Edgar Filing: LINN ENERGY, LLC

form10qq22009.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 June 30, 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 July 31, 2009, there were 121,284,576 units outstanding.

TABLE OF CONTENTS

		Page

	Glossary of Terms	ii

	Part I - Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of June 30, 2009, and December 31, 2008	1
	Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2009, and June 30, 2008	2
	Condensed Consolidated Statement of Unitholders’ Capital for the six months ended June 30, 2009	3
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009, and June 30, 2008	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures	43
	Part II - Other Information
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Submission of Matters to a Vote of Security Holders	45
Item 5.	Other Information	45
Item 6.	Exhibits	46

	Signature	47

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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

	June 30,			December 31,
	2009			2008
	(Unaudited)
	(in thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	27,100		$	28,668
Accounts receivable – trade, net		102,521			138,983
Derivative instruments		314,806			368,951
Other current assets		21,585			27,329
Total current assets		466,012			563,931

Noncurrent assets:
Oil and gas properties (successful efforts method)		3,928,302			3,831,183
Less accumulated depletion and amortization		(376,608	)		(278,805	)
		3,551,694			3,552,378

Other property and equipment		115,896			111,459
Less accumulated depreciation		(18,333	)		(13,171	)
		97,563			98,288

Derivative instruments		248,248			493,705
Other noncurrent assets		69,189			13,718
		317,437			507,423
Total noncurrent assets		3,966,694			4,158,089
Total assets	$	4,432,706		$	4,722,020

Liabilities and Unitholders’ Capital
Current liabilities:
Accounts payable and accrued expenses	$	120,360		$	163,662
Derivative instruments		42,671			47,005
Other accrued liabilities		27,103			27,163
Total current liabilities		190,134			237,830

Noncurrent liabilities:
Credit facility		1,118,000			1,403,393
Senior notes, net		488,167			250,175
Derivative instruments		32,387			39,350
Other noncurrent liabilities		33,831			30,586
Total noncurrent liabilities		1,672,385			1,723,504

Unitholders’ capital:
121,288,461 units and 114,079,533 units issued and outstanding at June 30, 2009, and December 31, 2008, respectively		2,067,661			2,109,089
Accumulated income		502,526			651,597
		2,570,187			2,760,686
Total liabilities and unitholders’ capital	$	4,432,706		$	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 June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands, except per unit amounts)
Revenues and other:
Oil, gas and natural gas liquid sales	$	91,906		$	255,586		$	171,770		$	431,458
Loss on oil and gas derivatives		(232,775	)		(870,804	)		(71,460	)		(1,139,598	)
Gas marketing revenues		1,183			3,593			1,699			6,409
Other revenues		641			642			1,607			1,121
		(139,045	)		(610,983	)		103,616			(700,610	)
Expenses:
Lease operating expenses		33,137			25,161			66,869			44,651
Transportation expenses		2,516			3,663			5,483			6,991
Gas marketing expenses		880			3,103			1,220			5,520
General and administrative expenses		20,291			18,020			43,592			37,096
Exploration costs		2,199			61			3,764			2,681
Depreciation, depletion and amortization		50,390			50,885			102,494			95,255
Taxes, other than income taxes		7,882			17,628			15,449			30,601
(Gain) loss on sale of assets and other, net		(5	)		―			(26,716	)		―
		117,290			118,521			212,155			222,795
Other income and (expenses):
Interest expense, net of amounts capitalized		(23,262	)		(23,332	)		(37,671	)		(48,625	)
Gain (loss) on interest rate swaps		11,918			31,604			347			(7,789	)
Other, net		(837	)		(4,313	)		(1,230	)		(4,476	)
		(12,181	)		3,959			(38,554	)		(60,890	)
Loss from continuing operations before income taxes		(268,516	)		(725,545	)		(147,093	)		(984,295	)
Income tax benefit (expense)		(185	)		164			(321	)		(45	)
Loss from continuing operations		(268,701	)		(725,381	)		(147,414	)		(984,340	)

Discontinued operations:
Gain (loss) on sale of assets, net of taxes		330			(1,028	)		(718	)		(1,322	)
Income (loss) from discontinued operations, net of taxes		(101	)		14,267			(939	)		14,161
		229			13,239			(1,657	)		12,839

Net loss	$	(268,472	)	$	(712,142	)	$	(149,071	)	$	(971,501	)

Loss per unit – continuing operations:
Units – basic	$	(2.31	)	$	(6.35	)	$	(1.28	)	$	(8.63	)
Units – diluted	$	(2.31	)	$	(6.35	)	$	(1.28	)	$	(8.63	)
Income (loss) per unit – discontinued operations:
Units – basic	$	0.01		$	0.12		$	(0.02	)	$	0.11
Units – diluted	$	0.01		$	0.12		$	(0.02	)	$	0.11
Net loss per unit:
Units – basic	$	(2.30	)	$	(6.23	)	$	(1.30	)	$	(8.52	)
Units – diluted	$	(2.30	)	$	(6.23	)	$	(1.30	)	$	(8.52	)
Weighted average units outstanding:
Units – basic		116,497			114,252			114,993			114,005
Units – diluted		116,497			114,252			114,993			114,005

Distributions declared per unit	$	0.63		$	0.63		$	1.26		$	1.26

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
Sale of units, net of underwriting discounts and expenses of $4,473		6,325			98,308			―			―			98,308
Issuance of units		1,070			―			―			―			―
Cancellation of units		(187	)		(2,696	)		―			2,696			―
Purchase of units					―			―			(2,696	)		(2,696	)
Distributions to unitholders					(144,994	)		―			―			(144,994	)
Unit-based compensation expenses					7,954			―			―			7,954
Net loss					―			(149,071	)		―			(149,071	)
June 30, 2009		121,288		$	2,067,661		$	502,526		$	―		$	2,570,187

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)

	Six Months Ended June 30,
	2009			2008
	(in thousands)
Cash flow from operating activities:
Net loss	$	(149,071	)	$	(971,501	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		102,494			101,469
Unit-based compensation expenses		7,954			7,852
Amortization and write-off of deferred financing fees and other		8,323			7,001
(Gain) loss on sale of assets, net		(24,933	)		1,326
Mark-to-market on derivatives:
Total losses		71,113			1,147,387
Cash settlements		212,993			(28,550	)
Cash settlements on canceled derivatives		4,197			(68,197	)
Premiums paid for derivatives		―			(1,278	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		35,809			(125,286	)
(Increase) decrease in other assets		3,639			(4,967	)
Decrease in accounts payable and accrued expenses		(15,536	)		(5,647	)
Increase in other liabilities		1,292			974
Net cash provided by operating activities		258,274			60,583
Cash flow from investing activities:
Acquisition of oil and gas properties		―			(570,504	)
Development of oil and gas properties		(125,107	)		(172,994	)
Purchases of other property and equipment		(4,952	)		(5,945	)
Proceeds from sales of oil and gas properties and other property and equipment		26,649			76,560
Net cash used in investing activities		(103,410	)		(672,883	)
Cash flow from financing activities:
Proceeds from sale of units		102,781			―
Purchase of units		(2,696	)		(1,642	)
Proceeds from issuance of debt		406,703			1,173,000
Principal payments on debt		(454,393	)		(384,916	)
Distributions to unitholders		(144,994	)		(144,755	)
Financing fees, offering expenses and other, net		(63,833	)		(21,216	)
Net cash provided by (used in) financing activities		(156,432	)		620,471
Net increase (decrease) in cash and cash equivalents		(1,568	)		8,171
Cash and cash equivalents:
Beginning		28,668			1,441
Ending	$	27,100		$	9,612

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 June 30, 2009, and for the three months and six months ended June 30, 2009, and June 30, 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. Subsequent events were evaluated through the issuance date of the financial statements, August 6, 2009. 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 commodity and interest rate 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 July 14, 2009, and August 5, 2009, the Company entered into agreements to purchase certain oil and gas properties located in the Permian Basin in Texas and New Mexico for contract prices of $22.6 million and $95.0 million, respectively. The Company anticipates closing the transactions in the third quarter of 2009, subject to closing conditions.

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 for the six months ended June 30, 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.

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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 “income (loss) from discontinued operations, net of taxes” on the condensed consolidated statements of operations:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Total revenues and other	$	(5	)	$	28,824		$	(1,216	)	$	49,985
Total operating expenses		(96	)		(8,054	)		277			(22,230	)
Interest expense		—			(6,503	)		—			(13,594	)
Income (loss) from discontinued operations, net of taxes	$	(101	)	$	14,267		$	(939	)	$	14,161

Discontinued operations activity in the three months and six months ended June 30, 2009, primarily represents activity related to post-closing adjustments. The Company computed interest expense related to discontinued operations for the three months and six months ended June 30, 2008, in accordance with Emerging Issues Task Force Issue (“EITF”) 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

Public Offering of Units

In May 2009, the Company sold 6,325,000 units representing limited liability company interests at $16.25 per unit ($15.60 per unit, net of underwriting discount), for net proceeds (after underwriting discount of $4.1 million and offering expenses of $0.4 million), of approximately $98.3 million, which was used to reduce indebtedness. The units were registered under the Securities Act of 1933, as amended (“Securities Act”) on a Registration Statement on Form S-3 filed May 11, 2009.

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. During the six months ended June 30, 2009, 123,800 units were repurchased at an average unit price of $12.99, for a total cost of approximately $1.6 million. All units were subsequently canceled. At June 30, 2009, approximately $85.4 million was available for unit repurchase under the program. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are repurchased at fair market value on the date of repurchase.

Cancellation of Units

During the six months ended June 30, 2009, the Company purchased 63,031 units for approximately $1.0 million, in conjunction with units received by the Company for the payment of minimum withholding taxes

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

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 six months ended June 30, 2009, are presented on the condensed consolidated statement of unitholders’ capital. On July 23, 2009, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the second quarter of 2009. The distribution totaling approximately $76.4 million will be paid August 14, 2009, to unitholders of record as of the close of business August 7, 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:

	June 30, 2009			December 31, 2008
	(in thousands)
Proved properties:
Leasehold acquisition	$	3,279,858		$	3,278,155
Development		559,328			460,730
Unproved properties		89,116			92,298
		3,928,302			3,831,183
Less accumulated depletion and amortization		(376,608	)		(278,805	)
	$	3,551,694		$	3,552,378

(5)	Business and Credit Concentrations

For the three months ended June 30, 2009, the Company’s four largest customers represented approximately 24%, 17%, 14% and 10% of the Company’s sales. For the six months ended June 30, 2009, the Company’s three largest customers represented approximately 21%, 18% and 15% of the Company’s sales. For the three months and six months ended June 30, 2008, the Company’s four largest customers represented 20%, 11%, 10% and 10%, and 19%, 11%, 11% and 10%, respectively, of the Company’s sales.

At June 30, 2009, trade accounts receivable from three customers were more than 10% of the Company’s total trade accounts receivable. At June 30, 2009, trade accounts receivable from the Company’s three largest customers represented approximately 20%, 18% and 13% of the Company’s receivables. At December 31, 2008, trade accounts receivable from two customers were more 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.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

(6)

Debt

At June 30, 2009, and December 31, 2008, the Company had the following debt outstanding:

	June 30, 2009		December 31, 2008
	(in thousands)

Credit facility (1)	$	1,118,000	$	1,403,393
Senior notes due 2017, net (2)		237,808		―
Senior notes due 2018, net (3)		250,359		250,175
Less current maturities		―		―
	$	1,606,167	$	1,653,568

(1)

Variable interest rate of 3.07% at June 30, 2009, and 2.47% at December 31, 2008.

(2)

Fixed interest rate of 11.75% and effective interest rate of 12.73%. Amount is net of unamortized discount of approximately $12.2 million at June 30, 2009.

(3)

Fixed interest rate of 9.875% and effective interest rate of 10.25%. Amount is net of unamortized discount of approximately $5.6 million and $5.8 million at June 30, 2009, and December 31, 2008, respectively.

Credit Facility

On April 28, 2009, the Company entered into a Fourth Amended and Restated Credit Agreement (“Credit Facility”), with an initial borrowing base of $1.75 billion and a maturity of August 2012, which amended and restated the Company’s existing credit facility, which had a maturity of August 2010. The terms of the Credit Facility required that, upon issuance of the senior notes in May 2009, (see below), the borrowing base be decreased by $62.5 million, to $1.69 billion. At June 30, 2009, available borrowing capacity was $563.9 million, which includes a $5.6 million reduction in availability for outstanding letters of credit. In connection with the amended and restated Credit Facility, the Company paid approximately $52.7 million in financing fees and expenses, which were deferred and will be amortized over the life of the Credit Facility.

Redetermination of the borrowing base under the Credit Facility occurs semi-annually, in April and October, as well as upon the occurrence of certain events, by the lenders in their sole discretion, based primarily on reserve reports that reflect 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 annum on the unused portion of the borrowing base under the Credit Facility.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

commodity and interest rate swaps; (iii) grant certain liens; (iv) make certain loans, acquisitions, capital expenditures and investments; (v) make distributions other than from available cash; and (vi) 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 those included prior to the amendment and restatement, which 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.

Senior Notes Due 2017

On May 12, 2009, the Company entered into a purchase agreement with a group of initial purchasers (“Initial Purchasers”), pursuant to which the Company agreed to issue $250.0 million in aggregate principal amount of the Company’s senior notes due 2017 (“2017 Notes”). The 2017 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 expenses) of approximately $230.8 million to reduce indebtedness under its Credit Facility. In connection with the 2017 Notes, the Company incurred financing fees and expenses of approximately $6.9 million, which will be amortized over the life of the 2017 Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. The $12.3 million discount on the 2017 Notes will be amortized over the life of the 2017 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 2017 Notes.

The 2017 Notes were issued under an Indenture dated May 18, 2009, (“Indenture”), mature May 15, 2017, and bear interest at 11.75%. Interest is payable semi-annually beginning November 15, 2009. The 2017 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 2017 Notes on a senior unsecured basis. The Indenture provides that the Company may redeem: (i) on or prior to May 15, 2011, up to 35% of the aggregate principal amount of the 2017 Notes at a redemption price of 111.75% of the principal amount, plus accrued and unpaid interest; (ii) prior to May 15, 2013, all or part of the 2017 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 May 15, 2013, all or part of the 2017 Notes at redemption prices equal to 105.875% in 2013, 102.938% in 2014 and 100% in 2015 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 2017 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2017 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.

In connection with the issuance and sale of the 2017 Notes, the Company entered into a Registration Rights Agreement (“Registration Rights Agreement”) with the Initial Purchasers. Under the Registration Rights Agreement, the Company agreed to use its reasonable best efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the 2017 Notes in exchange for outstanding 2017 Notes. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2017 Notes. The Company will not be

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obligated to file the registration statements described above if the restrictive legend on the 2017 Notes has been removed and the 2017 Notes are freely tradable (in each case, other than with respect to persons that are affiliates of the Company) pursuant to Rule 144 under the Securities Act, as of the 366th day after the 2017 Notes were issued. If the Company fails to satisfy its obligations under the Registration Rights Agreement, the Company may be required to pay additional interest to holders of the 2017 Notes under certain circumstances.

Senior Notes Due 2018

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 (“2018 Notes”). The 2018 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 expenses) of approximately $243.6 million to repay an outstanding term loan. In connection with the 2018 Notes, the Company incurred financing fees and expenses of approximately $7.8 million, which will be amortized over the life of the 2018 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 2018 Notes will be amortized over the life of the 2018 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 2018 Notes.

The 2018 Notes were issued under an Indenture dated June 27, 2008, (“Indenture”), mature July 1, 2018, and bear interest at 9.875%. Interest is payable semi-annually beginning January 1, 2009. The 2018 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 2018 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 2018 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 2018 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 2018 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 2018 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2018 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

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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 Statement of Financial Accounting Standards (“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”).

The following table summarizes open positions as of June 30, 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)		19,793			39,566			31,901			14,676			—			—
Average Price ($/MMBtu)	$	8.53		$	8.50		$	8.50		$	8.57		$	—		$	—
Puts:
Hedged Volume (MMMBtu)		3,480			6,960			6,960			—			—			—
Average Price ($/MMBtu)	$	7.50		$	7.50		$	7.50		$	—		$	—		$	—
PEPL Puts: (1)
Hedged Volume (MMMBtu)		2,667			10,634			13,259			5,934			—			—
Average Price ($/MMBtu)	$	7.85		$	7.85		$	7.85		$	7.85		$	—		$	—
Total:
Hedged Volume (MMMBtu)		25,940			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)		1,218			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)		922			2,250			2,352			500			—			—
Average Price ($/Bbl)	$	120.00		$	110.00		$	69.11		$	77.73		$	—		$	—
Collars:
Hedged Volume (MBbls)		125			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)		2,265			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)		23,458			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.

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(Unaudited)

Settled derivatives on gas production for the three months and six months ended June 30, 2009, included a volume of 12,970 MMMBtu and 25,940 MMMBtu at average contract prices of $8.32. Settled derivatives on oil and NGL production for the three months and six months ended June 30, 2009, included a volume of 1,132 MBbls and 2,265 MBbls at average contract prices 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.

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.

The following presents the settlement terms of the interest rate swaps at June 30, 2009:

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

Notional Amount	$	1,212,000		$	1,212,000		$	1,212,000		$	1,212,000		$	1,212,000
Fixed Rate		3.85	%		3.85	%		3.85	%		3.85	%		3.85	%

(1)

Actual settlement term is through January 6, 2014.

Outstanding Notional Amounts

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

	June 30, 2009		December 31, 2008

Outstanding notional amounts of gas contracts (MMMBtu)		155,830		196,756
Maximum number of months gas contracts outstanding		42		48
Outstanding notional amounts of oil contracts (MBbls)		18,964		21,229
Maximum number of months oil contracts outstanding		66		72
Outstanding notional amount of interest rate swaps (in thousands)	$	1,212,000	$	1,212,000
Maximum number of months interest rate swaps outstanding		54		24

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Balance Sheet Presentation

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

	June 30, 2009		December 31, 2008
	(in thousands)
Assets:
Commodity derivatives	$	729,816	$	977,847
Interest rate swaps		3,460		―
	$	733,276	$	977,847
Liabilities:
Commodity derivatives	$	179,556	$	119,124
Interest rate swaps		65,724		82,422
	$	245,280	$	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 $733.3 million at June 30, 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 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.

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 “gain (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 noncash items.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	111,144		$	(29,210	)	$	230,956		$	(34,019	)
Interest rate swaps		(10,557	)		(4,221	)		(20,671	)		(5,662	)
Canceled derivatives		(60	)		(68,197	)		4,197			(68,197	)
	$	100,527		$	(101,628	)	$	214,482		$	(107,878	)
Unrealized gains (losses):
Commodity derivatives	$	(343,919	)	$	(773,397	)	$	(306,673	)	$	(1,037,382	)
Interest rate swaps		22,535			35,825			21,078			(2,127	)
	$	(321,384	)	$	(737,572	)	$	(285,595	)	$	(1,039,509	)
Total gains (losses):
Commodity derivatives	$	(232,775	)	$	(870,804	)	$	(71,460	)	$	(1,139,598	)
Interest rate swaps		11,918			31,604			347			(7,789	)
	$	(220,857	)	$	(839,200	)	$	(71,113	)	$	(1,147,387	)

During the six months ended June 30, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production, resulting in realized gains of $4.3 million. During the three months and six months ended June 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Appalachian Basin (see Note 2), resulting in realized losses of approximately $68.2 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. The fair value of derivative instruments is determined utilizing pricing models for significantly similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties. 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.

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The following presents the Company’s fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at June 30, 2009. These items are included in “derivative instruments” on the condensed consolidated balance sheets.

	Fair Value Measurements on a Recurring Basis June 30, 2009
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	729,816	$	(166,762	)	$	563,054
Interest rate swaps	$	3,460	$	(3,460	)	$	—

Liabilities:
Commodity derivatives	$	179,556	$	(166,762	)	$	12,794
Interest rate swaps	$	65,724	$	(3,460	)	$	62,264

(1)

Represents counterparty netting under derivative netting agreements.

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 June 30, 2009. This item is included in “other noncurrent liabilities” on the condensed consolidated balance sheets.

	Level 3
	(in thousands)
Liabilities:
Asset retirement obligations – liabilities added related to drilling	$	42

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 credit-adjusted risk-free interest rate (average of 10.5% for the six months ended June 30, 2009). There was no impact to the Company’s results of operations for the three months and six months ended June 30, 2009, from the adoption of SFAS 157 for nonfinancial assets and liabilities.

At June 30, 2009, the Company also had 2017 Notes with a net carrying value of $237.8 million and a fair value of $242.8 million, and 2018 Notes with a net carrying value of $250.4 million and a fair value of $225.5 million (see Note 6). The fair values of the 2017 Notes and the 2018 Notes were estimated based on prices quoted from third-party financial institutions.

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(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		42
Current year accretion expense		1,229
Settlements		(386	)
Revision of estimates		1,007
Asset retirement obligations at June 30, 2009	$	30,814

(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 June 30, 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 June 30, 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 June 30, 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 (“FSP”) 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. This FSP requires retrospective adjustment of all prior period earnings per unit data. There was no impact to the Company from the adoption of this FSP for the three months or six months ended June 30, 2008, as it reported a loss from continuing operations for these periods.

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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 June 30, 2009:
Loss from continuing operations:
Allocated to units	$	(268,701	)
Allocated to unvested restricted units		―
	$	(268,701	)
Loss per unit:
Basic loss per unit				116,497	$	(2.31	)
Dilutive effect of unit equivalents				―		―
Diluted loss per unit				116,497	$	(2.31	)

Three months ended June 30, 2008:
Loss from continuing operations:
Allocated to units	$	(725,381	)
Allocated to unvested restricted units		―
	$	(725,381	)
Loss per unit:
Basic loss per unit				114,252	$	(6.35	)
Dilutive effect of unit equivalents				―		―
Diluted loss per unit				114,252	$	(6.35	)

Six months ended June 30, 2009:
Loss from continuing operations:
Allocated to units	$	(147,414	)
Allocated to unvested restricted units		―
	$	(147,414	)
Loss per unit:
Basic loss per unit				114,993	$	(1.28	)
Dilutive effect of unit equivalents				―		―
Diluted loss per unit				114,993	$	(1.28	)

Six months ended June 30, 2008:
Loss from continuing operations:
Allocated to units	$	(984,340	)
Allocated to unvested restricted units		―
	$	(984,340	)
Loss per unit:
Basic loss per unit				114,005	$	(8.63	)
Dilutive effect of unit equivalents				―		―
Diluted loss per unit				114,005	$	(8.63	)

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(Unaudited)

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 2.2 million and 2.1 million unit options and warrants for the three months and six months ended June 30, 2009, respectively. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 1.8 million and 1.7 million unit options and warrants for the three months and six months ended June 30, 2008, respectively. All equivalent units were anti-dilutive for the three months and six months ended June 30, 2009, and June 30, 2008, as the Company reported a loss from continuing operations.

(12)	Unit-Based Compensation

During the six months ended June 30, 2009, the Company granted an aggregate 1,083,755 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 $17.5 million. The unit options and restricted units vest over three years. For the three months and six months ended June 30, 2009, the Company recorded unit-based compensation expenses in continuing operations of approximately $3.7 million and $8.0 million, respectively. For the three months and six months ended June 30, 2008, the Company recorded unit-based compensation expenses in continuing operations of approximately $3.9 million and $7.5 million, respectively. These amounts are 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.

(14)	Related Party Transactions

At June 30, 2008, and during the six months ended June 30, 2008, on an aggregate basis, a group of certain direct or indirect wholly owned subsidiaries of Lehman Holdings owned more than 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. Lehman was considered a related party under the provisions of SFAS No. 57, “Related Party Disclosures,” during the period in which its unit ownership exceeded 10%. Lehman’s subsidiaries provided certain services to the Company, including participation in the Company’s Third Amended and Restated Credit Agreement, offering of 2018 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 and six months ended June 30, 2008, the Company paid distributions on units to Lehman of approximately $9.3 million and $18.5 million, respectively, interest on borrowings of approximately $1.0 million and $2.2 million, respectively, and financing fees of approximately $1.3 million and $1.8 million, respectively. In addition, during the three months and six months ended June 30, 2008, the Company paid Lehman approximately $0.5 million and $1.0 million, respectively, on settled derivative contracts, and during the six months ended June 30, 2008, the Company purchased approximately $1.3 million of oil swap contracts from Lehman.

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(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:

	June 30, 2009		December 31, 2008
	(in thousands)

Accrued compensation	$	7,761	$	11,366
Accrued interest		18,465		14,232
Other		877		1,565
	$	27,103	$	27,163

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

	Six Months Ended June 30,
	2009		2008
	(in thousands)

Cash payments for interest	$	29,012	$	60,662

Cash payments for income taxes	$	853	$	274

Noncash investing activities:
In connection with the purchase of oil and gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	―	$	579,254
Cash paid		―		(570,504	)
Liabilities assumed, net	$	―	$	8,750
Noncash financing activities:
Units issued in connection with the purchase of oil and gas properties	$	―	$	23,455

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 $1.7 million and $1.3 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at June 30, 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.

(16)	Recently Issued Pronouncements

Accounting Standards

In July 2009, the FASB issued SFAS No. 168, “FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS 168”), effective for financial statements for interim or annual reporting periods ending after September 15, 2009. SFAS 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative nongovernmental

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

GAAP, superseding existing FASB, American Institute of Certified Public Accountants, EITF and related literature. Beginning with the Form 10-Q for the quarter ended September 30, 2009, references to prior GAAP standards that were used to create the Codification will be replaced or supplemented with references to the relevant section of the Codification.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued and requires disclosure of the date through which an entity has evaluated subsequent events. SFAS 165 is effective for interim and annual periods ending after June 15, 2009, and the Company adopted it effective June 30, 2009. The adoption did not have a material impact on the Company’s results of operations or financial position.

In April 2009, the FASB issued three related FSPs to clarify the application of SFAS 157 to fair value measurements in the current economic environment, modify the recognition of other-than-temporary impairments of debt securities, and require companies to disclose the fair value of financial instruments in interim periods. The final FSPs are effective for interim and annual periods ending after June 15, 2009, and the Company adopted the new FSPs effective June 30, 2009. The adoption did not have a material impact on the Company’s results of operations or financial position. The three related FSPs are as follows:

FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability has Significantly Decreased and Identifying Transactions That Are Not Orderly,” provides guidance on how to determine the fair value of assets and liabilities under SFAS 157 in the current economic environment and reemphasizes that the objective of a fair value measurement remains the price that would be received to sell an asset or paid to transfer a liability at the measurement date.

FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” modifies the requirements for recognizing other-than-temporarily impaired debt securities and significantly changes the existing impairment model for such securities. It also modifies the presentation of other-than-temporary impairment losses and increases the frequency of and expands already required disclosures about other-than-temporary impairment for debt and equity securities.

FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” requires disclosures of the fair value of financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” as amended, in interim financial statements, adding to the current requirement to make those disclosures in annual financial statements. It also requires that companies disclose the method or methods and significant assumptions used to estimate the fair value of financial instruments and a discussion of changes, if any, in the method or methods and significant assumptions during the period.

In April 2009, the FASB issued FSP 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 FSP, assets acquired and liabilities assumed in a business combination that arise from contingencies are 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 is generally 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 is required to recognize all the assets acquired

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

(Unaudited)

and liabilities assumed at fair value with limited exceptions. SFAS 141(R) changes the accounting treatment for certain specific items, including acquisition costs, which are expensed as incurred and 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.

SEC Rule-Making Activity

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:

commodity prices – economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price unless contractual arrangements designate the price to be used;

disclosure of unproved reserves – probable and possible reserves may be disclosed separately on a voluntary basis;

proved undeveloped reserve guidelines – reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered;

reserve estimation using new technologies – reserves may be estimated through the use of reliable technology in addition to flow tests and production history; and

nontraditional resources – the definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.

The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted. The Company is currently evaluating the new rules and assessing the impact they will have on its reported oil and gas reserves. The SEC is coordinating with the FASB to obtain the revisions necessary to SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” and SFAS No. 69, “Disclosures about Oil and Gas Producing Activities,” to provide consistency with the new rules. In the event that consistency is not achieved in time for companies to comply with the new rules, the SEC will consider delaying the compliance date.

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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 June 30, 2009, included the following:

oil, gas and NGL sales of approximately $91.9 million, compared to $255.6 million in the second quarter of 2008;

average daily production of 219 MMcfe/d, compared to 224 MMcfe/d in the second quarter of 2008;

realized gains on commodity derivatives of approximately $111.1 million, compared to realized losses of $97.4 million in the second quarter of 2008;

capital expenditures of approximately $30.1 million, compared to $77.1 million in the second quarter of 2008;

19 wells drilled (all successful), compared to 70 wells drilled (all successful) in the second quarter of 2008; and

average of two operated drilling rigs.

Results from continuing operations for the six months ended June 30, 2009, included the following:

oil, gas and NGL sales of approximately $171.8 million, compared to $431.5 million in the six months ended June 30, 2008;

average daily production of 218 MMcfe/d, compared to 210 MMcfe/d in the six months ended June 30, 2008;

realized gains on commodity derivatives of approximately $235.2 million, compared to realized losses of $102.2 million in the six months ended June 30, 2008;

capital expenditures of approximately $103.5 million, compared to $163.2 million in the six months ended June 30, 2008;

60 wells drilled (59 successful), compared to 146 wells drilled (144 successful) in the six months ended June 30, 2008; and

average of three operated drilling rigs.

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

Commodity Derivative Repositioning

In the third quarter of 2009, the Company repositioned its commodity derivative portfolio to help protect against sustained weakness in commodity prices. The Company canceled oil and gas derivative contracts for years 2012 through 2014 and realized a net gain of approximately $44.8 million, which, along with an incremental premium payment of approximately $48.8 million, was used to raise prices for its oil and gas derivative contracts in years 2010 and 2011. As a result of these transactions, the Company anticipates the borrowing base under its Credit Facility will be reduced to approximately $1.65 billion; however, the Company anticipates the borrowing base under its Credit Facility will be increased in October 2009 due to its pending acquisitions in the Permian Basin (see Note 2).

The following table summarizes open positions as of July 31, 2009, and represents, as of such date, derivatives in place through December 31, 2013, on annual production volumes:

	Year 2009			Year 2010			Year 2011			Year 2012			Year 2013
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMMBtu)		16,494			39,566			31,901			—			—
Average Price ($/MMBtu)	$	8.53		$	8.90		$	9.50		$	—		$	—
Puts:
Hedged Volume (MMMBtu)		2,900			6,960			6,960			—			—
Average Price ($/MMBtu)	$	7.50		$	8.50		$	9.50		$	—		$	—
PEPL Puts: (1)
Hedged Volume (MMMBtu)		2,223			10,634			13,259			—			—
Average Price ($/MMBtu)	$	7.85		$	7.85		$	8.50		$	—		$	—
Total:
Hedged Volume (MMMBtu)		21,617			57,160			52,120			—			—
Average Price ($/MMBtu)	$	8.32		$	8.66		$	9.25		$	—		$	—

Oil Positions:
Fixed Price Swaps:
Hedged Volume (MBbls)		1,015			2,150			2,073			—			—
Average Price ($/Bbl)	$	90.00		$	90.00		$	90.00		$	—		$	—
Puts: (2)
Hedged Volume (MBbls)		768			2,250			2,352			—			—
Average Price ($/Bbl)	$	120.00		$	110.00		$	75.00		$	—		$	—
Collars:
Hedged Volume (MBbls)		104			250			276			—			—
Average Floor Price ($/Bbl)	$	90.00		$	90.00		$	90.00		$	—		$	—
Average Ceiling Price ($/Bbl)	$	114.25		$	112.00		$	112.25		$	—		$	—
Total:
Hedged Volume (MBbls)		1,887			4,650			4,701			—			—
Average Price ($/Bbl)	$	102.21		$	99.68		$	82.50		$	—		$	—

Gas Basis Differential Positions:
PEPL Basis Swaps:
Hedged Volume (MMMBtu)		19,548			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 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.

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

Acquisitions

Public Offering of Units

In May 2009, the Company sold 6,325,000 units representing limited liability company interests at $16.25 per unit ($15.60 per unit, net of underwriting discount), for net proceeds (after deducting underwriting discount and offering expenses), of approximately $98.3 million, which was used to reduce indebtedness under the Company’s Credit Facility. The units were registered under the Securities Act on a Registration Statement on Form S-3 filed May 11, 2009.

Senior Notes Due 2017

In May 2009, the Company issued $250.0 million in aggregate principal amount of the Company’s senior notes due 2017. The 2017 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 expenses) of approximately $230.8 million to reduce indebtedness under its Credit Facility. See “Senior Notes Due 2017” in “Liquidity and Capital Resources” below for additional details.

Credit Facility

In April 2009, the Company entered into an amended and restated Credit Facility, extending the maturity two years, from August 2010 to August 2012. In connection with the Credit Facility, the Company paid approximately $52.7 million in financing fees and expenses, which were deferred and will be amortized over the life of the Credit Facility. The Credit Facility will result in increased interest expense due to higher interest rates compared to the prior credit facility and amortization of financing fees. See “Credit Facility” in “Liquidity and Capital Resources” below for additional details.

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 or lenders in the Company’s Credit Facility will be able to perform under these agreements. 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 June 30, 2009, Compared to Three Months Ended June 30, 2008

	Three Months Ended June 30,
	2009			2008			Variance
	(in thousands)
Revenues and other:
Gas sales	$	34,313		$	118,331		$	(84,018	)
Oil sales		42,266			97,745			(55,479	)
NGL sales		15,327			39,510			(24,183	)
Total oil, gas and NGL sales		91,906			255,586			(163,680	)
Loss on oil and gas derivatives (1)		(232,775	)		(870,804	)		638,029
Gas marketing revenues		1,183			3,593			(2,410	)
Other revenues		641			642			(1	)
	$	(139,045	)	$	(610,983	)	$	471,938
Expenses:
Lease operating expenses	$	33,137		$	25,161		$	7,976
Transportation expenses		2,516			3,663			(1,147	)
Gas marketing expenses		880			3,103			(2,223	)
General and administrative expenses (2)		20,291			18,020			2,271
Exploration costs		2,199			61			2,138
Depreciation, depletion and amortization		50,390			50,885			(495	)
Taxes, other than income taxes		7,882			17,628			(9,746	)
(Gain) loss on sale of assets and other, net		(5	)		―			(5	)
	$	117,290		$	118,521		$	(1,231	)

Other income and (expenses)	$	(12,181	)	$	3,959		$	(16,140	)

Loss from continuing operations before income taxes	$	(268,516	)	$	(725,545	)	$	457,029

Notes to table:

(1)	During the three months ended June 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Appalachian Basin (see Note 2) resulting in realized losses of approximately $68.2 million.

(2)	General and administrative expenses for the three months ended June 30, 2009, and June 30, 2008, include approximately $3.6 million and $3.8 million, respectively, of noncash unit-based compensation expenses.

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

	Three Months Ended June 30,
	2009		2008		Variance
Average daily production:
Gas (MMcf/d)		131		131		—
Oil (MBbls/d)		8.7		9.3		(6	)%
NGL (MBbls/d)		5.9		6.2		(5	)%
Total (MMcfe/d)		219		224		(2	)%

Weighted average prices (hedged): (1)
Gas (Mcf)	$	8.17	$	9.92		(18	)%
Oil (Bbl)	$	113.68	$	81.11		40	%
NGL (Bbl)	$	28.49	$	70.55		(60	)%

Weighted average prices (unhedged): (2)
Gas (Mcf)	$	2.88	$	9.96		(71	)%
Oil (Bbl)	$	53.10	$	114.99		(54	)%
NGL (Bbl)	$	28.49	$	70.55		(60	)%

Representative NYMEX oil and gas prices:
Gas (MMBtu)	$	3.51	$	10.94		(68	)%
Oil (Bbl)	$	59.62	$	123.98		(52	)%

Costs per Mcfe of production:
Lease operating expenses	$	1.67	$	1.24		35	%
Transportation expenses	$	0.13	$	0.18		(28	)%
General and administrative expenses (3)	$	1.02	$	0.89		15	%
Depreciation, depletion and amortization	$	2.53	$	2.50		1	%
Taxes, other than income taxes	$	0.40	$	0.87		(54	)%

Notes to table:

(1)

Includes the effect of realized gains (losses) on derivatives of $111.1 million and $(29.2) million (excluding $68.2 million realized losses on canceled contracts in 2008) for the three months ended June 30, 2009, and June 30, 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 June 30, 2009, and June 30, 2008, include approximately $3.6 million and $3.8 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the three months ended June 30, 2009, and June 30, 2008, were $0.84 per Mcfe and $0.70 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 $163.7 million, or 64%, to approximately $91.9 million for the three months ended June 30, 2009, from $255.6 million for the three months ended June 30, 2008, due to lower commodity prices. Lower gas, oil and NGL prices decreased revenues by approximately $84.2 million, $49.3 million and $22.6 million, respectively.

Average daily production decreased to 219 MMcfe/d during the three months ended June 30, 2009, from 224 MMcfe/d during the three months ended June 30, 2008. Volume decreases during the three months ended June 30, 2009, decreased total oil, gas and NGL revenues by $7.6 million compared to the three months ended June 30, 2008.

The following presents average daily production by region:

	Three Months Ended June 30,
	2009		2008		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		137		145		(8	)	(6	)%
Mid-Continent Shallow		68		64		4		6	%
Western		14		15		(1	)	(7	)%
		219		224		(5	)	(2	)%

The 6% decrease in average daily production in the Mid-Continent Deep region primarily reflects the Company’s sale of assets in Oklahoma in August 2008 (see Note 2), its decision to suspend completions on recent wells drilled in the Granite Wash and shut-in production on certain wells. The 6% increase in average daily production in the Mid-Continent Shallow region reflects results of the Company’s drilling and optimization programs. 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.

Gain (Loss) on Oil and Gas Derivatives

The Company determines the fair value of its oil and gas derivatives utilizing 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 commodity derivatives. During the three months ended June 30, 2009, the Company had commodity derivative contracts in place for approximately 109% of its gas production and 85% of its oil and NGL production, which resulted in realized gains of $111.1 million. During the three months ended June 30, 2008, the Company recorded realized losses of approximately $97.4 million (including realized losses on canceled contracts on estimated future gas production primarily associated with properties in the Appalachian Basin (see Note 2) of approximately $68.2 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 second quarter of 2009, expected future oil and gas prices increased, which resulted in unrealized losses on derivatives of approximately $343.9 million for the three months ended June 30, 2009. During the second quarter of 2008, expected future oil and gas prices increased, which resulted in unrealized losses on derivatives of approximately $773.4 million for the three months ended June 30, 2008. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

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

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $7.9 million, to $33.1 million for the three months ended June 30, 2009, from $25.2 million for the three months ended June 30, 2008. Lease operating expenses per Mcfe also increased, to $1.67 per Mcfe for the three months ended June 30, 2009, from $1.24 per Mcfe for the three months ended June 30, 2008. Lease operating expenses increased primarily due to service and materials cost increases across all operating regions.

Transportation Expenses

Transportation expenses decreased by approximately $1.2 million, or 32%, to $2.5 million for the three months ended June 30, 2009, from $3.7 million for the three months ended June 30, 2008, driven primarily by lower fuel costs.

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 $2.3 million, or 13%, to $20.3 million for the three months ended June 30, 2009, from $18.0 million for the three months ended June 30, 2008. General and administrative expenses per Mcfe also increased, to $1.02 per Mcfe for the three months ended June 30, 2009, from $0.89 per Mcfe for the three months ended June 30, 2008. The increase in expense was primarily due to increases in salaries and benefits expenses of approximately $1.1 million and aggregate professional fees and insurance expenses of approximately $0.7 million.

Exploration Costs

Exploration costs were approximately $2.2 million for the three months ended June 30, 2009, compared to $61,000 for the three months ended June 30, 2008. The increase was primarily due to an increase in unproved leasehold costs of approximately $1.9 million during the three months ended June 30, 2009.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased slightly, by approximately $0.5 million, or 1%, to $50.4 million for the three months ended June 30, 2009, from $50.9 million for the three months ended June 30, 2008. Depreciation, depletion and amortization per Mcfe increased slightly to $2.53 per Mcfe for the three months ended June 30, 2009, from $2.50 per Mcfe for the three months ended June 30, 2008.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, decreased by approximately $9.7 million, or 55%, to $7.9 million for the three months ended June 30, 2009, from $17.6 million for the three months ended June 30, 2008. Production taxes, which are a function of revenues generated from production, decreased by approximately $10.1 million compared to the three months ended June 30, 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 $0.7 million compared to the three months ended June 30, 2008.

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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 June 30,
	2009			2008			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(23,262	)	$	(23,332	)	$	70
Gain on interest rate swaps		11,918			31,604			(19,686	)
Other, net		(837	)		(4,313	)		3,476
	$	(12,181	)	$	3,959		$	(16,140	)

Other income and (expenses) increased by approximately $16.1 million, due primarily to interest rate swap gains and losses. The unrealized mark-to-market gain on interest rate swaps decreased as the forward curve increased less during the three months ended June 30, 2009, than it did during the three months ended June 30, 2008. This was partially offset by increased realized losses on interest rate swaps during the three months ended June 30, 2009, compared to the three months ended June 30, 2008.

In the second quarter of 2009, the Company entered into an amended and restated Credit Facility and issued senior notes due 2017, which will result in increased interest expense due to higher interest rates and amortization of financing fees. See “Credit Facility” and “Senior Notes Due 2017” in “Liquidity and Capital Resources” below for additional details.

Income Tax Benefit (Expense)

Income tax benefit (expense) was approximately $(0.2) million and $0.2 million for the three months ended June 30, 2009 and June 30, 2008, respectively. Tax expense for the three months ended June 30, 2009, 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.

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

Results of Operations – Continuing Operations

Six Months Ended June 30, 2009, Compared to Six Months Ended June 30, 2008

	Six Months Ended June 30,
	2009			2008			Variance
	(in thousands)
Revenues and other:
Gas sales	$	76,541		$	203,759		$	(127,218	)
Oil sales		69,036			162,052			(93,016	)
NGL sales		26,193			65,647			(39,454	)
Total oil, gas and NGL sales		171,770			431,458			(259,688	)
Loss on oil and gas derivatives (1)		(71,460	)		(1,139,598	)		1,068,138
Gas marketing revenues		1,699			6,409			(4,710	)
Other revenues		1,607			1,121			486
	$	103,616		$	(700,610	)	$	804,226
Expenses:
Lease operating expenses	$	66,869		$	44,651		$	22,218
Transportation expenses		5,483			6,991			(1,508	)
Gas marketing expenses		1,220			5,520			(4,300	)
General and administrative expenses (2)		43,592			37,096			6,496
Exploration costs		3,764			2,681			1,083
Depreciation, depletion and amortization		102,494			95,255			7,239
Taxes, other than income taxes		15,449			30,601			(15,152	)
(Gain) loss on sale of assets and other, net		(26,716	)		―			(26,716	)
	$	212,155		$	222,795		$	(10,640	)

Other income and (expenses)	$	(38,554	)	$	(60,890	)	$	22,336

Loss from continuing operations before income taxes	$	(147,093	)	$	(984,295	)	$	837,202

Notes to table:

(1)

During the six months ended June 30, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production resulting in realized gains of $4.3 million. During the six months ended June 30, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Appalachian Basin (see Note 2) resulting in realized losses of approximately $68.2 million.

(2)	General and administrative expenses for the six months ended June 30, 2009, and June 30, 2008, include approximately $7.8 million and $7.4 million, respectively, of noncash unit-based compensation expenses.

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

	Six Months Ended June 30,
	2009		2008		Variance
Average daily production:
Gas (MMcf/d)		132		127		4	%
Oil (MBbls/d)		8.8		8.6		2	%
NGL (MBbls/d)		5.5		5.3		4	%
Total (MMcfe/d)		218		210		4	%

Weighted average prices (hedged): (1)
Gas (Mcf)	$	8.06	$	9.10		(11	)%
Oil (Bbl)	$	115.93	$	78.37		48	%
NGL (Bbl)	$	26.09	$	68.60		(62	)%

Weighted average prices (unhedged): (2)
Gas (Mcf)	$	3.21	$	8.85		(64	)%
Oil (Bbl)	$	43.45	$	103.88		(58	)%
NGL (Bbl)	$	26.09	$	68.60		(62	)%

Representative NYMEX oil and gas prices:
Gas (MMBtu)	$	4.21	$	9.49		(56	)%
Oil (Bbl)	$	51.35	$	110.94		(54	)%

Costs per Mcfe of production:
Lease operating expenses	$	1.70	$	1.17		45	%
Transportation expenses	$	0.14	$	0.18		(22	)%
General and administrative expenses (3)	$	1.11	$	0.97		14	%
Depreciation, depletion and amortization	$	2.60	$	2.50		4	%
Taxes, other than income taxes	$	0.39	$	0.80		(51	)%

Notes to table:

(1)

Includes the effect of realized gains (losses) on derivatives of $231.0 million (excluding $4.3 million realized gains on canceled contracts) and $(34.0) million (excluding $68.2 million realized losses on canceled contracts) for the six months ended June 30, 2009, and June 30, 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 six months ended June 30, 2009, and June 30, 2008, include approximately $7.8 million and $7.4 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the six months ended June 30, 2009, and June 30, 2008, were $0.91 per Mcfe and $0.78 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 $259.7 million, or 60%, to approximately $171.8 million for the six months ended June 30, 2009, from $431.5 million for the six months ended June 30, 2008, due to lower commodity prices. Lower gas, oil and NGL prices decreased revenues by approximately $134.6 million, $96.0 million and $42.7 million, respectively.

Average daily production increased to 218 MMcfe/d during the six months ended June 30, 2009, from 210 MMcfe/d during the six months ended June 30, 2008. Volume increases during the six months ended June 30, 2009, increased total oil, gas and NGL revenues by $13.6 million compared to the six months ended June 30, 2008.

The following presents average daily production by region:

	Six Months Ended June 30,
	2009		2008		Increase
Average daily production (MMcfe/d):
Mid-Continent Deep		140		137		3	2	%
Mid-Continent Shallow		64		59		5	8	%
Western		14		14		—	—
		218		210		8	4	%

The 2% increase in average daily production in the Mid-Continent Deep region reflects results of the Company’s ongoing optimization and workover projects focused on the base asset, partially offset by the Company’s sale of assets in Oklahoma in August 2008 (see Note 2), its decision to suspend completions on recent wells drilled in the Granite Wash and shut-in production on certain wells. The 8% increase in average daily production in the Mid-Continent Shallow region reflects results of the Company’s drilling and optimization programs. 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.

Gain (Loss) on Oil and Gas Derivatives

The Company determines the fair value of its oil and gas derivatives utilizing 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 commodity derivatives. During the six months ended June 30, 2009, the Company had commodity derivative contracts in place for approximately 109% of its gas production and 87% of its oil and NGL production, which resulted in realized gains of $235.2 million (including realized gains on canceled contracts of approximately $4.3 million). During the six months ended June 30, 2008, the Company recorded realized losses of approximately $102.2 million (including realized losses on canceled contracts of approximately $68.2 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 two quarters of 2009, expected future oil and gas prices increased, which resulted in unrealized losses on derivatives of approximately $306.7 million for the six months ended June 30, 2009. During the first two quarters of 2008, expected future oil and gas prices increased, which resulted in unrealized losses on derivatives of approximately $1.04 billion for the six months ended June 30, 2008. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

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

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $22.2 million, to $66.9 million for the six months ended June 30, 2009, from $44.7 million for the six months ended June 30, 2008. Lease operating expenses per Mcfe also increased, to $1.70 per Mcfe for the six months ended June 30, 2009, from $1.17 per Mcfe for the six months ended June 30, 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 materials cost increases across all operating regions.

Transportation Expenses

Transportation expenses decreased by approximately $1.5 million, or 21%, to $5.5 million for the six months ended June 30, 2009, from $7.0 million for the six months ended June 30, 2008, driven primarily by lower fuel costs.

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 $6.5 million, or 18%, to $43.6 million for the six months ended June 30, 2009, from $37.1 million for the six months ended June 30, 2008. General and administrative expenses per Mcfe also increased, to $1.11 per Mcfe for the six months ended June 30, 2009, from $0.97 per Mcfe for the six months ended June 30, 2008. The increase in expense was primarily due to increases in salaries and benefits expenses of approximately $3.2 million, charitable contributions of approximately $1.2 million and aggregate professional fees and insurance expenses of approximately $1.8 million.

Exploration Costs

Exploration costs increased by approximately $1.1 million, or 41%, to $3.8 million for the six months ended June 30, 2009, from $2.7 million for the six months ended June 30, 2008. The increase was primarily due to an increase in unproved leasehold costs of approximately $3.3 million, partially offset by a decrease in 3-D seismic and data library expenses.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $7.2 million, or 8%, to $102.5 million for the six months ended June 30, 2009, from $95.3 million for the six months ended June 30, 2008. Higher total production levels and higher depletion rates associated with downward year-end price-related reserve revisions were the main reason for the increase. Depreciation, depletion and amortization per Mcfe increased to $2.60 per Mcfe for the six months ended June 30, 2009, from $2.50 per Mcfe for the six months ended June 30, 2008.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, decreased by approximately $15.2 million, or 50%, to $15.4 million for the six months ended June 30, 2009, from $30.6 million for the six months ended June 30, 2008. Production taxes, which are a function of revenues generated from production, decreased by approximately $16.1 million compared to the six months ended June 30, 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 $1.5 million compared to the six months ended June 30, 2008.

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

The increase in (gain) loss on sale of assets and other, net for the six months ended June 30, 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)

	Six Months Ended June 30,
	2009			2008			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(37,671	)	$	(48,625	)	$	10,954
Gain (loss) on interest rate swaps		347			(7,789	)		8,136
Other, net		(1,230	)		(4,476	)		3,246
	$	(38,554	)	$	(60,890	)	$	22,336

Other income and (expenses) decreased by approximately $22.3 million due to lower interest expense and a gain on interest rate swaps during the six months ended June 30, 2009, compared to a loss on interest rate swaps during the six months ended June 30, 2008. Interest expense was driven by lower interest rates on the Credit Facility, which were driven by lower LIBOR rates. The unrealized mark-to-market change on interest rate swaps was a positive impact, as the forward curve decreased less during the six months ended June 30, 2009, than it did during the six months ended June 30, 2008. This was partially offset by increased realized losses on interest rate swaps during the six months ended June 30, 2009, compared to the six months ended June 30, 2008.

In the second quarter of 2009, the Company entered into an amended and restated Credit Facility and issued senior notes due in 2017, which will result in increased interest expense due to higher interest rates and amortization of financing fees. See “Credit Facility” and “2017 Notes” in “Liquidity and Capital Resources” below for additional details.

Income Tax Benefit (Expense)

Income tax expense was approximately $0.3 million and $45,000 for the six months ended June 30, 2009, and June 30, 2008, respectively. Tax expense for the six months ended June 30, 2009, 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.

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

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. For the six months ended June 30, 2009, the Company’s capital expenditures were approximately $103.5 million. For 2009, the Company estimates its total capital expenditures will be approximately $150.0 million. This estimate is under continuous review and is subject to ongoing adjustment. The Company expects to fund these capital expenditures with cash flow from operations.

As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company’s future success in growing reserves and production 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. In April 2009, the Company entered into an amended and restated Credit Facility with a maturity of August 2012. See “Credit Facility” below for additional details. At July 31, 2009, the Company had $548.0 million in available borrowing capacity under its Credit Facility. The Company’s Credit Facility, 2017 Notes and 2018 Notes impose certain restrictions on the Company’s ability to obtain additional debt financing. Based upon current expectations, the Company believes liquidity and capital resources will be sufficient for the conduct of its business and operations.

Cash Flows

The following presents a comparative cash flow summary:

	Six Months Ended June 30,
	2009			2008			Variance
	(in thousands)
Net cash:
Provided by operating activities	$	258,274		$	60,583		$	197,691
Used in investing activities		(103,410	)		(672,883	)		569,473
Provided by (used in) financing activities		(156,432	)		620,471			(776,903	)
Net increase (decrease) in cash and cash equivalents	$	(1,568	)	$	8,171		$	(9,739	)

Operating Activities

At June 30, 2009, the Company had $27.1 million of cash and cash equivalents compared to $28.7 million at December 31, 2008. Cash provided by operating activities for the six months ended June 30, 2009, was approximately $258.3 million, compared to $60.6 million for the six months ended June 30, 2008. The increase in operating cash flows was primarily driven by increased cash collections and 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 $103.4 million for the six months ended June 30, 2009, compared to $672.9 million for the six months ended June 30, 2008. The decrease in cash used in investing activities was primarily due to a lack of acquisition activity during the six months ended June 30, 2009, compared to the six months ended June 30, 2008. The total cash used in investing activities for the six months ended June 30, 2009, includes approximately $125.1 million for the drilling and development of oil and gas properties. During the six months ended June 30, 2009, the Company also received proceeds from sales of oil and gas properties totaling approximately $26.6 million, primarily due to the sale to Devon (see Note 2).

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

Financing Activities

Cash used by financing activities was approximately $156.4 million for the six months ended June 30, 2009, compared to cash provided by financing activities of $620.5 million for the six months ended June 30, 2008, primarily due to lower proceeds from the issuance of debt during the six months ended June 30, 2009, compared to proceeds received from the issuance of debt during the same period of the prior year. Cash provided by operating activities was sufficient to pay capital expenditures and distributions during the six months ended June 30, 2009. The following provides a comparative summary of proceeds from the issuance of debt and principal payments on debt:

	Six Months Ended June 30,
	2009			2008
	(in thousands)
Proceeds from issuance of debt:
Credit facility	$	169,000		$	523,000
Senior notes		237,703			250,000
Term loan		—			400,000
	$	406,703		$	1,173,000

Principal payments on debt:
Credit facility	$	(454,393	)	$	(140,000	)
Term loan		—			(243,602	)
Notes payable		—			(1,314	)
	$	(454,393	)	$	(384,916	)

Distributions

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

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

On July 23, 2009, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the second quarter of 2009. The distribution totaling approximately $76.4 million will be paid August 14, 2009, to unitholders of record as of the close of business August 7, 2009.

Credit Facility

On April 28, 2009, the Company entered into a Credit Facility with an initial borrowing base of $1.75 billion and a maturity of August 2012, which amended and restated the Company’s existing credit facility, which had a maturity of August 2010. The terms of the Credit Facility required that, upon issuance of the senior notes in May 2009, (see below), the borrowing base be decreased by $62.5 million, to $1.69 billion. At July 31, 2009, available borrowing capacity was $548.0 million, which includes a $5.5 million reduction in availability for outstanding letters of credit. In connection with the amended and restated Credit Facility, the Company paid approximately $52.7 million in financing fees and expenses, which were deferred and will be amortized over the life of the Credit Facility.

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

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 annum on the unused portion of the borrowing base under the Credit Facility.

The Credit Facility contains various covenants, substantially similar to those included prior to the amendment and restatement, which limit the Company’s ability to: (i) incur indebtedness; (ii) enter into commodity and interest rate swaps; (iii) grant certain liens; (iv) make certain loans, acquisitions, capital expenditures and investments; (v) make distributions other than from available cash; and (vi) 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 those included prior to the amendment and restatement, which 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.

Senior Notes Due 2017

On May 12, 2009, the Company entered into a purchase agreement with a group of Initial Purchasers, pursuant to which the Company agreed to issue $250.0 million in aggregate principal amount of the Company’s senior notes due 2017 (see Note 6). The 2017 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 expenses) of approximately $230.8 million to reduce indebtedness under its Credit Facility. In connection with the 2017 Notes, the Company incurred financing fees and expenses of approximately $6.9 million, which will be amortized over the life of the 2017 Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. The $12.3 million discount on the 2017 Notes will be amortized over the life of the 2017 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 2017 Notes.

The 2017 Notes were issued under an Indenture dated May 18, 2009, mature May 15, 2017, and bear interest at 11.75%. Interest is payable semi-annually beginning November 15, 2009. The 2017 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 2017 Notes on a senior unsecured basis. The Indenture provides that the Company may redeem: (i) on or prior to May 15, 2011, up to 35% of the aggregate principal amount of the 2017 Notes at a redemption price of 111.75% of the principal amount, plus accrued and unpaid interest; (ii) prior to May 15, 2013, all or part of the 2017 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 May 15, 2013, all or part of the 2017 Notes at redemption prices equal to 105.875% in 2013, 102.938% in 2014 and 100% in 2015 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 2017 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

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

In connection with the issuance and sale of the 2017 Notes, the Company entered into a Registration Rights Agreement with the Initial Purchasers. Under the Registration Rights Agreement, the Company agreed to use its reasonable best efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the 2017 Notes in exchange for outstanding 2017 Notes. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2017 Notes. The Company will not be obligated to file the registration statements described above if the restrictive legend on the 2017 Notes has been removed and the 2017 Notes are freely tradable (in each case, other than with respect to persons that are affiliates of the Company) pursuant to Rule 144 under the Securities Act, as of the 366th day after the 2017 Notes were issued. If the Company fails to satisfy its obligations under the Registration Rights Agreement, the Company may be required to pay additional interest to holders of the 2017 Notes under certain circumstances.

Senior Notes Due 2018

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 2018 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 expenses) of approximately $243.6 million to repay an outstanding term loan. In connection with the 2018 Notes, the Company incurred financing fees and expenses of approximately $7.8 million, which will be amortized over the life of the 2018 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 2018 Notes will be amortized over the life of the 2018 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 2018 Notes.

The 2018 Notes were issued under an Indenture dated June 27, 2008, mature July 1, 2018, and bear interest at 9.875%. Interest is payable semi-annually beginning January 1, 2009. The 2018 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 2018 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 2018 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 2018 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 2018 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 2018 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

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

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 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.

Contingencies

In September 2008 and October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed voluntary petitions for reorganization under Chapter 11 (see Note 10). As of June 30, 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 June 30, 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 six months ended June 30, 2009, and June 30, 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.

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in a table of contractual obligations in the 2008 Annual Report on Form 10-K. With the exception of $250.0 million of 2017 Notes, as of June 30, 2009, there have been no significant changes to the Company’s contractual obligations from December 31, 2008. See “Senior Notes Due 2017” above for additional details.

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and

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

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 11 and Note 16 for details regarding implementation of new accounting pronouncements.

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 June 30, 2009, the fair value of contracts that settle during the next 12 months was an asset of approximately $285.3 million and a liability of $3.1 million for a net asset of approximately $282.2 million. A 10% increase in the index oil and gas prices above the June 30, 2009, prices for the next twelve months would result in a net asset of approximately $204.6 million which represents a decrease in the fair value of approximately $77.6 million; conversely, a 10% decrease in the index oil and gas prices would result in a net asset of approximately $361.1 million which represents an increase in the fair value of approximately $78.9 million.

Interest Rate Risk

At June 30, 2009, the Company had long-term debt outstanding under its Credit Facility of approximately $1.12 billion, which incurred interest at floating rates (see Note 6). A 1% increase in LIBOR would result in an estimated $11.2 million increase in annual interest expense. The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates (see Note 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 June 30, 2009, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 6.65%. A 1% increase in the average public bond yield spread would result in an estimated $0.7 million increase in net income for the three months and six months ended June 30, 2009. At June 30, 2009, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 4.99%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $6.1 million decrease in net income for the three months and six months ended June 30, 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, as appropriate, the Company’s Audit Committee of the Board of Directors, 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 June 30, 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 conditions may change, or because the degree of compliance with policies or procedures may deteriorate.

There were no changes in the Company’s internal controls over financial reporting during the second 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. Except as set forth below, as of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

Changes to current federal tax laws may affect unitholders’ ability to take certain tax deductions.

Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect the ability to take certain operations-related deductions, including deductions for intangible drilling and percentage depletion, and deductions for United States production activities. We are unable to predict whether any changes, or other proposals to such laws, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

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 second 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)

April 1 – 30 (1)

9,364

$ 14.88

―

$ 85.4

(1)	During the second quarter of 2009, 9,364 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 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.

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PART II – OTHER INFORMATION - Continued

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

The Company’s Annual Meeting of Unitholders was held on May 5, 2009. Set forth below are descriptions of the matters voted on at the meeting and the results of the votes taken at the meeting.

To elect five directors to the Company’s Board of Directors to serve until the 2010 Annual Meeting of Unitholders.

Name of Director	Votes For		Votes Withheld

Michael C. Linn		96,423,360		1,388,585
George A. Alcorn		96,510,893		1,301,052
Terrence S. Jacobs		95,806,827		2,005,118
Joseph P. McCoy		96,573,812		1,238,133
Jeffrey C. Swoveland		96,497,948		1,313,997

To ratify the appointment of KPMG LLP as independent auditor of the Company for the fiscal year ending December 31, 2009.

Votes For	Votes Against	Abstentions

96,732,640	759,481	320,007

Item 5. Other Information

On August 5, 2009, the Company entered into an agreement to purchase certain oil and gas properties located in the Permian Basin in Texas and New Mexico for a contract price of $95.0 million. The Company anticipates that the acquisition will close in the third quarter of 2009, subject to closing conditions and will be financed with borrowings under the Company’s existing credit facility. The purchase and sale agreement for the acquisition will be filed as an exhibit to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2009.

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PART II – OTHER INFORMATION - Continued

Item 6. Exhibits

Exhibit Number			Description

4	.1	—	Indenture, dated May 18, 2009, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 18, 2009)
4	.2	—	Registration Rights Agreement, dated May 18, 2009, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on May 18, 2009)
10	.1†	—	First Amendment, dated May 15, 2009, to Fourth Amended and Restated Credit Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto
31	.1†	—	Section 302 Certification of 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.

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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: August 6, 2009	/s/ David B. Rottino
	David B. Rottino
	Senior Vice President and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)