Edgar Filing: LINN ENERGY, LLC

form10qq12009.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 March 31, 2009

¨	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 (1) has submitted electronically and posted on its corporate Web site, 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 ¨ No ¨

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

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

(Do not check if a smaller reporting company)

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

As of April 30, 2009, there were 114,974,267 units outstanding.

TABLE OF CONTENTS

		Page

	Glossary of Terms	ii

	Part I - Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008	1
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008	2
	Condensed Consolidated Statement of Unitholders’ Capital for the three months ended March 31, 2009	3
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and 2008	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34
	Part II - Other Information
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Submission of Matters to a Vote of Security Holders	35
Item 5.	Other Information	35
Item 6.	Exhibits	36
	Signature	37

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GLOSSARY OF TERMS

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

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

Bcf. One billion cubic feet.

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

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 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 gas to one Bbl of oil, condensate or natural gas liquids.

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

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of 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 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

	March 31,			December 31,
	2009			2008
	(Unaudited)
	(in thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	22,893		$	28,668
Accounts receivable – trade, net		110,561			138,983
Derivative instruments		428,638			368,951
Other current assets		47,142			27,329
Total current assets		609,234			563,931

Noncurrent assets:
Oil and gas properties (successful efforts method)		3,901,557			3,831,183
Less accumulated depletion and amortization		(329,248	)		(278,805	)
		3,572,309			3,552,378

Other property and equipment		114,131			111,459
Less accumulated depreciation		(15,773	)		(13,171	)
		98,358			98,288

Derivative instruments		480,067			493,705
Other noncurrent assets		12,950			13,718
		493,017			507,423
Total noncurrent assets		4,163,684			4,158,089
Total assets	$	4,772,918		$	4,722,020

Liabilities and Unitholders’ Capital
Current liabilities:
Accounts payable and accrued expenses	$	144,208		$	163,662
Derivative instruments		35,724			47,005
Other accrued liabilities		15,965			27,163
Total current liabilities		195,897			237,830

Noncurrent liabilities:
Credit facility		1,428,393			1,403,393
Senior notes, net		250,265			250,175
Derivative instruments		55,624			39,350
Other noncurrent liabilities		33,352			30,586
Total noncurrent liabilities		1,767,634			1,723,504

Unitholders’ capital:
114,975,396 and 114,079,533 units issued and outstanding at March 31, 2009 and December 31, 2008, respectively		2,038,389			2,109,089
Accumulated income		770,998			651,597
		2,809,387			2,760,686
Total liabilities and unitholders’ capital	$	4,772,918		$	4,722,020

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 March 31,
	2009			2008
	(in thousands, except per unit amounts)
Revenues and other:
Oil, gas and natural gas liquid sales	$	79,864		$	175,872
Gain (loss) on oil and gas derivatives		161,315			(268,794	)
Gas marketing revenues		516			2,816
Other revenues		966			479
		242,661			(89,627	)
Expenses:
Lease operating expenses		33,732			19,490
Transportation expenses		2,967			3,328
Gas marketing expenses		340			2,417
General and administrative expenses		23,301			19,076
Exploration costs		1,565			2,620
Depreciation, depletion and amortization		52,104			44,370
Taxes, other than income taxes		7,567			12,973
(Gain) loss on sale of assets and other, net		(26,711	)		―
		94,865			104,274
Other income and (expenses):
Interest expense, net of amounts capitalized		(14,409	)		(25,293	)
Loss on interest rate swaps		(11,571	)		(39,393	)
Other, net		(393	)		(163	)
		(26,373	)		(64,849	)
Income (loss) from continuing operations before income taxes		121,423			(258,750	)
Income tax expense		(136	)		(209	)
Income (loss) from continuing operations		121,287			(258,959	)

Discontinued operations:
Loss on sale of assets, net of taxes		(1,048	)		(294	)
Loss from discontinued operations, net of taxes		(838	)		(106	)
		(1,886	)		(400	)

Net income (loss)	$	119,401		$	(259,359	)

Income (loss) per unit – continuing operations:
Units – basic	$	1.06		$	(2.28	)
Units – diluted	$	1.06		$	(2.28	)
Loss per unit – discontinued operations:
Units – basic	$	(0.02	)	$	―
Units – diluted	$	(0.02	)	$	―
Net income (loss) per unit:
Units – basic	$	1.04		$	(2.28	)
Units – diluted	$	1.04		$	(2.28	)
Weighted average units outstanding:
Units – basic		113,473			113,757
Units – diluted		113,502			113,757

Distributions declared per unit	$	0.63		$	0.63

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, 2008		114,080		$	2,109,089		$	651,597	$	―		$	2,760,686
Issuance of units		1,072			―			―		―			―
Cancellation of units		(177	)		(2,465	)		―		2,465			―
Purchase of units					―			―		(2,465	)		(2,465	)
Distributions to unitholders					(72,538	)		―		―			(72,538	)
Unit-based compensation expenses					4,303			―		―			4,303
Net income					―			119,401		―			119,401
March 31, 2009		114,975		$	2,038,389		$	770,998	$	―		$	2,809,387

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)

	Three Months Ended March 31,
	2009			2008
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	119,401		$	(259,359	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		52,104			50,587
Unit-based compensation expenses		4,303			3,888
Amortization and write-off of deferred financing fees and other		2,487			1,876
(Gain) loss on sale of assets, net		(24,663	)		294
Mark-to-market on derivatives:
Total (gains) losses		(149,744	)		308,187
Cash settlements		104,430			(1,958	)
Cash settlements on canceled derivatives		4,257			―
Premiums paid for derivatives		―			(1,278	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		42,371			(45,878	)
(Increase) decrease in other assets		(20,150	)		1,245
Increase (decrease) in accounts payable and accrued expenses		(30,020	)		1,554
Increase (decrease) in other liabilities		(9,806	)		2,042
Net cash provided by operating activities		94,970			61,200
Cash flow from investing activities:
Acquisition of oil and gas properties		―			(515,894	)
Development of oil and gas properties		(67,984	)		(92,739	)
Purchases of other property and equipment		(2,767	)		(4,661	)
Proceeds from sales of oil and gas properties and other property and equipment		11,934			―
Net cash used in investing activities		(58,817	)		(613,294	)
Cash flow from financing activities:
Purchase of units		(2,465	)		(1,451	)
Proceeds from issuance of debt		75,000			667,000
Principal payments on debt		(50,000	)		(44,927	)
Distributions to unitholders		(72,538	)		(72,189	)
Financing fees and other, net		8,075			3,296
Net cash provided by (used in) financing activities		(41,928	)		551,729
Net decrease in cash and cash equivalents		(5,775	)		(365	)
Cash and cash equivalents:
Beginning		28,668			1,441
Ending	$	22,893		$	1,076

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 gas company focused on the development and acquisition of long life properties which complement its asset profile in producing basins within the United States.

Principles of Consolidation and Reporting

The condensed consolidated financial statements at March 31, 2009, and for the three months ended March 31, 2009 and 2008, are unaudited, but in the opinion of management include all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with United States generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations, and as such this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. 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.

Presentation Change

Certain amounts in the condensed consolidated financial statements and notes thereto have been reclassified to conform to the 2009 financial statement presentation. In particular, the condensed consolidated statements of operations include categories of expense titled “lease operating expenses,” “transportation expenses,” “exploration costs,” “taxes, other than income taxes” and “(gain) loss on sale of assets and other, net” which were not reported in prior period presentations. The new categories present expenses in greater detail than was previously reported and all comparative periods presented have been reclassified to conform to the 2009 financial statement presentation. There was no impact to net income (loss) for prior periods.

Discontinued Operations

The Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. (“Mid Atlantic”) operations have been classified as discontinued operations on the condensed consolidated statements of operations for all periods presented. Unless otherwise indicated, information about the statements of operations that is presented in the notes to condensed consolidated financial statements relates only to LINN Energy’s continuing operations. See Note 2 for additional details.

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

reserves of oil, gas and natural gas liquids (“NGL”), future cash flows from oil and gas properties, depreciation, depletion and amortization, asset retirement obligations, the fair value of derivatives and unit-based compensation expenses. 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. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. 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.

(2)	Acquisitions, Divestitures and Discontinued Operations

Acquisitions

On January 31, 2008, the Company completed the acquisition of certain oil and gas properties located primarily in the Mid-Continent Shallow region from Lamamco Drilling Company for a purchase price of $542.2 million.

Divestitures

On December 4, 2008, the Company completed the sale of its deep rights in certain central Oklahoma acreage, which includes the Woodford Shale interval, to Devon Energy Production Company, LP (“Devon”). During 2008, the Company received net proceeds of $153.2 million and the carrying value of net assets sold was $54.2 million. In the first quarter of 2009, certain post closing matters were resolved and the Company recorded a gain of $25.4 million, which is recorded in “(gain) loss on sale of assets and other, net” on the condensed consolidated statements of operations. Of this amount, approximately $13.9 million was received in April 2009 and is included in “other current assets” on the condensed consolidated balance sheets at March 31, 2009.

On August 15, 2008, the Company completed the sale of certain properties in the Verden area in Oklahoma to Laredo Petroleum, Inc. During 2008, the Company received net proceeds equal to the carrying value of net assets sold of $169.4 million.

On July 1, 2008, the Company completed the sale of its interests in oil and gas properties located in the Appalachian Basin to XTO Energy, Inc. During 2008, the Company received net proceeds of $566.5 million and the carrying value of net assets sold was $405.8 million. In addition, in March 2008, the Company exited the drilling and service business in the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic. The Company used the net proceeds from all divestitures to reduce indebtedness (see Note 6).

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

Discontinued Operations

The Company’s Appalachian Basin and Mid Atlantic operations have been classified as discontinued operations on the condensed consolidated statements of operations for all periods presented. The following summarizes the Appalachian Basin and Mid Atlantic amounts included in “loss from discontinued operations, net of taxes” on the condensed consolidated statements of operations:

	Three Months Ended March 31,
	2009			2008
	(in thousands)

Total revenues and other	$	(1,211	)	$	21,161
Total operating expenses		373			(14,176	)
Interest expense		―			(7,091	)
Loss from discontinued operations, net of taxes	$	(838	)	$	(106	)

Discontinued operations activity in the three months ended March 31, 2009 primarily represents activity related to post-closing adjustments. The Company computed interest expense related to discontinued operations in accordance with Emerging Issues Task Force Issue No. 87-24, “Allocation of Interest to Discontinued Operations” based on debt required to be repaid as a result of the disposal transaction.

(3)	Unitholders’ Capital

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. During the three months ended March 31, 2009, 123,800 units were purchased at an average unit price of $12.99, for a total cost of approximately $1.6 million. All units were subsequently canceled. At March 31, 2009, approximately $85.4 million remains available for unit repurchase under the program. The Company may purchase units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are purchased at fair market value on the date of purchase.

Issuance and Cancellation of Units

During the three months ended March 31, 2009, the Company purchased 53,667 units for approximately $0.9 million in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan (see Note 12). All units were subsequently canceled.

Distributions

Under the limited liability company agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the Company during the three months ended March 31, 2009 are presented on the condensed consolidated statement of unitholders’ capital. On

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

April 23, 2009, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the first quarter of 2009. The distribution totaling approximately $72.5 million will be paid on May 14, 2009, to unitholders of record as of the close of business on May 6, 2009.

(4)	Oil and Gas Capitalized Costs

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

	March 31, 2009			December 31, 2008
	(in thousands)
Proved properties:
Leasehold acquisition	$	3,278,033		$	3,278,155
Development		531,173			460,730
Unproved properties		92,351			92,298
		3,901,557			3,831,183
Less accumulated depletion and amortization		(329,248	)		(278,805	)
	$	3,572,309		$	3,552,378

(5)	Business and Credit Concentrations

For the three months ended March 31, 2009, the Company’s three largest customers represented 19%, 17% and 16% of the Company’s sales. For the three months ended March 31, 2008, the Company’s two largest customers represented 24% and 14% of the Company’s sales.

At March 31, 2009, trade accounts receivable from three customers were greater than 10% of the Company’s total trade accounts receivable. At March 31, 2009, trade accounts receivable from the Company’s three largest customers represented approximately 19%, 15% and 15% of the Company’s receivables. At December 31, 2008, trade accounts receivable from two customers were greater than 10% of the Company’s total trade accounts receivable. At December 31, 2008, trade accounts receivable from the Company’s two largest customers represented approximately 20% and 16% of the Company’s receivables.

(6)

Debt

At March 31, 2009, and December 31, 2008, the Company had the following debt outstanding:

	March 31, 2009		December 31, 2008
	(in thousands)

Credit facility (1)	$	1,428,393	$	1,403,393
Senior notes, net (2)		250,265		250,175
Less current maturities		―		―
	$	1,678,658	$	1,653,568

(1)

Variable interest rate of 2.03% at March 31, 2009, and 2.47% at December 31, 2008.

(2)

Fixed interest rate of 9.875% and effective interest rate of 10.25%. Amount is net of unamortized discount of approximately $5.7 million and $5.8 million at March 31, 2009, and December 31, 2008, respectively.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

Credit Facility

At March 31, 2009, the Company had a $1.85 billion borrowing base under its Third Amended and Restated Credit Agreement with a maturity of August 2010. On April 28, 2009, the Company entered into a Fourth Amended and Restated Credit Agreement (“Credit Facility”), which amended and restated the Company’s prior credit facility. The Credit Facility has a borrowing base of $1.75 billion and a maturity of August 2012. In connection with its new Credit Facility, during the second quarter of 2009, the Company paid approximately $52.6 million in financing fees, which were deferred and will be amortized over the life of the Credit Facility. In addition, during the second quarter of 2009, the Company wrote off deferred financing fees related to its prior credit facility of approximately $3.6 million.

The borrowing base under the Credit Facility will be redetermined semi-annually by the lenders in their sole discretion, based on, among other things, reserve reports as prepared by reserve engineers taking into account the oil and gas prices at such time. Significant declines in oil, gas or NGL 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 gas properties as well as a pledge of all ownership interests in its operating subsidiaries. The Company is required to maintain the mortgages on properties representing at least 80% of its oil and gas properties. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material operating subsidiaries and may be guaranteed by any future subsidiaries.

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.50% and 3.25% per annum or the alternate base rate (“ABR”) plus an applicable margin between 1.00% and 1.75% 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 fee of 0.5% per year on the unused portion of the borrowing base under the Credit Facility.

The Credit Facility contains various covenants, substantially similar to the prior credit facility, that limit the Company’s ability to incur indebtedness, enter into commodity and interest rate swaps, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, make distributions other than from available cash, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. The Credit Facility also contains covenants, substantially similar to the prior credit facility, that require the Company to maintain adjusted earnings to interest expense and current liquidity financial ratios. The Company is in compliance with all financial and other covenants of its Credit Facility.

At March 31, 2009, available borrowing under the prior credit facility was $415.4 million, which includes a $6.2 million reduction in availability for outstanding letters of credit. At April 30, 2009, available borrowing under the new Credit Facility was $296.0 million, which includes a $5.6 million reduction in availability for outstanding letters of credit.

Senior Notes

On June 24, 2008, the Company entered into a purchase agreement with a group of initial purchasers (“Initial Purchasers”) pursuant to which the Company agreed to issue $255.9 million in aggregate principal amount of the Company’s senior notes due 2018 (“Senior Notes”). The Senior Notes were offered and sold to the Initial Purchasers and then resold to qualified institutional buyers each in transactions exempt from the registration requirements under the Securities Act of 1933, as amended (“Securities Act”). The Company used the net proceeds (after deducting the Initial Purchasers’ discounts and offering expense) of approximately $243.6 million to repay an outstanding term loan. In connection with the Senior Notes, the Company incurred financing fees of approximately $7.8 million, which will be amortized over the life of

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

the Senior Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. The $5.9 million discount on the Senior Notes will be amortized over the life of the Senior Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. See Note 8 for fair value disclosures related to the Senior Notes.

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

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

(7)	Derivatives

Commodity Derivatives

The Company sells oil, gas and NGL in the normal course of its business and utilizes derivative instruments to minimize the variability in cash flows due to price movements in oil, gas and NGL. The Company enters into derivative instruments such as swap contracts, collars and put options to economically hedge a portion of its forecasted oil, gas and NGL sales. Oil puts are also used to economically hedge NGL sales. The Company did not designate these contracts as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, (“SFAS 133”); therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for additional disclosures about oil and gas commodity derivatives required by SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

The following table summarizes open positions as of March 31, 2009, and represents, as of such date, derivatives in place through December 31, 2014, on annual production volumes:

	Year 2009			Year 2010			Year 2011			Year 2012			Year 2013			Year 2014
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMMBtu)		29,689			39,566			31,901			14,676			―			―
Average Price ($/MMBtu)	$	8.53		$	8.50		$	8.50		$	8.57		$	―		$	―
Puts:
Hedged Volume (MMMBtu)		5,220			6,960			6,960			―			―			―
Average Price ($/MMBtu)	$	7.50		$	7.50		$	7.50		$	―		$	―		$	―
PEPL Puts: (1)
Hedged Volume (MMMBtu)		4,001			10,634			13,259			5,934			―			―
Average Price ($/MMBtu)	$	7.85		$	7.85		$	7.85		$	7.85		$	―		$	―
Total:
Hedged Volume (MMMBtu)		38,910			57,160			52,120			20,610			―			―
Average Price ($/MMBtu)	$	8.32		$	8.26		$	8.20		$	8.37		$	―		$	―

Oil Positions:
Fixed Price Swaps:
Hedged Volume (MBbls)		1,828			2,150			2,073			2,025			2,275			2,200
Average Price ($/Bbl)	$	90.00		$	90.00		$	84.22		$	84.22		$	84.22		$	84.22
Puts: (2)
Hedged Volume (MBbls)		1,382			2,250			2,352			500			―			―
Average Price ($/Bbl)	$	120.00		$	110.00		$	69.11		$	77.73		$	―		$	―
Collars:
Hedged Volume (MBbls)		187			250			276			348			―			―
Average Floor Price ($/Bbl)	$	90.00		$	90.00		$	90.00		$	90.00		$	―		$	―
Average Ceiling Price ($/Bbl)	$	114.25		$	112.00		$	112.25		$	112.35		$	―		$	―
Total:
Hedged Volume (MBbls)		3,397			4,650			4,701			2,873			2,275			2,200
Average Price ($/Bbl)	$	102.21		$	99.68		$	77.00		$	83.79		$	84.22		$	84.22

Gas Basis Differential Positions:
PEPL Basis Swaps:
Hedged Volume (MMMBtu)		35,187			43,166			35,541			34,066			31,700			―
Hedged Differential ($/MMBtu)	$	(0.97	)	$	(0.97	)	$	(0.96	)	$	(0.95	)	$	(1.01	)	$	―

(1)

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

(2)

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

Settled derivatives on gas production for the three months ended March 31, 2009 included a volume of 12,970 MMMBtu at an average contract price of $8.32. Settled derivatives on oil and NGL production for the three months ended March 31, 2009 included a volume of 1,132 MBbls at an average contract price of $102.21. The gas derivatives are settled based on the closing New York Mercantile Exchange (“NYMEX”) future price of gas or on the published PEPL spot price of 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.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

Interest Rate Swaps

The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparties the difference, and conversely, the counterparties are required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not designate the interest rate swap agreements as cash flow hedges under SFAS 133; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for additional disclosures about interest rate swaps required by SFAS 157.

During the three months ended March 31, 2009, the Company amended and extended its interest rate swap portfolio. The Company canceled, in a cashless transaction, its interest rate swap agreements that settled at a fixed rate of 5.06% through 2011, and entered into new agreements that settle at a fixed rate of 3.80% through 2014. The following presents the settlement terms of the interest rate swaps at March 31, 2009:

	Year 2009			Year 2010			Year 2011			Year 2012			Year 2013 (1)
	(dollars in thousands)

Notional Amount	$	1,250,000		$	1,250,000		$	1,250,000		$	1,250,000		$	1,250,000
Fixed Rate		3.80	%		3.80	%		3.80	%		3.80	%		3.80	%

(1)

Actual settlement term is through January 6, 2014.

In April 2009, the Company canceled one interest rate swap agreement. At April 30, 2009, the Company had swap agreements with an aggregate notional amount of $1.21 billion that settle at a fixed rate of 3.85% through 2014.

Outstanding Notional Amounts

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

	March 31, 2009		December 31, 2008

Outstanding notional amounts of gas contracts (MMMBtu)		168,800		196,756
Maximum number of months gas contracts outstanding		45		48
Outstanding notional amounts of oil contracts (MBbls)		20,096		21,229
Maximum number of months oil contracts outstanding		69		72
Outstanding notional amount of interest rate swaps (in thousands)	$	1,250,000	$	1,212,000
Maximum number of months interest rate swaps outstanding		57		24

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

Balance Sheet Presentation

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

	March 31, 2009		December 31, 2008
	(in thousands)
Assets:
Commodity derivatives	$	1,044,788	$	977,847
Interest rate swaps		553		―
	$	1,045,341	$	977,847
Liabilities:
Commodity derivatives	$	142,444	$	119,124
Interest rate swaps		85,540		82,422
	$	227,984	$	201,546

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 participants in its Credit Facility (see Note 6) which is secured by the Company’s oil and gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from the counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.05 billion at March 31, 2009. 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 are also lenders in the Company’s Credit Facility, and 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 swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated at March 31, 2009.

Gain (Loss) on Derivatives

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

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

	Three Months Ended March 31,
	2009			2008
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	119,812		$	(4,809	)
Canceled commodity derivatives		4,257			―
Interest rate swaps		(10,114	)		(1,441	)
	$	113,955		$	(6,250	)
Unrealized gains (losses):
Commodity derivatives	$	37,246		$	(263,985	)
Interest rate swaps		(1,457	)		(37,952	)
	$	35,789		$	(301,937	)
Total gains (losses):
Commodity derivatives	$	161,315		$	(268,794	)
Interest rate swaps		(11,571	)		(39,393	)
	$	149,744		$	(308,187	)

During the three months ended March 31, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production resulting in realized gains of $4.3 million.

(8)	Fair Value Measurements

Fair Value Measurements on a Recurring Basis

The Company accounts for its oil and gas commodity derivatives and interest rate swaps at fair value (see Note 7) on a recurring basis in accordance with the provisions of SFAS 157. As such, assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives and interest rate swaps.

The following presents the Company’s fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at March 31, 2009. These items are included in “derivative instruments” on the condensed consolidated balance sheets.

	Fair Value Measurements on a Recurring Basis March 31, 2009
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	1,044,788	$	(136,367	)	$	908,421
Interest rate swaps	$	553	$	(269	)	$	284

Liabilities:
Commodity derivatives	$	142,444	$	(136,367	)	$	6,077
Interest rate swaps	$	85,540	$	(269	)	$	85,271

(1)

Represents counterparty netting under derivative netting agreements.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

Fair Value Measurements on a Nonrecurring Basis

Effective January 1, 2009, the Company adopted SFAS 157 for nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis. The Company accounts for additions to its asset retirement obligation liability (see Note 9) and impairment of long-lived assets, if any, at fair value on a nonrecurring basis in accordance with the provisions of SFAS 157.

The following presents the Company’s fair value hierarchy for assets and liabilities measured at fair value on a nonrecurring basis at March 31, 2009. These items are included in “other noncurrent liabilities” on the condensed consolidated balance sheets.

	Level 3
	(in thousands)
Liabilities:
Asset retirement obligations – liabilities added related to drilling	$	32

The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandon cost per well based on Company experience; (ii) estimated remaining life per well based on average reserve life per field; and (iii) the Company’s average credit-adjusted risk-free interest rate (10.1% for the three months ended March 31, 2009). There was no impact to the Company’s results of operations for the three months ended March 31, 2009 from the adoption of SFAS 157 for nonfinancial assets and liabilities.

At March 31, 2009, the Company also had Senior Notes with a net carrying value of $250.3 million (see Note 6) and a fair value of $209.4 million. The fair value of the Senior Notes was estimated based on prices quoted from third-party financial institutions.

(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. See Note 8 for additional disclosures about asset retirement obligations required by SFAS 157.

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

Asset retirement obligations at December 31, 2008	$	28,922
Liabilities added related to drilling		32
Current year accretion expense		685
Settlements		(386	)
Revision of estimates		1,043
Asset retirement obligations at March 31, 2009	$	30,296

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

(10)	Commitments and Contingencies

On September 15, 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) with the United States Bankruptcy Court for the Southern District of New York (the “Court”). On October 3, 2008, Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) also filed a voluntary petition for reorganization under Chapter 11 with the Court. As of March 31, 2009, and December 31, 2008, the Company had a receivable of approximately $67.6 million from Lehman Commodity Services for canceled derivative contracts. The Company is pursuing various legal remedies to protect its interests. At March 31, 2009, and December 31, 2008, the Company estimated approximately $6.7 million of the receivable balance to be collectible. The net receivable of approximately $6.7 million is included in “other current assets” on the condensed consolidated balance sheets at March 31, 2009 and December 31, 2008. The Company believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

From time to time the Company is a party to various legal proceedings or is subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its business, financial position, results of operations or liquidity.

(11)	Earnings Per Unit

Effective January 1, 2009, the Company adopted Financial Accounting Standards Board (“FASB”) Staff Position EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”), which requires that the Company’s unvested restricted units be included in the computation of earnings per unit under the two-class method. FSP EITF 03-6-1 requires retrospective adjustment of all prior period earnings per unit data. The Company had no impact from the adoption of FSP EITF 03-6-1 as it reported a loss from continuing operations for the three months ended March 31, 2008.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

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

	Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Three months ended March 31, 2009:
Income from continuing operations:
Allocated to units	$	121,287
Allocated to unvested restricted units		(1,485	)
	$	119,802
Income per unit:
Basic income per unit					113,473	$	1.06
Dilutive effect of unit equivalents					29		―
Diluted income per unit					113,502	$	1.06

Three months ended March 31, 2008:
Loss from continuing operations:
Allocated to units	$	(258,959	)
Allocated to unvested restricted units		―
	$	(258,959	)

Loss per unit:
Basic loss per unit					113,757	$	(2.28	)
Dilutive effect of unit equivalents					―		―
Diluted loss per unit					113,757	$	(2.28	)

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 2.0 million and 1.6 million unit options and warrants for the three months ended March 31, 2009 and March 31, 2008, respectively. All equivalent units were anti-dilutive for the three months ended March 31, 2008, as the Company reported a loss from continuing operations.

(12)	Unit-Based Compensation

During the three months ended March 31, 2009, the Company granted 1,076,255 restricted units and 382,405 unit options to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $17.4 million. The unit options and restricted units vest ratably over three years. For the three months ended March 31, 2009 and 2008, the Company recorded unit-based compensation expenses in continuing operations of approximately $4.3 million and $3.6 million, respectively, and it is included in “lease operating expenses” or “general and administrative expenses” on the condensed consolidated statements of operations.

(13)	Income Taxes

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

(14)	Related Party Transactions

At March 31, 2008, and during the three months ended March 31, 2008, on an aggregate basis, a group of certain direct or indirect wholly owned subsidiaries of Lehman Holdings owned over 10% of the Company’s outstanding units. A reference to “Lehman” hereafter in this footnote refers to Lehman Holdings or one or more of its subsidiaries, as applicable. As such, Lehman was considered a related party under the provisions of SFAS No. 57, “Related Party Disclosures” during that time frame. Lehman’s subsidiaries provided certain services to the Company, including participation in the Company’s Credit Facility and offering of Senior Notes (see Note 6) and sale of commodity derivative instruments (see Note 7), which were all consummated on terms equivalent to those that prevail in arm’s-length transactions. During the three months ended March 31, 2008, the Company paid distributions on units to Lehman of approximately $9.3 million, interest on borrowings of approximately $1.1 million and financing fees of approximately $0.4 million. During the three months ended March 31, 2008, the Company purchased approximately $1.3 million of deal contingent oil swap contracts from Lehman and paid Lehman approximately $0.8 million on settled derivative contracts.

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

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

	March 31, 2009		December 31, 2008
	(in thousands)

Accrued compensation	$	6,629	$	11,366
Accrued interest		7,160		14,232
Other		2,176		1,565
	$	15,965	$	27,163

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

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

	Three Months Ended March 31,
	2009		2008
	(in thousands)

Cash payments for interest	$	20,610	$	29,902

Cash payments for income taxes	$	1	$	205

Non-cash investing activities:
In connection with the purchase of oil and gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	―	$	535,433
Cash paid		―		(515,894	)
Liabilities assumed, net	$	―	$	19,539
Non-cash financing activities:
Units issued in connection with the purchase of oil and gas properties	$	―	$	14,708

For purposes of the 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 $1.5 million and $1.3 million is included in “other noncurrent assets” on the consolidated balance sheets at March 31, 2009 and December 31, 2008, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility. At March 31, 2009, approximately $8.1 million was included in “accounts payable and accrued expenses” on the condensed consolidated balance sheets which represents reclassified net outstanding checks. There was no such balance at December 31, 2008.

(16)	Recently Issued Accounting Standards

In April 2009, the FASB issued FASB Staff Position FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP FAS 141(R)-1”). Under this standard, assets acquired and liabilities assumed in a business combination that arise from contingencies will be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability will generally be recognized in accordance with SFAS No. 5, “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss.” FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period on or after December 15, 2008. The Company will implement FSP FAS 141(R)-1 for acquisitions that occur after January 1, 2009.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS 141(R)”). Under SFAS 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed at fair value with limited exceptions. SFAS 141(R) will change the

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

accounting treatment for certain specific items, including acquisition costs, which will be expensed as incurred. SFAS 141(R) also includes new disclosure requirements. SFAS 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period on or after December 15, 2008. The Company will implement SFAS 141(R) for acquisitions that occur after January 1, 2009.

In September 2006, the FASB issued SFAS 157, which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the mark-to-market value. The Company adopted the provisions of SFAS 157 related to financial assets and liabilities and nonfinancial assets and liabilities measured on a recurring basis effective January 1, 2008, and related to nonfinancial assets and liabilities measured on a nonrecurring basis effective January 1, 2009 (see Note 8). There was no impact from the adoption related to items measured on a nonrecurring basis.

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Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. 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, gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement” below and in the Annual Report on Form 10-K, particularly in Part I. Item 1A. “Risk Factors.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

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

Executive Overview

LINN Energy is an independent oil and gas company focused on the development and acquisition of long life properties which complement its asset profile in producing basins within the United States. The Company’s oil, gas and NGL properties are located in three regions in the United States:

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

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

Western, which includes the Brea Olinda Field of the Los Angeles Basin in California.

The results of the Company’s Appalachian Basin and Mid Atlantic operations are classified as discontinued operations for all periods presented (see Note 2). Unless otherwise indicated, results of operations information presented herein relates only to LINN Energy’s continuing operations.

Results from continuing operations for the three months ended March 31, 2009, included the following:

oil, gas and NGL sales of approximately $79.9 million, compared to $175.9 million in the first quarter of 2008;

daily production of 217 MMcfe/d, compared to 196 MMcfe/d in the first quarter of 2008;

realized gains on commodity derivatives of approximately $124.1 million, compared to realized losses of $4.8 million in the first quarter of 2008;

capital expenditures of approximately $73.3 million;

41 wells drilled; and

average of 3 operated drilling rigs.

Renegotiated Credit Facility

In April 2009, the Company entered into a new $1.75 billion Credit Facility, extending the maturity two years, from August 2010 to August 2012. The new Credit Facility will result in increased interest expense due to higher interest rates and amortization of financing fees. See “Credit Facility” in “Liquidity and Capital Resources” below for additional details.

Unit Repurchase Plan

During the three months ended March 31, 2009, the Company repurchased, under its previously approved unit repurchase plan, 123,800 units at an average unit price of $12.99, for a total cost of approximately $1.6 million. All

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Item 2.

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

units were subsequently canceled. At March 31, 2009, approximately $85.4 million remains available for unit repurchase under the program. The Company may purchase units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are purchased at fair market value on the date of purchase.

Credit and Capital Market Disruption

Multiple events during 2008 and 2009 involving numerous financial institutions have effectively restricted current liquidity within the capital markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations to provide liquidity to the financial sector, capital markets currently remain constrained. To the extent the Company accesses credit or capital markets in the near term, its ability to obtain terms and pricing similar to its existing terms and pricing may be limited. In addition, the Company cannot be assured that counterparties to the Company’s derivative contracts will be able to perform under these contracts. For additional 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

Results of Operations – Continuing Operations

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

	Three Months Ended March 31,
	2009			2008			Variance
	(in thousands)
Revenues and other:
Gas sales	$	42,228		$	85,428		$	(43,200	)
Oil sales		26,770			64,307			(37,537	)
NGL sales		10,866			26,137			(15,271	)
Total oil, gas and NGL sales		79,864			175,872			(96,008	)
Gain (loss) on oil and gas derivatives		161,315			(268,794	)		430,109
Gas marketing revenues		516			2,816			(2,300	)
Other revenues		966			479			487
	$	242,661		$	(89,627	)	$	332,288
Expenses:
Lease operating expenses	$	33,732		$	19,490		$	14,242
Transportation expenses		2,967			3,328			(361	)
Gas marketing expenses		340			2,417			(2,077	)
General and administrative expenses (1)		23,301			19,076			4,225
Exploration costs		1,565			2,620			(1,055	)
Depreciation, depletion and amortization		52,104			44,370			7,734
Taxes, other than income taxes		7,567			12,973			(5,406	)
(Gain) loss on sale of assets and other, net		(26,711	)		―			(26,711	)
	$	94,865		$	104,274		$	(9,409	)

Other income and (expenses)	$	(26,373	)	$	(64,849	)	$	38,476

Income (loss) from continuing operations before income taxes	$	121,423		$	(258,750	)	$	380,173

Notes to table:

(1)	General and administrative expenses for the three months ended March 31, 2009 and 2008 includes approximately $4.2 million and $3.6 million, respectively, of non-cash unit-based compensation expenses.

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Item 2.

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

	Three Months Ended March 31,
	2009		2008		Variance
Average daily production:
Gas (MMcf/d)		133		123		8	%
Oil (MBbls/d)		8.8		7.8		13	%
NGL (MBbls/d)		5.2		4.4		18	%
Total (MMcfe/d)		217		196		11	%

Weighted average prices (hedged): (1)
Gas (Mcf)	$	7.94	$	8.22		(3	)%
Oil (Bbl)	$	118.19	$	74.98		58	%
NGL (Bbl)	$	23.32	$	65.84		(65	)%

Weighted average prices (unhedged): (2)
Gas (Mcf)	$	3.53	$	7.66		(54	)%
Oil (Bbl)	$	33.76	$	90.45		(63	)%
NGL (Bbl)	$	23.32	$	65.84		(65	)%

Representative NYMEX oil and gas prices:
Gas (MMBtu)	$	4.91	$	8.03		(39	)%
Oil (Bbl)	$	43.08	$	97.90		(56	)%

Costs per Mcfe of production:
Lease operating expenses	$	1.73	$	1.10		57	%
Transportation expenses	$	0.15	$	0.19		(21	)%
General and administrative expenses (3)	$	1.19	$	1.07		11	%
Depreciation, depletion and amortization	$	2.67	$	2.49		7	%
Taxes, other than income taxes	$	0.39	$	0.73		(47	)%

Notes to table:

(1)

Includes the effect of realized gains (losses) on derivatives of $119.8 million (excluding $4.3 million realized gains on canceled contracts) and $(4.8) million for the three months ended March 31, 2009 and 2008, respectively. The Company utilizes oil puts to hedge revenues associated with its NGL production; therefore, all realized gains (losses) on oil derivative contracts are included in weighted average oil prices, rather than weighted average NGL prices.

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

(3)

General and administrative expenses for the three months ended March 31, 2009 and 2008 includes approximately $4.2 million and $3.6 million, respectively, of non-cash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the three months ended March 31, 2009 and 2008 were $0.98 per Mcfe and $0.87 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, Gas and NGL Sales

Oil, gas and NGL sales decreased by approximately $96.0 million, or 55%, to approximately $79.9 million for the three months ended March 31, 2009, from $175.9 million for the three months ended March 31, 2008, due to lower commodity prices. Lower gas, oil and NGL prices decreased revenues by approximately $49.5 million, $45.0 million and $19.8 million, respectively.

Total production increased to 217 MMcfe/d during the three months ended March 31, 2009, from 196 MMcfe/d during the three months ended March 31, 2008. Volume increases during the three months ended March 31, 2009 increased total oil, gas and NGL revenues by $18.3 million compared to the three months ended March 31, 2008.

The following presents average daily production by region:

	Three Months Ended March 31,
	2009		2008		Increase
Average daily production (MMcfe/d):
Mid-Continent Deep		142		129		13	10	%
Mid-Continent Shallow		61		54		7	13	%
Western		14		13		1	8	%
		217		196		21	11	%

The 10% increase in average daily production in the Mid-Continent Deep region reflects results of the Company’s capital drilling program in the Texas Panhandle Granite Wash along with ongoing optimization and workover projects focused on the base asset. The 13% increase in average daily production in the Mid-Continent Shallow region reflects results of the Company’s capital drilling program in the Texas Panhandle, as well as production from acquired properties beginning in February 2008 (see Note 2). The Western region consists of a very low decline asset base and continues to produce at levels consistent with the comparable period of the prior year. Production in this region has now fully recovered from the effects of wildfires that occurred in the fourth quarter of 2008.

Gain (Loss) on Oil and Gas Derivatives

The Company determines the fair value of its oil and gas derivatives using pricing models that use a variety of techniques, including quotes and pricing analysis. See Note 7 and Note 8 for additional information and details regarding derivatives in place through December 31, 2014. During the three months ended March 31, 2009, the Company had commodity derivative contracts in place for approximately 108% of its gas production and 90% of its oil and NGL production, which resulted in realized gains of $124.1 million, of which $4.3 million related to derivative contracts on estimated future gas production canceled before the settlement date. During the three months ended March 31, 2008, the Company recorded realized losses of approximately $4.8 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 first quarter of 2009, expected future oil and gas prices decreased, which resulted in unrealized gains on derivatives of approximately $37.2 million for the three months ended March 31, 2009. During the first quarter of 2008, expected future oil and gas prices increased, which resulted in unrealized losses on derivatives of approximately $264.0 million for the three months ended March 31, 2008. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

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 $14.2 million, or 73%, to

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Item 2.

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

$33.7 million for the three months ended March 31, 2009, from $19.5 million for the three months ended March 31, 2008. Lease operating expenses per Mcfe also increased, to $1.73 per Mcfe for the three months ended March 31, 2009, from $1.10 per Mcfe for the three months ended March 31, 2008. Lease operating expenses increased primarily due to costs associated with properties acquired in the first quarter of 2008 in the Mid-Continent Shallow region (see Note 2), as well as commodity price-driven service and materials cost increases across all operating regions.

Transportation Expenses

Transportation expenses were comparable to 2008, and decreased by approximately $0.3 million, or 9%, to $3.0 million for the three months ended March 31, 2009, from $3.3 million for the three months ended March 31, 2008.

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 $4.2 million, or 22%, to $23.3 million for the three months ended March 31, 2009, from $19.1 million for the three months ended March 31, 2008. General and administrative expenses per Mcfe also increased, to $1.19 per Mcfe for the three months ended March 31, 2009, from $1.07 per Mcfe for the three months ended March 31, 2008. The increase in expense was primarily due to increases in employee severance expenses, including accelerated unit-based compensation expenses, of approximately $1.4 million, as well as increases in charitable contributions of approximately $1.2 million and higher professional service fees of approximately $1.2 million.

Exploration Costs

Exploration costs decreased by approximately $1.0 million, or 38%, to $1.6 million for the three months ended March 31, 2009, from $2.6 million for the three months ended March 31, 2008. The decrease was primarily due to a reduction in 3-D seismic and data library expenses of approximately $2.4 million, partially offset by an increase in unproved leasehold costs of approximately $1.4 million during the three months ended March 31, 2009, compared to the three months ended March 31, 2008.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $7.7 million, or 17%, to $52.1 million for the three months ended March 31, 2009, from $44.4 million for the three months ended March 31, 2008. Higher total production levels and higher depletion rates associated with year end price-related reserve revisions were the main reason for the increase. Depreciation, depletion and amortization per Mcfe increased to $2.67 per Mcfe for the three months ended March 31, 2009, from $2.49 per Mcfe for the three months ended March 31, 2008.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, decreased by approximately $5.4 million, or 42%, to $7.6 million for the three months ended March 31, 2009, from $13.0 million for the three months ended March 31, 2008. Production taxes, which are a function of revenues generated from production, decreased by approximately $6.0 million compared to the three months ended March 31, 2008, primarily due to lower commodity prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $0.8 million compared to the three months ended March 31, 2008.

(Gain) Loss on Sale of Assets and Other, Net

The increase in (gain) loss on sale of assets and other, net for the three months ended March 31, 2009 was primarily due to a gain of $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)

	Three Months Ended March 31,
	2009			2008			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(14,409	)	$	(25,293	)	$	10,884
Loss on interest rate swaps		(11,571	)		(39,393	)		27,822
Other, net		(393	)		(163	)		(230	)
	$	(26,373	)	$	(64,849	)	$	38,476

Other income and (expenses) decreased by approximately $38.5 million due to lower interest expense and a reduced loss on interest rate swaps. Interest expense was driven by lower interest rates on the Credit Facility, which were driven by lower LIBOR rates. The unrealized mark-to-market loss on interest rate swaps decreased as the forward curve decreased less during the three months ended March 31, 2009, than it did during the three months ended March 31, 2008.

In April 2009, the Company entered into a new Credit Facility, which will result in increased interest expense due to higher interest rates and amortization of financing fees. See “Credit Facility” in “Liquidity and Capital Resources” below for additional details.

Income Tax Benefit (Expense)

Income tax expense was approximately $0.1 million and $0.2 million for the three months ended March 31, 2009 and 2008, respectively. Tax expense for both periods primarily represents Texas margin tax expense. Limited liability companies are subject to state income tax in Texas. The Company is treated as a partnership for federal and state income tax purposes; however, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.

Liquidity and Capital Resources

Overview

The Company has utilized public and private equity, proceeds from bank borrowings and issuance of Senior Notes, and cash flow from operations for capital resources and liquidity. To date, the primary use of capital has been for the acquisition and development of oil and gas properties. The Company manages its working capital and cash requirements to borrow only as needed. In April 2009, the Company entered into a new $1.75 billion Credit Facility, extending the maturity two years, from August 2010 to August 2012. See “Credit Facility” below for additional details. The Company had $296.0 million in available borrowing capacity at April 30, 2009.

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

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Item 2.

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

Cash Flows

The following presents a comparative cash flow summary:

	Three Months Ended March 31,
	2009			2008			Variance
	(in thousands)
Net cash:
Provided by operating activities	$	94,970		$	61,200		$	33,770
Used in investing activities		(58,817	)		(613,294	)		554,477
Provided by (used in) financing activities		(41,928	)		551,729			(593,657	)
Net decrease in cash and cash equivalents	$	(5,775	)	$	(365	)	$	(5,410	)

Operating Activities

At March 31, 2009, the Company had $22.9 million of cash and cash equivalents compared to $28.7 million at December 31, 2008. Cash provided by operating activities for the three months ended March 31, 2009 was approximately $95.0 million, compared to $61.2 million for the three months ended March 31, 2008. The increase in operating cash flows was primarily driven by higher realized gains from oil and gas derivatives, partially offset by reduced oil and gas revenues associated with lower commodity prices.

Investing Activities

Cash used in investing activities was approximately $58.8 million for the three months ended March 31, 2009, compared to $613.3 million for the three months ended March 31, 2008. The decrease in cash used in investing activities was primarily due to a lack of acquisition activity during the three months ended March 31, 2009, compared to the three months ended March 31, 2008.

The total cash used in investing activities for the three months ended March 31, 2009 includes approximately $68.0 million for the drilling and development of oil and gas properties. For 2009, the Company estimates its total drilling and development capital expenditures will be approximately $150.0 million. This estimate is under continuous review and is subject to on-going adjustment. The Company expects to fund these capital expenditures with cash flow from operations. During the three months ended March 31, 2009, the Company also received proceeds from sales of oil and gas properties totaling approximately $11.9 million, primarily due to the sale to Devon (see Note 2).

Financing Activities

Cash used by financing activities was approximately $41.9 million for the three months ended March 31, 2009, compared to cash provided by financing activities of $551.7 million for the three months ended March 31, 2008. The change in financing cash flows was primarily due to operating cash flows that were lower than the total of capital expenditures and distributions paid during the three months ended March 31, 2009.

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Item 2.

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

Distributions

Under the limited liability company agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. The following provides a summary of distributions paid by the Company during the three months ended March 31, 2009:

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

February 2009	October 1 – December 31, 2008	$	0.63	$	72.5

On April 23, 2009, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the first quarter of 2009. The distribution totaling approximately $72.5 million will be paid on May 14, 2009, to unitholders of record as of the close of business on May 6, 2009.

Credit Facility

On April 28, 2009, the Company entered into a new Credit Facility with a borrowing base of $1.75 billion and a maturity of August 2012. In connection with its new Credit Facility, during the second quarter of 2009, the Company paid approximately $52.6 million in financing fees, which were deferred and will be amortized over the life of the Credit Facility. In addition, during the second quarter of 2009, the Company wrote off deferred financing fees related to its prior credit facility of approximately $3.6 million. At April 30, 2009, available borrowing under the Credit Facility was $296.0 million, which includes a $5.6 million reduction in availability for outstanding letters of credit.

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either LIBOR plus an applicable margin between 2.50% and 3.25% per annum or the ABR plus an applicable margin between 1.00% and 1.75% 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 fee of 0.5% per year on the unused portion of the borrowing base under the Credit Facility.

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Item 2.

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

Senior Notes

On June 24, 2008, the Company entered into a purchase agreement with a group of Initial Purchasers pursuant to which the Company agreed to issue $255.9 million in aggregate principal amount of the Company’s Senior Notes due 2018. The Senior Notes were offered and sold to the Initial Purchasers and then resold to qualified institutional buyers each in transactions exempt from the registration requirements under the Securities Act. The Company used the net proceeds (after deducting the Initial Purchasers’ discounts and offering expense) of approximately $243.6 million to repay an outstanding term loan. In connection with the Senior Notes, the Company incurred financing fees of approximately $7.8 million, which will be amortized over the life of the Senior Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. The $5.9 million discount on the Senior Notes will be amortized over the life of the Senior Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. As of April 30, 2009, the net carrying value of the Senior Notes was approximately $250.3 million and the fair value was approximately $228.1 million. The fair value of the Senior Notes was estimated based on prices quoted from third-party financial institutions.

The Senior Notes were issued under an Indenture dated June 27, 2008, mature on July 1, 2018, and bear interest at 9.875%. Interest is payable semi-annually beginning January 1, 2009. The Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries guaranteed the Senior Notes on a senior unsecured basis. The Indenture provides that the Company may redeem: (i) on or prior to July 1, 2011, up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus accrued and unpaid interest; (ii) prior to July 1, 2013, all or part of the Senior Notes at a redemption price equal to the principal amount, plus a make whole premium (as defined in the Indenture) and accrued and unpaid interest; and (iii) on or after July 1, 2013, all or part of the Senior Notes at redemption prices equal to 104.938% in 2013, 103.292% in 2014, 101.646% in 2015 and 100% in 2016 and thereafter. The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

Counterparty Credit Risk

The Company accounts for its oil and gas commodity derivatives and interest rate swaps at fair value (see Note 7). The Company’s counterparties are participants in its Credit Facility (see Note 6) which is secured by the Company’s oil and gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from the counterparties. The 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 are also lenders in the Company’s Credit Facility, and 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 swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Off-Balance Sheet Arrangements

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

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Item 2.

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

Contingencies

In September and October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed voluntary petitions for reorganization under Chapter 11 (see Note 10). As of March 31, 2009, and December 31, 2008, the Company had a receivable of approximately $67.6 million from Lehman Commodity Services for canceled derivative contracts. The Company is pursuing various legal remedies to protect its interests. Based on market expectations, the Company estimated approximately $6.7 million of the receivable balance to be collectible. The net receivable of approximately $6.7 million is included in “other current assets” on the condensed consolidated balance sheets at March 31, 2009 and December 31, 2008. The Company believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

During the three months ended March 31, 2009 and 2008, 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.

Critical Accounting Policies and Estimates

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

With the exception of accounting policies related to purchase accounting required under the provisions of SFAS 141(R) and FSP FAS 141(R)-1, there have been no significant changes with regard to the critical accounting policies disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. The policies disclosed include the accounting for oil and gas properties, revenue recognition, purchase accounting and derivative instruments.

New Accounting Pronouncements

See Note 16 for details regarding SFAS 157, SFAS 141(R) and FSP FAS 141(R)-1 implementation effective January 1, 2009. See Note 11 for details regarding FSP EITF 03-6-1 implementation effective January 1, 2009.

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Item 2.

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

Cautionary Statement

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

business strategy;

acquisition strategy;

financial strategy;

drilling locations;

oil, gas and NGL reserves;

realized oil, gas and NGL prices;

production volumes;

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

future operating results; and

plans, objectives, expectations and intentions.

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

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors listed in “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, 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 oil, gas and NGL 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 Annual Report on Form 10-K for the year ended December 31, 2008. 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 March 31, 2009, the fair value of contracts that settle during the next twelve months was an asset of approximately $390.0 million and a liability of $0.9 million for a net asset of approximately $389.1 million. A 10% increase in the index oil and gas prices above the March 31, 2009 prices for the next twelve months would result in a net asset of approximately $324.3 million which represents a decrease in the fair value of approximately $64.8 million; conversely, a 10% decrease in the index oil and gas prices would result in a net asset of approximately $454.4 million which represents an increase in the fair value of approximately $65.3 million.

Interest Rate Risk

On April 28, 2009, the Company entered into a new Credit Facility with a borrowing base of $1.75 billion and a maturity of August 2012 (see Note 6). At April 30, 2009, the Company had long-term debt outstanding under its Credit Facility of approximately $1.45 billion, which incurred interest at floating rates. A 1% increase in LIBOR would result in an estimated $14.5 million increase in annual interest expense. The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates (see Note 7).

Counterparty Credit Risk

The Company accounts for its oil and gas commodity derivatives and interest rate swaps at fair value on a recurring basis in accordance with the provisions of SFAS 157 (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 March 31, 2009, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 8.83%. A 1% increase in the average public bond yield spread would result in an estimated $1.4 million increase in net income for the three months ended March 31, 2009. At March 31, 2009, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 9.23%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $12.3 million decrease in net income for the three months ended March 31, 2009.

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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 March 31, 2009.

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 first quarter of 2009 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Not applicable.

Item 1A. Risk Factors

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, 2008. 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.

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

Issuer Purchases of Equity Securities

The following sets forth information with respect to the Company with respect to repurchases of its units during the first quarter of 2009:

Period	Total Number of Units Purchased		Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Units that May Yet be Purchased Under the Plans or Programs (2)
							(in millions)

January 1 – 31 (1)		53,667	$	15.98		―	$	87.0
March 1 – 31		123,800	$	12.99		123,800	$	85.4

(1)	During the first quarter of 2009, 53,667 units purchased were related to units received by the Company for the payment of withholding taxes due on units issued under its equity compensation plan.

(2)

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units. The Company may purchase units from time to time on the open market or in negotiated purchases. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

On May 5, 2009, the Board of Directors of the Company approved a Change of Control Protection Plan (“COC Plan”), to be effective April 25, 2009, applicable to all full-time employees of the Company (other than those with separate employment agreements) that provides for certain benefits payable upon a separation of service for specified reasons that occurs within two years following a change of control (as defined in the COC Plan).

The foregoing description does not purport to be complete and is qualified in its entirety by reference to the COC Plan, a copy of which is attached as Exhibit 10.3 to this Quarterly Report on Form 10-Q.

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Item 6. Exhibits

Exhibit Number			Description

10	.1*†	—	Fourth Amended and Restated Credit Agreement dated as of April 28, 2009 among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto
10	.2*†	—	Fourth Amended and Restated Guaranty and Pledge Agreement, dated as of April 28, 2009, made by Linn Energy, LLC and each of the other Obligors in favor of BNP Paribas, as Administrative Agent
10	.3*†	—	Linn Energy, LLC Change of Control Protection Plan, dated as of April 25, 2009
31	.1†	—	Section 302 Certification of Michael C. Linn, Chairman and Chief Executive Officer of Linn Energy, LLC
31	.2†	—	Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32	.1†	—	Section 906 Certification of Michael C. Linn, Chairman and Chief Executive Officer of Linn Energy, LLC
32	.2†	—	Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC

†	Filed herewith.

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

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SIGNATURE

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

	LINN ENERGY, LLC
	(Registrant)


Date: May 7, 2009	/s/ David B. Rottino
	David B. Rottino
	Senior Vice President and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)