Consolidated Statements of Unitholders’ Capital for the nine months ended September 30, 2008	3
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44
	Part II - Other Information
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Submission of Matters to a Vote of Security Holders	45
Item 5.	Other Information	45
Item 6.	Exhibits	46
	Signature	47

Table of Contents

GLOSSARY OF TERMS

As commonly used in the oil and 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.

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

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 gas to one Bbl of oil, condensate or natural gas liquids.

Mid-Continent I. February 2007 acquisition of oil and gas properties in the Texas Panhandle from Cavallo Energy LP, acting through its general partner, Stallion Energy LLC, for a contract price of $415.0 million.

Mid-Continent II. June 2007 acquisition of oil and gas properties in the Texas Panhandle for a contract price of $90.5 million.

Mid-Continent III. August 2007 acquisition of oil and gas properties in Oklahoma, Kansas and the Texas Panhandle from Dominion Resources, Inc. for a contract price of $2.05 billion.

Mid-Continent IV. January 2008 acquisition of oil and gas properties in Oklahoma from Lamamco Drilling Company for a contract price of $552.2 million.

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 gas to one Bbl of oil, condensate or natural gas liquids.

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.

NYMEX. The New York Mercantile Exchange.

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

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
	2008			2007
	(Unaudited)
	(in thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	47,269		$	1,441
Accounts receivable – trade, net		260,071			149,850
Derivative instruments		61,201			26,100
Other current assets, net		17,491			5,768
Total current assets		386,032			183,159

Noncurrent assets:
Oil and gas properties and equipment (successful efforts method)		3,822,413			3,618,741
Less accumulated depreciation, depletion and amortization		(205,520	)		(127,265	)
		3,616,893			3,491,476

Other property and equipment		21,974			37,407
Less accumulated depreciation		(3,564	)		(5,383	)
		18,410			32,024

Derivative instruments		2,027			—
Goodwill		—			64,419
Other noncurrent assets, net		14,119			36,625
Noncurrent assets held for sale		58,432			—
		74,578			101,044
Total assets	$	4,095,913		$	3,807,703

Liabilities and Unitholders’ Capital
Current liabilities:
Accounts payable and accrued expenses	$	188,911		$	223,636
Derivative instruments		20,707			6,148
Other current liabilities		8,508			12,943
Total current liabilities		218,126			242,727

Noncurrent liabilities:
Credit facility		1,521,393			1,443,000
Senior notes, net		250,086			—
Derivative instruments		122,079			63,813
Other noncurrent liabilities		29,931			31,522
Total noncurrent liabilities		1,923,489			1,538,335

Unitholders’ capital:
115,158,483 units and 113,815,914 units issued and outstanding at September 30, 2008 and December 31, 2007, respectively		2,191,207			2,374,660
Accumulated loss		(236,909	)		(348,019	)
		1,954,298			2,026,641
Total liabilities and unitholders’ capital	$	4,095,913		$	3,807,703

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands, except per unit amounts)
Revenues and other:
Oil, gas and natural gas liquid sales	$	240,634		$	61,318		$	672,092		$	117,380
Gain (loss) on oil and gas derivatives		845,818			(65,440	)		(293,780	)		(143,588	)
Natural gas marketing revenues		4,647			2,995			11,056			7,656
Other revenues		561			924			1,682			2,056
		1,091,660			(203	)		391,050			(16,496	)
Expenses:
Operating expenses		56,970			22,306			139,732			39,915
Natural gas marketing expenses		4,061			2,451			9,738			6,426
General and administrative expenses		18,695			12,657			56,093			34,850
Data license expenses		―			―			2,475			―
Bad debt expenses		1,436			―			1,436			―
Depreciation, depletion and amortization		51,727			16,825			146,210			29,295
		132,889			54,239			355,684			110,486
Other income and (expenses):
Interest expense, net of amounts capitalized		(22,574	)		(10,839	)		(71,199	)		(19,429	)
Loss on interest rate swaps		(9,694	)		(3,151	)		(17,483	)		(2,954	)
Other, net		(3,558	)		(2,422	)		(8,034	)		(2,944	)
		(35,826	)		(16,412	)		(96,716	)		(25,327	)
Income (loss) from continuing operations before income taxes		922,945			(70,854	)		(61,350	)		(152,309	)
Income tax provision		(1,002	)		(977	)		(1,047	)		(5,007	)
Income (loss) from continuing operations		921,943			(71,831	)		(62,397	)		(157,316	)

Discontinued operations:
Gain on sale of assets, net of taxes		162,442			―			161,120			―
Income (loss) from discontinued operations, net of taxes		(1,774	)		(4,391	)		12,387			(3,879	)
Net income (loss) from discontinued operations		160,668			(4,391	)		173,507			(3,879	)

Net income (loss)	$	1,082,611		$	(76,222	)	$	111,110		$	(161,195	)

Net income (loss) per unit – continuing operations:
Units – basic	$	8.06		$	(0.89	)	$	(0.55	)	$	(2.54	)
Units – diluted	$	8.05		$	(0.89	)	$	(0.55	)	$	(2.54	)
Net income (loss) per unit – discontinued operations:
Units – basic	$	1.41		$	(0.05	)	$	1.52		$	(0.06	)
Units – diluted	$	1.41		$	(0.05	)	$	1.52		$	(0.06	)
Net income (loss) per unit:
Units – basic	$	9.47		$	(0.94	)	$	0.97		$	(2.60	)
Units – diluted	$	9.46		$	(0.94	)	$	0.97		$	(2.60	)
Weighted average units outstanding:
Units – basic		114,321			69,207			114,111			58,072
Units – diluted		114,476			69,207			114,111			58,072
Class D – basic		―			11,792			―			3,974
Class D – diluted		―			11,792			―			3,974

Distributions declared per unit	$	0.63		$	0.57		$	1.89		$	1.61

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF UNITHOLDERS’ CAPITAL

(Unaudited)

	Nine Months Ended September 30, 2008
	Units			Unitholders’ Capital			Accumulated Income (Loss)			Treasury Units (at Cost)			Total Unitholders’ Capital
	(in thousands)

Balance as of December 31, 2007		113,816		$	2,374,660		$	(348,019	)	$	―		$	2,026,641
Issuance of units		1,437			23,483			―			―			23,483
Purchase of units		(95	)		―			―			(1,981	)		(1,981	)
Cancellation of units		―			(1,981	)		―			1,981			―
Distributions to unitholders					(217,331	)		―			―			(217,331	)
Unit-based compensation expenses					12,376			―			―			12,376
Net income					―			111,110			―			111,110
Balance as of September 30, 2008		115,158		$	2,191,207		$	(236,909	)	$	―		$	1,954,298

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2008			2007
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	111,110		$	(161,195	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		152,599			49,109
Unit-based compensation and unit warrant expenses		12,376			10,890
Bad debt expenses		1,436			―
Amortization and write-off of deferred financing fees and other		12,271			4,108
Gain on sale of assets		(161,120	)		(867	)
Deferred income tax		―			3,359
Mark-to-market on derivatives:
Total losses		311,263			146,542
Cash settlements		(72,416	)		24,896
Cash settlements on canceled derivatives		(81,358	)		―
Premiums paid for derivatives		(129,520	)		(257,092	)
Changes in assets and liabilities:
Increase in accounts receivable		(99,448	)		(47,163	)
(Increase) decrease in other assets		(3,821	)		10,614
Increase (decrease) in accounts payable and accrued expenses		(14,473	)		24,205
Increase in other liabilities		3,889			4,626
Net cash provided by (used in) operating activities		42,788			(187,968	)
Cash flow from investing activities:
Acquisition of oil and gas properties		(575,622	)		(2,572,614	)
Additions to oil and gas properties		(249,833	)		(54,170	)
Purchases of other property and equipment		(2,783	)		(12,494	)
Proceeds from sales of oil and gas properties and other property and equipment		744,133			2,974
Net cash used in investing activities		(84,105	)		(2,636,304	)
Cash flow from financing activities:
Proceeds from sale and issuance of units		―			2,120,000
Purchase of units		(1,981	)		(7,399	)
Proceeds from issuance of debt		1,422,000			1,140,000
Principal payments on debt		(1,095,116	)		(265,947	)
Distributions to unitholders		(217,331	)		(90,165	)
Financing fees and other, net		(20,427	)		(45,224	)
Net cash provided by financing activities		87,145			2,851,265
Net increase in cash and cash equivalents		45,828			26,993
Cash and cash equivalents:
Beginning		1,441			6,595
Ending	$	47,269		$	33,588

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	Basis of Presentation

Linn Energy, LLC (“Linn Energy” or the “Company”) is an independent oil and gas company focused on the development and acquisition of long life properties which complement its asset profile in producing basins within the United States.

The condensed consolidated financial statements at September 30, 2008, and for the three and nine months ended September 30, 2008 and 2007, are unaudited, but in the opinion of management include all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with United States generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations, and 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, 2007. 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.

Certain amounts in the condensed consolidated financial statements and notes thereto have been reclassified to conform to the 2008 financial statement presentation. Such reclassifications include those related to the presentation of discontinued operations (see Note 2) on the condensed consolidated statements of operations.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation.

Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these condensed consolidated financial statements in conformity with GAAP. Actual results could differ from those estimates.

The Company’s Appalachian Basin and Mid Atlantic Well Service (“Mid Atlantic”) operations have been classified as discontinued operations on the condensed consolidated statement of operations for all periods presented. Unless otherwise indicated, information about the statement of operations that is presented in the notes to condensed consolidated financial statements relates only to Linn Energy’s continuing operations.

(2)	Assets Held for Sale and Discontinued Operations

On July 1, 2008, the Company completed the sale of its interests in oil and gas properties located in the Appalachian Basin to XTO Energy, Inc. (“XTO”) for a contract price of $600.0 million. Net proceeds were $568.1 million and the carrying value of net assets sold was $405.3 million, resulting in a gain on the sale of $162.8 million, which is recorded in “discontinued operations: gain on sale of assets, net of taxes” on the condensed consolidated statements of operations. The gain is subject to normal post-closing adjustments. The Company used the net proceeds from the sale to repay loans outstanding under its term loan agreement and reduce indebtedness under its credit facility (see Note 8).

In addition, in March 2008, the Company exited the drilling and service business in the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic Well Service (“Mid Atlantic”). At September 30, 2008, substantially all of the property and equipment previously held by Mid Atlantic totaling $9.2 million had been sold. During the three and nine months ended September 30, 2008, the Company recorded a loss on the sale of the Mid Atlantic assets of $0.3 million and $1.6 million, respectively, which is recorded in “discontinued operations: gain on sale of assets, net of taxes” on the condensed consolidated statements of operations.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

The following summarizes the Appalachian Basin and Mid Atlantic amounts included in income from discontinued operations on the condensed consolidated statements of operations.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)

Total revenues and other	$	(421	)	$	14,707		$	49,564		$	51,394
Total operating expenses		(1,549	)		(13,980	)		(23,779	)		(39,051	)
Interest expense		196			(5,774	)		(13,398	)		(17,246	)
Income (loss) from discontinued operations		(1,774	)		(5,047	)		12,387			(4,903	)
Income tax benefit		―			656			―			1,024
Income (loss) from discontinued operations, net of taxes	$	(1,774	)	$	(4,391	)	$	12,387		$	(3,879	)

The Company computed interest expense related to discontinued operations in accordance with Emerging Issues Task Force Issue No. 87-24, “Allocation of Interest to Discontinued Operations” based on debt required to be repaid as a result of the disposal transaction.

On August 15, 2008, the Company completed the sale of certain of its assets in the Verden area in Oklahoma to Laredo Petroleum, Inc. (“Laredo”) for a contract price of $185.0 million, subject to closing adjustments. Net proceeds and the carrying value of net assets sold were approximately $167.5 million. The Verden assets were acquired by the Company with its acquisition of oil and gas properties from Dominion Resources, Inc. (“Dominion”) in August 2007. The Company used the net proceeds from the sale to reduce indebtedness (see Note 8).

In addition, on October 9, 2008, the Company entered into an agreement to sell its deep rights in certain central Oklahoma acreage, which includes the Woodford Shale interval, for a contract price of $229.1 million, subject to closing adjustments. The sale includes no producing reserves and Linn Energy will retain the rights to the shallow portion of this acreage. The Company anticipates closing in the fourth quarter of 2008, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. At September 30, 2008, the carrying value of net assets to be sold of approximately $58.1 million is included in “noncurrent assets held for sale” on the condensed consolidated balance sheet. These assets were acquired by the Company with its acquisition of oil and gas properties from Dominion in August 2007. The Company plans to use the net proceeds from the sale to reduce indebtedness (see Note 8).

(3)	Acquisitions

The Company accounts for its acquisitions using the purchase method of accounting as prescribed in SFAS No. 141, “Business Combinations.” On January 31, 2008, the Company completed the acquisition of certain oil and gas properties located primarily in the Mid-Continent region from Lamamco Drilling Company (“Lamamco”) for a contract price of $552.2 million, subject to closing adjustments (“Mid-Continent IV”). The acquisition was financed with a combination of borrowings under the Company’s credit facility and proceeds from a term loan entered into at closing (see Note 8).

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

The following presents the purchase accounting for the Mid-Continent IV acquisition, based on estimates of fair value:

	Mid-Continent IV
	(in thousands)

Cash		$	537,124
Estimated transaction costs			635
			537,759
Fair value of liabilities assumed			4,029
Total purchase price		$	541,788

The following presents the allocation of the purchase price for the Mid-Continent IV acquisition, based on estimates of fair value:

	Mid-Continent IV
	(in thousands)

Current assets		$	1,811
Oil and gas properties			537,868
Other property and equipment			2,109
		$	541,788

The purchase price and purchase price allocation above are based on reserve reports, published market prices and estimates by management. The most significant assumptions are related to the estimated fair values assigned to proved oil and gas properties. To estimate the fair values of these properties, the Company utilized estimates of oil and gas reserves. The Company estimated future prices to apply to the estimated reserve quantities acquired, and estimated future operating and development costs to arrive at estimates of future net revenues. The Company also reviewed comparable purchases and sales of oil and gas properties within the same regions.

The following unaudited pro forma financial information presents a summary of Linn Energy’s consolidated results of continuing operations for the three and nine months ended September 30, 2008 and 2007, assuming the Mid-Continent IV acquisition had been completed as of January 1, 2007, including adjustments to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information also assumes that the following 2007 acquisitions were completed as of January 1, 2007:

February 1, 2007, acquisition of certain oil and gas properties and related assets in the Texas Panhandle for a contract price of $415.0 million (“Mid-Continent I”)

June 12, 2007, acquisition of certain oil and gas properties in the Texas Panhandle for a contract price of $90.5 million (“Mid-Continent II”)

August 31, 2007, acquisition of certain oil and gas properties in the Mid-Continent, in Oklahoma, Kansas and the Texas Panhandle for a contract price of $2.05 billion (“Mid-Continent III”)

The revenues and expenses of the Mid-Continent I, Mid-Continent II and Mid-Continent III assets are included in the consolidated results of the Company as of February 1, 2007, June 12, 2007 and

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

September 1, 2007, respectively. The revenues and expenses of the Mid-Continent IV assets are included in the consolidated results of the Company effective February 1, 2008. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of January 1, 2007. All amounts reflect continuing operations.

	Three Months Ended September 30,			Nine Months Ended September 30,
	2007			2008			2007
	(in thousands, except per unit amounts)

Total revenues and other	$	81,183		$	400,323		$	265,758
Total operating expenses	$	97,376		$	360,321		$	268,299
Loss from continuing operations	$	(51,488	)	$	(61,391	)	$	(96,482	)

Loss from continuing operations per unit:
Units – basic	$	(0.64	)	$	(0.54	)	$	(1.56	)
Units – diluted	$	(0.64	)	$	(0.54	)	$	(1.56	)

Class D – basic	$	(0.64	)	$	―		$	(1.56	)
Class D – diluted	$	(0.64	)	$	―		$	(1.56	)

(4)

Goodwill

The entire goodwill balance of $64.4 million at December 31, 2007 related to the Mid-Continent III acquisition in August 2007 (see Note 3).

The following reflects the changes in the carrying amount of goodwill during the nine months ended September 30, 2008 and the year ended December 31, 2007 (in thousands):

Balance, December 31, 2006	$	—
Mid-Continent III acquisition		64,419
Balance, December 31, 2007		64,419
Purchase accounting adjustments:
Post closing statement and other		7,935
Verden assets (1)		(19,200	)
Woodford Shale assets (1)		(53,154	)
Balance, September 30, 2008	$	—

(1)

Represents update to preliminary purchase accounting in which amounts were allocated to unproved oil and gas properties and subsequently sold or held for sale as of September 30, 2008 (see Note 2).

(5)	Unitholders’ Capital

Issuance of Units

During the nine months ended September 30, 2008, the Company issued 410,000 units in connection with the termination of certain contractual obligations in the Western region (equal to a fair value of approximately $8.7 million).

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

During the nine months ended September 30, 2008, the Company issued 600,000 units in connection with the acquisition of certain gas properties in the Appalachian Basin (equal to a fair value of approximately $14.7 million).

Cancellation of Units

During the nine months ended September 30, 2008, the Company purchased 94,521 restricted units from employees for approximately $2.0 million in conjunction with the vesting of restricted unit awards. The proceeds were used to fund the employees’ minimum payroll taxes on the awards, and the Company canceled the units.

(6)	Oil and Gas Capitalized Costs

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

	September 30,			December 31,
	2008			2007
	(in thousands)
Proved properties:
Leasehold acquisition	$	3,306,728		$	3,095,400
Development		331,914			254,251
Unproved properties		95,833			156,908
Gas compression plant and pipelines		87,938			112,182
		3,822,413			3,618,741
Less accumulated depletion, depreciation and amortization		(205,520	)		(127,265	)
	$	3,616,893		$	3,491,476

(7)	Business and Credit Concentrations

For the three and nine months ended September 30, 2008, the Company’s four largest customers represented approximately 17%, 12%, 11% and 10% and 19%, 11%, 11% and 10%, respectively, of the Company’s sales. For the three and nine months ended September 30, 2007, the Company’s two largest customers represented approximately 27% and 25%, and 31% and 25%, respectively, of the Company’s sales.

At September 30, 2008, three customers’ trade accounts receivable from oil, gas and natural gas liquids (“NGL”) sales accounted for more than 10% of the Company’s total trade accounts receivable. As of September 30, 2008, trade accounts receivable from the Company’s three largest customers represented approximately 19%, 14% and 10% of the Company’s receivables. At December 31, 2007, three customers’ trade accounts receivable from oil, gas and NGL sales accounted for more than 10% of the Company’s total trade accounts receivable. As of December 31, 2007, trade accounts receivable from the Company’s three largest customers represented approximately 22%, 13% and 12% of the Company’s receivables.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

(8) Debt

At September 30, 2008 and December 31, 2007, the Company had the following debt outstanding:

	September 30,		December 31,
	2008		2007
	(in thousands)

Credit facility (1)	$	1,521,393	$	1,443,000
Senior notes, net (2)		250,086		—
Less current maturities		—		—
	$	1,771,479	$	1,443,000

(1)

Variable rate of 4.39% at September 30, 2008 and 7.02% at December 31, 2007.

(2)

Fixed rate of 9.875%; net of unamortized discount of approximately $5.8 million at September 30, 2008.

Credit Facility

At September 30, 2008, the Company had a $1.85 billion borrowing base under its Third Amended and Restated Credit Agreement (“Credit Facility”) with a maturity of August 2010. During the third quarter of 2008, the Company repaid $513.6 million in indebtedness under its Credit Facility with net proceeds from the sales of Appalachian Basin and Verden properties (see Note 2).

Certain subsidiaries of Lehman Brothers Holdings Inc. (“Lehman Holdings”), including Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”), were lenders in the Company’s Credit Facility. In September 2008 and October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (see Note 11). At September 30, 2008, available borrowing under the Credit Facility was $313.9 million, which includes a $6.5 million reduction in availability for outstanding letters of credit and an $8.2 million reduction for the unfunded portion of Lehman Holdings’ subsidiaries’ approximate 2.5% commitment. In October 2008, the Company replaced Lehman Holdings’ subsidiaries with another lender and Lehman Holdings’ subsidiaries no longer participate in the Company’s Credit Facility. Available borrowing under the Credit Facility was $285.2 million at October 31, 2008 which includes a $6.4 million reduction in availability for outstanding letters of credit and the restoration of the previously unavailable Lehman Holdings’ subsidiaries’ commitment.

Term Loan

On January 31, 2008, in order to fund a portion of the January 2008 acquisition of oil and gas properties in the Mid-Continent (see Note 3), the Company entered into a $400.0 million Second Lien Term Loan Agreement (“Term Loan”) maturing on July 31, 2009. Interest was determined by reference to LIBOR plus an applicable margin of 5.0% for the first twelve months and 7.5% for the remaining period until maturity or a domestic bank rate plus an applicable margin of 3.5% for the first twelve months and 6.0%

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for the remaining period until maturity. On June 30, 2008, the Company repaid $243.6 million in indebtedness under the Term Loan with net proceeds from the Senior Notes (see below). On July 1, 2008, the Company repaid the balance of the term loan of $156.4 million. Deferred financing fees associated with the Term Loan of approximately $1.9 million and $4.6 million were written off during the three and nine months ended September 30, 2008, respectively.

Senior Notes

On June 24, 2008, the Company entered into a purchase agreement with a group of initial purchasers (“Initial Purchasers”) pursuant to which the Company agreed to issue $255.9 million in aggregate principal amount of the Company’s senior notes due 2018 (“Senior Notes”). The Senior Notes were offered and sold to the Initial Purchasers and then resold to qualified institutional buyers each in transactions exempt from the registration requirements under the Securities Act of 1933, as amended (“Securities Act”). The Company used the net proceeds (after deducting the Initial Purchasers’ discounts and offering expense) of approximately $243.6 million to repay loans outstanding under the Company’s Term Loan (see above). In connection with the Senior Notes, the Company incurred financing fees of approximately $7.3 million, which will be amortized over the life of the Senior Notes and recorded in interest expense. The $5.9 million discount on the Senior Notes will be amortized over the life of the Senior Notes and recorded in interest expense.

The Senior Notes were issued under an Indenture dated June 27, 2008 (“Indenture”), mature on July 1, 2018 and bear interest at 9.875%. Interest is payable semi-annually beginning January 1, 2009. The 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 guaranteed the Senior Notes on a senior unsecured basis. The Indenture provides that the Company may redeem: 1) on or prior to July 1, 2011, up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus accrued and unpaid interest, 2) prior to July 1, 2013, all or part of the Senior Notes at a redemption price equal to the principal amount, plus a make whole premium (as defined in the Indenture) and accrued and unpaid interest, and 3) on or after July 1, 2013, all or part of the Senior Notes at redemption prices equal to 104.938% in 2013, 103.292% in 2014, 101.646% in 2015 and 100% in 2016 and thereafter. The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The Senior Notes’ Indenture contains covenants that, among other things, limit the Company’s 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.

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In connection with the issuance and sale of the Senior Notes, the Company entered into a Registration Rights Agreement (“Registration Rights Agreement”) with the Initial Purchasers. Under the Registration Rights Agreement, the Company agreed to use its reasonable best 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 identical to the Senior Notes in exchange for outstanding Senior Notes. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the Senior Notes. The Company will not be obligated to file the registration statements described above if the restrictive legend on the Senior Notes has been removed and the Senior Notes are freely tradable (in each case, other than with respect to persons that are affiliates of the Company) pursuant to Rule 144 under the Securities Act, as of the 366th day after the Senior Notes were issued. If the Company fails to satisfy its obligations under the Registration Rights Agreement, the Company may be required to pay additional interest to holders of the Senior Notes under certain circumstances.

(9)	Derivatives

Commodity Derivatives

The Company sells oil, gas and NGL in the normal course of its business and utilizes derivative instruments to minimize the variability in cash flows due to price movements in oil, gas and NGL. The Company enters into derivative instruments such as swap contracts, collars and put options to economically hedge a portion of its forecasted oil, gas and NGL sales. Oil puts are also used to economically hedge NGL sales. The Company did not designate these contracts as cash flow hedges under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended, (“SFAS 133”); therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 10 for additional disclosures about oil and gas commodity derivatives as required by Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”).

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The following table summarizes open positions as of September 30, 2008 and represents, as of such date, derivatives in place through December 31, 2014, on annual production volumes:

	Year 2008			Year 2009			Year 2010			Year 2011			Year 2012			Year 2013		Year 2014
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMMBtu)		9,936			39,586			39,566			31,901			29,662			―		―
Average Price ($/MMBtu)	$	8.68		$	8.53		$	8.20		$	8.27		$	8.46		$	―	$	―
Puts:
Hedged Volume (MMMBtu)		1,766			6,960			6,960			6,960			―			―		―
Average Price ($/MMBtu)	$	8.07		$	7.50		$	7.50		$	7.50		$	―		$	―	$	―
PEPL Puts: (1)
Hedged Volume (MMMBtu)		964			5,334			10,634			13,259			5,934			―		―
Average Price ($/MMBtu)	$	7.85		$	7.85		$	7.85		$	7.85		$	7.85		$	―	$	―
Total:
Hedged Volume (MMMBtu)		12,666			51,880			57,160			52,120			35,596			―		―
Average Price ($/MMBtu)	$	8.53		$	8.32		$	8.05		$	8.06		$	8.36		$	―	$	―

Oil Positions:
Fixed Price Swaps:
Hedged Volume (MBbls)		688			2,437			2,150			2,073			2,025			2,275		2,200
Average Price ($/Bbl)	$	82.11		$	90.00		$	90.00		$	84.22		$	84.22		$	84.22	$	84.22
Puts: (2)
Hedged Volume (MBbls)		467			1,843			2,250			2,352			500			―		―
Average Price ($/Bbl)	$	73.34		$	120.00		$	110.00		$	69.11		$	77.73		$	―	$	―
Collars:
Hedged Volume (MBbls)		―			250			250			276			348			―		―
Average Floor Price ($/Bbl)	$	―		$	90.00		$	90.00		$	90.00		$	90.00		$	―	$	―
Average Ceiling Price ($/Bbl)	$	―		$	114.25		$	112.00		$	112.25		$	112.35		$	―	$	―
Total:
Hedged Volume (MBbls)		1,155			4,530			4,650			4,701			2,873			2,275		2,200
Average Price ($/Bbl)	$	78.57		$	102.21		$	99.68		$	77.00		$	83.79		$	84.22	$	84.22

Gas Basis Differential Positions:
PEPL Basis Swaps: (3)
Hedged Volume (MMMBtu)		9,036			34,666			29,366			26,741			34,066			―		―
Hedged Differential ($/MMBtu)	$	(0.95	)	$	(0.95	)	$	(0.95	)	$	(0.95	)	$	(0.95	)	$	―	$	―

(1)

Settle on the Panhandle Eastern Pipeline (“PEPL”) spot price of gas to hedge basis differential associated with gas production in the Mid-Continent region.

(2)

The Company utilizes oil puts to hedge revenues associated with its NGL production.

(3)

Represents a swap of the basis between the New York Mercantile Exchange (“NYMEX”) and the PEPL spot price of gas of $(0.95) per MMBtu for the volumes hedged.

Settled derivatives on gas production for the three and nine months ended September 30, 2008 included a volume of 12,906 MMMBtu and 38,064 MMMBtu at an average contract price of $8.53 and $8.47, respectively. Settled derivatives on oil and NGL production for the three and nine months ended September 30, 2008 included a volume of 1,013 MBbls and 3,151 MBbls at an average contract price of $78.07 and $77.56, respectively. The gas derivatives are settled based on the closing NYMEX future price of gas or on the published PEPL spot price of gas on the settlement date, which occurs on the third day

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preceding the production month. The oil transactions are settled based on the average month’s daily NYMEX price of light oil and settlement occurs on the final day of the production month.

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 minimizes the credit risk in derivative instruments by 1) limiting its exposure to any single counterparty, 2) entering into derivative instruments only with counterparties that are also lenders in the Company’s Credit Facility, each of which currently meet the Company’s minimum credit quality standard, and 3) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. See Note 11 for details about canceled commodity contracts with Lehman Commodity Services.

Interest Rate Swaps

The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparties the difference, and conversely, the counterparties are required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not designate the interest rate swap agreements as cash flow hedges under SFAS No. 133; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 10 for additional disclosures about interest rate swaps as required by SFAS 157.

The following presents the settlement terms of the interest rate swaps:

	Year 2008			Year 2009			Year 2010			Year 2011 (1)
	(dollars in thousands)

Notional Amount	$	1,212,000		$	1,212,000		$	1,212,000		$	1,212,000
Fixed Rate		4.20	%		5.06	%		5.06	%		5.06	%

(1)

Represents interest rate swaps that settle in January 2011.

Outstanding Notional Amounts

The following presents the outstanding notional amounts and maximum number of months outstanding of derivative instruments:

	September 30,		December 31,
	2008		2007

Outstanding notional amounts of gas contracts (MMMBtu)		209,422		275,769
Maximum number of months gas contracts outstanding		51		59
Outstanding notional amounts of oil contracts (MBbls)		22,383		16,214
Maximum number of months oil contracts outstanding		75		72
Outstanding notional amount of interest rate swaps (in thousands)	$	1,212,000	$	1,212,000
Maximum number of months interest rate swaps outstanding		27		36

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Balance Sheet Presentation

The Company’s commodity derivatives and interest rate swap 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,		December 31,
	2008		2007
	(in thousands)
Assets:
Commodity derivatives	$	299,128	$	246,124
Interest rate swaps		179		2,548
	$	299,307	$	248,672
Liabilities:
Commodity derivatives	$	341,126	$	260,058
Interest rate swaps		37,739		32,475
	$	378,865	$	292,533

The Company’s counterparties are participants in its Credit Facility (see Note 8) which is secured by the Company’s oil and gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from the counterparties. The maximum amount of loss due to credit risk, based on the gross fair value of financial instruments that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts was approximately $8.4 million at September 30, 2008. In accordance with the Company’s standard practice, its commodity and interest rate swap derivatives are subject to counterparty netting under the agreements governing such derivatives and therefore the risk of such loss is mitigated at September 30, 2008.

Gain (Loss) on Derivatives

Gains and losses on derivatives are reported on the condensed consolidated statements of operations in “gain (loss) on oil and gas derivatives” and “loss on interest rate swaps” and include realized and unrealized gains (losses). Realized gains (losses), excluding canceled commodity derivatives, represent amounts related to the settlement of derivative instruments, and for commodity derivatives, are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are non-cash items. The following presents the Company’s reported gains and losses on derivative instruments:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	(28,270	)	$	10,756		$	(62,289	)	$	24,649
Canceled commodity derivatives		(13,161	)		―			(81,358	)		―
Interest rate swaps		(5,817	)		647			(11,479	)		729
	$	(47,248	)	$	11,403		$	(155,126	)	$	25,378
Unrealized gains (losses):
Commodity derivatives (1)	$	887,249		$	(76,196	)	$	(150,133	)	$	(168,237	)
Interest rate swaps		(3,877	)		(3,798	)		(6,004	)		(3,683	)
	$	883,372		$	(79,994	)	$	(156,137	)	$	(171,920	)
Total gains (losses):
Commodity derivatives	$	845,818		$	(65,440	)	$	(293,780	)	$	(143,588	)
Interest rate swaps		(9,694	)		(3,151	)		(17,483	)		(2,954	)
	$	836,124		$	(68,591	)	$	(311,263	)	$	(146,542	)

(1)

Includes a net unrealized gain of approximately $6.7 million related to canceled derivative contracts with Lehman Commodity Services (see Note 11) for the three and nine months ended September 30, 2008.

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In addition, in September 2008, the Company canceled (before the contract settlement date) all of its commodity derivative contracts with Lehman Commodity Services as counterparty. The Company entered into contracts for substantially the same volumes at identical strike prices with another participant in its Credit Facility for a cost of approximately $67.6 million. As a result, effective September 17, 2008, Lehman Commodity Services was no longer a counterparty to any of the Company’s commodity derivative contracts and the Company’s overall derivative positions are unchanged. See Note 11 for details about the Company’s receivable for the canceled derivative contracts from Lehman Commodity Services.

(10)	Fair Value of Financial Instruments

The Company accounts for its oil and gas commodity derivatives and interest rate swaps at fair value (see Note 9) on a recurring basis. Effective January 1, 2008, the Company adopted SFAS 157 for these financial instruments. SFAS 157 defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and enhances disclosure requirements for fair value measurements. The impact of the adoption of SFAS 157 to the Company’s results of operations was a decrease to net income by approximately $66.6 million, or $0.58 per unit, for the three months ended September 30, 2008, resulting from an assumed credit risk adjustment. The impact of the adoption was an increase to net income by approximately $21.4 million, or $0.19 per unit, for the nine months ended September 30, 2008, resulting from an assumed credit risk adjustment.

The fair value of derivative instruments is determined utilizing pricing models for significantly similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

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Fair Value Hierarchy

In accordance with SFAS 157, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1

Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2

Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives and interest rate swaps).

Level 3

Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

As required by SFAS 157, when the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

The following presents the Company’s fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at September 30, 2008. These items are included in “derivative instruments” on the condensed consolidated balance sheet.

	Fair Value Measurements on a Recurring Basis September 30, 2008
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	299,128	$	(235,900	)	$	63,228
Interest rate swaps	$	179	$	(179	)	$	―

Liabilities:
Commodity derivatives	$	341,126	$	(235,900	)	$	105,226
Interest rate swaps	$	37,739	$	(179	)	$	37,560

(1)

Represents counterparty netting under derivative netting agreements.

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(11)	Commitments and Contingencies

On September 15, 2008, Lehman Holdings filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) with the United States Bankruptcy Court for the Southern District of New York (the “Court”). On October 3, 2008, Lehman Commodity Services also filed a voluntary petition for reorganization under Chapter 11 with the Court. As of September 30, 2008, the Company had a receivable of approximately $67.6 million from Lehman Commodity Services for canceled derivative contracts (see Note 9). The Company is pursuing various legal remedies to protect its interests. Based on market expectations, at September 30, 2008, the Company estimated approximately $6.7 million of the receivable balance to be collectible. The net receivable of approximately $6.7 million is included in “other current assets, net” on the condensed consolidated balance sheet at September 30, 2008. The associated gain of approximately $67.6 million and the estimated loss of approximately $60.9 million is included in “gain (loss) on oil and gas derivatives” on the condensed consolidated statements of operations for the three and nine months ended September 30, 2008, for a net gain of approximately $6.7 million. The Company believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

From time to time the Company is a party to various legal proceedings or is subject to industry rulings that could bring rise to claims 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 business, financial position, results of operations or liquidity.

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(12)	Earnings Per Unit

The following table summarizes the calculation of basic and diluted net income (loss) per unit:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008		2007			2008			2007
	(in thousands, except per unit amounts)

Income (loss) from continuing operations	$	921,943	$	(71,831	)	$	(62,397	)	$	(157,316	)
Net income (loss) from discontinued operations		160,668		(4,391	)		173,507			(3,879	)
Net income (loss)	$	1,082,611	$	(76,222	)	$	111,110		$	(161,195	)

Weighted average units outstanding:
Basic units outstanding		114,321		69,207			114,111			58,072
Dilutive effect of unit equivalents		155		―			―			―
Diluted units outstanding		114,476		69,207			114,111			58,072

Weighted average Class D units outstanding: (1)
Basic Class D units outstanding		―		11,792			―			3,974
Dilutive effect of unit equivalents		―		―			―			―
Diluted Class D units outstanding		―		11,792			―			3,974

Net income (loss) per unit – continuing operations:
Units – basic	$	8.06	$	(0.89	)	$	(0.55	)	$	(2.54	)
Units – diluted	$	8.05	$	(0.89	)	$	(0.55	)	$	(2.54	)
Class D units – basic (1)	$	―	$	(0.89	)	$	―		$	(2.54	)
Class D units – diluted (1)	$	―	$	(0.89	)	$	―		$	(2.54	)

Net income (loss) per unit – discontinued operations:
Units – basic	$	1.41	$	(0.05	)	$	1.52		$	(0.06	)
Units – diluted	$	1.41	$	(0.05	)	$	1.52		$	(0.06	)
Class D units – basic (1)	$	―	$	(0.05	)	$	―		$	(0.06	)
Class D units – diluted (1)	$	―	$	(0.05	)	$	―		$	(0.06	)

Net income (loss) per unit:
Units – basic	$	9.47	$	(0.94	)	$	0.97		$	(2.60	)
Units – diluted	$	9.46	$	(0.94	)	$	0.97		$	(2.60	)
Class D units – basic (1)	$	―	$	(0.94	)	$	―		$	(2.60	)
Class D units – diluted (1)	$	―	$	(0.94	)	$	―		$	(2.60	)

(1)

Class D units were converted to units on a one-for-one basis in November 2007.

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Basic units outstanding excludes the effect of average anti-dilutive common stock equivalents related to unit options and warrants and unvested restricted units of 2.1 million and 2.5 million for the three and nine months ended September 30, 2008, respectively. Basic units outstanding excludes the effect of average anti-dilutive common stock equivalents related to unit options and warrants and unvested restricted units of 2.0 million and 1.9 million for the three and nine months ended September 30, 2007, respectively. In addition, basic units outstanding excludes the effect of average anti-dilutive Class D units for the three and nine months ended September 30, 2007. All equivalent units were anti-dilutive for the nine months ended September 30, 2008 and the three and nine months ended September 30, 2007, as the Company reported a loss from continuing operations.

(13)	Unit-Based Compensation

Employee Grants

During the nine months ended September 30, 2008, the Company granted an aggregate 584,770 restricted units and 691,000 unit options to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $14.3 million. The majority of these restricted units and options vest ratably over three years. In addition, during the nine months ended September 30, 2008, the Company granted 15,784 phantom units to independent members of its Board of Directors with a fair value of approximately $0.4 million. The phantom units vest over one year. For the three and nine months ended September 30, 2008, the Company recorded unit-based compensation expense in continuing operations of approximately $3.9 million and $11.4 million, respectively, as a non-cash charge against income before income taxes and it is included in “operating expenses” or “general and administrative expenses” on the condensed consolidated statements of operations. For the three and nine months ended September 30, 2007, the Company recorded unit-based compensation and unit warrant expense in continuing operations of approximately $3.1 million and $10.6 million, respectively.

(14)	Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of the Company being passed through to the unitholders, with the exception of the state of Texas. As such, no recognition of federal income taxes for the Company or its subsidiaries that are organized as limited liability companies have been provided for in the accompanying financial statements. Limited liability companies are subject to state income taxes in Texas. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.

(15)	Related Party Transactions

Lehman Holdings

During 2007 and through July 3, 2008, on an aggregate basis, a group of certain direct or indirect wholly owned subsidiaries of Lehman Holdings owned over 10% of the Company’s outstanding units. As such, Lehman Holdings was considered a related party under the provisions of SFAS No. 57 “Related Party Disclosures” during that time frame. Lehman Holdings’ subsidiaries provided certain services to the Company, including participation in the Company’s Credit Facility, Term Loan, offering of Senior Notes (see Note 8), sale of Appalachian Basin assets (see Note 2) and sale of commodity derivative instruments (see Note 9), which were all consummated on terms equivalent to those that prevail in arm’s-length transactions. A reference to “Lehman” hereafter in this footnote refers to Lehman Holdings or one or more of its subsidiaries, as applicable. See Note 11 for details about Lehman’s Chapter 11 filings.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

During the nine months ended September 30, 2008 (through July 3), the Company paid Lehman interest on borrowings of approximately $2.2 million and financing fees of approximately $1.8 million. During the three and nine months ended September 30, 2007, the Company paid Lehman interest on borrowings of approximately $0.5 million and $1.2 million, respectively, and financing fees of approximately $0.1 million and $0.1 million, respectively.

During the three and nine months ended September 30, 2007, in conjunction with its private placements of units, the Company paid Lehman underwriting fees of approximately $10.0 million and $13.5 million, respectively. Lehman was a participant in the private placements and the Company received approximately $260.0 million and $378.7 million, respectively, of proceeds from Lehman in relation to these transactions during the three and nine months ended September 30, 2007.

During the nine months ended September 30, 2008 (through July 3), the Company paid distributions on units to Lehman of approximately $18.5 million. During the three and nine months ended September 30, 2007, the Company paid distributions on units to Lehman of approximately $2.4 million and $5.7 million, respectively. During the nine months ended September 30, 2008 (through July 3), the Company paid Lehman approximately $18.8 million, on settled commodity derivative contracts. During the three and nine months ended September 30, 2007, Lehman paid the Company approximately $0.2 million and $1.1 million, respectively, on settled commodity derivative contracts. During the nine months ended September 30, 2008 (through July 3), the Company purchased approximately $1.3 million of deal contingent oil swap contracts from Lehman. In addition, during the three and nine months ended September 30, 2007, the Company paid Lehman approximately $204.1 million for oil and gas swap contracts.

The following sets forth the amounts due to or from Lehman as of December 31, 2007 (in thousands):

Assets:
Current oil and gas derivative assets	$	14,226
Liabilities:
Accrued interest payable	$	162
Other current liabilities	$	1,278
Long-term debt	$	40,404
Noncurrent oil and gas derivative liabilities	$	7,028

Other

Eric P. Linn, brother of the Company’s Chairman and Chief Executive Officer, served as President of one of the Company’s wholly owned subsidiaries. Effective March 31, 2008, Mr. Linn’s employment with the Company terminated and he executed a Severance Agreement and Release. Under the terms of that agreement, Mr. Linn will receive $0.2 million in cash, six months of outplacement services, accelerated vesting of certain unvested restricted units and unvested options, and payment of COBRA coverage until December 31, 2008 or until obtainment of other comparable health care benefits.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

(16)	Supplemental Disclosures to the Consolidated Statements of Cash Flows

	Nine Months Ended September 30,
	2008			2007
	(in thousands)
Supplemental disclosure of cash flow information:
Cash payments for interest	$	78,176		$	29,339
Supplemental disclosure of non-cash investing activities:
In connection with the purchase of oil and gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	584,238		$	2,581,913
Cash paid		(575,622	)		(2,572,614	)
Liabilities assumed, net	$	8,616		$	9,299
Supplemental disclosure of non-cash financing activities:
Units issued in connection with the purchase of oil and gas properties	$	23,455		$	―

For purposes of the statement 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 $1.1 million and $0.5 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at September 30, 2008 and December 31, 2007, respectively, and represents cash the Company has deposited 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 Facility. At December 31, 2007, the Company had approximately $5.2 million of outstanding checks, the balance of which is included in “other current liabilities” on the condensed consolidated balance sheet.

(17)	Recently Issued Accounting Standards

In April 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of the Useful Life of Intangible Assets,” which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company is currently evaluating the impact the provisions of this FSP will have on its results of operations and financial position, but does not expect it will be material.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an Amendment of FASB Statement 133” (“SFAS 161”). SFAS 161 requires expanded disclosure regarding derivatives and hedging activities including disclosure of the fair values of derivative instruments and their gains and losses in tabular form. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early adoption encouraged. The Company adopted SFAS 161 effective January 1, 2008 (see Note 9). The adoption of the requirements of SFAS 161, which solely expanded disclosures, had no effect on the Company’s results of operations or financial position.

In February 2008, the FASB issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

on a recurring basis. On January 1, 2008, the Company adopted the provisions of SFAS 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis (see Note 10). On January 1, 2009, the Company will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include those measured at fair value in goodwill impairment testing, indefinite-lived intangible assets measured at fair value for impairment assessment, nonfinancial long-lived assets measured at fair value for impairment assessment, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. The Company is currently evaluating the impact the provisions of SFAS 157 related to these items will have on its results of operations and financial position.

In October 2008, the FASB issued FASB Staff Position FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP 157-3”), which clarifies the application of SFAS 157 in a market that is not active. FSP 157-3 is effective upon issuance and the Company is currently evaluating the impact that FSP 157-3 will have on its results of operations and financial position, but does not expect it will be material.

(18)	Subsequent Event

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units. The Company may purchase units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time.

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

The following discussion and analysis 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 Annual Report on Form 10-K. A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”

Executive Summary

Linn Energy is an independent oil and gas company focused on the development and acquisition of long life properties which complement its asset profile in producing basins within the United States. From its initial public offering in January 2006 through the date of this report (excluding the Appalachian Basin properties sold in July 2008 discussed below), the Company has completed ten acquisitions of working and royalty interests in oil and gas properties and related gathering and pipeline assets. Total acquired proved reserves were approximately 1.7 Tcfe at an acquisition cost of approximately $2.15 per Mcfe. See Note 3 for details about the Company’s recent acquisitions. The Company finances acquisitions with a combination of proceeds from the issuance of its units, bank borrowings and cash flow from operations.

On July 1, 2008, the Company completed the sale of its interests in oil and gas properties located in the Appalachian Basin to XTO for a contract price of $600.0 million, subject to closing adjustments (see Note 2). The assets include approximately 197 Bcfe of proved reserves at December 31, 2007. Net proceeds were $568.1 million and the carrying value of net assets sold was $405.3 million, resulting in a gain on the sale of $162.8 million, which is recorded in “discontinued operations: gain on sale of assets, net of taxes” on the condensed consolidated statements of operations. The gain is subject to normal post-closing adjustments. The Company used the net proceeds from the sale to repay loans outstanding under its term loan agreement and reduce indebtedness under its Credit Facility (see Note 8). Also, in March 2008, the Company exited the drilling and service business in the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic. During the three and nine months ended September 30, 2008, the Company recorded a loss on the sale of the Mid Atlantic assets of $0.3 million and $1.6 million, respectively, which is also recorded in “discontinued operations: gain on sale of assets, net of taxes” on the condensed consolidated statements of operations.

The results of the Company’s Appalachian Basin and Mid Atlantic operations are classified as discontinued operations for all periods presented. Unless otherwise indicated, results of operations information presented herein relates only to Linn Energy’s continuing operations.

Third quarter 2008 results from continuing operations included the following:

oil, gas and NGL sales of approximately $240.6 million, compared to $61.3 million in the third quarter of 2007;

daily production of 227.4 MMcfe/d, compared to 90.6 MMcfe/d in the third quarter of 2007;

lease operating expenses of $1.90 per Mcfe, compared to $2.03 per Mcfe in the third quarter of 2007;

capital expenditures of $59.2 million, excluding expenditures for acquisitions and discontinued operations;

63 wells drilled; and

average of 9 operated drilling rigs.

Nine months ended September 30, 2008 results from continuing operations included the following:

oil, gas and NGL sales of approximately $672.1 million, compared to $117.4 million in the nine months ended September 30, 2007;

daily production of 215.5 MMcfe/d, compared to 57.7 MMcfe/d in the nine months ended September 30, 2007;

lease operating expenses of $1.56 per Mcfe, compared to $1.92 per Mcfe in the nine months ended September 30, 2007;

capital expenditures of $222.4 million, excluding expenditures for acquisitions and discontinued operations; for 2008, the Company estimates its total capital expenditures from continuing operations will be approximately $300.0 million;

209 wells drilled; and

average of 12 operated drilling rigs.

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

Canceled Commodity Contracts

During the three and nine months ended September 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production resulting in realized losses of $13.2 million and $81.4 million, respectively. The future gas production under the canceled contracts primarily related to properties in the Appalachian Basin and Verden areas (see Note 2). In addition, in September 2008, the Company canceled (before the contract settlement date) all of its commodity derivative contracts with Lehman Commodity Services as counterparty and entered into contracts for substantially the same volumes at identical strike prices with another participant in its Credit Facility for a cost of approximately $67.6 million. As a result, effective September 17, 2008, Lehman Commodity Services was no longer a counterparty to any of the Company’s commodity derivative contracts and the Company’s overall derivative positions are unchanged.

In September and October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed voluntary petitions for reorganization under Chapter 11. As of September 30, 2008, the Company had a receivable of approximately $67.6 million from Lehman Commodity Services for canceled derivative contracts (see Note 9). The Company is pursuing various legal remedies to protect its interests. Based on market expectations, at September 30, 2008, the Company estimated approximately $6.7 million of the receivable balance to be collectible. The net receivable of approximately $6.7 million is included in “other current assets, net” on the condensed consolidated balance sheet at September 30, 2008. The associated gain of approximately $67.6 million and the estimated loss of approximately $60.9 million is included in “gain (loss) on oil and gas derivatives” on the condensed consolidated statements of operations for the three and nine months ended September 30, 2008, for a net gain of approximately $6.7 million. The Company believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

Asset Sales

On August 15, 2008, the Company completed the sale of certain of its assets in the Verden area in Oklahoma to Laredo for a contract price of $185.0 million, subject to closing adjustments. The assets include approximately 50,000 net acres and 45 Bcfe of proved reserves at December 31, 2007. Net proceeds and the carrying value of net assets sold were approximately $167.5 million. The Verden assets were acquired by the Company with its acquisition of oil and gas properties from Dominion in August 2007. The Company used the net proceeds from the sale to reduce indebtedness (see Note 8).

In addition, on October 9, 2008, the Company entered into an agreement to sell its deep rights in certain central Oklahoma acreage, which includes the Woodford Shale interval, for a contract price of $229.1 million, subject to closing adjustments. The sale includes approximately 38,000 net acres and no producing reserves. Linn Energy will retain the rights to the shallow portion of this acreage. The Company anticipates closing in the fourth quarter of 2008, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. At September 30, 2008, the carrying value of net assets to be sold of approximately $58.1 million is included in “noncurrent assets held for sale” on the condensed consolidated balance sheet. These assets were acquired by the Company with its acquisition of oil and gas properties from Dominion in August 2007. The Company plans to use the net proceeds from the sale to reduce indebtedness (see Note 8).

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company's outstanding units. The Company may purchase units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time.

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

Results of Operations – Continuing Operations

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

	Three Months Ended September 30,
	2008			2007			Variance
	(in thousands)
Revenues and other:
Gas sales	$	100,558		$	23,913		$	76,645
Oil sales		95,888			23,499			72,389
NGL sales		44,188			13,906			30,282
Total oil, gas and NGL sales		240,634			61,318			179,316
Gain (loss) on oil and gas derivatives (1)		845,818			(65,440	)		911,258
Natural gas marketing revenues		4,647			2,995			1,652
Other revenues		561			924			(363	)
	$	1,091,660		$	(203	)	$	1,091,863

Expenses:
Operating expenses:
Lease operating and other	$	39,730		$	16,880		$	22,850
Production and ad valorem taxes		17,240			5,426			11,814
Natural gas marketing expenses		4,061			2,451			1,610
General and administrative expenses (2)		18,695			12,657			6,038
Bad debt expenses		1,436			―			1,436
Depreciation, depletion and amortization		51,727			16,825			34,902
	$	132,889		$	54,239		$	78,650

Other income and (expenses)	$	(35,826	)	$	(16,412	)	$	(19,414	)

Notes to table:

(1)	During the three months ended September 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Verden area (see Note 2) resulting in a realized loss of $13.2 million.

(2)	General and administrative expenses for the three months ended September 30, 2008 and 2007 includes approximately $3.9 million and $3.1 million, respectively, of non-cash unit-based compensation and unit warrant expenses.

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

	Three Months Ended September 30,
	2008		2007		Variance
Average daily production – continuing operations:
Gas (MMcf/d)		126.6		51.0		148.2	%
Oil (MBbls/d)		9.5		3.6		163.9	%
NGL (MBbls/d)		7.3		3.0		143.3	%
Total (MMcfe/d)		227.4		90.6		151.0	%

Average daily production – discontinued operations:
Total (MMcfe/d)		1.0		23.4		(95.7	)%

Weighted average prices (hedged): (1)
Gas (Mcf)	$	8.05	$	7.37		9.2	%
Oil (Bbl)	$	85.30	$	70.70		20.7	%
NGL (Bbl)	$	65.56	$	50.75		29.2	%

Weighted average prices (unhedged): (2)
Gas (Mcf)	$	8.63	$	5.10		69.2	%
Oil (Bbl)	$	109.96	$	70.36		56.3	%
NGL (Bbl)	$	65.56	$	50.75		29.2	%

Representative NYMEX oil and gas prices:
Gas (MMBtu)	$	10.25	$	6.16		66.4	%
Oil (Bbl)	$	117.98	$	75.38		56.5	%

Costs per Mcfe of production:
Operating expenses:
Lease operating and other	$	1.90	$	2.03		(6.4	)%
Production and ad valorem taxes	$	0.82	$	0.65		26.2	%
General and administrative expenses (3)	$	0.89	$	1.52		(41.4	)%
Depreciation, depletion and amortization	$	2.47	$	2.02		22.3	%

Notes to table:

(1)	Includes the effect of realized losses of $28.2 million (excluding the $13.2 million loss noted on the previous page) and realized gains of $10.8 million on derivatives for the three months ended September 30, 2008 and 2007, respectively.

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

(3)

General and administrative expenses for the three months ended September 30, 2008 and 2007 includes approximately $3.9 million and $3.1 million, respectively, of non-cash unit-based compensation and unit warrant expenses. Excluding these amounts, general and administrative expenses for the three months ended September 30, 2008 and 2007 were $0.71 per Mcfe and $1.15 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company’s performance.

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

Oil, Gas and NGL Sales

Oil, gas and NGL sales increased by approximately $179.3 million, or 292%, to approximately $240.6 million for the three months ended September 30, 2008, from $61.3 million for the three months ended September 30, 2007.

The increase in gas, oil and NGL revenues was primarily attributable to increased production as a result of acquisitions and, to a lesser extent, drilling. Total production increased to 227.4 MMcfe/d during the three months ended September 30, 2008, from 90.6 MMcfe/d during the three months ended September 30, 2007. The increase in production was due primarily to the Mid-Continent III oil and gas properties acquired in August 2007 (see Note 3). In addition, the Company drilled 63 wells during the three months ended September 30, 2008, compared to 17 wells during the same period of 2007. Volume increases during the three months ended September 30, 2008 increased total gas, oil and NGL revenues by $93.7 million compared to the same period of 2007.

Gas production increased to 126.6 MMcf/d during the three months ended September 30, 2008, from 51.0 MMcf/d during the three months ended September 30, 2007, primarily due to the 2007 and 2008 acquisitions in the Mid-Continent region (see Note 3) and to drilling. The increase in the weighted average price of gas for the period, to $8.63 per Mcf, from $5.10 per Mcf, contributed approximately $41.1 million to the increase in gas revenues.

Oil production increased to 9.5 MBbls/d during the three months ended September 30, 2008, from 3.6 MBbls/d during the three months ended September 30, 2007, due to acquisitions in the Mid-Continent region and the drilling of new wells. Acquisitions and drilling also increased NGL production to 7.3 MBbls/d during the three months ended September 30, 2008, from 3.0 MBbls/d during the comparative period of the prior year. The increase in the weighted average price of oil for the period, to $109.96 per Bbl, from $70.36 per Bbl, contributed approximately $34.5 million to the increase in oil revenues. The increase in the weighted average price of NGL for the period, to $65.56 per Bbl, from $50.75 per Bbl, contributed approximately $10.0 million to the increase in NGL revenues.

Commodity Derivative Activities

The Company determines the fair value of its oil and gas derivatives using pricing models that use a variety of techniques, including quotes and pricing analysis. See Note 9 and Note 10 for additional information and details regarding derivatives in place through December 31, 2014. During the three months ended September 30, 2008, the Company had commodity derivative contracts for approximately 111% of its gas production and 66% of its oil and NGL production, which resulted in realized losses of approximately $28.2 million, or $41.4 million including $13.2 million of realized losses on canceled derivative contracts. During the three months ended September 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Verden area (see Note 2) resulting in a realized loss of approximately $13.2 million. During the three months ended September 30, 2007, the Company recorded realized gains of approximately $10.8 million. Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives. During the third quarter of 2008, expected future oil and gas prices decreased, which resulted in unrealized gains on derivatives of approximately $887.2 million for the three months ended September 30, 2008. The Company reported unrealized losses of approximately $76.2 million for the three months ended September 30, 2007. The three months ended September 30, 2008 also includes a net unrealized gain of approximately $6.7 million related to canceled derivative contracts with Lehman Commodity Services (see Note 11).

Expenses

Lease Operating and Other

Lease operating and other expenses include expenses such as labor, field office, vehicle, supervision, transportation, maintenance, tools and supplies and workover expenses. As noted below, total lease operating expenses increased; however, lease operating expenses per equivalent unit of production (excluding production and ad valorem taxes) decreased to $1.90 per Mcfe for the three months ended September 30, 2008, compared to $2.03 per Mcfe for the three months ended September 30, 2007, due to acquired properties providing cost efficiencies and economies of scale.

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

Lease operating and other expenses increased by approximately $22.8 million, or 135%, to $39.7 million for the three months ended September 30, 2008, from $16.9 million for the three months ended September 30, 2007. Operating expenses increased primarily due to higher production and costs associated with the 2007 and 2008 acquisitions in the Mid-Continent region.

Production and Ad Valorem Taxes

Production and ad valorem taxes were approximately 7% and 9% of total sales for the three months ended September 30, 2008 and 2007, respectively. Production and ad valorem taxes increased by approximately $11.8 million, to $17.2 million for the three months ended September 30, 2008, from $5.4 million for the three months ended September 30, 2007. Production taxes, which are a function of revenues generated from production, increased by approximately $10.6 million compared to the same period of 2007. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $1.2 million compared to the three months ended September 30, 2007.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees and executive officers, related benefits, office leases and professional fees. As noted below, total general and administrative expenses increased; however, expenses per equivalent unit of production decreased to $0.89 per Mcfe for the three months ended September 30, 2008, compared to $1.52 per Mcfe for the three months ended September 30, 2007, due to increases in production, cost efficiencies and economies of scale provided by acquired properties.

General and administrative expenses increased by approximately $6.0 million, or 47%, to $18.7 million for the three months ended September 30, 2008, from $12.7 million for the three months ended September 30, 2007. The increase in general and administrative expenses over the third quarter of 2007 was primarily due to costs incurred to support the Company’s increased size and infrastructure growth. Salaries and benefits expense and employee unit-based compensation expense increased approximately $3.1 million and $0.9 million, respectively, during the three months ended September 30, 2008 compared to the same period of 2007. Information technology costs, such as software, data administration and data conversion costs increased by approximately $0.7 million during the three months ended September 30, 2008 compared to the same period of 2007. In addition, control of well insurance expense increased by approximately $1.9 million during the three months ended September 30, 2008, primarily for properties in the Mid-Continent region acquired in 2007 and 2008 (see Note 3). The increase in general and administrative expenses was partially offset by recovery of expenses under a transition services agreement with XTO (see Note 2).

Bad Debt Expenses

During the three months ended September 30, 2008, the Company recorded bad debt expense of approximately $1.4 million associated with accounts receivable from a customer that filed a petition for reorganization under Chapter 11.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $34.9 million, to $51.7 million for the three months ended September 30, 2008, from $16.8 million for the three months ended September 30, 2007. Higher total production levels, primarily due to the Company’s acquisitions in the Mid-Continent in 2008 and 2007, were the main reason for the increase.

Other Income and (Expenses)

Other income and (expenses) increased by approximately $19.4 million, to expense of $35.8 million for the three months ended September 30, 2008, compared to expense of $16.4 million for the three months ended September 30, 2007, primarily due to an increase in interest expense of approximately $11.7 million related to increased debt levels associated with borrowings to fund acquisitions and drilling. In addition, total losses on interest rate swaps increased approximately $6.5 million over the prior year. The Company’s interest rate swaps were not designated as cash flow hedges under SFAS 133, even though they reduce exposure to changes in interest rates (see Note 9). The changes in fair values of these instruments were recorded as unrealized losses of approximately $3.9 million and $3.8 million for the three months ended September 30, 2008 and 2007, respectively. These amounts are non-cash

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

items. Additionally, the Company wrote-off deferred financing fees associated with its Term Loan (see Note 8), of approximately $1.9 million during the three months ended September 30, 2008, which contributed to the increase in other income and (expenses).

Income Taxes

Income tax expense was approximately $1.0 million for both the three months ended September 30, 2008 and 2007. The Company is a limited liability company treated as a partnership for federal and state income tax purposes. Limited liability companies are subject to state income taxes in Texas. Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Tax expense for the three months ended September 30, 2008 primarily represents Texas margin tax expense. Tax expense for the three months ended September 30, 2007 relates primarily to 2006 expense recovery. The Company’s taxable subsidiaries generated net operating losses for the year ended December 31, 2006, which were subsequently recovered through an intercompany service charge, resulting in tax expense for the three months ended September 30, 2007.

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

Results of Operations – Continuing Operations

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

	Nine Months Ended September 30,
	2008			2007			Variance
	(in thousands)
Revenues and other:
Gas sales	$	304,317		$	41,241		$	263,076
Oil sales		257,940			45,708			212,232
NGL sales		109,835			30,431			79,404
Total oil, gas and NGL sales		672,092			117,380			554,712
Loss on oil and gas derivatives (1)		(293,780	)		(143,588	)		(150,192	)
Natural gas marketing revenues		11,056			7,656			3,400
Other revenues		1,682			2,056			(374	)
	$	391,050		$	(16,496	)	$	407,546

Expenses:
Operating expenses:
Lease operating and other	$	92,350		$	30,184		$	62,166
Production and ad valorem taxes		47,382			9,731			37,651
Natural gas marketing expenses		9,738			6,426			3,312
General and administrative expenses (2)		56,093			34,850			21,243
Data license expenses		2,475			―			2,475
Bad debt expenses		1,436			―			1,436
Depreciation, depletion and amortization		146,210			29,295			116,915
	$	355,684		$	110,486		$	245,198

Other income and (expenses)	$	(96,716	)	$	(25,327	)	$	(71,389	)

Notes to table:

(1)

During the nine months ended September 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Appalachian Basin and Verden areas (see Note 2) resulting in realized losses of $81.4 million.

(2)	General and administrative expenses for the nine months ended September 30, 2008 and 2007 includes approximately $11.3 million and $10.6 million, respectively, of non-cash unit-based compensation and unit warrant expenses.

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

	Nine Months Ended September 30,
	2008		2007		Variance
Average daily production – continuing operations:
Gas (MMcf/d)		126.1		27.1		365.3	%
Oil (MBbls/d)		8.9		2.9		206.9	%
NGL (MBbls/d)		6.0		2.2		172.7	%
Total (MMcfe/d)		215.5		57.7		273.5	%

Average daily production – discontinued operations:
Total (MMcfe/d)		16.5		23.4		(29.5	)%

Weighted average prices (hedged): (1)
Gas (Mcf)	$	8.75	$	8.02		9.1	%
Oil (Bbl)	$	80.85	$	64.72		24.9	%
NGL (Bbl)	$	67.34	$	52.42		28.5	%

Weighted average prices (unhedged): (2)
Gas (Mcf)	$	8.78	$	5.55		58.2	%
Oil (Bbl)	$	106.06	$	58.23		82.1	%
NGL (Bbl)	$	67.34	$	50.38		33.7	%

Representative NYMEX oil and gas prices:
Gas (MMBtu)	$	9.74	$	6.83		42.6	%
Oil (Bbl)	$	113.29	$	66.23		71.1	%

Costs per Mcfe of production:
Operating expenses:
Lease operating and other	$	1.56	$	1.92		(18.8	)%
Production and ad valorem taxes	$	0.80	$	0.62		29.0	%
General and administrative expenses (3)	$	0.95	$	2.21		(57.0	)%
Depreciation, depletion and amortization	$	2.48	$	1.86		33.3	%

Notes to table:

(1)	Includes the effect of realized losses of $62.2 million (excluding the $81.4 million losses noted on the previous page) and realized gains of $24.6 million on derivatives for the nine months ended September 30, 2008 and 2007, respectively.

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

(3)

General and administrative expenses for the nine months ended September 30, 2008 and 2007 includes approximately $11.3 million and $10.6 million, respectively, of non-cash unit-based compensation and unit warrant expenses. Excluding these amounts, general and administrative expenses for the nine months ended September 30, 2008 and 2007 were $0.76 per Mcfe and $1.54 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company’s performance.

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

Oil, Gas and NGL Sales

Oil, gas and NGL sales increased by approximately $554.7 million, or 472%, to approximately $672.1 million for the nine months ended September 30, 2008, from $117.4 million for the nine months ended September 30, 2007.

The increase in gas, oil and NGL revenues was primarily attributable to increased production as a result of acquisitions and, to a lesser extent, drilling. Total production increased to 215.5 MMcfe/d during the nine months ended September 30, 2008, from 57.7 MMcfe/d during the nine months ended September 30, 2007. The increase in production was due primarily to the Mid-Continent III oil and gas properties acquired in August 2007 (see Note 3). In addition, the Company drilled 209 wells during the nine months ended September 30, 2008, compared to 75 wells during the same period of 2007. Volume increases during the nine months ended September 30, 2008 increased total gas, oil and NGL revenues by $299.0 million compared to the same period of 2007.

Gas production increased to 126.1 MMcf/d during the nine months ended September 30, 2008, from 27.1 MMcf/d during the nine months ended September 30, 2007, primarily due to the 2007 and 2008 acquisitions in the Mid-Continent region (see Note 3) and to drilling. The increase in the weighted average price of gas for the period, to $8.78 per Mcf, from $5.55 per Mcf, contributed approximately $111.7 million to the increase in gas revenues.

Oil production increased to 8.9 MBbls/d during the nine months ended September 30, 2008, from 2.9 MBbls/d during the nine months ended September 30, 2007, due to acquisitions in the Mid-Continent region and the drilling of new wells. Acquisitions and drilling also increased NGL production to 6.0 MBbls/d during the nine months ended September 30, 2008, from 2.2 MBbls/d during the comparative period of the prior year. The increase in the weighted average price of oil for the period, to $106.06 per Bbl, from $58.23 per Bbl, contributed approximately $116.3 million to the increase in oil revenues. The increase in the weighted average price of NGL for the period, to $67.34 per Bbl, from $50.38 per Bbl, contributed approximately $27.7 million to the increase in NGL revenues.

Commodity Derivative Activities

The Company determines the fair value of its oil and gas derivatives using pricing models that use a variety of techniques, including quotes and pricing analysis. See Note 9 and Note 10 for additional information and details regarding derivatives in place through December 31, 2014. During the nine months ended September 30, 2008, the Company had commodity derivative contracts for approximately 110% of its gas production and 78% of its oil and NGL production, which resulted in realized losses of approximately $62.2 million, or $143.6 million including $81.4 million of realized losses on canceled derivative contracts. During the nine months ended September 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Appalachian Basin and Verden areas (see Note 2) resulting in realized losses of $81.4 million. During the nine months ended September 30, 2007, the Company recorded realized gains of approximately $24.6 million. Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives. During the first six months of 2008 and the first nine months of 2007, expected future oil and gas prices increased, which resulted in unrealized losses on derivatives of approximately $150.1 million and $168.2 million for the nine months ended September 30, 2008 and 2007, respectively. Market value adjustments, if realized in the future, would be offset by higher actual prices for production. The nine months ended September 30, 2008 also includes a net unrealized gain of approximately $6.7 million related to canceled derivative contracts with Lehman Commodity Services (see Note 11).

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

Expenses

Lease Operating and Other

Lease operating and other expenses include expenses such as labor, field office, vehicle, supervision, transportation, maintenance, tools and supplies and workover expenses. As noted below, total lease operating expenses increased; however, lease operating expenses per equivalent unit of production (excluding production and ad valorem taxes) decreased to $1.56 per Mcfe for the nine months ended September 30, 2008, compared to $1.92 per Mcfe for the nine months ended September 30, 2007, due to acquired properties providing cost efficiencies and economies of scale.

Lease operating and other expenses increased by approximately $62.2 million, or 206%, to $92.4 million for the nine months ended September 30, 2008, from $30.2 million for the nine months ended September 30, 2007. Operating expenses increased primarily due to higher production and costs associated with the 2007 and 2008 acquisitions in the Mid-Continent region, including expenses associated with the addition of approximately 150 field and direct field support employees in the third quarter of 2007.

Production and Ad Valorem Taxes

Production and ad valorem taxes were approximately 7% and 8% of total sales for the nine months ended September 30, 2008 and 2007, respectively. Production and ad valorem taxes increased by approximately $37.7 million, to $47.4 million for the nine months ended September 30, 2008, from $9.7 million for the nine months ended September 30, 2007. Production taxes, which are a function of revenues generated from production, increased by approximately $33.3 million compared to the same period of 2007. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $4.4 million compared to the nine months ended September 30, 2007.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees and executive officers, related benefits, office leases and professional fees. As noted below, total general and administrative expenses increased; however, expenses per equivalent unit of production decreased to $0.95 per Mcfe for the nine months ended September 30, 2008, compared to $2.21 per Mcfe for the nine months ended September 30, 2007, due to increases in production, cost efficiencies and economies of scale provided by acquired properties.

General and administrative expenses increased by approximately $21.2 million, or 61%, to $56.1 million for the nine months ended September 30, 2008, from $34.9 million for the nine months ended September 30, 2007. The increase in general and administrative expenses over the first nine months of 2007 was primarily due to costs incurred to support the Company’s increased size and infrastructure growth, including the addition of a regional operating office in Oklahoma. Salaries and benefits expense and employee unit-based compensation expense increased approximately $15.0 million and $2.2 million, respectively, during the nine months ended September 30, 2008 compared to the same period of 2007. Information technology costs, such as software, data administration and data conversion costs increased by approximately $4.0 million during the nine months ended September 30, 2008 compared to the same period of 2007. In addition, control of well insurance expense increased by approximately $2.6 million during the nine months ended September 30, 2008, primarily for properties in the Mid-Continent region acquired in 2007 and 2008 (see Note 3). The increase in general and administrative expenses was partially offset by lower professional service fees, unit warrant expenses and recovery of expenses under a transition services agreement with XTO (see Note 2).

Data License Expenses

The Company incurred expenses of approximately $2.5 million for data license fees during the nine months ended September 30, 2008. These expenses primarily represent payments for access to 3-D seismic and other data libraries in the Mid-Continent for periods ranging from one to 50 years or more and enable the Company to maximize drilling opportunities in that region.

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

Bad Debt Expenses

During the nine months ended September 30, 2008, the Company recorded bad debt expense of approximately $1.4 million associated with accounts receivable from a customer that filed a petition for reorganization under Chapter 11.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $116.9 million, to $146.2 million for the nine months ended September 30, 2008, from $29.3 million for the nine months ended September 30, 2007. Higher total production levels, primarily due to the Company’s acquisitions in the Mid-Continent in 2008 and 2007, were the main reason for the increase.

Other Income and (Expenses)

Other income and (expenses) increased by approximately $71.4 million, to expense of $96.7 million for the nine months ended September 30, 2008, compared to expense of $25.3 million for the nine months ended September 30, 2007, primarily due to an increase in interest expense of approximately $51.8 million related to higher debt levels associated with borrowings to fund acquisitions and drilling. In addition, total losses on interest rate swaps increased by approximately $14.5 million over the prior year. The Company’s interest rate swaps were not designated as cash flow hedges under SFAS 133, even though they reduce exposure to changes in interest rates (see Note 9). The changes in fair values of these instruments were recorded as unrealized losses of approximately $6.0 million and $3.7 million for the nine months ended September 30, 2008 and 2007, respectively. These amounts are non-cash items. Additionally, the Company wrote-off deferred financing fees associated with its Term Loan (see Note 8), of approximately $4.6 million during the nine months ended September 30, 2008, which contributed to the increase in other income and (expenses).

Income Taxes

Income tax expense was approximately $1.0 million and $5.0 million for the nine months ended September 30, 2008 and 2007, respectively. The Company is a limited liability company treated as a partnership for federal and state income tax purposes. Limited liability companies are subject to state income taxes in Texas. Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Tax expense for the nine months ended September 30, 2008 primarily represents Texas margin tax expense. Tax expense for the nine months ended September 30, 2007 relates primarily to 2006 expense recovery. The Company’s taxable subsidiaries generated net operating losses for the year ended December 31, 2006, which were subsequently recovered through an intercompany service charge, resulting in tax expense for the nine months ended September 30, 2007.

Results of Operations – Discontinued Operations

The following table presents comparative data for the Company’s discontinued operations related to its Appalachian Basin assets. See Note 2 for additional details about discontinued operations.

	Three Months Ended							Nine Months Ended
	September 30,							September 30,
	2008		2007		Variance			2008		2007		Variance
Average daily production:
Gas (MMcf/d)		1.0		22.8		(95.6	)%		15.9		22.8		(30.3	)%
Oil (MBbls/d)		―		0.1		(100.0	)%		0.1		0.1		―
Total (MMcfe/d)		1.0		23.4		(95.7	)%		16.5		23.4		(29.5	)%

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

The sale of properties in the Appalachian Basin (see Note 2) will produce taxable gains or losses to unitholders. The amount of gain or loss will be determined at unitholder level, based on each affected unitholder’s tax basis in the disposed properties and allocated sale proceeds and in accordance with the terms of the Company’s Second Amended and Restated Limited Liability Company Agreement, as amended, and the applicable tax laws, and will be reflected in unitholder K-1s to be provided in the spring of 2009.

Liquidity and Capital Resources

The Company has utilized public and private equity, proceeds from bank borrowings and cash flow from operations for capital resources and liquidity. To date, the primary use of capital has been for the acquisition and development of oil and gas properties. The Company manages its working capital and cash requirements to borrow only as needed. The Company had $285.2 million in available borrowing capacity at October 31, 2008.

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 will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves. The Company actively reviews acquisition opportunities on an ongoing basis. If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts, if available, or obtain additional debt or equity financing. The Company’s Credit Facility and Senior Notes impose certain restrictions on the Company’s ability to obtain additional debt financing. Based upon current expectations, the Company believes liquidity and capital resources will be sufficient for the conduct of its business and operations.

Cash Flows

The following presents a comparative cash flow summary for the periods reported.

	Nine Months Ended September 30,
	2008			2007			Variance
	(in thousands)
Cash flow statement information:
Net cash:
Provided by (used in) operating activities (1) (2)	$	42,788		$	(187,968	)	$	230,756
Used in investing activities		(84,105	)		(2,636,304	)		2,552,199
Provided by financing activities		87,145			2,851,265			(2,764,120	)
Increase in cash and cash equivalents	$	45,828		$	26,993		$	18,835

(1)

The nine months ended September 30, 2008 and 2007 includes premiums paid for derivatives of approximately $129.5 million and $257.1 million, respectively. Premiums paid during the nine months ended September 30, 2008 include $67.6 million for contracts that replaced those with Lehman Commodity Services (see Note 11).

(2)

During the nine months ended September 30, 2008, the Company cancelled (before the contract settlement date) derivative contracts on estimated future gas production resulting in realized losses of $81.4 million. The future gas production under the canceled contracts primarily related to properties in the Appalachian Basin and Verden areas.

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

Operating Activities

At September 30, 2008, the Company had $47.3 million cash and cash equivalents compared to $1.4 million at December 31, 2007. Cash provided by operating activities for the nine months ended September 30, 2008 was approximately $42.8 million, compared to cash used by operating activities of $188.0 million for the nine months ended September 30, 2007. The increase in cash provided by operating activities was primarily due to increased production during the nine months ended September 30, 2008. During the nine months ended September 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Appalachian Basin and Verden areas (see Note 2) resulting in realized losses of approximately $81.4 million. In addition, premiums paid for derivatives were approximately $129.5 million during the nine months ended September 30, 2008, compared to $257.1 million during the nine months ended September 30, 2007. Premiums paid during the nine months ended September 30, 2008 include $67.6 million for contracts that replaced those with Lehman Commodity Services (see Note 11). The premiums paid were for derivative contracts that hedge future production for up to five years. These derivative contracts are expected to provide or stabilize the Company’s future cash flow and were funded through the Company’s Credit Facility. See Note 9 for additional details about commodity derivatives. The amount of derivative contracts the Company enters into in the future will be directly related to expected future production.

Investing Activities

Cash used in investing activities was approximately $84.1 million for the nine months ended September 30, 2008, compared to $2.64 billion for the nine months ended September 30, 2007. The decrease in cash used in investing activities was due to a decrease in acquisition and development activity and an increase in proceeds from asset sales during the nine months ended September 30, 2008, compared to the same period of the prior year.

The total cash used in investing activities for the nine months ended September 30, 2008 includes $510.1 million for the January 2008 acquisition of properties in the Mid-Continent (see Note 3). Other acquisitions, including acquisitions of additional working interests in current wells, were approximately $65.5 million and other property and equipment purchases were $2.8 million. The total for the nine months ended September 30, 2008 also includes approximately $249.8 million for the drilling and development of oil and gas properties. During the nine months ended September 30, 2008, the Company also received proceeds from the sale of oil and gas properties to XTO and Laredo, and other plant and equipment of approximately $744.1 million (see Note 2).

Financing Activities

Cash provided by financing activities was approximately $87.1 million for the nine months ended September 30, 2008, compared to $2.85 billion for the nine months ended September 30, 2007. During the nine months ended September 30, 2008, total proceeds from the issuance of debt were $1.42 billion and total repayments of debt were $1.10 billion. See additional discussion about the Company’s Credit Facility, Term Loan and Senior Notes below. In addition, see detail of distributions paid during the nine months ended September 30, 2008 below.

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

Distributions

Under the limited liability company agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. The following provides a summary of distributions paid by the Company during the nine months ended September 30, 2008:

		Distributions
Date Paid	Period Covered by Distribution	Per Unit		Total
				(in millions)

August 2008	April 1 – June 30, 2008	$	0.63	$	72.6
May 2008	January 1 – March 31, 2008	$	0.63	$	72.6
February 2008	October 1 – December 31, 2007	$	0.63	$	72.2

In October 2008, the Company’s Board of Directors declared a cash distribution of $0.63 per unit, or $2.52 per unit on an annualized basis, with respect to the third quarter of 2008. The distribution totaling approximately $72.6 million will be paid on November 14, 2008 to unitholders of record as of the close of business on November 7, 2008.

Credit Facility

At October 31, 2008, the Company had a $1.85 billion borrowing base under its Credit Facility with a maturity of August 2010 (see Note 8). During the third quarter of 2008, the Company repaid $513.6 million in indebtedness under its Credit Facility with net proceeds from the sales of Appalachian Basin and Verden properties (see Note 2).

The borrowing base under the Credit Facility will be redetermined semi-annually by the lenders in their sole discretion, based on, among other things, reserve reports as prepared by reserve engineers taking into account the oil and gas prices at such time. At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either LIBOR plus an applicable margin between 1.00% and 1.75% per annum or the ABR plus an applicable margin between 0% and 0.25% per annum. As noted above, the Company depends on its Credit Facility for future capital needs. In addition, the Company has drawn on the Credit Facility to fund or partially fund quarterly cash distribution payments, since it uses operating cash flows for investing activities and borrows as cash is needed. Absent such borrowing, the Company would have at times experienced a shortfall in cash available to pay the declared quarterly cash distribution amount. If an event of default occurs and is continuing under the Credit Facility, the Company would be unable to make borrowings to fund distributions.

Certain subsidiaries of Lehman Holdings, including Lehman Commodity Services, were lenders in the Company’s Credit Facility. In September 2008 and October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed voluntary petitions for reorganization under Chapter 11 (see “Contingencies” below). In October 2008, the Company replaced Lehman Holdings’ subsidiaries with other lenders and Lehman Holdings’ subsidiaries no longer participate in the Company’s Credit Facility. Available borrowing under the Credit Facility was $285.2 million at October 31, 2008 which includes a $6.4 million reduction in availability for outstanding letters of credit.

Term Loan

On January 31, 2008, in order to fund a portion of the January 2008 acquisition of oil and gas properties in the Mid-Continent (see Note 3), the Company entered into a $400.0 million Term Loan maturing on July 31, 2009 (see Note 8). On June 30, 2008, the Company repaid $243.6 million in indebtedness under the Term Loan with net proceeds from the Senior Notes (see below). On July 1, 2008, the Company repaid the balance of the term loan of $156.4 million. Deferred financing fees associated with the Term Loan of approximately $1.9 million and $4.6 million were written off during the three and nine months ended September 30, 2008, respectively.

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

Senior Notes

On June 24, 2008, the Company entered into a purchase agreement with a group of Initial Purchasers pursuant to which the Company agreed to issue $255.9 million in aggregate principal amount of the Company’s Senior Notes due 2018 (see Note 8). The Senior Notes were offered and sold to the Initial Purchasers and then resold to qualified institutional buyers each in transactions exempt from the registration requirements under the Securities Act. The Company used the net proceeds (after deducting the Initial Purchasers’ discounts and offering expense) of approximately $243.6 million to repay loans outstanding under the Company’s Term Loan (see above). In connection with the Senior Notes, the Company incurred financing fees of approximately $7.3 million, which will be amortized over the life of the Senior Notes and recorded in interest expense. The $5.9 million discount on the Senior Notes will be amortized over the life of the Senior Notes and recorded in interest expense.

The Senior Notes were issued under an Indenture dated June 27, 2008, mature on July 1, 2018 and bear interest at 9.875%. Interest is payable semi-annually beginning January 1, 2009. The 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 guaranteed the Senior Notes on a senior unsecured basis. The Indenture provides that the Company may redeem: 1) on or prior to July 1, 2011, up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus accrued and unpaid interest, 2) prior to July 1, 2013, all or part of the Senior Notes at a redemption price equal to the principal amount, plus a make whole premium (as defined in the Indenture) and accrued and unpaid interest, and 3) on or after July 1, 2013, all or part of the Senior Notes at redemption prices equal to 104.938% in 2013, 103.292% in 2014, 101.646% in 2015 and 100% in 2016 and thereafter. The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

In connection with the issuance and sale of the Senior Notes, the Company entered into a Registration Rights Agreement with the Initial Purchasers. Under the Registration Rights Agreement, the Company agreed to use its reasonable best 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 identical to the Senior Notes in exchange for outstanding Senior Notes. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the Senior Notes. The Company will not be obligated to file the registration statements described above if the restrictive legend on the Senior Notes has been removed and the Senior Notes are freely tradable (in each case, other than with respect to persons that are affiliates of the Company) pursuant to Rule 144 under the Securities Act, as of the 366th day after the Senior Notes were issued. If the Company fails to satisfy its obligations under the Registration Rights Agreement, the Company may be required to pay additional interest to holders of the Senior Notes under certain circumstances.

Fair Value of Financial Instruments

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

approximately $21.4 million, or $0.19 per unit, for the nine months ended September 30, 2008, resulting from an assumed credit risk adjustment.

The Company’s counterparties are participants in its Credit Facility (see Note 8) which is secured by the Company’s oil and gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from the counterparties. The maximum amount of loss due to credit risk, based on the gross fair value of financial instruments that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts was approximately $8.4 million at September 30, 2008. In accordance with the Company’s standard practice, its commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is mitigated at September 30, 2008.

Off-Balance Sheet Arrangements

At September 30, 2008, the Company did not have any off-balance sheet arrangements.

Contingencies

In September and October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed voluntary petitions for reorganization under Chapter 11 (see Note 11). As of September 30, 2008, the Company had a receivable of approximately $67.6 million from Lehman Commodity Services for canceled derivative contracts (see Note 9). The Company is pursuing various legal remedies to protect its interests. Based on market expectations, at September 30, 2008, the Company estimated approximately $6.7 million of the receivable balance to be collectible. The net receivable of approximately $6.7 million is included in “other current assets, net” on the condensed consolidated balance sheet at September 30, 2008. The associated gain of approximately $67.6 million and the estimated loss of approximately $60.9 million is included in “gain (loss) on oil and gas derivatives” on the condensed consolidated statements of operations for the three and nine months ended September 30, 2008, for a net gain of approximately $6.7 million. The Company believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

During the nine months ended June 2008 and 2007, 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.

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in a table of contractual obligations in the 2007 Annual Report on Form 10-K. With the exception of a $400.0 million Term Loan (repaid in July 2008) and $255.9 million of Senior Notes, as of September 30, 2008, there have been no significant changes to the Company’s contractual obligations from December 31, 2007. See “Term Loan” and “Senior Notes” above for additional details.

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

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of financial statements.

As of September 30, 2008, there have been no significant changes with regard to the critical accounting policies disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The policies disclosed included the accounting for oil and gas properties, revenue recognition, purchase accounting and derivative instruments.

New Accounting Standards

See Note 17 for detail regarding SFAS 157 implementation effective January 1, 2008 and January 1, 2009, and also for detail regarding SFAS 161 implementation effective January 1, 2008.

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

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 statements about the Company’s:

business strategy;

acquisition strategy;

financial strategy;

drilling locations;

oil, gas and NGL reserves;

realized oil, gas and NGL prices;

production volumes;

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

future operating results; and

plans, objectives, expectations and intentions.

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 listed in “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 and herein, and elsewhere in the Annual Report and also in the Company’s Quarterly Reports on Form 10-Q. 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.

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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. A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”

Commodity Price Risk

The Company enters into derivative contracts with respect to a portion of its projected production through various transactions that provide an economic hedge of the risk related to the future prices received. The Company does not enter into derivative contracts for trading purposes. See Note 9 for additional details. At September 30, 2008, the fair value of contracts that settle during the next twelve months was an asset of approximately $58.3 million and a liability of approximately $1.9 million for a net asset of approximately $56.4 million, for which the Company is owed by its counterparties. A 10% increase in the index oil and gas prices above the September 30, 2008 prices for the next twelve months would result in a net liability of approximately $27.5 million which represents a decrease in the fair value of approximately $83.9 million; conversely, a 10% decrease in the index oil and gas prices would result in a net asset of approximately $143.4 million which represents an increase in the fair value of approximately $87.0 million.

Interest Rate Risk

At September 30, 2008, the Company had long-term debt outstanding under its Credit Facility of approximately $1.52 billion, which incurred interest at floating rates. See Note 8 for additional details. As of September 30, 2008, the interest rate based on LIBOR was approximately 4.39%. A 1% increase in LIBOR would result in an estimated $15.2 million increase in annual interest expense. The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. See Note 9 for additional details.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2008.

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 consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

There were no changes in the Company’s internal controls over financial reporting during the three months ended September 30, 2008 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Not applicable.

Item 1A. Risk Factors

Part I, Item 1A, “Risk Factors,” included in the Company’s Annual Report Form 10-K for the year ended December 31, 2007 includes a detailed discussion of the Company’s risk factors. The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in the Company’s 2007 Form 10-K.

Disruptions in the capital and credit markets as a result of the global financial crisis may adversely affect our hedge positions.

To achieve more predictable cash flow and to reduce our exposure to fluctuations in the prices of oil, gas and NGL, we enter into hedging arrangements for a significant portion of our production. Given the recent failures of major financial institutions, we cannot be assured that our counterparties will be able to perform under our hedge contracts. If a counterparty fails to perform and the hedging arrangement is terminated, our cash flow, and ability to pay distributions could be impacted.

Unitholders may be subject to taxable gains upon dispositions of properties.

We may dispose of properties in transactions that result in gains that will be allocated to you, and such gains may be either ordinary gains or capital gains to you. Even where we dispose of properties that are capital assets, what otherwise would be capital gains to you may be recharacterized as ordinary gains in order to “recapture” ordinary deductions that were previously allocated to you related to the same properties. In addition, such an allocation of ordinary or capital gains may increase your taxable income, and you may be required to pay federal income taxes and state and local income taxes, even if we have not made a cash distribution to you subsequent to our disposal of the properties. Your allocable share of the taxable gains also may be greater than your interest in our profits. If you contributed property in exchange for our units, your capital account would have been credited with the fair market value of the property at the time (your “book” basis), which may have exceeded your “tax” basis of property. This could also be the case if you held our units at a time when we issued additional units to other unitholders (resulting in a revaluation of our assets). Gains are required to be allocated to you in order to eliminate this “book-tax disparity.”

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number			Description

2	.1*†	—	Asset Purchase and Sale Agreement, dated October 9, 2008, between Linn Energy Holdings, LLC, Mid-Continent I, LLC, Mid-Continent II, LLC, Linn Operating, Inc. and Devon Energy Production Company, LP
2	.2†	—	First Amendment, dated as of August 6, 2008, to Asset Purchase and Sale Agreement between Linn Energy Holdings, LLC, Linn Operating, Inc., Mid-Continent I, LLC, Mid-Continent II, LLC, Linn Exploration Mid-Continent, LLC, as sellers, and Laredo Petroleum, Inc., as buyer
10	.1	—	Fourth Amendment, dated effective August 20, 2008, to Third Amended and Restated Credit Agreement among Linn Energy, LLC, as Borrower, BNP Paribas, as Administrative Agent, and the lenders and agents party thereto (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 26, 2008)
31	.1†	—	Section 302 Certification of Michael C. Linn, Chairman 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 Michael C. Linn, Chairman 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

†	Filed 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 6, 2008	/s/ David B. Rottino
	David B. Rottino
	Senior Vice President and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)