Edgar Filing: LINN ENERGY, LLC

form10q22010.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, 2010

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

for the transition period from _______________ to _______________

Commission File Number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)


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

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

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

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

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

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

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

As of June 30, 2010, there were 147,353,365 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, 2010, and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2010, and June 30, 2009	2
	Condensed Consolidated Statement of Unitholders’ Capital for the six months ended June 30, 2010	3
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2010, and June 30, 2009	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	42

	Part II - Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Reserved	44
Item 5.	Other Information	44
Item 6.	Exhibits	45

	Signature	46

Table of Contents

GLOSSARY OF TERMS

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

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

Bcf. One billion cubic feet.

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

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

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

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

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

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

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

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

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

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.

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

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2010			2009
	(Unaudited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	209,741		$	22,231
Accounts receivable – trade, net		141,570			109,311
Derivative instruments		302,475			249,756
Other current assets		39,870			28,162
Total current assets		693,656			409,460

Noncurrent assets:
Oil and natural gas properties (successful efforts method)		4,914,282			4,076,795
Less accumulated depletion and amortization		(563,500	)		(463,413	)
		4,350,782			3,613,382

Other property and equipment		130,192			118,867
Less accumulated depreciation		(29,236	)		(23,583	)
		100,956			95,284

Derivative instruments		224,069			145,457
Other noncurrent assets		104,711			76,673
		328,780			222,130
Total noncurrent assets		4,780,518			3,930,796
Total assets	$	5,474,174		$	4,340,256

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	164,203		$	124,358
Derivative instruments		9,713			51,025
Other accrued liabilities		52,975			33,922
Total current liabilities		226,891			209,305

Noncurrent liabilities:
Credit facility		600,000			1,100,000
Senior notes, net		1,758,169			488,831
Derivative instruments		33,470			53,923
Other noncurrent liabilities		42,185			36,193
Total noncurrent liabilities		2,433,824			1,678,947

Unitholders’ capital:
147,353,365 units and 129,940,617 units issued and outstanding at June 30, 2010, and December 31, 2009, respectively		2,334,958			2,098,599
Accumulated income		478,501			353,405
		2,813,459			2,452,004
Total liabilities and unitholders’ capital	$	5,474,174		$	4,340,256

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

Table of Contents

LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	153,195		$	91,906		$	302,581		$	171,770
Gains (losses) on oil and natural gas derivatives		123,791			(232,775	)		219,794			(71,460	)
Natural gas marketing revenues		1,223			1,183			2,617			1,699
Other revenues		195			641			448			1,607
		278,404			(139,045	)		525,440			103,616
Expenses:
Lease operating expenses		38,367			33,137			69,589			66,869
Transportation expenses		5,256			2,516			9,876			5,483
Natural gas marketing expenses		772			880			1,741			1,220
General and administrative expenses		23,306			20,291			47,794			43,592
Exploration costs		155			2,199			4,016			3,764
Bad debt expenses		(208	)		—			(19	)		—
Depreciation, depletion and amortization		57,941			50,390			107,132			102,494
Taxes, other than income taxes		10,391			7,882			20,591			15,449
Gains on sale of assets and other, net		(52	)		(5	)		(374	)		(26,716	)
		135,928			117,290			260,346			212,155
Other income and (expenses):
Interest expense, net of amounts capitalized		(45,969	)		(23,262	)		(73,622	)		(37,671	)
Gains (losses) on interest rate swaps		(33,245	)		11,918			(56,407	)		347
Other, net		(3,691	)		(837	)		(4,292	)		(1,230	)
		(82,905	)		(12,181	)		(134,321	)		(38,554	)
Income (loss) from continuing operations before income taxes		59,571			(268,516	)		130,773			(147,093	)
Income tax benefit (expense)		215			(185	)		(5,677	)		(321	)
Income (loss) from continuing operations		59,786			(268,701	)		125,096			(147,414	)

Discontinued operations:
Gains (losses) on sale of assets, net of taxes		—			330			—			(718	)
Loss from discontinued operations, net of taxes		—			(101	)		—			(939	)
		—			229			—			(1,657	)
Net income (loss)	$	59,786		$	(268,472	)	$	125,096		$	(149,071	)

Income (loss) per unit – continuing operations:
Basic	$	0.41		$	(2.31	)	$	0.90		$	(1.28	)
Diluted	$	0.40		$	(2.31	)	$	0.90		$	(1.28	)
Income (loss) per unit – discontinued operations:
Basic	$	—		$	0.01		$	—		$	(0.02	)
Diluted	$	—		$	0.01		$	—		$	(0.02	)
Net income (loss) per unit:
Basic	$	0.41		$	(2.30	)	$	0.90		$	(1.30	)
Diluted	$	0.40		$	(2.30	)	$	0.90		$	(1.30	)
Weighted average units outstanding:
Basic		146,124			116,497			137,874			114,993
Diluted		146,462			116,497			138,234			114,993

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.

Table of Contents

LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL

(Unaudited)

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

December 31, 2009		129,941		$	2,098,599		$	353,405	$	―		$	2,452,004
Sale of units, net of underwriting discounts and expenses of $17,563		17,250			413,687			—		—			413,687
Issuance of units		658			798			—		—			798
Cancellation of units		(496	)		(11,832	)		—		11,832			—
Purchase of units					—			—		(11,832	)		(11,832	)
Distributions to unitholders					(175,435	)		—		—			(175,435	)
Unit-based compensation expenses					7,400			—		—			7,400
Excess tax benefit from unit-based compensation					1,741			—		—			1,741
Net income					—			125,096		—			125,096
June 30, 2010		147,353		$	2,334,958		$	478,501	$	—		$	2,813,459

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

Table of Contents

LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2010			2009
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	125,096		$	(149,071	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		107,132			102,494
Unit-based compensation expenses		7,400			7,954
Bad debt expenses		(19	)		—
Amortization and write-off of deferred financing fees and other		15,711			8,323
Gains on sale of assets and other, net		(515	)		(24,933	)
Deferred income tax		2,702			―
Mark-to-market on derivatives:
Total (gains) losses		(163,387	)		71,113
Cash settlements		135,594			212,993
Cash settlements on canceled derivatives		(74,275	)		4,197
Premiums paid for derivatives		(91,028	)		—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		(22,791	)		35,809
Decrease in other assets		11,859			3,639
Increase (decrease) in accounts payable and accrued expenses		3,108			(15,536	)
Increase in other liabilities		18,596			1,292
Net cash provided by operating activities		75,183			258,274

Cash flow from investing activities:
Acquisition of oil and natural gas properties, net of cash acquired		(771,189	)		—
Development of oil and natural gas properties		(62,357	)		(125,107	)
Purchases of other property and equipment		(8,125	)		(4,952	)
Proceeds from sale of properties and equipment		586			26,649
Net cash used in investing activities		(841,085	)		(103,410	)

Cash flow from financing activities:
Proceeds from sale of units		431,250			102,781
Proceeds from borrowings		2,188,176			406,703
Repayments of debt		(1,420,000	)		(454,393	)
Distributions to unitholders		(175,435	)		(144,994	)
Financing fees, offering expenses and other, net		(60,488	)		(63,833	)
Excess tax benefit from unit-based compensation		1,741			—
Purchase of units		(11,832	)		(2,696	)
Net cash provided by (used in) financing activities		953,412			(156,432	)

Net increase (decrease) in cash and cash equivalents		187,510			(1,568	)
Cash and cash equivalents:
Beginning		22,231			28,668
Ending	$	209,741		$	27,100

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	Basis of Presentation

Nature of Business

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

Principles of Consolidation and Reporting

The condensed consolidated financial statements at June 30, 2010, and for the three months and six months ended June 30, 2010, and June 30, 2009, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with United States generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations, and as such this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

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

Use of Estimates

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(2)	Acquisitions and Divestitures

Acquisitions – 2010

On May 27, 2010, the Company completed the acquisition of interests in Henry Savings LP and Henry Savings Management LLC (collectively referred to as “Henry”) that primarily hold oil and natural gas properties located in the Permian Basin. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $317.9 million in cash, including a deposit of $30.5 million paid in March 2010, and recorded a receivable from Henry of $10.1 million, resulting in total consideration for the acquisition of approximately $307.8 million. The transaction was financed with borrowings under the Company’s Credit Facility (as defined in Note 6). The acquisition increased the Company’s position in the Permian Basin.

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

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

These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

Assets:
Cash acquired	$	15,367
Current and other assets		31,107
Oil and natural gas properties		770,602
Total assets acquired	$	817,076

Liabilities:
Current liabilities	$	26,653
Asset retirement obligations		4,784
Total liabilities assumed	$	31,437
Net assets acquired	$	785,639

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

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

Acquisitions – Pending

On June 30, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Permian Basin for a contract price of $90.0 million. The Company anticipates the acquisition will close on or before August 16, 2010, subject to closing conditions and will be financed with internally generated cash flow and proceeds from borrowings under its Credit Facility.

On July 16, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the East Texas Oil Field in Gregg and Rusk counties for a contract price of $95.0 million. The Company anticipates the acquisition will close on or before October 1, 2010, subject to closing conditions and will be financed with internally generated cash flow and proceeds from borrowings under its Credit Facility.

Acquisitions – 2009

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Divestitures

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

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

(3)	Unitholders’ Capital

Public Offering of Units

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

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. During the six months ended June 30, 2010, 486,700 units were repurchased at an average unit price of $23.79, for a total cost of approximately $11.6 million. All units were subsequently canceled. At June 30, 2010, approximately $73.8 million was available for unit repurchase under the program. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are repurchased at fair market value on the date of repurchase.

Cancellation of Units

During the six months ended June 30, 2010, the Company purchased 9,055 units for approximately $0.3 million, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan (see Note 5). All units were subsequently canceled.

Distributions

Under the Company’s limited liability company agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the Company during the six months ended June 30, 2010, are presented on the condensed consolidated statement of unitholders’ capital. On July 27, 2010, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the second quarter of 2010. This distribution, totaling approximately $92.9 million, will be paid on August 13, 2010, to unitholders of record as of the close of business on August 6, 2010.

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(4) Oil and Natural Gas Capitalized Costs

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

	June 30, 2010			December 31, 2009
	(in thousands)
Proved properties:
Leasehold acquisition	$	4,118,304		$	3,398,292
Development		664,632			600,436
Unproved properties		131,346			78,067
		4,914,282			4,076,795
Less accumulated depletion and amortization		(563,500	)		(463,413	)
	$	4,350,782		$	3,613,382

(5)	Unit-Based Compensation

During the six months ended June 30, 2010, the Company granted an aggregate 653,254 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $16.7 million. The restricted units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(in thousands)

General and administrative expenses	$	3,196	$	3,568	$	7,210	$	7,769
Lease operating expenses		69		83		190		185
Total unit-based compensation expenses	$	3,265	$	3,651	$	7,400	$	7,954
Income tax benefit	$	1,291	$	—	$	2,927	$	—

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(6)

Debt

The following summarizes debt outstanding:

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

Credit facility	$	600		$	600		2.64	%	$	1,100		$	1,100		2.98	%
11.75% senior notes due 2017		250			281		12.73	%		250			279		12.73	%
9.875% senior notes due 2018		256			271		10.25	%		256			271		10.25	%
8.625% senior notes due 2020		1,300			1,327		9.00	%		―			―		―
Less current maturities		―			―					―			―
		2,406		$	2,479					1,606		$	1,650
Unamortized discount		(48	)							(17	)
Total debt, net of discount	$	2,358							$	1,589

(1)

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

(2)

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

Credit Facility

On April 6, 2010, the Company entered into an amendment to its Fourth Amended and Restated Credit Agreement (“Credit Facility”) that provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015. On June 2, 2010, at the Company’s request and upon approval of all the lenders, the borrowing base under the Credit Facility was increased to $1.50 billion as a result of the increased value of the Company’s oil and natural gas reserves related to recent acquisitions (see Note 2).

In connection with amendments to its Credit Facility during 2010, the Company incurred financing fees and expenses of approximately $16.2 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations. At June 30, 2010, available borrowing capacity was $895.0 million, which includes a $5.0 million reduction in availability for outstanding letters of credit.

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

Senior Notes Due 2017 and Senior Notes Due 2018

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

Senior Notes Due 2020

On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (“2020 Notes”) at a price of 97.552%. The 2020 Notes were sold to a group of initial purchasers (“Initial Purchasers”) and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $1.24 billion (after deducting the Initial Purchasers’ discounts and offering expenses). The Company used the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility. The remaining proceeds were used to fund or partially fund acquisitions and for general corporate purposes. In connection with the 2020 Notes, the Company incurred financing fees and expenses of approximately $27.5 million, which will be amortized over the life of the 2020 Notes. The $31.8 million discount on the 2020 Notes will also be amortized over the life of the 2020 Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

The 2020 Notes were issued under an Indenture dated April 6, 2010, (“Indenture”), mature April 15, 2020, and bear interest at 8.625%. Interest is payable semi-annually beginning October 15, 2010. The 2020 Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries has guaranteed the 2020 Notes on a senior unsecured basis. The Indenture provides that the Company may redeem: (i) on or prior to April 15, 2013, up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 108.625% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to April 15, 2015, all or part of the 2020 Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the Indenture) and accrued and unpaid interest; and (iii) on or after April 15, 2015, all or part of the 2020 Notes at redemption prices equal to 104.313% in 2015, 102.875% in 2016, 101.438% in 2017 and 100% in 2018 and thereafter, in each case, of the principal amount redeemed, plus accrued and unpaid interest. The 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 2020 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the

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

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

(7)	Derivatives

Commodity Derivatives

The Company sells oil, natural gas and NGL in the normal course of its business and utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company enters into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural 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; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	June 30 – December 31, 2010			2011			2012			2013			2014		2015
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		19,783			31,901			31,110			31,025			31,025		31,025
Average price ($/MMBtu)	$	8.90		$	9.50		$	6.25		$	6.25		$	6.25	$	6.25
Puts:
Hedged volume (MMMBtu)		3,480			6,960			25,364			25,295			―		―
Average price ($/MMBtu)	$	8.50		$	9.50		$	6.25		$	6.25		$	―	$	―
PEPL puts: (1)
Hedged volume (MMMBtu)		5,317			13,259			―			―			―		―
Average price ($/MMBtu)	$	7.85		$	8.50		$	―		$	―		$	―	$	―
Total:
Hedged volume (MMMBtu)		28,580			52,120			56,474			56,320			31,025		31,025
Average price ($/MMBtu)	$	8.66		$	9.25		$	6.25		$	6.25		$	6.25	$	6.25

Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)		1,075			2,803			3,386			3,376			―		―
Average price ($/Bbl)	$	90.00		$	89.91		$	98.92		$	98.92		$	―	$	―
Puts: (3)
Hedged volume (MBbls)		1,125			2,352			2,196			2,190			―		―
Average price ($/Bbl)	$	110.00		$	75.00		$	75.00		$	75.00		$	―	$	―
Collars:
Hedged volume (MBbls)		125			276			―			―			―		―
Average floor price ($/Bbl)	$	90.00		$	90.00		$	―		$	―		$	―	$	―
Average ceiling price ($/Bbl)	$	112.00		$	112.25		$	―		$	―		$	―	$	―
Total:
Hedged volume (MBbls)		2,325			5,431			5,582			5,566			―		―
Average price ($/Bbl)	$	99.68		$	83.46		$	89.51		$	89.51		$	―	$	―

Natural gas basis differential positions:
PEPL basis swaps: (1)
Hedged volume (MMMBtu)		21,583			35,541			34,066			31,700			―		―
Hedged differential ($/MMBtu)	$	(0.97	)	$	(0.96	)	$	(0.95	)	$	(1.01	)	$	―	$	―

(1)

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

(2)

As presented in the table above, the Company has outstanding fixed price oil swaps on 8,250 Bbls of daily production at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013. The Company has derivative contracts that extend these swaps at a price of $100.00 per Bbl for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other future years.

(3)

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

In March 2010, the Company entered into commodity derivative contracts, consisting of natural gas swaps and puts for 2012 through 2015, and paid premiums for put options of approximately $15.0 million. In addition, in April 2010, the Company entered into commodity derivative contracts, consisting of oil and natural gas swaps and puts for 2011 through 2015, and paid premiums for put options of approximately $76.0 million.

Settled derivatives on natural gas production for the three months and six months ended June 30, 2010, included volumes of 14,290 MMMBtu and 28,580 MMMBtu, respectively, at average contract prices of $8.66 per MMBtu. Settled derivatives on oil and NGL production for the three months and six months ended June 30, 2010, included volumes of 1,162 MBbls and 2,325 MBbls, respectively, at average contract prices of $99.68 per Bbl. The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or on the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month. The oil derivatives are settled based on the month’s average daily NYMEX price of light oil and settlement occurs on the final day of the production month.

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 counterparty the difference, and conversely, the counterparty is required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not designate the interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about interest rate swaps.

In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of 2020 Notes (see Note 6). The Company canceled (before the contract settlement date) all of its interest rate swap agreements for the remainder of 2010, resulting in a realized loss of approximately $35.6 million. In June 2010, the Company canceled (before the contract settlement date) certain interest rate swap agreements for 2011 through 2013, based on the balance outstanding under its Credit Facility, resulting in a realized loss of approximately $38.7 million.

The following presents the settlement terms of the Company’s interest rate swaps at June 30, 2010:

	2011			2012			2013 (1)
	(dollars in thousands)

Notional amount	$	600,000		$	600,000		$	600,000
Fixed rate		3.85	%		3.85	%		3.85	%

(1)

Actual settlement term is through January 6, 2014.

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Balance Sheet Presentation

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

	June 30, 2010		December 31, 2009
	(in thousands)
Assets:
Commodity derivatives	$	764,324	$	549,879
Interest rate swaps		―		2,603
	$	764,324	$	552,482
Liabilities:
Commodity derivatives	$	242,875	$	192,573
Interest rate swaps		38,088		69,644
	$	280,963	$	262,217

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current or former participants or affiliates of current or former participants in its Credit Facility (see Note 6), which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $764.3 million at June 30, 2010. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated.

Gains (Losses) on Derivatives

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	83,160		$	111,144		$	145,663		$	230,956
Interest rate swaps		―			(10,557	)		(8,021	)		(20,671	)
Canceled derivatives		(74,275	)		(60	)		(74,275	)		4,197
	$	8,885		$	100,527		$	63,367		$	214,482
Unrealized gains (losses):
Commodity derivatives	$	40,631		$	(343,919	)	$	74,131		$	(306,673	)
Interest rate swaps		41,030			22,535			25,889			21,078
	$	81,661		$	(321,384	)	$	100,020		$	(285,595	)
Total gains (losses):
Commodity derivatives	$	123,791		$	(232,775	)	$	219,794		$	(71,460	)
Interest rate swaps		(33,245	)		11,918			(56,407	)		347
	$	90,546		$	(220,857	)	$	163,387		$	(71,113	)

During the three months and six months ended June 30, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements for the remainder of 2010 and certain interest rate swap agreements for 2011 through 2013, resulting in realized losses of approximately $74.3 million. During the six months ended June 30, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future natural gas production resulting in realized gains of $4.3 million.

(8)	Fair Value Measurements on a Recurring Basis

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

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

	June 30, 2010
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	764,324	$	(237,780	)	$	526,544
Interest rate swaps	$	―	$	―		$	―

Liabilities:
Commodity derivatives	$	242,875	$	(237,780	)	$	5,095
Interest rate swaps	$	38,088	$	―		$	38,088

(1)

Represents counterparty netting under agreements governing such derivatives.

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(9)	Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the six months ended June 30, 2010); and (iv) a credit-adjusted risk-free interest rate (average of 9.0% for the six months ended June 30, 2010).

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

Asset retirement obligations at December 31, 2009	$	33,135
Liabilities added from acquisitions		4,810
Liabilities added from drilling		88
Current year accretion expense		1,290
Settlements		(126	)
Asset retirement obligations at June 30, 2010	$	39,197

(10)	Commitments and Contingencies

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

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Three months ended June 30, 2010:
Income from continuing operations:
Allocated to units	$	59,786
Allocated to unvested restricted units		(592	)
	$	59,194
Income per unit:
Basic income per unit					146,124	$	0.41
Dilutive effect of unit equivalents					338		(0.01	)
Diluted income per unit					146,462	$	0.40

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	)

Six months ended June 30, 2010:
Income from continuing operations:
Allocated to units	$	125,096
Allocated to unvested restricted units		(1,336	)
	$	123,760
Income per unit:
Basic income per unit					137,874	$	0.90
Dilutive effect of unit equivalents					360		—
Diluted income per unit					138,234	$	0.90

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	)

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 0.6 million unit options and warrants for the three months and six months ended June 30, 2010. Basic units

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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. All equivalent units were anti-dilutive for the three months and six months ended June 30, 2009, as the Company reported a loss from continuing operations.

(12)	Income Taxes

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

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

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

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

Accrued compensation	$	9,046	$	14,378
Accrued interest		42,803		18,332
Other		1,126		1,212
	$	52,975	$	33,922

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

	Six Months Ended June 30,
	2010			2009
	(in thousands)

Cash payments for interest, net of amounts capitalized	$	39,492		$	29,012
Cash payments for income taxes	$	1,681		$	853
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	792,242		$	—
Cash paid, net of cash acquired		(771,189	)		—
Receivable from seller		10,391			—
Liabilities assumed	$	31,444		$	—

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of $2.5 million and $2.1 million is included in “other noncurrent assets” on the condensed

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

consolidated balance sheets at June 30, 2010, and December 31, 2009, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

Table of Contents

Item 2.

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

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

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

Executive Overview

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

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

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

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

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

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

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

oil, natural gas and NGL sales of approximately $153.2 million, compared to $91.9 million for the second quarter of 2009;

average daily production of 256 MMcfe/d, compared to 219 MMcfe/d for the second quarter of 2009;

realized gains on commodity derivatives of approximately $83.2 million, compared to $111.1 million for the second quarter of 2009;

adjusted EBITDA of approximately $175.0 million, compared to $143.3 million for the second quarter of 2009;

adjusted net income of approximately $52.6 million, compared to $52.8 million for the second quarter of 2009;

capital expenditures, excluding acquisitions, of approximately $45.8 million, compared to $30.1 million for the second quarter of 2009; and

26 wells drilled (all successful), compared to 19 wells drilled (all successful) for the second quarter of 2009.

Results for the six months ended June 30, 2010, included the following:

oil, natural gas and NGL sales of approximately $302.6 million, compared to $171.8 million for the six months ended June 30, 2009;

Table of Contents

Item 2.

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

average daily production of 235 MMcfe/d, compared to 218 MMcfe/d for the six months ended June 30, 2009;

realized gains on commodity derivatives of approximately $145.7 million, compared to $235.2 million for the six months ended June 30, 2009;

adjusted EBITDA of approximately $326.5 million, compared to $281.4 million for the six months ended June 30, 2009;

adjusted net income of approximately $100.0 million, compared to $108.3 million for the six months ended June 30, 2009;

capital expenditures, excluding acquisitions, of approximately $72.9 million, compared to $103.5 million for the six months ended June 30, 2009; and

39 wells drilled (all successful), compared to 60 wells drilled (59 successful) for the six months ended June 30, 2009.

Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions. The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives, and depreciation, depletion and amortization. Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, impairment of goodwill and long-lived assets and (gains) losses on sale of assets, net. See “Non-GAAP Financial Measures” on page 37 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Acquisitions – Pending

Acquisitions - 2010

The following provides a summary of acquisitions completed by the Company during the six months ended June 30, 2010. See Note 2 for additional details.

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

Table of Contents

Item 2.

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

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

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

Financing and Liquidity

During 2010, the Company took steps to further strengthen its liquidity and extend its weighted average debt maturities. On April 6, 2010, the Company amended its Fourth Amended and Restated Credit Agreement (“Credit Facility”), which provided the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extended the maturity from August 2012 to April 2015. On June 2, 2010, the borrowing base under the Credit Facility was increased to $1.50 billion as a result of the increased value of the Company’s oil and natural gas reserves related to recent acquisitions (see Note 2). On April 6, 2010, the Company also issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (“2020 Notes”) and used the net proceeds of approximately $1.24 billion to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility. The remaining proceeds were used to fund or partially fund acquisitions and for general corporate purposes. In addition, on March 29, 2010, the Company completed a public offering of units for net proceeds of approximately $413.7 million, a portion of which the Company used to finance the HighMount acquisition. At July 15, 2010, the Company had approximately $895.0 million in available borrowing capacity under its Credit Facility.

Table of Contents

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

	Three Months Ended June 30,
	2010			2009			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	51,451		$	34,313		$	17,138
Oil sales		76,250			42,266			33,984
NGL sales		25,494			15,327			10,167
Total oil, natural gas and NGL sales		153,195			91,906			61,289
Gains (losses) on oil and natural gas derivatives		123,791			(232,775	)		356,566
Natural gas marketing revenues		1,223			1,183			40
Other revenues		195			641			(446	)
	$	278,404		$	(139,045	)	$	417,449
Expenses:
Lease operating expenses	$	38,367		$	33,137		$	5,230
Transportation expenses		5,256			2,516			2,740
Natural gas marketing expenses		772			880			(108	)
General and administrative expenses (1)		23,306			20,291			3,015
Exploration costs		155			2,199			(2,044	)
Bad debt expenses		(208	)		—			(208	)
Depreciation, depletion and amortization		57,941			50,390			7,551
Taxes, other than income taxes		10,391			7,882			2,509
Gains on sale of assets and other, net		(52	)		(5	)		(47	)
	$	135,928		$	117,290		$	18,638
Other income and (expenses)	$	(82,905	)	$	(12,181	)	$	(70,724	)
Income (loss) from continuing operations before income taxes	$	59,571		$	(268,516	)	$	328,087

Adjusted EBITDA (2)	$	174,973		$	143,251		$	31,722
Adjusted net income (2)	$	52,633		$	52,803		$	(170	)

(1)	General and administrative expenses for the three months ended June 30, 2010, and June 30, 2009, include approximately $3.2 million and $3.6 million, respectively, of noncash unit-based compensation expenses.

(2)	This is a non-GAAP measure used by management to analyze the Company’s performance. See “Non-GAAP Financial Measures” on page 37 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Table of Contents

Item 2.

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

	Three Months Ended June 30,
	2010		2009		Variance
Average daily production:
Natural gas (MMcf/d)		140		131		7	%
Oil (MBbls/d)		11.6		8.7		33	%
NGL (MBbls/d)		7.7		5.9		31	%
Total (MMcfe/d)		256		219		17	%

Weighted average prices (hedged): (1)
Natural gas (Mcf)	$	8.58	$	8.17		5	%
Oil (Bbl)	$	96.03	$	113.68		(16	)%
NGL (Bbl)	$	36.32	$	28.49		27	%

Weighted average prices (unhedged): (2)
Natural gas (Mcf)	$	4.04	$	2.88		40	%
Oil (Bbl)	$	72.21	$	53.10		36	%
NGL (Bbl)	$	36.32	$	28.49		27	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.09	$	3.51		17	%
Oil (Bbl)	$	78.03	$	59.62		31	%

Costs per Mcfe of production:
Lease operating expenses	$	1.65	$	1.67		(1	)%
Transportation expenses	$	0.23	$	0.13		77	%
General and administrative expenses (3)	$	1.00	$	1.02		(2	)%
Depreciation, depletion and amortization	$	2.49	$	2.53		(2	)%
Taxes, other than income taxes	$	0.45	$	0.40		13	%

(1)

Includes the effect of realized gains on derivatives of approximately $83.2 million and $111.1 million for the three months ended June 30, 2010, and June 30, 2009, 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, 2010, and June 30, 2009, include approximately $3.2 million and $3.6 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the three months ended June 30, 2010, and June 30, 2009, were $0.86 per Mcfe and $0.84 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company’s performance.

Table of Contents

Item 2.

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $61.3 million, or 67%, to approximately $153.2 million for the three months ended June 30, 2010, from $91.9 million for the three months June 30, 2009, due to higher commodity prices and higher production volumes. Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $20.2 million, $14.7 million and $5.5 million, respectively.

Average daily production volumes increased to 256 MMcfe/d during the three months ended June 30, 2010, from 219 MMcfe/d during the three months ended June 30, 2009. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $13.7 million, $2.5 million and $4.7 million, respectively.

	Three Months Ended June 30,
	2010		2009		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		135		137		(2	)	(1	)%
Mid-Continent Shallow		68		68		—		—
California		14		14		—		—
Permian Basin		19		—		19		—
Michigan		20		—		20		—
		256		219		37		17	%

The 1% decrease in average daily production volumes in the Mid-Continent Deep region primarily reflects natural declines, in addition to no capital development during the second half of 2009 due to low commodity prices, partially offset by the impact of the Company’s 2010 capital drilling program in the Granite Wash. Average daily production volumes in the Mid-Continent Shallow and California regions reflect the impact of drilling and optimization programs which offset the effects of natural declines. Average daily production volumes in the Permian Basin region reflect the Merit, Henry and Forest acquisitions in the first and second quarters of 2010 and the third quarter of 2009, respectively. Average daily production volumes in the Michigan region reflect the HighMount acquisition in the second quarter of 2010 (see Note 2).

Gains (Losses) on Oil and Natural Gas Derivatives

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for additional information about commodity derivatives. During the three months ended June 30, 2010, the Company had commodity derivative contracts for approximately 112% of its natural gas production and 66% of its oil and NGL production, which resulted in realized gains of approximately $83.2 million. During the three months ended June 30, 2009, the Company recorded realized gains of approximately $111.1 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 2010, expected future oil and natural gas prices decreased, which resulted in unrealized gains on derivatives of approximately $40.6 million for the three months ended June 30, 2010. During the second quarter of 2009, expected future oil and natural gas prices increased, which resulted in unrealized losses on derivatives of approximately $343.9 million for the three months ended June 30, 2009. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

Table of Contents

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 $5.3 million, or 16%, to $38.4 million for the three months ended June 30, 2010, from $33.1 million for the three months ended June 30, 2009. Lease operating expenses increased primarily due to costs associated with properties acquired in the Permian Basin and Michigan regions during the first and second quarters of 2010 and the third quarter of 2009 (see Note 2). Lease operating expenses per Mcfe decreased, to $1.65 per Mcfe for the three months ended June 30, 2010, from $1.67 per Mcfe for the three months ended June 30, 2009.

Transportation Expenses

Transportation expenses increased by approximately $2.8 million, or 112%, to $5.3 million for the three months ended June 30, 2010, from $2.5 million for the three months ended June 30, 2009, primarily due to increased expenses on nonoperated properties and increased production volumes from the 2009 and 2010 acquisitions in the Permian Basin and Michigan regions. Transportation expenses included an adjustment to transportation rates associated with owned facilities.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees and executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $3.0 million, or 15%, to $23.3 million for the three months ended June 30, 2010, from $20.3 million for the three months ended June 30, 2009. The increase was primarily due to an increase in salaries and benefits expense of approximately $1.9 million, driven primarily by increased employee headcount, and acquisition integration expenses of approximately $1.3 million. General and administrative expenses per Mcfe decreased, to $1.00 per Mcfe for the three months ended June 30, 2010, from $1.02 per Mcfe for the three months ended June 30, 2009.

Exploration Costs

Exploration costs decreased by approximately $2.0 million, or 91%, to $0.2 million for the three months ended June 30, 2010, from $2.2 million for the three months ended June 30, 2009. The decrease was primarily due to a decrease in unproved leasehold costs of approximately $1.7 million.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $7.5 million, or 15%, to $57.9 million for the three months ended June 30, 2010, from $50.4 million for the three months ended June 30, 2009. Higher total production volume levels, primarily due to the Company’s acquisitions in the Permian Basin and Michigan regions in the first and second quarters of 2010 and the third quarter of 2009, were the main reason for the increase. Depreciation, depletion and amortization per Mcfe decreased to $2.49 per Mcfe for the three months ended June 30, 2010, from $2.53 per Mcfe for the three months ended June 30, 2009.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $2.5 million, or 32%, to $10.4 million for the three months ended June 30, 2010, from $7.9 million for the three months ended June 30, 2009. Severance taxes, which are a function of revenues generated from production, increased by approximately $2.5 million compared to the three months ended June 30, 2009, primarily due to higher commodity prices and higher total production volume levels. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, were essentially unchanged compared to the three months ended June 30, 2009.

Table of Contents

Item 2.

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

Other Income and (Expenses)

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

Interest expense, net of amounts capitalized	$	(45,969	)	$	(23,262	)	$	(22,707	)
Realized losses on interest rate swaps		—			(10,557	)		10,557
Realized losses on canceled interest rate swaps		(74,275	)		(60	)		(74,215	)
Unrealized gains on interest rate swaps		41,030			22,535			18,495
Other, net		(3,691	)		(837	)		(2,854	)
	$	(82,905	)	$	(12,181	)	$	(70,724	)

Other income and (expenses) increased by approximately $70.7 million during the three months ended June 30, 2010, compared to the three months ended June 30, 2009, primarily due to increased realized losses on interest rate swaps. During the three months ended June 30, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements for the remainder of 2010 and certain interest rate swap agreements for 2011 through 2013, resulting in realized losses of approximately $74.3 million. These losses were partially offset by an increase in unrealized gains on interest rate swaps during the three months ended June 30, 2010, compared to the three months ended June 30, 2009. Additionally, in the second quarter of 2010, the Company entered into an amendment to its Credit Facility and issued 2020 Notes, which resulted in increased interest expense due to higher interest rates and higher amortization of financing fees. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Benefit (Expense)

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized an income tax benefit of approximately $0.2 million for the three months ended June 30, 2010, compared to an income tax expense of approximately $0.2 million for the same period in 2009.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $31.7 million, or 22%, to $175.0 million for the three months ended June 30, 2010, from $143.3 million for the three months ended June 30, 2009, primarily due to higher production revenues resulting from higher commodity prices and higher total production volume levels, partially offset by lower realized gains on commodity derivatives. See “Non-GAAP Financial Measures” on page 37 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Table of Contents

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, 2010, Compared to Six Months Ended June 30, 2009

	Six Months Ended June 30,
	2010			2009			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	104,313		$	76,541		$	27,772
Oil sales		142,190			69,036			73,154
NGL sales		56,078			26,193			29,885
Total oil, natural gas and NGL sales		302,581			171,770			130,811
Gains (losses) on oil and natural gas derivatives		219,794			(71,460	)		291,254
Natural gas marketing revenues		2,617			1,699			918
Other revenues		448			1,607			(1,159	)
	$	525,440		$	103,616		$	421,824
Expenses:
Lease operating expenses	$	69,589		$	66,869		$	2,720
Transportation expenses		9,876			5,483			4,393
Natural gas marketing expenses		1,741			1,220			521
General and administrative expenses (1)		47,794			43,592			4,202
Exploration costs		4,016			3,764			252
Bad debt expenses		(19	)		—			(19	)
Depreciation, depletion and amortization		107,132			102,494			4,638
Taxes, other than income taxes		20,591			15,449			5,142
Gains on sale of assets and other, net		(374	)		(26,716	)		26,342
	$	260,346		$	212,155		$	48,191
Other income and (expenses)	$	(134,321	)	$	(38,554	)	$	(95,767	)
Income (loss) from continuing operations before income taxes	$	130,773		$	(147,093	)	$	277,866

Adjusted EBITDA (2)	$	326,482		$	281,412		$	45,070
Adjusted net income (2)	$	99,998		$	108,333		$	(8,335	)

(1)	General and administrative expenses for the six months ended June 30, 2010, and June 30, 2009, include approximately $7.2 million and $7.8 million, respectively, of noncash unit-based compensation expenses.

(2)	This is a non-GAAP measure used by management to analyze the Company’s performance. See “Non-GAAP Financial Measures” on page 37 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Table of Contents

Item 2.

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

	Six Months Ended June 30,
	2010		2009		Variance
Average daily production:
Natural gas (MMcf/d)		125		132		(5	)%
Oil (MBbls/d)		10.7		8.8		22	%
NGL (MBbls/d)		7.6		5.5		38	%
Total (MMcfe/d)		235		218		8	%

Weighted average prices (hedged): (1)
Natural gas (Mcf)	$	8.86	$	8.06		10	%
Oil (Bbl)	$	98.93	$	115.93		(15	)%
NGL (Bbl)	$	40.81	$	26.09		56	%

Weighted average prices (unhedged): (2)
Natural gas (Mcf)	$	4.61	$	3.21		44	%
Oil (Bbl)	$	73.37	$	43.45		69	%
NGL (Bbl)	$	40.81	$	26.09		56	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.70	$	4.21		12	%
Oil (Bbl)	$	78.37	$	51.35		53	%

Costs per Mcfe of production:
Lease operating expenses	$	1.64	$	1.70		(4	)%
Transportation expenses	$	0.23	$	0.14		64	%
General and administrative expenses (3)	$	1.12	$	1.11		1	%
Depreciation, depletion and amortization	$	2.52	$	2.60		(3	)%
Taxes, other than income taxes	$	0.48	$	0.39		23	%

(1)

Includes the effect of realized gains on derivatives of approximately $145.7 million and $231.0 million (excluding $4.3 million in realized gains on canceled contracts) for the six months ended June 30, 2010, and June 30, 2009, 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, 2010, and June 30, 2009, include approximately $7.2 million and $7.8 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the six months ended June 30, 2010, and June 30, 2009, were $0.95 per Mcfe and $0.91 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company’s performance.

Table of Contents

Item 2.

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $130.8 million, or 76%, to approximately $302.6 million for the six months ended June 30, 2010, from $171.8 million for the six months June 30, 2009, due to higher commodity prices and higher oil and NGL production volumes, partially offset by lower natural gas production volumes. Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $58.0 million, $31.8 million and $20.2 million, respectively.

Average daily production volumes increased to 235 MMcfe/d during the six months ended June 30, 2010, from 218 MMcfe/d during the six months ended June 30, 2009. Higher oil and NGL production volumes resulted in an increase in revenues of approximately $15.1 million and $9.7 million, respectively. Lower natural gas production volumes resulted in a decrease in natural gas revenues of approximately $4.0 million.

	Six Months Ended June 30,
	2010		2009		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		129		140		(11	)	(8	)%
Mid-Continent Shallow		66		64		2		3	%
California		14		14		—		—
Permian Basin		16		—		16		—
Michigan		10		—		10		—
		235		218		17		8	%

The 8% decrease in average daily production volumes in the Mid-Continent Deep region primarily reflects natural declines, in addition to no capital development during the second half of 2009 due to low commodity prices, partially offset by the Company’s 2010 capital drilling program in the Granite Wash. The 3% increase in average daily production volumes in the Mid-Continent Shallow region reflects improvements in processing agreement terms partially offset by natural declines. Average daily production volumes in the California region reflect the impact of optimization projects which offset the effect of natural declines. Average daily production volumes in the Permian Basin region reflect the Merit, Henry and Forest acquisitions in the first and second quarters of 2010 and the third quarter of 2009, respectively. Average daily production volumes in the Michigan region reflect the HighMount acquisition in the second quarter of 2010 (see Note 2).

Gains (Losses) on Oil and Natural Gas Derivatives

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for additional information about commodity derivatives. During the six months ended June 30, 2010, the Company had commodity derivative contracts for approximately 126% of its natural gas production and 70% of its oil and NGL production, which resulted in realized gains of approximately $145.7 million. During the six months ended June 30, 2009, the Company recorded realized gains of approximately $235.2 million (including realized gains on canceled contracts of approximately $4.3 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 2010, expected future oil and natural gas prices decreased, which resulted in unrealized gains on derivatives of approximately $74.1 million for the six months ended June 30, 2010. During the first two quarters of 2009, expected future oil and natural gas prices increased, which resulted in unrealized losses on derivatives of approximately $306.7 million for the six months ended June 30, 2009. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

Table of Contents

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 $2.7 million, or 4%, to $69.6 million for the six months ended June 30, 2010, from $66.9 million for the six months ended June 30, 2009. Lease operating expenses increased primarily due to costs associated with properties acquired in the first and second quarters of 2010 and the third quarter of 2009 in the Permian Basin and Michigan regions (see Note 2). This increase was partially offset by the receipt of insurance proceeds during the six months ended June 30, 2010, as reimbursement for costs incurred related to a California wildfire in 2008. Lease operating expenses per Mcfe decreased, to $1.64 per Mcfe for the six months ended June 30, 2010, from $1.70 per Mcfe for the six months ended June 30, 2009.

Transportation Expenses

Transportation expenses increased by approximately $4.4 million, or 80%, to $9.9 million for the six months ended June 30, 2010, from $5.5 million for the six months ended June 30, 2009, primarily due to increased expenses on nonoperated properties and increased production volumes from the 2009 and 2010 acquisitions in the Permian Basin and Michigan regions. Transportation expenses included an adjustment to transportation rates associated with owned facilities.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees and executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $4.2 million, or 10%, to $47.8 million for the six months ended June 30, 2010, from $43.6 million for the six months ended June 30, 2009. General and administrative expenses per Mcfe also increased, to $1.12 per Mcfe for the six months ended June 30, 2010, from $1.11 per Mcfe for the six months ended June 30, 2009. The increase was primarily due to an increase in salaries and benefits expense of approximately $4.1 million, driven primarily by increased employee headcount, and acquisition integration expenses of approximately $2.0 million. These increases were partially offset by a decrease in professional fees.

Exploration Costs

Exploration costs increased by approximately $0.2 million, or 5%, to $4.0 million for the six months ended June 30, 2010, from $3.8 million for the six months ended June 30, 2009. The increase was primarily due to an increase in unproved leasehold costs.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $4.6 million, or 4%, to $107.1 million for the six months ended June 30, 2010, from $102.5 million for the six months ended June 30, 2009. Higher total production volume levels, primarily due to the Company’s acquisitions in the Permian Basin and Michigan regions in the first and second quarters of 2010 and the third quarter of 2009, were the main reason for the increase. Depreciation, depletion and amortization per Mcfe decreased to $2.52 per Mcfe for the six months ended June 30, 2010, from $2.60 per Mcfe for the six months ended June 30, 2009.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $5.2 million, or 34%, to $20.6 million for the six months ended June 30, 2010, from $15.4 million for the six months ended June 30, 2009. Severance taxes, which are a function of revenues generated from production, increased by approximately $5.2 million compared to the six months ended June 30, 2009, primarily due to higher commodity prices and higher total production volume levels. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, were essentially unchanged compared to the six months ended June 30, 2009.

Table of Contents

Item 2.

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

Gains on Sale of Assets and Other, Net

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

Other Income and (Expenses)

	Six Months Ended June 30,
	2010			2009			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(73,622	)	$	(37,671	)	$	(35,951	)
Realized losses on interest rate swaps		(8,021	)		(20,671	)		12,650
Realized losses on canceled interest rate swaps		(74,275	)		(60	)		(74,215	)
Unrealized gains on interest rate swaps		25,889			21,078			4,811
Other, net		(4,292	)		(1,230	)		(3,062	)
	$	(134,321	)	$	(38,554	)	$	(95,767	)

Other income and (expenses) increased by approximately $95.8 million during the six months ended June 30, 2010, compared to the six months ended June 30, 2009, primarily due to increased realized losses on interest rate swaps. During the six months ended June 30, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements for the remainder of 2010 and certain interest rate swap agreements for 2011 through 2013, resulting in realized losses of approximately $74.3 million. This was partially offset by an increase in unrealized gains on interest rate swaps during the six months ended June 30, 2010, compared to the six months ended June 30, 2009. Additionally, in the second quarter of 2010, the Company entered into an amendment to its Credit Facility and issued 2020 Notes, which resulted in increased interest expense due to higher interest rates and higher amortization of financing fees. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Benefit (Expense)

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $5.7 million and $0.3 million for the six months ended June 30, 2010, and June 30, 2009, respectively. Income tax expense increased during the six months ended June 30, 2010, primarily due to an increase in taxable income at Linn Operating, Inc., the Company’s service subsidiary.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $45.1 million, or 16%, to $326.5 million for the six months ended June 30, 2010, from $281.4 million for the six months ended June 30, 2009, primarily due to higher production revenues resulting from higher commodity prices and higher oil and NGL production volumes, partially offset by lower realized gains on commodity derivatives. See “Non-GAAP Financial Measures” on page 37 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Table of Contents

Item 2.

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

Liquidity and Capital Resources

The Company utilizes funds from equity and debt offerings, bank borrowings and cash generated from operations for capital resources and liquidity. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties. For the six months ended June 30, 2010, the Company’s capital expenditures, excluding acquisitions, were approximately $72.9 million. For 2010, the Company estimates its capital expenditures, excluding acquisitions, will be approximately $230.0 million. This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustment. The Company expects to fund these capital expenditures primarily with cash flow from operations.

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

Statements of Cash Flows

The following is a comparative cash flow summary:

	Six Months Ended June 30,
	2010			2009			Variance
	(in thousands)
Net cash:
Provided by operating activities (1)	$	75,183		$	258,274		$	(183,091	)
Used in investing activities		(841,085	)		(103,410	)		(737,675	)
Provided by (used in) financing activities		953,412			(156,432	)		1,109,844
Net increase (decrease) in cash and cash equivalents	$	187,510		$	(1,568	)	$	189,078

(1)	The six months ended June 30, 2010, includes premiums paid for commodity derivatives of approximately $91.0 million.

Operating Activities

Cash provided by operating activities for the six months ended June 30, 2010, was approximately $75.2 million, compared to $258.3 million for the six months ended June 30, 2009. The decrease was primarily due to approximately $91.0 million in premiums paid for commodity derivative contracts and approximately $74.3 million in realized losses on canceled interest rate derivatives during the six months ended June 30, 2010.

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

Table of Contents

Item 2.

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

Investing Activities

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

	Six Months Ended June 30,
	2010			2009
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties, net of cash acquired	$	(771,189	)	$	—
Capital expenditures		(70,482	)		(130,059	)
Proceeds from sale of properties and equipment		586			26,649
	$	(841,085	)	$	(103,410	)

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

Capital expenditures were lower for the six months ended June 30, 2010, compared to the same period in 2009, primarily due to the timing of drilling activities. The Company’s drilling program was accelerated in the first half of 2009 but was curtailed due to low commodity prices during the second half of the year. It is anticipated that the drilling program will be accelerated during the second half of 2010 and capital expenditures for full year 2010 are expected to be approximately $230.0 million.

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

Financing Activities

Cash provided by financing activities was approximately $953.4 million for the six months ended June 30, 2010, compared to cash used in financing activities of $156.4 million for the six months ended June 30, 2009. The increase in financing cash flow was primarily attributable to proceeds from the Company’s March 2010 offering of units (see below) and increased borrowings to fund acquisitions, partially offset by repayments of debt. The following provides a comparative summary of proceeds from borrowings and repayments of debt:

	Six Months Ended June 30,
	2010			2009
	(in thousands)
Proceeds from borrowings:
Credit facility	$	920,000		$	169,000
Senior notes		1,268,176			237,703
	$	2,188,176		$	406,703
Repayments of debt:
Credit facility	$	(1,420,000	)	$	(454,393	)

Debt

On April 6, 2010, the Company entered into an amendment to its Credit Facility, which provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015. On June 2, 2010, the borrowing base under the Credit Facility was increased to $1.50 billion as a result of the increased value of the Company’s oil and natural gas reserves related to recent acquisitions (see Note 2). In addition, on April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes

Table of Contents

Item 2.

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

due 2020 and received net proceeds of approximately $1.24 billion. The Company used the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility. The remaining proceeds were used to fund or partially fund acquisitions and for general corporate purposes. At July 15, 2010, the Company had approximately $895.0 million in available borrowing capacity under its Credit Facility. The Company also has outstanding $250.0 million in aggregate principal amount of 11.75% senior notes due 2017, $255.9 million in aggregate principal amount of 9.875% senior notes due 2018 and $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020. For additional information about the Company’s debt instruments, such as interest rates and covenants, see Note 6. The Company is in compliance with all financial and other covenants of the Credit Facility and senior notes.

The Company depends on its Credit Facility for future capital needs. In addition, the Company has drawn on the Credit Facility to fund or partially fund quarterly cash distribution payments, since it uses operating cash flow for investing activities and borrows as cash is needed. Absent such borrowings, the Company would have at times experienced a shortfall in cash available to pay the declared quarterly cash distribution amount. If an event of default occurs and is continuing under the Credit Facility, the Company would be unable to make borrowings to fund distributions. For additional information about this matter and other risk factors that could affect the Company, see Item 1A. “Risk Factors.”

Counterparty Credit Risk

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

Public Offering of Units

Distributions

Under the Company’s limited liability company agreement, unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. The following provides a summary of distributions paid by the Company during the six months ended June 30, 2010:

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

February 2010	October 1 – December 31, 2009	$	0.63	$	82.3
May 2010	January 1 – March 31, 2010	$	0.63	$	93.1

Table of Contents

Item 2.

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

On July 27, 2010, the Company’s Board of Directors declared a cash distribution of $0.63 per unit, or $2.52 per unit on an annualized basis, with respect to the second quarter of 2010. This distribution, totaling approximately $92.9 million, will be paid on August 13, 2010, to unitholders of record as of the close of business on August 6, 2010.

Off-Balance Sheet Arrangements

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

Contingencies

During the six months ended June 30, 2010, and June 30, 2009, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2009 Annual Report on Form 10-K. With the exception of: (i) an amendment to the Company’s Credit Facility that provides a $1.50 billion facility and extends the maturity from August 2012 to April 2015; and (ii) the issuance of $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020, there have been no significant changes to the Company’s contractual obligations from December 31, 2009. See Note 6 for additional information about the Company’s debt instruments. On April 6, 2010, the Company entered into an amendment to its Fourth Amended and Restated Credit Agreement (“Credit Facility”) that provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015. On June 2, 2010, at the Company’s request and upon approval of all the lenders, the borrowing base under the Credit Facility was increased to $1.50 billion as a result of the increased value of the Company’s oil and natural gas reserves related to recent acquisitions (see Note 2).

Non-GAAP Financial Measures

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

Adjusted EBITDA (Non-GAAP Measure)

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

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

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

Interest expense;

Depreciation, depletion and amortization;

Impairment of goodwill and long-lived assets;

Write-off of deferred financing fees and other;

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

Table of Contents

Item 2.

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

Unrealized (gains) losses on commodity derivatives;

Unrealized (gains) losses on interest rate derivatives;

Realized (gains) losses on interest rate derivatives;

Realized (gains) losses on canceled derivatives;

Unit-based compensation expenses;

Exploration costs; and

Income tax (benefit) expense.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)

Income (loss) from continuing operations	$	59,786		$	(268,701	)	$	125,096		$	(147,414	)
Plus:
Net operating cash flow from acquisitions and divestitures, effective date through closing date		13,126			—			18,517			—
Interest expense, cash		17,941			8,402			39,693			29,012
Interest expense, noncash		28,028			14,860			33,929			8,659
Depreciation, depletion and amortization		57,941			50,390			107,132			102,494
Write-off of deferred financing fees and other		2,076			204			2,076			204
(Gains) losses on sale of assets and other, net		256			60			670			(25,651	)
Unrealized (gains) losses on commodity derivatives		(40,631	)		343,919			(74,131	)		306,673
Unrealized gains on interest rate derivatives		(41,030	)		(22,535	)		(25,889	)		(21,078	)
Realized losses on interest rate derivatives		—			10,557			8,021			20,671
Realized (gains) losses on canceled derivatives		74,275			60			74,275			(4,197	)
Unit-based compensation expenses		3,265			3,651			7,400			7,954
Exploration costs		155			2,199			4,016			3,764
Income tax (benefit) expense		(215	)		185			5,677			321
Adjusted EBITDA from continuing operations	$	174,973		$	143,251		$	326,482		$	281,412

Net cash used in operating activities for the three months ended June 30, 2010, was approximately $(4.5) million and includes cash interest payments of approximately $17.8 million, premiums paid for commodity derivatives of approximately $76.0 million, realized losses on canceled derivatives of approximately $74.3 million and other items totaling approximately $11.4 million that are not included in adjusted EBITDA. Net cash provided by operating activities for the three months ended June 30, 2009, was approximately $163.3 million and includes cash interest payments of approximately $8.4 million, cash settlements on interest rate derivatives of approximately $10.7 million, cash received to settle certain post-closing matters related to the Woodford Shale sale of approximately $(13.9) million and other items totaling approximately $(25.2) million that are not included in adjusted EBITDA. Net cash provided by operating activities for the six months ended June 30, 2010, was approximately $75.2 million and includes cash interest payments of approximately $39.5 million, cash settlements on interest rate derivatives of approximately $11.1 million, premiums paid for commodity derivatives of approximately $91.0 million, realized losses on canceled derivatives of approximately $74.3 million and other items totaling approximately $35.4 million that are not included in adjusted EBITDA. Net cash provided by operating activities for the six months ended June 30, 2009, was approximately $258.3 million and includes cash interest payments of approximately $29.0 million, cash settlements on interest rate derivatives of approximately $19.8 million, realized gains on canceled derivatives of approximately $(4.2) million and other items totaling approximately $(21.5) million that are not included in adjusted EBITDA.

Table of Contents

Item 2.

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

Adjusted Net Income (Non-GAAP Measure)

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands, except per unit amounts)

Income (loss) from continuing operations	$	59,786		$	(268,701	)	$	125,096		$	(147,414	)
Plus:
Unrealized (gains) losses on commodity derivatives		(40,631	)		343,919			(74,131	)		306,673
Unrealized gains on interest rate derivatives		(41,030	)		(22,535	)		(25,889	)		(21,078	)
Realized (gains) losses on canceled derivatives		74,275			60			74,275			(4,197	)
(Gains) losses on sale of assets, net		233			60			647			(25,651	)
Adjusted net income from continuing operations	$	52,633		$	52,803		$	99,998		$	108,333

Income (loss) from continuing operations per unit – basic	$	0.41		$	(2.31	)	$	0.90		$	(1.28	)
Plus, per unit:
Unrealized (gains) losses on commodity derivatives		(0.27	)		2.95			(0.52	)		2.66
Unrealized gains on interest rate derivatives		(0.28	)		(0.19	)		(0.19	)		(0.18	)
Realized (gains) losses on canceled derivatives		0.50			—			0.53			(0.04	)
(Gains) losses on sale of assets, net		—			—			—			(0.22	)
Adjusted net income from continuing operations per unit – basic	$	0.36		$	0.45		$	0.72		$	0.94

Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards Not Yet Adopted

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

Table of Contents

Item 2.

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

Cautionary Statement

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

business strategy;

acquisition strategy;

financial strategy;

drilling locations;

oil, natural gas and NGL reserves;

realized oil, natural gas and NGL prices;

production volumes;

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

future operating results; and

plans, objectives, expectations and intentions.

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

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2009, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K. A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”

Commodity Price Risk

The Company enters into derivative contracts with respect to a portion of its projected production through various transactions that provide an economic hedge of the risk related to the future prices received. The Company does not enter into derivative contracts for trading purposes (see Note 7). At June 30, 2010, the fair value of contracts that settle during the next 12 months was an asset of approximately $277.1 million and a liability of $2.4 million for a net asset of approximately $274.7 million. A 10% increase in the index oil and natural gas prices above the June 30, 2010, prices for the next 12 months would result in a net asset of approximately $198.5 million which represents a decrease in the fair value of approximately $76.2 million; conversely, a 10% decrease in the index oil and natural gas prices would result in a net asset of approximately $350.3 million which represents an increase in the fair value of approximately $75.6 million.

Interest Rate Risk

At June 30, 2010, the Company had long-term debt outstanding under its Credit Facility of approximately $600.0 million, which incurred interest at floating rates (see Note 6). A 1% increase in LIBOR would result in an estimated $6.0 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 commodity and interest rate derivatives at fair value on a recurring basis (see Note 8). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.

At June 30, 2010, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 4.38%. A 1% increase in the average public bond yield spread would result in an estimated $0.7 million increase in net income for the six months ended June 30, 2010. At June 30, 2010, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.21%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $4.1 million decrease in net income for the six months ended June 30, 2010.

Table of Contents

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2010.

Changes in the Company’s Internal Control Over Financial Reporting

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

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

There were no changes in the Company’s internal controls over financial reporting during the second quarter of 2010 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

General

The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. The Company does not expect these matters to have a material adverse impact on its financial condition or results of operations.

Environmental

In May 2010, the Company entered into a settlement agreement with the South Coast Air Quality Management District under which the Company agreed to pay penalties and fees for improper natural gas flaring under its current permit. The Company has not been cited for violation of emission standards associated with this activity and it is taking appropriate steps to remedy the situation. The Company estimates that total penalties associated with this matter will be approximately $100,000 and has paid approximately $69,000 as of June 30, 2010. The Company does not expect this matter to have a material adverse impact on its financial condition or results of operations.

Item 1A. Risk Factors

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

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

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

The recently enacted Health Care and Education Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects certain individuals, estates and trusts to an Unearned Income Medicare Contribution tax of 3.8% on certain income. In the case of an individual having a modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns), the provision imposes a tax equal to 3.8% of the lesser of such excess and the individual’s “net investment income,” which will include net income and gains from the ownership or disposition of our units.

Table of Contents

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’s repurchases of its units during the second quarter of 2010:

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 (1)
							(in millions)

May 1 – 31		486,700	$	23.79		486,700	$	73.8

(1)

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.

Item 4. Reserved

Item 5. Other Information

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

Table of Contents

Item 6. Exhibits

Exhibit Number			Description
2	.1*†	—	Purchase and Sale Agreement, dated June 30, 2010, between Linn Energy Holdings, LLC, as purchaser and Element Petroleum, LP and CrownRock, LP, as sellers
2	.2*†	—	Purchase and Sale Agreement, dated July 16, 2010, between Linn Energy Holdings, LLC, as purchaser and SND Operating, LLC, SND Energy Company, Inc. and Topcat Energy, LLC, as sellers
4	.1*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of June 27, 2008 between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee
4	.2*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of May 18, 2009 between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee
4	.3*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of April 6, 2010 between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee
10	.1*	—	Third Amendment, dated June 2, 2010, to Fourth Amended and Restated Credit Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto
10	.2*	—	First Amendment, dated April 6, 2010, to Fourth Amended and Restated Guaranty and Pledge Agreement made by Linn Energy, LLC and each of the other Obligors in favor of BNP Paribas, as Administrative Agent
10	.3* **	—	Amendment No. 2 to Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, dated July 19, 2010
31	.1*	—	Section 302 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
31	.2*	—	Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32	.1*	—	Section 906 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
32	.2*	—	Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
101	.INS***	—	XBRL Instance Document
101	.SCH***	—	XBRL Taxonomy Extension Schema Document
101	.CAL***	—	XBRL Taxonomy Extension Calculation Linkbase Document
101	.DEF***	—	XBRL Taxonomy Extension Definition Linkbase Document
101	.LAB***	—	XBRL Taxonomy Extension Label Linkbase Document
101	.PRE***	—	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.

**	Management Contract of Compensatory Plan or Arrangement required to be filed as an exhibit hereto pursuant to Item 601 of Regulation S-K.

***	Furnished herewith.

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

Table of Contents

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: July 29, 2010	/s/ David B. Rottino
	David B. Rottino
	Senior Vice President of Finance, Business Development and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)