Edgar Filing: LINN ENERGY, LLC

form10qq32010.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, 2010

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

for the transition period from _______________ to _______________

Commission File Number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)


Delaware	65-1177591
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
600 Travis, Suite 5100 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(281) 840-4000 (Registrant’s telephone number, including area code)

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

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

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

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

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

As of September 30, 2010, there were 147,419,333 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, 2010, and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2010, and September 30, 2009	2
	Condensed Consolidated Statement of Unitholders’ Capital for the nine months ended September 30, 2010	3
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2010, and September 30, 2009	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45

	Part II - Other Information
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Reserved	47
Item 5.	Other Information	47
Item 6.	Exhibits	48

	Signature	49

Table of Contents

GLOSSARY OF TERMS

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

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

Bcf. One billion cubic feet.

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

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

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

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

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

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

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

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

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

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.

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

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
	2010			2009
	(Unaudited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	418,060		$	22,231
Accounts receivable – trade, net		162,432			109,311
Derivative instruments		314,456			249,756
Other current assets		43,261			28,162
Total current assets		938,209			409,460

Noncurrent assets:
Oil and natural gas properties (successful efforts method)		5,083,662			4,076,795
Less accumulated depletion and amortization		(622,216	)		(463,413	)
		4,461,446			3,613,382

Other property and equipment		139,445			118,867
Less accumulated depreciation		(32,149	)		(23,583	)
		107,296			95,284

Derivative instruments		179,125			145,457
Other noncurrent assets		132,590			76,673
		311,715			222,130
Total noncurrent assets		4,880,457			3,930,796
Total assets	$	5,818,666		$	4,340,256

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	203,341		$	124,358
Derivative instruments		2,859			51,025
Other accrued liabilities		88,920			33,922
Total current liabilities		295,120			209,305

Noncurrent liabilities:
Credit facility		―			1,100,000
Senior notes, net		2,741,735			488,831
Derivative instruments		8,733			53,923
Other noncurrent liabilities		43,264			36,193
Total noncurrent liabilities		2,793,732			1,678,947

Unitholders’ capital:
147,419,333 units and 129,940,617 units issued and outstanding at September 30, 2010, and December 31, 2009, respectively		2,247,170			2,098,599
Accumulated income		482,644			353,405
		2,729,814			2,452,004
Total liabilities and unitholders’ capital	$	5,818,666		$	4,340,256

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,
	2010			2009			2010			2009
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	177,306		$	102,989		$	479,887		$	274,759
Gains (losses) on oil and natural gas derivatives		43,505			(14,065	)		263,299			(85,525	)
Natural gas marketing revenues		635			1,351			3,252			3,050
Other revenues		915			150			1,363			1,757
		222,361			90,425			747,801			194,041
Expenses:
Lease operating expenses		41,901			33,453			111,490			100,322
Transportation expenses		5,154			6,367			15,030			11,850
Natural gas marketing expenses		468			98			2,209			1,318
General and administrative expenses		23,751			19,655			71,545			63,247
Exploration costs		281			861			4,297			4,625
Bad debt expenses		(70	)		500			(89	)		500
Depreciation, depletion and amortization		62,482			49,440			169,614			151,934
Taxes, other than income taxes		12,011			5,965			32,602			21,414
(Gains) losses on sale of assets and other, net		6,073			1,999			5,699			(24,717	)
		152,051			118,338			412,397			330,493
Other income and (expenses):
Interest expense, net of amounts capitalized		(53,497	)		(28,025	)		(127,119	)		(65,696	)
Losses on interest rate swaps		(11,501	)		(25,709	)		(67,908	)		(25,362	)
Other, net		(1,136	)		(757	)		(5,428	)		(1,987	)
		(66,134	)		(54,491	)		(200,455	)		(93,045	)
Income (loss) from continuing operations before income taxes		4,176			(82,404	)		134,949			(229,497	)
Income tax expense		(33	)		(58	)		(5,710	)		(379	)
Income (loss) from continuing operations		4,143			(82,462	)		129,239			(229,876	)

Discontinued operations:
Losses on sale of assets, net of taxes		―			―			―			(718	)
Loss from discontinued operations, net of taxes		―			(1,247	)		―			(2,186	)
		―			(1,247	)		―			(2,904	)
Net income (loss)	$	4,143		$	(83,709	)	$	129,239		$	(232,780	)

Income (loss) per unit – continuing operations:
Basic	$	0.03		$	(0.69	)	$	0.91		$	(1.97	)
Diluted	$	0.03		$	(0.69	)	$	0.91		$	(1.97	)
Loss per unit – discontinued operations:
Basic	$	―		$	(0.01	)	$	―		$	(0.03	)
Diluted	$	―		$	(0.01	)	$	―		$	(0.03	)
Net income (loss) per unit:
Basic	$	0.03		$	(0.70	)	$	0.91		$	(2.00	)
Diluted	$	0.03		$	(0.70	)	$	0.91		$	(2.00	)
Weighted average units outstanding:
Basic		145,956			119,792			140,598			116,610
Diluted		146,458			119,792			141,006			116,610

Distributions declared per unit	$	0.63		$	0.63		$	1.89		$	1.89

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL

(Unaudited)

	Units			Unitholders’ Capital			Accumulated Income		Treasury Units (at Cost)			Total Unitholders’ Capital
	(in thousands)

December 31, 2009		129,941		$	2,098,599		$	353,405	$	―		$	2,452,004
Sale of units, net of underwriting discounts and expenses of $17,563		17,250			413,687			—		—			413,687
Issuance of units		724			2,694			—		—			2,694
Cancellation of units		(496	)		(11,832	)		—		11,832			—
Purchase of units					—			—		(11,832	)		(11,832	)
Distributions to unitholders					(268,343	)		—		—			(268,343	)
Unit-based compensation expenses					10,546			—		—			10,546
Excess tax benefit from unit-based compensation					1,819			—		—			1,819
Net income					—			129,239		—			129,239
September 30, 2010		147,419		$	2,247,170		$	482,644	$	—		$	2,729,814

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,
	2010			2009
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	129,239		$	(232,780	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		169,614			151,934
Unit-based compensation expenses		10,546			11,473
Bad debt expenses		(89	)		500
Amortization and write-off of deferred financing fees and other		20,729			14,231
Gains on sale of assets and other, net		(619	)		(22,572	)
Deferred income tax		2,956			―
Mark-to-market on derivatives:
Total (gains) losses		(195,391	)		110,887
Cash settlements		218,559			299,114
Cash settlements on canceled derivatives		(123,865	)		48,977
Premiums paid for derivatives		(91,027	)		(93,606	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		(43,173	)		39,260
Decrease in other assets		15,894			365
Increase (decrease) in accounts payable and accrued expenses		15,483			(3,232	)
Increase in other liabilities		54,563			5,573
Net cash provided by operating activities		183,419			330,124

Cash flow from investing activities:
Acquisition of oil and natural gas properties, net of cash acquired		(894,521	)		(116,694	)
Development of oil and natural gas properties		(104,694	)		(152,149	)
Purchases of other property and equipment		(15,030	)		(5,832	)
Proceeds from sale of properties and equipment		696			26,682
Net cash used in investing activities		(1,013,549	)		(247,993	)

Cash flow from financing activities:
Proceeds from sale of units		431,250			102,781
Proceeds from borrowings		3,170,816			599,203
Repayments of debt		(2,020,000	)		(513,893	)
Distributions to unitholders		(268,343	)		(221,430	)
Financing fees, offering expenses and other, net		(77,751	)		(64,169	)
Excess tax benefit from unit-based compensation		1,819			—
Purchase of units		(11,832	)		(2,696	)
Net cash provided by (used in) financing activities		1,225,959			(100,204	)

Net increase (decrease) in cash and cash equivalents		395,829			(18,073	)
Cash and cash equivalents:
Beginning		22,231			28,668
Ending	$	418,060		$	10,595

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

Nature of Business

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company. LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in the United States, primarily in the Mid-Continent, California, Permian Basin and Michigan.

Principles of Consolidation and Reporting

The condensed consolidated financial statements at September 30, 2010, and for the three months and nine months ended September 30, 2010, and September 30, 2009, are unaudited, but in the opinion of management include all adjustments (consisting 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, 2009. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. Unless otherwise indicated, information about the condensed consolidated statements of operations that is presented herein relates only to continuing operations.

Use of Estimates

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(2)	Acquisitions and Divestitures

Acquisitions – 2010

On July 16, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the East Texas Oil Field in Gregg and Rusk counties for a contract price of $95.0 million. On September 29, 2010, in accordance with the terms of the purchase agreement, the Company sent a notice to the sellers of the Company’s intention to terminate the purchase agreement as a result of certain conditions to closing not being met. The Company paid a deposit of $9.2 million in July 2010, which is reported in “other current assets” on the condensed consolidated balance sheet at September 30, 2010. On October 11, 2010, arbitration proceedings were initiated concerning the termination of the purchase agreement and the return of the deposit.

On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from Crownrock, LP and Element Petroleum, LP (collectively referred to as “CrownQuest/Element”). The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $95.8 million in cash and recorded a receivable of $2.3 million, resulting in total consideration for the acquisition of approximately $93.5 million. The transaction was financed with borrowings under the Company’s Credit Facility (as defined in Note 6).

On May 27, 2010, the Company completed the acquisition of interests in Henry Savings LP and Henry Savings Management LLC (collectively referred to as “Henry”) that primarily hold oil and natural gas properties located in the Permian Basin. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $317.9 million in cash, including a deposit of $30.5 million paid in March 2010, and recorded a receivable from Henry of $10.1 million, resulting in total consideration for the acquisition of approximately $307.8 million. The transaction was financed with borrowings under the Company’s Credit Facility.

On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount Exploration & Production LLC (“HighMount”) that hold oil and natural gas properties in the Antrim Shale located in northern Michigan. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $326.8 million in cash, including a deposit of $33.0 million paid in March 2010. The transaction was financed with a portion of the net proceeds from the Company’s March 2010 public offering of units (see Note 3). The acquisition provided the Company with a new operating region in Michigan.

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico, from certain affiliates of Merit Energy Company (“Merit”). The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $152.0 million in cash, including a deposit of $15.5 million paid in November 2009, and recorded a receivable from Merit of $1.0 million, resulting in total consideration for the acquisition of approximately $151.0 million. The transaction was financed with borrowings under the Company’s Credit Facility. The acquisition provided strategic additions to the Company’s positions in the Permian Basin and Mid-Continent.

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

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

Assets:
Cash acquired	$	15,367
Current and noncurrent assets		32,170
Oil and natural gas properties		864,829
Total assets acquired	$	912,366

Liabilities:
Current liabilities	$	32,024
Asset retirement obligations		4,974
Total liabilities assumed	$	36,998
Net assets acquired	$	875,368

Current and noncurrent assets include trade accounts receivable, inventory, prepaid drilling costs, vehicles, natural gas imbalance receivables, land, natural gas plant and investments in noncontrolled entities. Current liabilities include trade accounts payable, natural gas imbalance payables, ad valorem taxes payable and environmental liabilities.

The fair values of oil and natural gas properties were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.

Acquisition – Subsequent Event

On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin, from Crownrock, LP and Patriot Resources Partners LLC (collectively referred to as “CrownQuest/Patriot”) for a combined price of $250.2 million. The transactions were financed with cash on hand and included a deposit of $12.7 million paid by the Company in September 2010. The initial accounting for the business combination is not complete pending detailed analyses of the facts and circumstances that existed as of the acquisition date.

Acquisition – Pending

On September 2, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin for a contract price of $120.0 million. The Company anticipates the acquisition will close on or before November 16, 2010, subject to closing conditions, and will be financed with cash on hand and proceeds from borrowings under its Credit Facility.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Acquisitions – 2009

On August 31, 2009, and September 30, 2009, the Company completed the acquisitions of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian Corporation (collectively referred to as “Forest”) for aggregate total consideration of $113.8 million. The results of operations of these properties have been included in the condensed consolidated financial statements since these dates. The transactions were financed with borrowings under the Company’s Credit Facility. The acquisitions represented a strategic entry into the Permian Basin for the Company.

Divestitures

In December 2008, the Company completed the sale of its deep rights in certain central Oklahoma acreage, which included the Woodford Shale interval. In the first quarter of 2009, certain post-closing matters were resolved and the Company recorded a gain of $25.4 million, which is included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statement of operations for the nine months ended September 30, 2009.

In July 2008, the Company completed the sale of its interests in oil and natural gas properties in the Appalachian Basin and, in March 2008, the Company also exited the drilling and service business in this basin. The results of these operations were classified as discontinued operations on the condensed consolidated statements of operations and the amounts recorded in 2009 primarily represent post-closing adjustments.

(3)	Unitholders’ Capital

Public Offering of Units

On March 29, 2010, the Company sold 17,250,000 units representing limited liability company interests at $25.00 per unit ($24.00 per unit, net of underwriting discount) for net proceeds of approximately $413.7 million (after underwriting discount of $17.3 million and estimated offering expenses of $0.3 million). The Company used a portion of the net proceeds from the sale of these units to finance the HighMount acquisition (see Note 2).

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 from time to time on the open market or in negotiated purchases. During the nine months ended September 30, 2010, 486,700 units were repurchased at an average unit price of $23.79 for a total cost of approximately $11.6 million. All units were subsequently canceled. At September 30, 2010, approximately $73.8 million was available for unit repurchase under the program. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are repurchased at fair market value on the date of repurchase.

Cancellation of Units

During the nine months ended September 30, 2010, the Company purchased 9,055 units for approximately $0.3 million, in conjunction with units received by the Company for the payment of minimum withholding

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

taxes due on units issued under its equity compensation plan (see Note 5). All units were subsequently canceled.

Distributions

Under the Company’s 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. Distributions paid by the Company during the nine months ended September 30, 2010, are presented on the condensed consolidated statement of unitholders’ capital. On October 25, 2010, the Company’s Board of Directors declared a cash distribution of $0.66 per unit with respect to the third quarter of 2010, which represents a 5% increase over the previous quarter. This distribution, totaling approximately $97.3 million, will be paid on November 12, 2010, to unitholders of record as of the close of business on November 4, 2010.

(4)	Oil and Natural Gas Capitalized Costs

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

	September 30, 2010			December 31, 2009
	(in thousands)
Proved properties:
Leasehold acquisition	$	4,224,209		$	3,398,292
Development		728,093			600,436
Unproved properties		131,360			78,067
		5,083,662			4,076,795
Less accumulated depletion and amortization		(622,216	)		(463,413	)
	$	4,461,446		$	3,613,382

(5)	Unit-Based Compensation

During the nine months ended September 30, 2010, the Company granted an aggregate 673,754 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $17.3 million. The restricted units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)

General and administrative expenses	$	3,070	$	3,435	$	10,280	$	11,204
Lease operating expenses		76		84		266		269
Total unit-based compensation expenses	$	3,146	$	3,519	$	10,546	$	11,473
Income tax benefit	$	1,162	$	—	$	3,897	$	—

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(6)

Debt

The following summarizes debt outstanding:

	September 30, 2010								December 31, 2009
	Carrying Value			Fair Value (1)		Interest Rate (2)			Carrying Value			Fair Value (1)		Interest Rate (2)
	(in millions, except percentages)

Credit facility	$	―		$	―		―		$	1,100		$	1,100		2.98	%
11.75% senior notes due 2017		250			280		12.73	%		250			279		12.73	%
9.875% senior notes due 2018		256			286		10.25	%		256			271		10.25	%
8.625% senior notes due 2020		1,300			1,373		9.00	%		―			―		―
7.75% senior notes due 2021		1,000			1,003		8.00	%		―			―		―
Less current maturities		―			―					―			―
		2,806		$	2,942					1,606		$	1,650
Unamortized discount		(64	)							(17	)
Total debt, net of discount	$	2,742							$	1,589

(1)

The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.

(2)

Represents variable interest rate for the Credit Facility and effective interest rates for the senior notes.

Credit Facility

The Company’s Fourth Amended and Restated Revolving Credit Facility (“Credit Facility”) provides the Company a $1.50 billion facility with a maturity of April 2015. In connection with amendments to its Credit Facility during 2010, the Company incurred financing fees and expenses of approximately $16.2 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. At September 30, 2010, the borrowing base under the Credit Facility was $1.25 billion and available borrowing capacity was approximately $1.24 billion, which includes a $5.1 million reduction in availability for outstanding letters of credit. In October 2010, in connection with the regular semi-annual borrowing base redetermination, the borrowing base was increased to $1.50 billion, and at October 25, 2010, available borrowing capacity was approximately $1.49 billion, which includes a $5.1 million reduction in availability for outstanding letters of credit.

Redetermination of the borrowing base under the Credit Facility occurs semi-annually, in April and October, as well as upon the occurrence of certain events, by the lenders at their sole discretion, based primarily on reserve reports that reflect commodity prices at such time. The Company also has the right to request one additional borrowing base redetermination per year in connection with certain acquisitions, which right was last exercised in June 2010. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its oil and natural gas properties as well as a pledge of all ownership interests in its material operating subsidiaries. The Company is required to maintain the mortgages on properties representing at least 80% of the total value of its oil and natural gas properties. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material operating subsidiaries and are required to be guaranteed by any future subsidiaries.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

At the Company’s election, interest on borrowings under the Credit Facility, as amended in April 2010, is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or the alternate base rate (“ABR”) plus an applicable margin between 1.00% and 2.00% per annum. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. The Company is required to pay a quarterly fee of 0.5% per annum on the unused portion of the borrowing base under the Credit Facility. The Credit Facility contains various covenants substantially similar to those included prior to the amendment. The Company is in compliance with all financial and other covenants of the Credit Facility.

Senior Notes Due 2021

On September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (“2021 Notes”) at a price of 98.264%. The 2021 Notes were sold to a group of initial purchasers (“2021 Initial Purchasers”) and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $962.5 million (after deducting the 2021 Initial Purchasers’ discount and offering expenses). The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility and to unwind its remaining interest rate swap agreements. The remaining proceeds will be used to fund or partially fund acquisitions and for general corporate purposes. In connection with the 2021 Notes, the Company incurred financing fees and expenses of approximately $20.1 million, which will be amortized over the life of the 2021 Notes. The discount on the 2021 Notes, which totaled $17.4 million, will also be amortized over the life of the 2021 Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

The 2021 Notes were issued under an indenture dated September 13, 2010, (“2021 Indenture”), mature February 1, 2021, and bear interest at 7.75%. Interest is payable semi-annually beginning March 15, 2011. The 2021 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 has guaranteed the 2021 Notes on a senior unsecured basis. The 2021 Indenture provides that the Company may redeem: (i) on or prior to September 15, 2013, up to 35% of the aggregate principal amount of the 2021 Notes at a redemption price of 107.75% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to September 15, 2015, all or part of the 2021 Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the 2021 Indenture) and accrued and unpaid interest; and (iii) on or after September 15, 2015, all or part of the 2021 Notes at redemption prices equal to 103.875% in 2015, 102.583% in 2016, 101.292% in 2017 and 100% in 2018 and thereafter, in each case, of the principal amount redeemed, plus accrued and unpaid interest. The 2021 Indenture also provides that, if a change of control (as defined in the 2021 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2021 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2021 Indenture contains covenants substantially similar to those under the Company’s 11.75% senior notes due 2017, 9.875% senior notes due 2018 and 8.625% senior notes due 2020 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. The Company is in compliance with all financial and other covenants of the 2021 Notes.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

In connection with the issuance and sale of the 2021 Notes, the Company entered into a Registration Rights Agreement (“2021 Registration Rights Agreement”) with the 2021 Initial Purchasers. Under the 2021 Registration Rights Agreement, the Company agreed, in certain circumstances, 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 2021 Notes in exchange for outstanding 2021 Notes. Additionally, in certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2021 Notes. However, the Company will not be obligated to file the registration statements described above if the restrictive legend on the 2021 Notes has been removed and the 2021 Notes are freely tradable (in each case, other than with respect to persons that are affiliates of the Company) pursuant to Rule 144 of the Securities Act, as of the 366th day after the 2021 Notes were issued. If the Company fails to satisfy its obligations under the 2021 Registration Rights Agreement, the Company may be required to pay additional interest to holders of the 2021 Notes under certain circumstances.

Senior Notes Due 2020

On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (“2020 Notes”) at a price of 97.552%. The 2020 Notes were sold to a group of initial purchasers (“2020 Initial Purchasers”) and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act. The Company received net proceeds of approximately $1.24 billion (after deducting the 2020 Initial Purchasers’ discount and offering expenses). The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with an amendment to its Credit Facility. The remaining proceeds were used to fund or partially fund acquisitions and for general corporate purposes. In connection with the 2020 Notes, the Company incurred financing fees and expenses of approximately $27.5 million, which will be amortized over the life of the 2020 Notes. The discount on the 2020 Notes, which totaled $31.8 million, will also be amortized over the life of the 2020 Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

The 2020 Notes were issued under an indenture dated April 6, 2010, (“2020 Indenture”), mature April 15, 2020, and bear interest at 8.625%. Interest is payable semi-annually beginning October 15, 2010. The 2020 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 has guaranteed the 2020 Notes on a senior unsecured basis. The 2020 Indenture provides that the Company may redeem: (i) on or prior to April 15, 2013, up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 108.625% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to April 15, 2015, all or part of the 2020 Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the 2020 Indenture) and accrued and unpaid interest; and (iii) on or after April 15, 2015, all or part of the 2020 Notes at redemption prices equal to 104.313% in 2015, 102.875% in 2016, 101.438% in 2017 and 100% in 2018 and thereafter, in each case, of the principal amount redeemed, plus accrued and unpaid interest. The 2020 Indenture also provides that, if a change of control (as defined in the 2020 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2020 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2020 Indenture contains covenants substantially similar to those under the Company’s 11.75% senior notes due 2017, 9.875% senior notes due 2018 and 7.75% senior notes due 2021 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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of the 2020 Notes.

In connection with the issuance and sale of the 2020 Notes, the Company entered into a Registration Rights Agreement (“2020 Registration Rights Agreement”) with the 2020 Initial Purchasers. Under the 2020 Registration Rights Agreement, the Company agreed, in certain circumstances, 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 2020 Notes in exchange for outstanding 2020 Notes. Additionally, in certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2020 Notes. However, the Company will not be obligated to file the registration statements described above if the restrictive legend on the 2020 Notes has been removed and the 2020 Notes are freely tradable (in each case, other than with respect to persons that are affiliates of the Company) pursuant to Rule 144 of the Securities Act, as of the 366th day after the 2020 Notes were issued. If the Company fails to satisfy its obligations under the 2020 Registration Rights Agreement, the Company may be required to pay additional interest to holders of the 2020 Notes under certain circumstances.

Senior Notes Due 2017 and Senior Notes Due 2018

On May 18, 2009, the Company issued $250.0 million in aggregate principal amount of 11.75% senior notes due May 15, 2017, at a price of 95.081%. On June 27, 2008, the Company issued $255.9 million in aggregate principal amount of 9.875% senior notes due July 1, 2018, at a price of 97.684%.

(7)	Derivatives

Commodity Derivatives

The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company enters into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil and natural gas sales. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

The following table summarizes open positions as of September 30, 2010, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:

	September 30 – December 31, 2010			2011			2012			2013			2014		2015
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		9,891			31,901			49,410			49,275			49,275		49,275
Average price ($/MMBtu)	$	8.90		$	9.50		$	5.97		$	5.97		$	5.97	$	5.97
Puts:
Hedged volume (MMMBtu)		1,740			6,960			25,364			25,295			―		―
Average price ($/MMBtu)	$	8.50		$	9.50		$	6.25		$	6.25		$	―	$	―
PEPL puts: (1)
Hedged volume (MMMBtu)		2,659			13,259			―			―			―		―
Average price ($/MMBtu)	$	7.85		$	8.50		$	―		$	―		$	―	$	―
Total:
Hedged volume (MMMBtu)		14,290			52,120			74,774			74,570			49,275		49,275
Average price ($/MMBtu)	$	8.66		$	9.25		$	6.07		$	6.07		$	5.97	$	5.97

Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)		538			2,803			4,484			4,471			4,654		1,643
Average price ($/Bbl)	$	90.00		$	89.91		$	95.88		$	95.88		$	89.03	$	87.04
Puts:
Hedged volume (MBbls)		562			2,352			2,196			2,190			―		―
Average price ($/Bbl)	$	110.00		$	75.00		$	75.00		$	75.00		$	―	$	―
Collars:
Hedged volume (MBbls)		62			276			―			―			―		―
Average floor price ($/Bbl)	$	90.00		$	90.00		$	―		$	―		$	―	$	―
Average ceiling price ($/Bbl)	$	112.00		$	112.25		$	―		$	―		$	―	$	―
Total:
Hedged volume (MBbls)		1,162			5,431			6,680			6,661			4,654		1,643
Average price ($/Bbl)	$	99.68		$	83.46		$	89.01		$	89.01		$	89.03	$	87.04

Natural gas basis differential positions:
PEPL basis swaps: (1)
Hedged volume (MMMBtu)		10,791			35,541			34,066			31,700			―		―
Hedged differential ($/MMBtu)	$	(0.97	)	$	(0.96	)	$	(0.95	)	$	(1.01	)	$	―	$	―

(1)

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

(2)

As presented in the table above, the Company has certain outstanding fixed price oil swaps on 8,250 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2015, December 31, 2016, and December 31, 2017, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

During the first half of 2010, the Company entered into commodity derivative contracts, consisting of oil and natural gas swaps and puts for certain years through 2015, and paid premiums for put options of approximately $91.0 million. In addition, in September 2010, the Company entered into commodity derivative contracts consisting of oil swaps for 2012 through 2015.

Settled derivatives on natural gas production for the three months and nine months ended September 30, 2010, included volumes of 14,290 MMMBtu and 42,870 MMMBtu, respectively, at average contract prices of $8.66 per MMBtu. Settled derivatives on oil production for the three months and nine months ended September 30, 2010, included volumes of 1,162 MBbls and 3,487 MBbls, respectively, at average contract prices of $99.68 per Bbl. The natural gas derivatives are settled based on the closing New York Mercantile Exchange (“NYMEX”) futures price of natural gas or on the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month. The oil derivatives are settled based on the month’s average daily NYMEX price of light oil and settlement occurs on the final day of the production month.

In October 2010, the Company entered into commodity derivative contracts, consisting of oil swaps and natural gas swaps and puts for certain years through 2015, and paid premiums for put options of approximately $29.3 million. At October 25, 2010, the Company had derivative contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and $84.09 per Bbl for oil and $8.66 per MMBtu and $8.24 per MMBtu for natural gas, respectively. Additionally, the Company has derivative contracts in place covering a substantial portion of its exposure to the Mid-Continent natural gas basis differential through 2015.

Interest Rate Swaps

The Company may from time to time enter 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 counterparty the difference, and conversely, the counterparty is required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company does not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.

In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of the 2020 Notes (see Note 6). In conjunction with the repayment of borrowings under its Credit Facility with proceeds from the issuance of the 2020 Notes, during the second quarter of 2010, the Company canceled (before the contract settlement date) certain interest rate swap agreements for 2010 through 2013, resulting in realized losses of approximately $74.3 million. In September 2010, the Company canceled (before the contract settlement date) all of its remaining interest rate swap agreements in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of the 2021 Notes (see Note 6). The cancellation of the interest rate swap agreements in September 2010, resulted in a realized loss of approximately $49.6 million.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Balance Sheet Presentation

The Company’s commodity and interest rate 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, 2010		December 31, 2009
	(in thousands)
Assets:
Commodity derivatives	$	762,142	$	549,879
Interest rate swaps		―		2,603
	$	762,142	$	552,482
Liabilities:
Commodity derivatives	$	280,153	$	192,573
Interest rate swaps		―		69,644
	$	280,153	$	262,217

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current or former participants or affiliates of current or former participants in its Credit Facility (see Note 6), which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $762.1 million at September 30, 2010. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives” and “losses on interest rate swaps” and include realized and unrealized gains (losses). Realized gains (losses), excluding canceled 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 noncash items.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

The following presents the Company’s reported gains and losses on derivative instruments:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	82,910		$	97,209		$	228,573		$	328,165
Interest rate swaps		―			(10,958	)		(8,021	)		(31,629	)
Canceled derivatives		(49,590	)		44,780			(123,865	)		48,977
	$	33,320		$	131,031		$	96,687		$	345,513
Unrealized gains (losses):
Commodity derivatives	$	(39,405	)	$	(156,054	)	$	34,726		$	(462,727	)
Interest rate swaps		38,089			(14,751	)		63,978			6,327
	$	(1,316	)	$	(170,805	)	$	98,704		$	(456,400	)
Total gains (losses):
Commodity derivatives	$	43,505		$	(14,065	)	$	263,299		$	(85,525	)
Interest rate swaps		(11,501	)		(25,709	)		(67,908	)		(25,362	)
	$	32,004		$	(39,774	)	$	195,391		$	(110,887	)

During the three months and nine months ended September 30, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements resulting in realized losses of approximately $49.6 million and $123.9 million, respectively. During the three months and nine months ended September 30, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized net gains of approximately $44.8 million and $49.0 million, respectively.

(8)	Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity and interest rate derivatives at fair value (see Note 7) on a recurring basis. The fair value of derivative instruments is determined utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity and interest rate derivatives.

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

	September 30, 2010
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	762,142	$	(268,561	)	$	493,581

Liabilities:
Commodity derivatives	$	280,153	$	(268,561	)	$	11,592

(1)

Represents counterparty netting under agreements governing such derivatives.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(9)	Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the nine months ended September 30, 2010); and (iv) a credit-adjusted risk-free interest rate (average of 8.8% for the nine months ended September 30, 2010).

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

Asset retirement obligations at December 31, 2009	$	33,135
Liabilities added from acquisitions		4,974
Liabilities added from drilling		166
Current year accretion expense		2,017
Settlements		(148	)
Asset retirement obligations at September 30, 2010	$	40,144

(10)	Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits and is involved in various other disputes arising in the ordinary course of business, including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

(11)	Earnings Per Unit

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Three months ended September 30, 2010:
Income from continuing operations:
Allocated to units	$	4,143
Allocated to unvested restricted units		(46	)
	$	4,097
Income per unit:
Basic income per unit					145,956	$	0.03
Dilutive effect of unit equivalents					502		―
Diluted income per unit					146,458	$	0.03

Three months ended September 30, 2009:
Loss from continuing operations:
Allocated to units	$	(82,462	)
Allocated to unvested restricted units		—
	$	(82,462	)
Loss per unit:
Basic loss per unit					119,792	$	(0.69	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					119,792	$	(0.69	)

Nine months ended September 30, 2010:
Income from continuing operations:
Allocated to units	$	129,239
Allocated to unvested restricted units		(1,361	)
	$	127,878
Income per unit:
Basic income per unit					140,598	$	0.91
Dilutive effect of unit equivalents					408		―
Diluted income per unit					141,006	$	0.91

Nine months ended September 30, 2009:
Loss from continuing operations:
Allocated to units	$	(229,876	)
Allocated to unvested restricted units		—
	$	(229,876	)
Loss per unit:
Basic loss per unit					116,610	$	(1.97	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					116,610	$	(1.97	)

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 0.3 million and 0.6 million unit options and warrants for the three months and nine months ended

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

September 30, 2010, respectively. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 2.2 million and 2.1 million unit options and warrants for the three months and nine months ended September 30, 2009, respectively. All equivalent units were anti-dilutive for the three months and nine months ended September 30, 2009, as the Company reported a loss from continuing operations.

(12)	Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan and certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the states of Texas and Michigan and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company. Amounts recognized for these taxes are reported in “income tax expense” on the condensed consolidated statements of operations.

(13)	Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	September 30, 2010		December 31, 2009
	(in thousands)

Accrued compensation	$	12,922	$	14,378
Accrued interest		75,484		18,332
Other		514		1,212
	$	88,920	$	33,922

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

	Nine Months Ended September 30,
	2010			2009
	(in thousands)

Cash payments for interest, net of amounts capitalized	$	55,404		$	50,990
Cash payments for income taxes	$	1,785		$	922
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	896,999		$	116,882
Cash paid, net of cash acquired		(872,621	)		(116,694	)
Receivables from sellers		12,620			2,729
Liabilities assumed	$	36,998		$	2,917

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of $2.7 million and $2.1 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at September 30, 2010, and December 31, 2009, respectively, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

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

The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2009, and elsewhere in the Annual Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.” Unless otherwise indicated, results of operations information presented herein relates only to continuing operations.

Executive Overview

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

Mid-Continent Deep, which includes the Texas Panhandle Deep Granite Wash formation and deep formations in Oklahoma and Kansas;

Mid-Continent Shallow, which includes the Texas Panhandle Brown Dolomite formation and shallow formations in Oklahoma, Louisiana and Illinois;

California, which includes the Brea Olinda Field of the Los Angeles Basin;

Permian Basin, which includes areas in West Texas and Southeast New Mexico; and

Michigan, which includes the Antrim Shale formation in the northern part of the state.

Results for the three months ended September 30, 2010, included the following:

oil, natural gas and NGL sales of approximately $177.3 million, compared to $103.0 million for the third quarter of 2009;

average daily production of 283 MMcfe/d, compared to 217 MMcfe/d for the third quarter of 2009;

realized gains on commodity derivatives of approximately $82.9 million, compared to $142.0 million for the third quarter of 2009;

adjusted EBITDA of approximately $185.0 million, compared to $142.4 million for the third quarter of 2009;

adjusted net income of approximately $56.3 million, compared to $45.9 million for the third quarter of 2009;

capital expenditures, excluding acquisitions, of approximately $74.5 million, compared to $24.5 million for the third quarter of 2009; and

37 wells drilled (36 successful), compared to six wells drilled (all successful) for the third quarter of 2009.

Results for the nine months ended September 30, 2010, included the following:

oil, natural gas and NGL sales of approximately $479.9 million, compared to $274.8 million for the nine months ended September 30, 2009;

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

average daily production of 251 MMcfe/d, compared to 218 MMcfe/d for the nine months ended September 30, 2009;

realized gains on commodity derivatives of approximately $228.6 million, compared to $377.2 million for the nine months ended September 30, 2009;

adjusted EBITDA of approximately $511.4 million, compared to $423.8 million for the nine months ended September 30, 2009;

adjusted net income of approximately $156.3 million, compared to $154.3 million for the nine months ended September 30, 2009;

capital expenditures, excluding acquisitions, of approximately $147.4 million, compared to $128.0 million for the nine months ended September 30, 2009; and

75 wells drilled (74 successful), compared to 66 wells drilled (65 successful) for the nine months ended September 30, 2009.

Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions. The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives, and depreciation, depletion and amortization. Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, impairment of goodwill and long-lived assets and (gains) losses on sale of assets, net. See “Non-GAAP Financial Measures” on page 40 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Acquisition – Pending

Acquisitions – 2010

On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin, from CrownQuest/Patriot for a combined price of $250.2 million. The acquisitions increased the Company’s position in the Permian Basin and included approximately 18 MMBoe (105 Bcfe) of proved reserves as of the acquisition date. Proved reserves as of the acquisition date were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. The majority of the reserves were oil reserves.

On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from CrownQuest/Element for total consideration of approximately $93.5 million. The acquisition increased the Company’s position in the Permian Basin and included approximately 7 MMBoe (40 Bcfe) of proved

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

reserves as of the acquisition date. Proved reserves as of the acquisition date were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. The majority of the reserves were oil reserves.

On May 27, 2010, the Company completed the acquisition of interests in Henry that primarily hold oil and natural gas properties located in the Permian Basin for total consideration of approximately $307.8 million. The acquisition significantly increased the Company’s position in the Permian Basin and included approximately 17 MMBoe (102 Bcfe) of proved reserves as of the acquisition date. Proved reserves as of the acquisition date were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. Proved reserves as of the effective date, April 1, 2010, estimated using forward strip oil and natural gas prices, were 18 MMBoe (108 Bcfe). The majority of the reserves were oil reserves.

On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount that hold oil and natural gas properties in the Antrim Shale located in northern Michigan for total consideration of approximately $326.8 million. The acquisition provided the Company with a new operating region in northern Michigan and included approximately 238 Bcfe of proved reserves as of the acquisition date. Proved reserves as of the acquisition date were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. Proved reserves as of the effective date, March 1, 2010, estimated using forward strip oil and natural gas prices, were 266 Bcfe. The majority of the reserves were natural gas reserves.

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico from Merit for total consideration of approximately $151.0 million. The acquisition provided strategic additions to the Company’s positions in the Permian Basin and Mid-Continent, and included approximately 12 MMBoe (73 Bcfe) of proved reserves as of the acquisition date. Proved reserves as of the acquisition date were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. The majority of the reserves were oil reserves.

Senior Notes Due 2021

On September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (“2021 Notes”) and received net proceeds of approximately $962.5 million. The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility and to unwind its remaining interest rate swap agreements. The remaining proceeds will be used to fund or partially fund acquisitions and for general corporate purposes.

Commodity Derivatives

The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to pay distributions, service debt and manage its business. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices.

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

The following table summarizes open positions as of October 25, 2010, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:

	October 25 – December 31, 2010			2011			2012			2013			2014			2015
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		6,595			31,901			49,410			50,278			54,202			53,837
Average price ($/MMBtu)	$	8.90		$	9.50		$	5.97		$	5.96		$	5.93		$	5.95
Puts:
Hedged volume (MMMBtu)		1,160			19,297			25,364			25,295			23,178			23,178
Average price ($/MMBtu)	$	8.50		$	5.98		$	6.25		$	6.25		$	5.00		$	5.00
PEPL puts: (1)
Hedged volume (MMMBtu)		1,772			13,259			―			―			―			―
Average price ($/MMBtu)	$	7.85		$	8.50		$	―		$	―		$	―		$	―
Total:
Hedged volume (MMMBtu)		9,527			64,457			74,774			75,573			77,380			77,015
Average price ($/MMBtu)	$	8.66		$	8.24		$	6.07		$	6.06		$	5.65		$	5.66

Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)		538			4,737			6,734			7,318			7,026			1,643
Average price ($/Bbl)	$	90.00		$	88.25		$	93.16		$	97.58		$	93.58		$	87.04
Puts:
Hedged volume (MBbls)		562			2,352			2,196			2,190			―			―
Average price ($/Bbl)	$	110.00		$	75.00		$	75.00		$	75.00		$	―		$	―
Collars:
Hedged volume (MBbls)		62			276			―			―			―			―
Average floor price ($/Bbl)	$	90.00		$	90.00		$	―		$	―		$	―		$	―
Average ceiling price ($/Bbl)	$	112.00		$	112.25		$	―		$	―		$	―		$	―
Total:
Hedged volume (MBbls)		1,162			7,365			8,930			9,508			7,026			1,643
Average price ($/Bbl)	$	99.68		$	84.09		$	88.69		$	92.38		$	93.58		$	87.04

Natural gas basis differential positions:
PEPL basis swaps: (1)
Hedged volume (MMMBtu)		7,194			35,541			37,735			38,854			42,194			42,194
Hedged differential ($/MMBtu)	$	(0.97	)	$	(0.96	)	$	(0.89	)	$	(0.89	)	$	(0.39	)	$	(0.39	)

(1)

(2)

As presented in the table above, the Company has certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2015, December 31, 2016, and December 31, 2017, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

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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, 2010, Compared to Three Months Ended September 30, 2009

	Three Months Ended September 30,
	2010			2009			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	53,801		$	35,208		$	18,593
Oil sales		95,625			50,135			45,490
NGL sales		27,880			17,646			10,234
Total oil, natural gas and NGL sales		177,306			102,989			74,317
Gains (losses) on oil and natural gas derivatives		43,505			(14,065	)		57,570
Natural gas marketing revenues		635			1,351			(716	)
Other revenues		915			150			765
	$	222,361		$	90,425		$	131,936
Expenses:
Lease operating expenses	$	41,901		$	33,453		$	8,448
Transportation expenses		5,154			6,367			(1,213	)
Natural gas marketing expenses		468			98			370
General and administrative expenses (1)		23,751			19,655			4,096
Exploration costs		281			861			(580	)
Bad debt expenses		(70	)		500			(570	)
Depreciation, depletion and amortization		62,482			49,440			13,042
Taxes, other than income taxes		12,011			5,965			6,046
Losses on sale of assets and other, net		6,073			1,999			4,074
	$	152,051		$	118,338		$	33,713
Other income and (expenses)	$	(66,134	)	$	(54,491	)	$	(11,643	)
Income (loss) from continuing operations before income taxes	$	4,176		$	(82,404	)	$	86,580

Adjusted EBITDA (2)	$	184,964		$	142,378		$	42,586
Adjusted net income (2)	$	56,301		$	45,924		$	10,377

(1)	General and administrative expenses for the three months ended September 30, 2010, and September 30, 2009, include approximately $3.1 million and $3.4 million, respectively, of noncash unit-based compensation expenses.

(2)	This is a non-GAAP measure used by management to analyze the Company’s performance. See “Non-GAAP Financial Measures” on page 40 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

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

	Three Months Ended September 30,
	2010		2009		Variance
Average daily production:
Natural gas (MMcf/d)		143		122		17	%
Oil (MBbls/d)		14.6		8.8		66	%
NGL (MBbls/d)		8.9		7.1		25	%
Total (MMcfe/d)		283		217		30	%

Weighted average prices (hedged): (1)
Natural gas (Mcf)	$	8.32	$	8.38		(1	)%
Oil (Bbl)	$	91.80	$	109.30		(16	)%
NGL (Bbl)	$	34.21	$	27.06		26	%

Weighted average prices (unhedged): (2)
Natural gas (Mcf)	$	4.09	$	3.14		30	%
Oil (Bbl)	$	71.42	$	61.90		15	%
NGL (Bbl)	$	34.21	$	27.06		26	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.38	$	3.39		29	%
Oil (Bbl)	$	76.20	$	68.86		11	%

Costs per Mcfe of production:
Lease operating expenses	$	1.61	$	1.67		(4	)%
Transportation expenses	$	0.20	$	0.32		(38	)%
General and administrative expenses (3)	$	0.91	$	0.98		(7	)%
Depreciation, depletion and amortization	$	2.40	$	2.47		(3	)%
Taxes, other than income taxes	$	0.46	$	0.30		53	%

(1)	Includes the effect of realized gains on derivatives of approximately $82.9 million and $97.2 million (excluding $44.8 million of realized net gains on canceled contracts) for the three months ended September 30, 2010, and September 30, 2009, 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, 2010, and September 30, 2009, include approximately $3.1 million and $3.4 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the three months ended September 30, 2010, and September 30, 2009, were $0.79 per Mcfe and $0.81 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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $74.3 million or 72% to approximately $177.3 million for the three months ended September 30, 2010, from $103.0 million for the three months ended September 30, 2009, due to higher commodity prices and higher production volumes. Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $12.8 million, $12.5 million and $5.8 million, respectively.

Average daily production volumes increased to 283 MMcfe/d during the three months ended September 30, 2010, from 217 MMcfe/d during the three months ended September 30, 2009. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $32.8 million, $6.0 million and $4.4 million, respectively.

	Three Months Ended September 30,
	2010		2009		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		136		132		4		3	%
Mid-Continent Shallow		66		71		(5	)	(7	)%
California		14		14		—		—
Permian Basin		36		—		36		—
Michigan		31		—		31		—
		283		217		66		30	%

The 3% increase in average daily production volumes in the Mid-Continent Deep region primarily reflects the impact of the Company’s 2010 capital drilling program in the Granite Wash, partially offset by natural declines. The 7% decrease in average daily production volumes in the Mid-Continent Shallow region primarily reflects an adjustment to processing terms made during the third quarter of 2009. Average daily production volumes in the California region reflect the impact of drilling and optimization programs which offset the effects of natural declines. Average daily production volumes in the Permian Basin region reflect the Merit, Henry, CrownQuest/Element and Forest acquisitions in the first, second and third quarters of 2010 and the third quarter of 2009, respectively. Average daily production volumes in the Michigan region reflect the HighMount acquisition in the second quarter of 2010 (see Note 2).

Gains (Losses) on Oil and Natural Gas Derivatives

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for additional information about commodity derivatives. During the three months ended September 30, 2010, the Company had commodity derivative contracts for approximately 109% of its natural gas production and 87% of its oil production, which resulted in realized gains of approximately $82.9 million. During the three months ended September 30, 2009, the Company recorded realized gains of approximately $142.0 million (including realized net gains on canceled contracts of approximately $44.8 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 2010 and 2009, expected future oil and natural gas prices increased, which resulted in unrealized losses on derivatives of approximately $39.4 million and $156.1 million for the three months ended September 30, 2010, and September 30, 2009, respectively. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

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

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $8.4 million or 25% to $41.9 million for the three months ended September 30, 2010, from $33.5 million for the three months ended September 30, 2009. Lease operating expenses increased primarily due to costs associated with properties acquired in the Permian Basin and Michigan regions during 2010 and late in the third quarter of 2009 (see Note 2). Lease operating expenses per Mcfe decreased to $1.61 per Mcfe for the three months ended September 30, 2010, from $1.67 per Mcfe for the three months ended September 30, 2009.

Transportation Expenses

Transportation expenses decreased by approximately $1.2 million or 19% to $5.2 million for the three months ended September 30, 2010, from $6.4 million for the three months ended September 30, 2009, primarily due to increased expenses on nonoperated properties during the three months ended September 30, 2009.

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. General and administrative expenses increased by approximately $4.1 million or 21% to $23.8 million for the three months ended September 30, 2010, from $19.7 million for the three months ended September 30, 2009. The increase was primarily due to an increase in salaries and benefits expense of approximately $1.8 million, driven primarily by increased employee headcount, and acquisition integration expenses of approximately $1.7 million. General and administrative expenses per Mcfe decreased to $0.91 per Mcfe for the three months ended September 30, 2010, from $0.98 per Mcfe for the three months ended September 30, 2009.

Exploration Costs

Exploration costs decreased by approximately $0.6 million or 67% to $0.3 million for the three months ended September 30, 2010, from $0.9 million for the three months ended September 30, 2009. The decrease was primarily due to fewer lease-term expirations related to unproved leasehold costs.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $13.1 million or 27% to $62.5 million for the three months ended September 30, 2010, from $49.4 million for the three months ended September 30, 2009. Higher total production volume levels, primarily due to the Company’s acquisitions in the Permian Basin and Michigan regions in 2010 and late in the third quarter of 2009, were the main reason for the increase. Depreciation, depletion and amortization per Mcfe decreased to $2.40 per Mcfe for the three months ended September 30, 2010, from $2.47 per Mcfe for the three months ended September 30, 2009.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $6.0 million or 100% to $12.0 million for the three months ended September 30, 2010, from $6.0 million for the three months ended September 30, 2009. Severance taxes, which are a function of revenues generated from production, increased by approximately $4.4 million compared to the three months ended September 30, 2009, primarily due to higher commodity prices and higher total production volume levels. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased slightly compared to the three months ended September 30, 2009, primarily due to property acquisitions in the Permian Basin.

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

Other Income and (Expenses)

	Three Months Ended September 30,
	2010			2009			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(53,497	)	$	(28,025	)	$	(25,472	)
Realized losses on interest rate swaps		―			(10,958	)		10,958
Realized losses on canceled interest rate swaps		(49,590	)		―			(49,590	)
Unrealized gains (losses) on interest rate swaps		38,089			(14,751	)		52,840
Other, net		(1,136	)		(757	)		(379	)
	$	(66,134	)	$	(54,491	)	$	(11,643	)

Other income and (expenses) increased by approximately $11.6 million during the three months ended September 30, 2010, compared to the three months ended September 30, 2009. During the three months ended September 30, 2010, the Company canceled (before the contract settlement date) all of its remaining interest rate swap agreements, resulting in a realized loss of approximately $49.6 million. This loss was offset by an increase in unrealized gains and a decrease in realized losses on interest rate swaps during the three months ended September 30, 2010, compared to the three months ended September 30, 2009. Additionally, in the second and third quarters of 2010, the Company entered into an amendment to its Credit Facility and issued the 2020 Notes and the 2021 Notes, which resulted in increased interest expense due to higher interest rates and higher amortization of financing fees. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Expense

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized an income tax expense of approximately $33 thousand for the three months ended September 30, 2010, compared to an income tax expense of approximately $58 thousand for the same period in 2009.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $42.6 million or 30% to $185.0 million for the three months ended September 30, 2010, from $142.4 million for the three months ended September 30, 2009, primarily due to higher production revenues resulting from higher commodity prices and higher total production volume levels, partially offset by lower realized gains on commodity derivatives. See “Non-GAAP Financial Measures” on page 40 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.

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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, 2010, Compared to Nine Months Ended September 30, 2009

	Nine Months Ended September 30,
	2010			2009			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	158,114		$	111,749		$	46,365
Oil sales		237,815			119,171			118,644
NGL sales		83,958			43,839			40,119
Total oil, natural gas and NGL sales		479,887			274,759			205,128
Gains (losses) on oil and natural gas derivatives		263,299			(85,525	)		348,824
Natural gas marketing revenues		3,252			3,050			202
Other revenues		1,363			1,757			(394	)
	$	747,801		$	194,041		$	553,760
Expenses:
Lease operating expenses	$	111,490		$	100,322		$	11,168
Transportation expenses		15,030			11,850			3,180
Natural gas marketing expenses		2,209			1,318			891
General and administrative expenses (1)		71,545			63,247			8,298
Exploration costs		4,297			4,625			(328	)
Bad debt expenses		(89	)		500			(589	)
Depreciation, depletion and amortization		169,614			151,934			17,680
Taxes, other than income taxes		32,602			21,414			11,188
(Gains) losses on sale of assets and other, net		5,699			(24,717	)		30,416
	$	412,397		$	330,493		$	81,904
Other income and (expenses)	$	(200,455	)	$	(93,045	)	$	(107,410	)
Income (loss) from continuing operations before income taxes	$	134,949		$	(229,497	)	$	364,446

Adjusted EBITDA (2)	$	511,446		$	423,790		$	87,656
Adjusted net income (2)	$	156,299		$	154,257		$	2,042

(1)	General and administrative expenses for the nine months ended September 30, 2010, and September 30, 2009, include approximately $10.3 million and $11.2 million, respectively, of noncash unit-based compensation expenses.

(2)	This is a non-GAAP measure used by management to analyze the Company’s performance. See “Non-GAAP Financial Measures” on page 40 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

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

	Nine Months Ended September 30,
	2010		2009		Variance
Average daily production:
Natural gas (MMcf/d)		131		129		2	%
Oil (MBbls/d)		12.0		8.8		36	%
NGL (MBbls/d)		8.0		6.1		31	%
Total (MMcfe/d)		251		218		15	%

Weighted average prices (hedged): (1)
Natural gas (Mcf)	$	8.66	$	8.16		6	%
Oil (Bbl)	$	96.01	$	113.69		(16	)%
NGL (Bbl)	$	38.35	$	26.47		45	%

Weighted average prices (unhedged): (2)
Natural gas (Mcf)	$	4.42	$	3.18		39	%
Oil (Bbl)	$	72.57	$	49.68		46	%
NGL (Bbl)	$	38.35	$	26.47		45	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.59	$	3.93		17	%
Oil (Bbl)	$	77.65	$	57.19		36	%

Costs per Mcfe of production:
Lease operating expenses	$	1.63	$	1.69		(4	)%
Transportation expenses	$	0.22	$	0.20		10	%
General and administrative expenses (3)	$	1.04	$	1.06		(2	)%
Depreciation, depletion and amortization	$	2.47	$	2.56		(4	)%
Taxes, other than income taxes	$	0.48	$	0.36		33	%

(1)	Includes the effect of realized gains on derivatives of approximately $228.6 million and $328.2 million (excluding $49.0 million of realized net gains on canceled contracts) for the nine months ended September 30, 2010, and September 30, 2009, 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, 2010, and September 30, 2009, include approximately $10.3 million and $11.2 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the nine months ended September 30, 2010, and September 30, 2009, were $0.89 per Mcfe and $0.88 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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $205.1 million or 75% to approximately $479.9 million for the nine months ended September 30, 2010, from $274.8 million for the nine months ended September 30, 2009, due to higher commodity prices and higher production volumes. Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $75.0 million, $44.2 million and $26.0 million, respectively.

Average daily production volumes increased to 251 MMcfe/d during the nine months ended September 30, 2010, from 218 MMcfe/d during the nine months ended September 30, 2009. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $43.6 million, $2.2 million and $14.1 million, respectively.

	Nine Months Ended September 30,
	2010		2009		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		132		137		(5	)	(4	)%
Mid-Continent Shallow		66		67		(1	)	(1	)%
California		14		14		—		—
Permian Basin		22		—		22		—
Michigan		17		—		17		—
		251		218		33		15	%

The 4% decrease in average daily production volumes in the Mid-Continent Deep region primarily reflects natural declines, in addition to minimal capital development during the second half of 2009 due to low commodity prices, partially offset by the impact of the Company’s 2010 capital drilling program in the Granite Wash. Average daily production volumes in the Mid-Continent Shallow and California regions reflect the impact of optimization projects which offset the effect of natural declines. Average daily production volumes in the Permian Basin region reflect the Merit, Henry, CrownQuest/Element and Forest acquisitions in the first, second and third quarters of 2010 and the third quarter of 2009, respectively. Average daily production volumes in the Michigan region reflect the HighMount acquisition in the second quarter of 2010 (see Note 2).

Gains (Losses) on Oil and Natural Gas Derivatives

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for additional information about commodity derivatives. During the nine months ended September 30, 2010, the Company had commodity derivative contracts for approximately 120% of its natural gas production and 106% of its oil production, which resulted in realized gains of approximately $228.6 million. During the nine months ended September 30, 2009, the Company recorded realized gains of approximately $377.2 million (including realized net gains on canceled contracts of approximately $49.0 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 three quarters of 2010, expected future oil and natural gas prices decreased, which resulted in unrealized gains on derivatives of approximately $34.7 million for the nine months ended September 30, 2010. During the first three quarters of 2009, expected future oil and natural gas prices increased, which resulted in unrealized losses on derivatives of approximately $462.7 million for the nine months ended September 30, 2009. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

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

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $11.2 million or 11% to $111.5 million for the nine months ended September 30, 2010, from $100.3 million for the nine months ended September 30, 2009. Lease operating expenses increased primarily due to costs associated with properties acquired in the Permian Basin and Michigan regions in 2010 and late in the third quarter of 2009 (see Note 2). Lease operating expenses per Mcfe decreased to $1.63 per Mcfe for the nine months ended September 30, 2010, from $1.69 per Mcfe for the nine months ended September 30, 2009.

Transportation Expenses

Transportation expenses increased by approximately $3.1 million or 26% to $15.0 million for the nine months ended September 30, 2010, from $11.9 million for the nine months ended September 30, 2009, primarily due to increased production volumes. Transportation expenses also increased due to higher transportation rates associated with owned facilities.

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. General and administrative expenses increased by approximately $8.3 million or 13% to $71.5 million for the nine months ended September 30, 2010, from $63.2 million for the nine months ended September 30, 2009. The increase was primarily due to an increase in salaries and benefits expense of approximately $5.9 million, driven primarily by increased employee headcount, and acquisition integration expenses of approximately $3.7 million. These increases were partially offset by a decrease in professional fees. General and administrative expenses per Mcfe decreased to $1.04 per Mcfe for the nine months ended September 30, 2010, from $1.06 per Mcfe for the nine months ended September 30, 2009.

Exploration Costs

Exploration costs decreased by approximately $0.3 million or 7% to $4.3 million for the nine months ended September 30, 2010, from $4.6 million for the nine months ended September 30, 2009. The decrease was primarily due to fewer lease-term expirations related to unproved leasehold costs.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $17.7 million or 12% to $169.6 million for the nine months ended September 30, 2010, from $151.9 million for the nine months ended September 30, 2009. Higher total production volume levels, primarily due to the Company’s acquisitions in the Permian Basin and Michigan regions in 2010 and late in the third quarter of 2009, were the main reason for the increase. Depreciation, depletion and amortization per Mcfe decreased to $2.47 per Mcfe for the nine months ended September 30, 2010, from $2.56 per Mcfe for the nine months ended September 30, 2009.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $11.2 million or 52% to $32.6 million for the nine months ended September 30, 2010, from $21.4 million for the nine months ended September 30, 2009. Severance taxes, which are a function of revenues generated from production, increased by approximately $9.6 million compared to the nine months ended September 30, 2009, primarily due to higher commodity prices and higher total production volume levels. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased slightly compared to the nine months ended September 30, 2009, primarily due to property acquisitions in the Permian Basin.

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

During the nine months ended September 30, 2009, the Company recorded a gain of approximately $25.4 million from the sale of Woodford Shale assets (see Note 2).

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

Other Income and (Expenses)

	Nine Months Ended September 30,
	2010			2009			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(127,119	)	$	(65,696	)	$	(61,423	)
Realized losses on interest rate swaps		(8,021	)		(31,629	)		23,608
Realized losses on canceled interest rate swaps		(123,865	)		(60	)		(123,805	)
Unrealized gains on interest rate swaps		63,978			6,327			57,651
Other, net		(5,428	)		(1,987	)		(3,441	)
	$	(200,455	)	$	(93,045	)	$	(107,410	)

Other income and (expenses) increased by approximately $107.4 million during the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009, primarily due to increased realized losses on canceled interest rate swaps. During the nine months ended September 30, 2010, the Company canceled (before the contract settlement date) all of its remaining interest rate swap agreements, resulting in realized losses of approximately $123.9 million. These losses were partially offset by an increase in unrealized gains and a decrease in realized losses on interest rate swaps during the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009. Additionally, in the second and third quarters of 2010, the Company entered into an amendment to its Credit Facility and issued the 2020 Notes and the 2021 Notes, which resulted in increased interest expense due to higher interest rates and higher amortization of financing fees. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Expense

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $5.7 million and $0.4 million for the nine months ended September 30, 2010, and September 30, 2009, respectively. Income tax expense increased during the nine months ended September 30, 2010, primarily due to an increase in income as a result of cost recovery for unit-based compensation at the Company’s taxable subsidiary.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $87.6 million or 21% to $511.4 million for the nine months ended September 30, 2010, from $423.8 million for the nine months ended September 30, 2009, primarily due to higher production revenues resulting from higher commodity prices and higher total production volumes, partially offset by lower realized gains on commodity derivatives. See “Non-GAAP Financial Measures” on page 40 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.

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

Liquidity and Capital Resources

The Company utilizes funds from equity and debt offerings, bank borrowings and cash generated from operations for capital resources and liquidity. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties. For the nine months ended September 30, 2010, the Company’s capital expenditures, excluding acquisitions, were approximately $147.4 million. For 2010, the Company estimates its capital expenditures, excluding acquisitions, will be approximately $250.0 million. This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustment. The Company expects to fund these capital expenditures primarily with cash flow from operations.

As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves. The Company actively reviews acquisition opportunities on an ongoing basis. If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts, if available, or obtain additional debt or equity financing. The Company’s Credit Facility and other borrowings 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 to conduct its business and operations.

Statements of Cash Flows

The following is a comparative cash flow summary:

	Nine Months Ended September 30,
	2010			2009			Variance
	(in thousands)
Net cash:
Provided by operating activities (1)	$	183,419		$	330,124		$	(146,705	)
Used in investing activities		(1,013,549	)		(247,993	)		(765,556	)
Provided by (used in) financing activities		1,225,959			(100,204	)		1,326,163
Net increase (decrease) in cash and cash equivalents	$	395,829		$	(18,073	)	$	413,902

(1)	The nine months ended September 30, 2010, and September 30, 2009, include premiums paid for commodity derivatives of approximately $91.0 million and $93.6 million, respectively.

Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2010, was approximately $183.4 million, compared to $330.1 million for the nine months ended September 30, 2009. The decrease was primarily due to approximately $123.9 million in realized losses on canceled interest rate derivatives during the nine months ended September 30, 2010, compared to approximately $49.0 million in realized net gains on canceled commodity derivatives during the same period in 2009.

Premiums paid were for commodity derivative contracts that hedge future production and were primarily funded through the Company’s Credit Facility. These derivative contracts provide the Company long-term cash flow predictability to manage its business, service debt and pay distributions. The production volumes attributed to the derivative contracts the Company enters into in the future will be directly related to expected future production. See Note 7 and Note 8 for additional details about commodity derivatives.

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

Investing Activities

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

	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties, net of cash acquired	$	(894,521	)	$	(116,694	)
Capital expenditures		(119,724	)		(157,981	)
Proceeds from sale of properties and equipment		696			26,682
	$	(1,013,549	)	$	(247,993	)

The primary use of cash in investing activities is for capital spending, which is partially offset by proceeds from asset sales. Cash used in investing activities for the nine months ended September 30, 2010, relates to the acquisition of properties in Michigan, the Permian Basin and Mid-Continent regions. See Note 2 for additional details.

Capital expenditures were lower for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to the timing of drilling activities. The Company’s drilling program was accelerated in the first half of 2009 but was curtailed due to low commodity prices during the second half of the year. The drilling program has been accelerated during the second half of 2010 and capital expenditures for full year 2010 are expected to be approximately $250.0 million.

Proceeds from sale of properties were lower for the nine months ended September 30, 2010, compared to the same period in 2009, primarily due to the proceeds received in 2009 related to the sale of acreage in central Oklahoma (see Note 2).

Financing Activities

Cash provided by financing activities was approximately $1.23 billion for the nine months ended September 30, 2010, compared to cash used in financing activities of $100.2 million for the nine months ended September 30, 2009. The increase in financing cash flow was primarily attributable to proceeds from the Company’s March 2010 offering of units (see below) and increased borrowings to fund acquisitions, partially offset by repayments of debt. The following provides a comparative summary of proceeds from borrowings and repayments of debt:

	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Proceeds from borrowings:
Credit facility	$	920,000		$	361,500
Senior notes		2,250,816			237,703
	$	3,170,816		$	599,203
Repayments of debt:
Credit facility	$	(2,020,000	)	$	(513,893	)

Debt

The Company’s Credit Facility has a borrowing base of $1.50 billion and a maturity of April 2015. On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 and received net proceeds of approximately $1.24 billion. The Company used a portion of the net proceeds to repay all

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

of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with an amendment to its Credit Facility. The remaining proceeds were used to fund or partially fund acquisitions and for general corporate purposes. In addition, on September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 and received net proceeds of approximately $962.5 million. The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility and to unwind its remaining interest rate swap agreements. The remaining proceeds will be used to fund or partially fund acquisitions and for general corporate purposes.

At October 25, 2010, the Company had approximately $1.49 billion in available borrowing capacity under its Credit Facility. The Company also has outstanding $250.0 million in aggregate principal amount of 11.75% senior notes due 2017, $255.9 million in aggregate principal amount of 9.875% senior notes due 2018, $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021. For additional information about the Company’s debt instruments, such as interest rates and covenants, see Note 6. The Company is in compliance with all financial and other covenants of the Credit Facility and senior notes.

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 flow for investing activities and borrows as cash is needed. Absent such borrowings, 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. For additional information about this matter and other risk factors that could affect the Company, see Item 1A. “Risk Factors.”

Counterparty Credit Risk

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

Public Offering of Units

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

Distributions

Under the Company’s limited liability company agreement, 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, 2010:

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

August 2010	April 1 – June 30, 2010	$	0.63	$	92.9
May 2010	January 1 – March 31, 2010	$	0.63	$	93.1
February 2010	October 1 – December 31, 2009	$	0.63	$	82.3

On October 25, 2010, the Company’s Board of Directors declared a cash distribution of $0.66 per unit, or $2.64 per unit on an annualized basis, with respect to the third quarter of 2010, which represents a 5% increase over the previous quarter. This distribution, totaling approximately $97.3 million, will be paid on November 12, 2010, to unitholders of record as of the close of business on November 4, 2010.

Off-Balance Sheet Arrangements

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

Contingencies

The Company has been named as a defendant in a number of lawsuits and is involved in various other disputes arising in the ordinary course of business, including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes is adequate to provide for potential liabilities based upon its evaluation of these matters. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

During the nine months ended September 30, 2010, and September 30, 2009, 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 the table of contractual obligations in the 2009 Annual Report on Form 10-K. With the exception of: (i) an amendment to the Company’s Credit Facility that provides a $1.50 billion facility and extends the maturity from August 2012 to April 2015; (ii) the issuance of $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020; and (iii) the issuance of $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021, there have been no significant changes to the Company’s contractual obligations from December 31, 2009. See Note 6 for additional information about the Company’s debt instruments.

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

Non-GAAP Financial Measures

The non-GAAP financial measures of adjusted EBITDA and adjusted net income, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with income from continuing operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDA and adjusted net income should not be considered in isolation or as a substitute for GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA (Non-GAAP Measure)

Adjusted EBITDA is a measure used by Company management to indicate (prior to the establishment of any reserves by its Board of Directors) the cash distributions the Company expects to make to its unitholders. Adjusted EBITDA is also a quantitative measure used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

The Company defines adjusted EBITDA as income (loss) from continuing operations plus the following adjustments:

Net operating cash flow from acquisitions and divestitures, effective date through closing date;

Interest expense;

Depreciation, depletion and amortization;

Impairment of goodwill and long-lived assets;

Write-off of deferred financing fees and other;

(Gains) losses on sale of assets and other, net;

Provision for legal matters;

Unrealized (gains) losses on commodity derivatives;

Unrealized (gains) losses on interest rate derivatives;

Realized (gains) losses on interest rate derivatives;

Realized (gains) losses on canceled derivatives;

Unit-based compensation expenses;

Exploration costs; and

Income tax (benefit) expense.

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

The following presents a reconciliation of income (loss) from continuing operations to adjusted EBITDA:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands)

Income (loss) from continuing operations	$	4,143		$	(82,462	)	$	129,239		$	(229,876	)
Plus:
Net operating cash flow from acquisitions and divestitures, effective date through closing date		4,200			3,593			22,717			3,593
Interest expense, cash		16,125			21,978			55,818			50,990
Interest expense, noncash		37,372			6,047			71,301			14,706
Depreciation, depletion and amortization		62,482			49,440			169,614			151,934
Write-off of deferred financing fees and other		―			―			2,076			204
(Gains) losses on sale of assets and other, net		1,276			2,361			1,946			(23,290	)
Provision for legal matters		5,000			―			5,000			―
Unrealized (gains) losses on commodity derivatives		39,405			156,054			(34,726	)		462,727
Unrealized (gains) losses on interest rate derivatives		(38,089	)		14,751			(63,978	)		(6,327	)
Realized losses on interest rate derivatives		―			10,958			8,021			31,629
Realized (gains) losses on canceled derivatives		49,590			(44,780	)		123,865			(48,977	)
Unit-based compensation expenses		3,146			3,519			10,546			11,473
Exploration costs		281			861			4,297			4,625
Income tax expense		33			58			5,710			379
Adjusted EBITDA from continuing operations	$	184,964		$	142,378		$	511,446		$	423,790

The following presents a reconciliation of net cash provided by operating activities to adjusted EBITDA:

Net cash provided by operating activities for the three months ended September 30, 2010, was approximately $108.2 million and includes cash interest payments of approximately $15.9 million, realized losses on canceled derivatives of approximately $49.6 million and other items totaling approximately $11.3 million that are not included in adjusted EBITDA. Net cash provided by operating activities for the three months ended September 30, 2009, was approximately $71.9 million and includes cash interest payments of approximately $21.7 million, realized gains on canceled derivatives of approximately $(44.8) million, cash settlements on interest rate derivatives of approximately $11.0 million, premiums paid for commodity derivatives of approximately $93.6 million and other items totaling approximately $(11.0) million that are not included in adjusted EBITDA. Net cash provided by operating activities for the nine months ended September 30, 2010, was approximately $183.4 million and includes cash interest payments of approximately $55.4 million, cash settlements on interest rate derivatives of approximately $11.1 million, realized losses on canceled derivatives of approximately $123.9 million, premiums paid for commodity derivatives of approximately $91.0 million and other items totaling approximately $46.6 million that are not included in adjusted EBITDA. Net cash provided by operating activities for the nine months ended September 30, 2009, was approximately $330.1 million and includes cash interest payments of approximately $50.7 million, cash settlements on interest rate derivatives of approximately $30.8 million, realized gains on canceled derivatives of approximately $(49.0) million, premiums paid for commodity derivatives of $93.6 million and other items totaling approximately $(32.4) million that are not included in adjusted EBITDA.

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

Adjusted Net Income (Non-GAAP Measure)

Adjusted net income is a performance measure used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, impairment of goodwill and long-lived assets and (gains) losses on sale of assets, net.

The following presents a reconciliation of income (loss) from continuing operations to adjusted net income:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands, except per unit amounts)

Income (loss) from continuing operations	$	4,143		$	(82,462	)	$	129,239		$	(229,876	)
Plus:
Unrealized (gains) losses on commodity derivatives		39,405			156,054			(34,726	)		462,727
Unrealized (gains) losses on interest rate derivatives		(38,089	)		14,751			(63,978	)		(6,327	)
Realized (gains) losses on canceled derivatives		49,590			(44,780	)		123,865			(48,977	)
(Gains) losses on sale of assets, net		1,252			2,361			1,899			(23,290	)
Adjusted net income from continuing operations	$	56,301		$	45,924		$	156,299		$	154,257

Income (loss) from continuing operations per unit – basic	$	0.03		$	(0.69	)	$	0.91		$	(1.97	)
Plus, per unit:
Unrealized (gains) losses on commodity derivatives		0.26			1.30			(0.24	)		3.96
Unrealized (gains) losses on interest rate derivatives		(0.26	)		0.12			(0.45	)		(0.05	)
Realized (gains) losses on canceled derivatives		0.34			(0.37	)		0.87			(0.42	)
(Gains) losses on sale of assets, net		0.01			0.02			0.01			(0.20	)
Adjusted net income from continuing operations per unit – basic	$	0.38		$	0.38		$	1.10		$	1.32

Critical Accounting Policies and Estimates

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

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

Recently Issued Accounting Standards Not Yet Adopted

There are no recently issued accounting standards not yet adopted that the Company expects will have a material impact to its results of operations or financial position.

Cautionary Statement

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

business strategy;

acquisition strategy;

financial strategy;

drilling locations;

oil, natural gas and NGL reserves;

realized oil, natural gas and NGL prices;

production volumes;

lease operating expenses, general and administrative expenses 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 set forth in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2009, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2009 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.”

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 7). At September 30, 2010, the fair value of contracts that settle during the next 12 months was an asset of approximately $285.7 million and a liability of $2.9 million for a net asset of approximately $282.8 million. A 10% increase in the index oil and natural gas prices above the September 30, 2010, prices for the next 12 months would result in a net asset of approximately $215.4 million which represents a decrease in the fair value of approximately $67.4 million; conversely, a 10% decrease in the index oil and natural gas prices would result in a net asset of approximately $350.4 million which represents an increase in the fair value of approximately $67.6 million.

Counterparty Credit Risk

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

At September 30, 2010, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 3.76%. A 1% increase in the average public bond yield spread would result in an estimated $1.1 million increase in net income for the nine months ended September 30, 2010. At September 30, 2010, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.21%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $1.6 million decrease in net income for the nine months ended September 30, 2010.

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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, 2010.

Changes in the Company’s Internal Control Over Financial Reporting

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

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

There were no changes in the Company’s internal controls over financial reporting during the third quarter of 2010 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

For a discussion of general legal proceedings, see Note 10 of Notes to Condensed Consolidated Financial Statements.

Environmental

In May 2010, the Company entered into a settlement agreement with the South Coast Air Quality Management District under which the Company agreed to pay penalties and fees for improper natural gas flaring under its current permit. The Company has not been cited for violation of emission standards associated with this activity and it is taking appropriate steps to remedy the situation. The Company estimates that total penalties associated with this matter will be approximately $100 thousand and has paid approximately $73 thousand as of September 30, 2010. The Company does not expect this matter to have a material adverse impact on its financial condition or results of operations.

Item 1A. Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial position, results of operations, liquidity or the trading price of our units are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009. Except as set forth below, as of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

The value of an investment in our units could be affected by recent and potential federal tax increases.

Absent new legislation extending the current rates, in taxable years beginning after December 31, 2010, the highest marginal United States federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects certain individuals, estates and trusts to an Unearned Income Medicare Contribution tax of 3.8% on certain income. In the case of an individual having a modified adjusted gross income in excess of $200 thousand (or $250 thousand for married taxpayers filing joint returns), the provision imposes a tax equal to 3.8% of the lesser of such excess and the individual’s “net investment income,” which will include net income and gains from the ownership or disposition of our units.

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

Issuer Purchases of Equity Securities

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the three months ended September 30, 2010. At September 30, 2010, approximately $73.8 million was available for unit repurchase under the program.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Reserved

Item 5. Other Information

The Company is a limited liability company and its units representing limited liability company interests (“units”) are listed on the NASDAQ Global Select Market. The SEC’s taxonomy for interactive data reporting does not contain tags that include the term “units” for all existing equity accounts; therefore, in certain instances, the Company has used tags that refer to “shares” or “stock” rather than “units” in its interactive data exhibit. These tags were selected to enhance comparability between the Company and its peers and it should not be inferred from the usage of these tags that an investment in the Company is in any form other than “units” as described above. The Company’s interactive data files are included as Exhibit 101 to this Quarterly Report on Form 10-Q.

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Item 6. Exhibits

Exhibit Number			Description
2	.1*†	—	Purchase and Sale Agreement, dated September 3, 2010, between Linn Energy Holdings, LLC, as purchaser and Patriot Resources Partners LLC, as seller
2	.2*†	—	Purchase and Sale Agreement, dated September 3, 2010, between Linn Energy Holdings, LLC, as purchaser and Crownrock, LP, as seller
2	.3*†	—	Purchase and Sale Agreement, dated September 2, 2010, between Linn Energy Holdings, LLC, as purchaser and Element Petroleum, LP, as seller
3	.1	—	Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC, dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Current Report on Form 8-K filed September 7, 2010)
4	.1	—	Indenture, dated September 13, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed September 13, 2010)
4	.2	—	Registration Rights Agreement, dated September 13, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed September 7, 2010)
10	.1*	—	Fourth Amendment, dated October 15, 2010, to Fourth Amended and Restated Credit Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto
31	.1*	—	Section 302 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
31	.2*	—	Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32	.1*	—	Section 906 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
32	.2*	—	Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
101	.INS**	—	XBRL Instance Document
101	.SCH**	—	XBRL Taxonomy Extension Schema Document
101	.CAL**	—	XBRL Taxonomy Extension Calculation Linkbase Document
101	.DEF**	—	XBRL Taxonomy Extension Definition Linkbase Document
101	.LAB**	—	XBRL Taxonomy Extension Label Linkbase Document
101	.PRE**	—	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.

**	Furnished herewith.

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

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SIGNATURE

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

	LINN ENERGY, LLC
	(Registrant)


Date: October 28, 2010	/s/ David B. Rottino
	David B. Rottino
	Senior Vice President of Finance, Business Development and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)