Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders

Linn Energy, LLC:

We have audited the accompanying consolidated balance sheets of Linn Energy, LLC and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, unitholders’ capital, and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Linn Energy, LLC and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Linn Energy, LLC’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2012, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP            

Houston, Texas

February 23, 2012, except for Note 16, as to which the date is May 8, 2012

LINN ENERGY, LLC

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,114		$	236,001
Accounts receivable – trade, net		284,565			184,624
Derivative instruments		255,063			234,675
Other current assets		80,734			55,609
Total current assets		621,476			710,909
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		7,835,650			5,664,503
Less accumulated depletion and amortization		(1,033,617	)		(719,035	)
		6,802,033			4,945,468
Other property and equipment		197,235			139,903
Less accumulated depreciation		(48,024	)		(35,151	)
		149,211			104,752
Derivative instruments		321,840			56,895
Other noncurrent assets		105,577			115,124
		427,417			172,019
Total noncurrent assets		7,378,661			5,222,239
Total assets	$	8,000,137		$	5,933,148
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	403,450		$	219,830
Derivative instruments		14,060			12,839
Other accrued liabilities		75,898			82,439
Total current liabilities		493,408			315,108
Noncurrent liabilities:
Credit facility		940,000			—
Senior notes, net		3,053,657			2,742,902
Derivative instruments		3,503			39,797
Other noncurrent liabilities		80,659			47,125
Total noncurrent liabilities		4,077,819			2,829,824
Commitments and contingencies (Note 11)
Unitholders’ capital:
177,364,558 units and 159,009,795 units issued and outstanding at December 31, 2011, and December 31, 2010, respectively		2,751,354			2,549,099
Accumulated income		677,556			239,117
		3,428,910			2,788,216
Total liabilities and unitholders’ capital	$	8,000,137		$	5,933,148

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

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LINN ENERGY, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2011			2010			2009
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	1,162,037		$	690,054		$	408,219
Gains (losses) on oil and natural gas derivatives		449,940			75,211			(141,374	)
Marketing revenues		5,868			3,966			4,380
Other revenues		4,609			3,049			1,924
		1,622,454			772,280			273,149
Expenses:
Lease operating expenses		232,619			158,382			132,647
Transportation expenses		28,358			19,594			18,202
Marketing expenses		3,681			2,716			2,154
General and administrative expenses		133,272			99,078			86,134
Exploration costs		2,390			5,168			7,169
Bad debt expenses		(22	)		(46	)		401
Depreciation, depletion and amortization		334,084			238,532			201,782
Impairment of long-lived assets		—			38,600			—
Taxes, other than income taxes		78,522			45,182			27,605
(Gains) losses on sale of assets and other, net		3,516			6,536			(24,598	)
		816,420			613,742			451,496
Other income and (expenses):
Loss on extinguishment of debt		(94,612	)		—			—
Interest expense, net of amounts capitalized		(259,725	)		(193,510	)		(92,701	)
Losses on interest rate swaps		—			(67,908	)		(26,353	)
Other, net		(7,792	)		(7,167	)		(2,661	)
		(362,129	)		(268,585	)		(121,715	)
Income (loss) from continuing operations before income taxes		443,905			(110,047	)		(300,062	)
Income tax benefit (expense)		(5,466	)		(4,241	)		4,221
Income (loss) from continuing operations		438,439			(114,288	)		(295,841	)
Discontinued operations:
Losses on sale of assets, net of taxes		—			—			(158	)
Loss from discontinued operations, net of taxes		—			—			(2,193	)
		—			—			(2,351	)
Net income (loss)	$	438,439		$	(114,288	)	$	(298,192	)
Income (loss) per unit – continuing operations:
Basic	$	2.52		$	(0.80	)	$	(2.48	)
Diluted	$	2.51		$	(0.80	)	$	(2.48	)
Loss per unit – discontinued operations:
Basic	$	—		$	—		$	(0.02	)
Diluted	$	—		$	—		$	(0.02	)
Net income (loss) per unit:
Basic	$	2.52		$	(0.80	)	$	(2.50	)
Diluted	$	2.51		$	(0.80	)	$	(2.50	)
Weighted average units outstanding:
Basic		172,004			142,535			119,307
Diluted		172,729			142,535			119,307
Distributions declared per unit	$	2.70		$	2.55		$	2.52

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

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LINN ENERGY, LLC

CONSOLIDATED STATEMENTS OF UNITHOLDERS’ CAPITAL

	Units			Unitholders’ Capital			Accumulated Income (Deficit)			Treasury Units (at Cost)			Total Unitholders’ Capital
	(in thousands)
December 31, 2008		114,080		$	2,109,089		$	651,597		$	—		$	2,760,686
Sale of units, net of underwriting discounts and expenses of $12,369		14,950			279,299			—			—			279,299
Issuance of units		1,098			494			—			—			494
Cancellation of units		(187	)		(2,696	)		—			2,696			—
Purchase of units					—			—			(2,696	)		(2,696	)
Distributions to unitholders					(303,316	)		—			—			(303,316	)
Unit-based compensation expenses					15,089			—			—			15,089
Reclassification of distributions paid on forfeited restricted units					63			—			—			63
Excess tax benefit from unit-based compensation					577			—			—			577
Net loss					—			(298,192	)		—			(298,192	)
December 31, 2009		129,941			2,098,599			353,405			—			2,452,004
Sale of units, net of underwriting discounts and expenses of $34,556		28,750			809,774			—			—			809,774
Issuance of units		815			4,418			—			—			4,418
Cancellation of units		(496	)		(11,832	)		—			11,832			—
Purchase of units					—			—			(11,832	)		(11,832	)
Distributions to unitholders					(365,711	)		—			—			(365,711	)
Unit-based compensation expenses					13,792			—			—			13,792
Reclassification of distributions paid on forfeited restricted units					59			—			—			59
Net loss					—			(114,288	)		—			(114,288	)
December 31, 2010		159,010			2,549,099			239,117			—			2,788,216
Sale of units, net of underwriting discounts and expenses of $27,427		17,514			651,522			—			—			651,522
Issuance of units		1,371			7,446			—			—			7,446
Cancellation of units		(530	)		(17,352	)		—			17,352			—
Purchase of units					—			—			(17,352	)		(17,352	)
Distributions to unitholders					(466,488	)		—			—			(466,488	)
Unit-based compensation expenses					22,243			—			—			22,243
Reclassification of distributions paid on forfeited restricted units					79			—			—			79
Excess tax benefit from unit-based compensation					4,805			—			—			4,805
Net income					—			438,439			—			438,439
December 31, 2011		177,365		$	2,751,354		$	677,556		$	—		$	3,428,910

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

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LINN ENERGY, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	438,439		$	(114,288	)	$	(298,192	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		334,084			238,532			201,782
Impairment of long-lived assets		—			38,600			—
Unit-based compensation expenses		22,243			13,792			15,089
Loss on extinguishment of debt		94,612			—			—
Amortization and write-off of deferred financing fees and other		23,828			27,014			21,824
(Gains) losses on sale of assets and other, net		(281	)		1,718			(22,842	)
Deferred income tax		310			3,088			(6,436	)
Mark-to-market on derivatives:
Total (gains) losses		(449,940	)		(7,303	)		167,727
Cash settlements		237,134			302,875			362,936
Cash settlements on canceled derivatives		26,752			(123,865	)		48,977
Premiums paid for derivatives		(134,352	)		(120,376	)		(93,606	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		(120,055	)		(66,283	)		29,117
(Increase) decrease in other assets		(2,951	)		2,926			(3,051	)
Increase (decrease) in accounts payable and accrued expenses		58,216			25,457			(4,675	)
Increase (decrease) in other liabilities		(9,333	)		49,031			8,154
Net cash provided by operating activities		518,706			270,918			426,804
Cash flow from investing activities:
Acquisition of oil and natural gas properties, net of cash acquired		(1,500,193	)		(1,351,033	)		(130,735	)
Development of oil and natural gas properties		(574,635	)		(204,832	)		(170,458	)
Purchases of other property and equipment		(55,229	)		(18,181	)		(7,784	)
Proceeds from sale of properties and equipment and other		(303	)		(7,362	)		26,704
Net cash used in investing activities		(2,130,360	)		(1,581,408	)		(282,273	)
Cash flow from financing activities:
Proceeds from sale of units		678,949			844,330			291,668
Proceeds from borrowings		2,534,240			3,300,816			639,203
Repayments of debt		(1,301,029	)		(2,150,000	)		(704,893	)
Distributions to unitholders		(466,488	)		(365,711	)		(303,316	)
Financing fees, offering expenses and other, net		(56,358	)		(93,343	)		(71,511	)
Excess tax benefit from unit-based compensation		4,805			—			577
Purchase of units		(17,352	)		(11,832	)		(2,696	)
Net cash provided by (used in) financing activities		1,376,767			1,524,260			(150,968	)
Net increase (decrease) in cash and cash equivalents		(234,887	)		213,770			(6,437	)
Cash and cash equivalents:
Beginning		236,001			22,231			28,668
Ending	$	1,114		$	236,001		$	22,231

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

5

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Basis of Presentation and Significant Accounting Policies

Nature of Business

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005. The Company completed its initial public offering (“IPO”) in January 2006 and its units representing limited liability company interests (“units”) are listed on The NASDAQ Global Select Market under the symbol “LINE.” 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 (“U.S.”), primarily in the Mid-Continent, the Permian Basin, Michigan, California and the Williston Basin.

The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s unitholders. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (the “Agreement”), unitholders have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the Agreement.

Principles of Consolidation and Reporting

The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The 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. Subsequent events were evaluated through the issuance date of the financial statements.

The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or unitholders’ capital.

Discontinued Operations

Discontinued operations in 2009 primarily represent activity related to post-closing adjustments associated with the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations disposed of in 2008.

Use of Estimates

The preparation of the accompanying 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, if any, 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 continuous changes in the economic environment will be reflected in the financial statements in future periods.

6

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Recently Issued Accounting Standards Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU will be applied prospectively and is effective for periods beginning after December 15, 2011. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

Cash Equivalents

For purposes of the 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. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.

Accounts Receivable – Trade, Net

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at December 31, 2011, and December 31, 2010.

Inventories

Materials, supplies and commodity inventories are valued at the lower of average cost or market.

Oil and Natural Gas Properties

Proved Properties

The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine

7

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

the fair values of proved 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. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $2 million, $1 million and $300,000 for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

Impairment of Proved Properties

Based on the analysis described above, the Company recorded no impairment charge of proved oil and natural gas properties for the years ended December 31, 2011, and December 31, 2009. For the year ended December 31, 2010, the Company recorded a noncash impairment charge, before and after tax, of approximately $39 million primarily associated with proved oil and natural gas properties related to an unfavorable marketing contract. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved 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. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million, $5 million and $7 million for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, which are included in “exploration costs” on the consolidated statements of operations.

8

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Other Property and Equipment

Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets.

Revenue Recognition

Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.

The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2011, and December 31, 2010, the Company had natural gas production imbalance receivables of approximately $19 million and $18 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $9 million and $8 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.

The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in Brea, California. Any excess electricity is sold to the California wholesale power market. This revenue is included in “other revenues” on the consolidated statements of operations.

Restricted Cash

Restricted cash of approximately $4 million and $3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2011, and December 31, 2010, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts and put options. In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2011, the Company had no outstanding interest rate swap agreements.

Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. 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. The Company uses certain pricing models to determine the fair value

9

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.

Unit-Based Compensation

The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based payments granted to employees and nonemployee directors. The fair value of unit-based payments, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards.

The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation.

The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is reported in “excess tax benefit from unit-based compensation” on the consolidated statements of unitholders’ capital.

Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt (see Note 6). At December 31, 2011, and December 31, 2010, net deferred financing fees of approximately $94 million and $102 million, respectively, are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement. For the years ended December 31, 2011, December 31, 2010, and December 31, 2009, amortization expense of approximately $16 million, $17 million and $14 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

Fair Value of Financial Instruments

The carrying values of the Company’s receivables, payables and Credit Facility (as defined in Note 6) are estimated to be substantially the same as their fair values at December 31, 2011, and December 31, 2010. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.

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. As such, with the exception of the states of Texas and Michigan, the Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below.

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, which are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and

10

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for detail of amounts recorded in the consolidated financial statements.

Note 2 – Acquisitions, Divestitures and Discontinued Operations

Acquisitions – 2011

On December 15, 2011, the Company completed the acquisition of certain oil and natural gas properties located primarily in the Granite Wash of Texas and Oklahoma from Plains Exploration & Production Company (“Plains”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. The Company paid approximately $544 million in total consideration for these properties. The transaction was financed initially with borrowings under the Company’s Credit Facility, as defined in Note 6.

On November 1, 2011, and November 18, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $108 million in cash and recorded a payable of approximately $2 million, resulting in total consideration for the acquisitions of approximately $110 million. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On June 1, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Cleveland play, located in the Texas Panhandle, from Panther Energy Company, LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. The Company paid approximately $223 million in total consideration for these properties. The transaction was financed primarily with proceeds from the Company’s May 2011 debt offering, as described below.

On May 2, 2011, and May 11, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Williston Basin. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $154 million in cash and recorded a receivable of approximately $1 million, resulting in total consideration for the acquisitions of approximately $153 million. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On April 1, 2011, and April 5, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin, including properties from SandRidge Exploration and Production, LLC (“SandRidge”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $239 million in total consideration for the acquisitions. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties located in the Williston Basin from an affiliate of Concho Resources Inc. (“Concho”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. The Company paid $196 million in cash and recorded a receivable from Concho of approximately $2 million, resulting in total consideration for the acquisition of approximately $194 million. The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.

During 2011, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company, in the aggregate, paid approximately $38 million in total consideration for these properties.

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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.

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

Assets:
Current	$	5,981
Noncurrent		748
Oil and natural gas properties		1,516,737
Total assets acquired	$	1,523,466
Liabilities:
Current	$	2,130
Asset retirement obligations		19,853
Total liabilities assumed	$	21,983
Net assets acquired	$	1,501,483

Current assets include receivables, prepaids and inventory and noncurrent assets include other property and equipment. Current liabilities include payables, ad valorem taxes payable and other liabilities.

The fair values of oil and natural gas properties and asset retirement obligations 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; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate.

The revenues and expenses related to the properties acquired from Plains, Panther, SandRidge and Concho are included in the condensed consolidated results of operations of the Company as of December 15, 2011, June 1, 2011, April 1, 2011, and March 31, 2011, respectively. The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the years ended December 31, 2011, and December 31, 2010, assuming the acquisitions of Plains, Panther, SandRidge and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of this date.

	Year Ended December 31,
	2011		2010
	(in thousands, except per unit amounts)
Total revenues and other	$	1,819,878	$	939,572
Total operating expenses	$	901,967	$	720,360
Net income (loss)	$	528,046	$	(86,952	)
Net income (loss) per unit:
Basic	$	3.01	$	(0.57	)
Diluted	$	3.00	$	(0.57	)

12

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Other

In July 2010, the Company entered into a definitive purchase and sale agreement (“PSA”) to acquire certain oil and natural gas properties for a contract price of $95 million. Upon the execution of the PSA, the Company paid a deposit of approximately $9 million. In September 2010, in accordance with the terms of the PSA, the Company terminated the PSA as a result of certain conditions to closing not being met. The other party to the PSA disputed the termination of the PSA and held the deposit. On March 28, 2011, an arbitration panel granted a favorable final ruling to the Company with regard to the termination of the PSA and the return of the deposit. The deposit plus interest was received by the Company in April 2011.

Acquisitions – 2010 and 2009

The following is a summary of certain significant acquisitions completed by the Company during the years ended December 31, 2010, and December 31, 2009:

• On November 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Element Petroleum, LP for approximately $118 million.

• On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Crownrock, LP and Patriot Resources Partners LLC for approximately $260 million.

• On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from Crownrock, LP and Element Petroleum, LP for approximately $95 million.

• On May 27, 2010, the Company completed the acquisition of interests in Henry Savings LP and Henry Savings Management LLC that primarily hold oil and natural gas properties located in the Permian Basin for approximately $323 million.

• On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount Exploration & Production LLC that hold oil and natural gas properties in the Antrim Shale located in northern Michigan for approximately $327 million.

• 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 for approximately $151 million.

• On August 31, 2009, and September 30, 2009, the Company completed two 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 for approximately $114 million.

Divestitures

In 2009, certain post-closing matters related to the 2008 sale of the deep rights interests in certain central Oklahoma acreage were resolved and the Company recorded a gain of approximately $25 million, which is included in “(gains) losses on sale of assets and other, net” on the consolidated statements of operations for the year ended December 31, 2009.

Discontinued Operations

Discontinued operations of approximately $2 million in 2009 primarily represent activity related to post-closing adjustments associated with the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations disposed of in 2008.

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 3 – Unitholders’ Capital

Equity Distribution Agreement

On August 23, 2011, the Company entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. In connection with entering into the agreement, the Company incurred expenses of approximately $423,000. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

In September 2011, the Company issued and sold 16,060 units representing limited liability company interests at an average unit price of $38.25 for proceeds of approximately $602,000 (net of approximately $12,000 in commissions). In December 2011, the Company issued and sold 772,104 units representing limited liability company interests at an average unit price of $38.03 for proceeds of approximately $29 million (net of approximately $587,000 in commissions). In connection with the issue and sale of these units, the Company incurred professional service expenses of approximately $139,000. The Company used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At December 31, 2011, units equaling approximately $470 million in aggregate offering price remained available to be issued and sold under the agreement.

Public Offering of Units

In March 2011, the Company sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million). The Company used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Senior Notes and 2018 Senior Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Senior Notes and 2018 Senior Notes (see Note 6). The Company used the remaining net proceeds from the sale of units to finance a portion of the March 31, 2011, acquisition in the Williston Basin.

In December 2010, the Company sold 11,500,000 units representing limited liability company interests at $35.92 per unit ($34.48 per unit, net of underwriting discount) for net proceeds of approximately $396 million (after underwriting discount and offering expenses of approximately $17 million). The Company used the net proceeds from the sale of these units to repay all outstanding indebtedness under its Credit Facility and for other general corporate purposes, including the partial notes redemption (see Note 6).

In March 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 $414 million (after underwriting discount and offering expenses of approximately $17 million). The Company used a portion of the net proceeds from the sale of these units to finance the HighMount acquisition.

In October 2009, the Company sold 8,625,000 units representing limited liability company interests at $21.90 per unit ($21.024 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering expenses of approximately $8 million). The Company used the net proceeds from the sale of these units to reduce indebtedness under the Credit Facility.

In May 2009, the Company sold 6,325,000 units representing limited liability company interests at $16.25 per unit ($15.60 per unit, net of underwriting discount) for net proceeds of approximately $98 million (after underwriting discount and offering expenses of approximately $4 million). The Company used the net proceeds from the sale of these units to reduce indebtedness under the Credit Facility.

14

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Equity Distribution Agreement and Public Offering of Units – Subsequent Events

In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions). The Company used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At January 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.

In January 2012, the Company also completed a public offering of units in which it sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. During the year ended December 31, 2011, 529,734 units were repurchased at an average unit price of $32.76 for a total cost of approximately $17 million. During the year ended December 31, 2010, 486,700 units were repurchased at an average unit price of $23.79 for a total cost of approximately $12 million. During the year ended December 31, 2009, 123,800 units were repurchased at an average unit price of $12.99 for a total cost of approximately $2 million. All units were subsequently canceled.

At December 31, 2011, approximately $56 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.

Issuance and Cancellation of Units

During the years ended December 31, 2010, and December 31, 2009, the Company purchased 9,055 units and 63,031 units for approximately $300,000 and $1 million, respectively, 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. The Company purchased no units during the year ended December 31, 2011.

Distributions

Under the 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 are presented on the consolidated statements of unitholders’ capital. On January 27, 2012, the Company’s Board of Directors declared a cash distribution of $0.69 per unit with respect to the fourth quarter of 2011. The distribution, totaling approximately $138 million, was paid February 14, 2012, to unitholders of record as of the close of business February 7, 2012.

15

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 4 – Business and Credit Concentrations

Cash

The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash.

Revenue and Trade Receivables

The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1).

For the year ended December 31, 2011, the Company’s three largest customers represented 13%, 10% and 10%, respectively, of the Company’s sales. For the year ended December 31, 2010, the Company’s three largest customers represented 17%, 14% and 13%, respectively, of the Company’s sales. For the year ended December 31, 2009, the Company’s three largest customers represented 22%, 18% and 15%, respectively, of the Company’s sales.

At December 31, 2011, trade accounts receivable from three customers represented approximately 12%, 10% and 10%, respectively, of the Company’s receivables. At December 31, 2010, trade accounts receivable from three customers represented approximately 16%, 12% and 11%, respectively, of the Company’s receivables.

Note 5 – Unit-Based Compensation and Other Benefit Plans

Incentive Plan Summary

The Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (the “Plan”), originally became effective in December 2005. The Plan, which is administered by the Compensation Committee of the Board of Directors (“Compensation Committee”), permits granting unit grants, unit options, restricted units, phantom units and unit appreciation rights to employees, consultants and nonemployee directors under the terms of the Plan. The unit options and restricted units vest ratably over three years. The contractual life of unit options is 10 years. Unit awards were initially issued in conjunction with the Company’s IPO in January 2006.

The Plan limits the number of units that may be delivered pursuant to awards to 12.2 million units. The Board of Directors and the Compensation Committee have the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits to the participant without the consent of the participant.

Upon exercise or vesting of an award of units, or an award settled in units, the Company will issue new units, acquire units on the open market or directly from any person, or use any combination of the foregoing, at the Compensation Committee’s discretion. If the Company issues new units upon exercise or vesting of an award, the total number of units outstanding will increase. To date, the Company has issued awards of unit grants, unit options, restricted units and phantom units. The Plan provides for all of the following types of awards:

Unit Grants – A unit grant is a unit that vests immediately upon issuance.

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Unit Options – A unit option is a right to purchase a unit at a specified price at terms determined by the Compensation Committee. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant, and in general, will become exercisable over a vesting period but may accelerate upon a change in control of the Company. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s unvested unit options will be automatically forfeited unless the option agreement or the Compensation Committee provides otherwise.

Restricted Units – A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture, and may contain such terms as the Compensation Committee shall determine. The Company intends the restricted units under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of its units. Therefore, Plan participants will not pay any consideration for the restricted units they receive. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s unvested restricted units will be automatically forfeited unless the Compensation Committee or the terms of the award agreement provide otherwise.

Phantom Units/Unit Appreciation Rights – These awards may be settled in units, cash or a combination thereof. Such grants contain terms as determined by the Compensation Committee, including the period or terms over which phantom units vest. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s phantom units or unit appreciation rights will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. While phantom units require no payment from the grantee, unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant. At December 31, 2011, the Company had 36,784 phantom units issued and outstanding. To date, the Company has not issued unit appreciation rights.

Securities Authorized for Issuance Under the Plan

As of December 31, 2011, approximately 1.4 million units were issuable under the Plan pursuant to outstanding award or other agreements, and 5.2 million additional units were reserved for future issuance under the Plan.

Accounting for Unit-Based Compensation

The Company recognizes as expense, beginning at the grant date, the fair value of unit options and other equity-based compensation issued to employees and nonemployee directors. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations. A summary of unit-based compensation expenses included on the consolidated statements of operations is presented below:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
General and administrative expenses	$	21,131	$	13,450	$	14,743
Lease operating expenses		1,112		342		346
Total unit-based compensation expenses	$	22,243	$	13,792	$	15,089
Income tax benefit	$	8,219	$	5,096	$	5,968

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Restricted/Unrestricted Units

The fair value of unrestricted unit grants and restricted units issued is determined based on the fair market value of the Company units on the date of grant. A summary of the status of the nonvested units as of December 31, 2011, is presented below:

	Number of Nonvested Units			Weighted Average Grant-Date Fair Value
Nonvested units at December 31, 2010		1,451,556		$	21.16
Granted		1,110,502		$	38.54
Vested		(651,760	)	$	20.22
Forfeited		(50,636	)	$	33.32
Nonvested units at December 31, 2011		1,859,662		$	31.54

The weighted average grant-date fair value of unrestricted unit grants and restricted units granted was $25.89 and $16.11 during the years ended December 31, 2010, and December 31, 2009, respectively.

As of December 31, 2011, there was approximately $38 million of unrecognized compensation cost related to nonvested restricted units. The cost is expected to be recognized over a weighted average period of approximately 1.5 years. The total fair value of units that vested was approximately $13 million, $14 million and $11 million for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

In January 2012, the Company granted 913,663 restricted units as part of its annual review of its employees, including executives, compensation.

Changes in Unit Options and Unit Options Outstanding

The following provides information related to unit option activity for the year ended December 31, 2011:

	Number of Units Underlying Options			Weighted Average Exercise Price Per Unit		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Contractual Life in Years
Outstanding at December 31, 2010		1,720,393		$	22.48	$	3.05		6.71
Exercised		(310,400	)	$	23.99	$	3.83
Outstanding at December 31, 2011		1,409,993		$	22.14	$	2.87		5.83
Exercisable at December 31, 2011		1,282,526		$	22.76	$	3.11		5.70

No unit options were granted during the years ended December 31, 2011, or December 31, 2010. The weighted average grant-date fair value of options granted was $0.55 during the year ended December 31, 2009. The total intrinsic value of options exercised was approximately $5 million, $2 million and $124,000, during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively. The Company received approximately $7 million from the exercise of options during the year ended December 31, 2011.

As of December 31, 2011, total unrecognized compensation cost related to nonvested unit options was approximately $4,000. The cost is expected to be recognized over a weighted average period of approximately one month. In addition, the exercisable unit options at December 31, 2011, have an aggregate intrinsic value of approximately $19 million and all outstanding unit options have an aggregate intrinsic value of approximately $22

18

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

million. The total fair value of all options that vested during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, was approximately $500,000, $1 million and $2 million, respectively. No options expired during the years ended December 31, 2011, December 31, 2010, or December 31, 2009.

The fair value of unit-based compensation for unit options was estimated on the date of grant using a Black-Scholes pricing model based on certain assumptions. The Company’s determination of the fair value of unit-based payment awards is affected by the Company’s unit price as well as assumptions regarding a number of complex and subjective variables. The Company’s employee unit options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and often are expected to be exercised prior to their contractual maturity.

Expected volatilities used in the estimation of fair value have been determined using available volatility data for the Company as well as an average of volatility computations of other identified peer companies in the oil and natural gas industry. Expected distributions are estimated based on the Company’s distribution rate at the date of grant. Historical data of the Company and other identified peer companies is used to estimate expected term because, due to the limited period of time its equity units have been publicly traded, the Company does not have sufficient historical exercise data to compute a reasonable estimate. Forfeitures are estimated using historical Company data and are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. All employees granted awards have been determined to have similar behaviors for purposes of determining the expected term used to estimate fair value. The risk-free rate for periods within the expected term of the unit option is based on the U.S. Treasury yield curve in effect at the time of grant. The fair values of the 2009 unit option grants were based upon the following assumptions:

	2009
Expected volatility		30.59%
Expected distributions		15.80	%	–	16.79	%
Risk-free rate		1.24	%	–	1.91	%
Expected term		5 years

Although the fair value of unit option grants is determined in accordance with applicable accounting standards, using a Black-Scholes pricing model, that value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction.

Nonemployee Grants

During the year ended December 31, 2007, the Company granted an aggregate 150,000 unit warrants to certain individuals in connection with an acquisition transition services agreement. The unit warrants, all of which remain outstanding, have an exercise price of $25.50 per unit warrant, are fully exercisable at December 31, 2011, and expire 10 years from the date of issuance.

Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 4% of eligible compensation contributed by the employee on a before-tax basis for the year ending December 31, 2009. For the years ended December 31, 2011, and December 31, 2010, the Company contribution was equal to 100% of the first 6% of eligible employee compensation. The Company contributed approximately $4 million, $3 million and $2 million during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants.

19

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 6 – Debt

The following summarizes debt outstanding:

	December 31, 2011								December 31, 2010
	Carrying Value			Fair Value (1)		Interest Rate (2)			Carrying Value			Fair Value  (1)		Interest Rate (2)
	(in millions, except percentages)
Credit facility	$	940		$	940		2.57	%	$	—		$	—		—
11.75% senior notes due 2017		41			46		12.73	%		250			288		12.73	%
9.875% senior notes due 2018		14			16		10.25	%		256			279		10.25	%
6.50% senior notes, due 2019		750			742		6.62	%		—			—		—
8.625% senior notes due 2020		1,300			1,406		9.00	%		1,300			1,396		9.00	%
7.75% senior notes due 2021		1,000			1,036		8.00	%		1,000			1,021		8.00	%
Less current maturities		—			—					—			—
		4,045		$	4,186					2,806		$	2,984
Unamortized discount		(51	)							(63	)
Total debt, net of discount	$	3,994							$	2,743

(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 May 2, 2011, the Company entered into a Fifth Amended and Restated Credit Agreement (“Credit Facility”), which provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount of $1.5 billion. In October 2011, as part of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with the maximum commitment amount remaining unchanged at $1.5 billion. The maturity date is April 2016.

During 2011, in connection with amendments to its Credit Facility, the Company incurred financing fees and expenses of approximately $4 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 consolidated statements of operations. At December 31, 2011, available borrowing capacity under the Credit Facility was $556 million, which includes a $4 million reduction in availability for outstanding letters of credit.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion. The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions. 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 and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries. The Company and its subsidiaries are required to maintain the mortgages on properties representing at least 80% of the total value of its and its subsidiaries’ oil and natural gas properties. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus

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an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum equal to 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The Company is in compliance with all financial and other covenants of the Credit Facility.

Senior Notes Due 2019

On May 13, 2011, the Company issued $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “2019 Senior Notes”) at a price of 99.232%. The 2019 Senior Notes were sold to a group of 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 $729 million (after deducting the initial purchasers’ discount and offering expenses). The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, fund or partially fund acquisitions and for general corporate purposes. In connection with the 2019 Senior Notes, the Company incurred financing fees and expenses of approximately $15 million, which will be amortized over the life of the 2019 Senior Notes. The discount on the 2019 Senior Notes, which totaled approximately $6 million, will also be amortized over the life of the 2019 Senior Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

The 2019 Senior Notes were issued under an indenture dated May 13, 2011 (“2019 Indenture”), mature May 15, 2019, and bear interest at 6.50%. Interest is payable semi-annually on May 15 and November 15, beginning November 15, 2011. The 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries has guaranteed the 2019 Senior Notes on a senior unsecured basis. The 2019 Indenture provides that the Company may redeem: (i) on or prior to May 15, 2014, up to 35% of the aggregate principal amount of the 2019 Senior Notes at a redemption price of 106.50% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to May 15, 2015, all or part of the 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the 2019 Indenture) and accrued and unpaid interest; and (iii) on or after May 15, 2015, all or part of the 2019 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The 2019 Indenture also provides that, if a change of control (as defined in the 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2019 Indenture contains covenants substantially similar to those under the Company’s 2010 Issued Senior Notes and Original Senior Notes, as defined below, that, among other things, limit the Company’s ability to: (i) pay distributions, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of the 2019 Senior Notes.

In connection with the issuance and sale of the 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“2019 Registration Rights Agreement”) with the initial purchasers. Under the 2019 Registration Rights Agreement, the Company agreed to use reasonable 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 2019 Senior Notes in exchange for outstanding 2019 Senior Notes within 400 days after the notes were issued. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2019 Senior Notes. If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the 2019 Senior Notes under certain circumstances.

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Senior Notes Due 2020 and Senior Notes Due 2021

On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”). On September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”). The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the 2019 Senior Notes.

Senior Notes Due 2017 and Senior Notes Due 2018

The Company also has $41 million (originally $250 million) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Senior Notes”) and $14 million (originally $256 million) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 2017 Senior Notes, the “Original Senior Notes”). The indentures related to the Original Senior Notes originally contained redemption provisions and covenants that were substantially similar to those of the 2010 Issued Senior Notes; however, in connection with the tender offers described below, the indentures were amended and most of the covenants and certain default provisions were eliminated.

Redemptions of Original Senior Notes

In March 2011, in accordance with the provisions of the indentures related to the 2017 Senior Notes and the 2018 Senior Notes, the Company redeemed 35%, or $87 million and $90 million, respectively, of each of its original aggregate principal amount of the 2017 Senior Notes and 2018 Senior Notes. After the redemptions, $163 million and $166 million, respectively, of the 2017 Senior Notes and 2018 Senior Notes remained outstanding.

Tender Offers for and Repurchase of Original Senior Notes

On February 28, 2011, the Company commenced cash tender offers (“Offers”) and related consent solicitations to purchase any and all of its outstanding 2017 Senior Notes and 2018 Senior Notes. The Offers expired on March 25, 2011. Holders who validly tendered 2017 Senior Notes and 2018 Senior Notes on or before March 14, 2011, received total consideration of $1,212.50 and $1,172.50, respectively, for each $1,000 principal amount of such notes accepted for purchase. Total consideration included a consent payment of $30.00 per $1,000 principal amount of notes accepted for purchase. Holders who validly tendered 2017 Senior Notes and 2018 Senior Notes after March 14, 2011, but before March 25, 2011, received $1,182.50 and $1,142.50, respectively, for each $1,000 principal amount of such notes accepted for purchase.

In March 2011, in connection with its Offers and related consent solicitations, the Company accepted and purchased: 1) $105 million of the aggregate principal amount of its outstanding 2017 Senior Notes (or 65% of the remaining outstanding principal amount of its 2017 Senior Notes), and 2) $126 million of the aggregate principal amount of its outstanding 2018 Senior Notes (or 76% of the remaining outstanding principal amount of its 2018 Senior Notes).

In conjunction with each tender offer, the Company received consents to amendments to the indentures of the 2017 Senior Notes and 2018 Senior Notes, which eliminated most of the covenants and certain default provisions applicable to the series of notes issued under such indentures. The amendments became effective upon the execution of the supplemental indentures to the indentures governing each of the 2017 Senior Notes and the 2018 Senior Notes.

In June 2011, the Company repurchased an additional portion of its remaining outstanding 2017 Senior Notes and 2018 Senior Notes for approximately $17 million (or 29% of the remaining outstanding principal amount of its 2017 Senior Notes) and approximately $24 million (or 61% of the remaining outstanding principal amount of its 2018

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Senior Notes), respectively. In December 2011, the Company also repurchased an additional portion of its remaining outstanding 2018 Senior Notes for approximately $2 million (or 9% of the remaining outstanding principal amount of its 2018 Senior Notes). After giving effect to the tender offers and subsequent repurchases of the 2017 Senior Notes and the 2018 Senior Notes, aggregate principal amounts of $41 million and $14 million, respectively, remain outstanding at December 31, 2011.

In connection with the redemptions, cash tender offers and additional repurchases of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $95 million for the year ended December 31, 2011.

Note 7 – Derivatives

Commodity Derivatives

The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. At December 31, 2011, the Company had no outstanding collars. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

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The following table summarizes open positions as of December 31, 2011, and represents, as of such date, derivatives in place through December 31, 2016, on annual production volumes:

	2012			2013			2014			2015			2016
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		56,730			64,367			73,456			82,490			2,745
Average price ($/MMBtu)	$	5.85		$	5.69		$	5.69		$	5.75		$	5.00
Puts:
Hedged volume (MMMBtu)		38,357			37,340			30,660			32,850			—
Average price ($/MMBtu)	$	5.83		$	5.85		$	5.00		$	5.00		$	—
Total:
Hedged volume (MMMBtu)		95,087			101,707			104,116			115,340			2,745
Average price ($/MMBtu)	$	5.84		$	5.75		$	5.49		$	5.54		$	5.00
Oil positions:
Fixed price swaps: (1)
Hedged volume (MBbls)		8,171			9,033			9,034			9,581			—
Average price ($/Bbl)	$	97.37		$	98.05		$	95.39		$	98.25		$	—
Puts:
Hedged volume (MBbls)		2,196			2,300			—			—			—
Average price ($/Bbl)	$	100.00		$	100.00		$	—		$	—		$	—
Total:
Hedged volume (MBbls)		10,367			11,333			9,034			9,581			—
Average price ($/Bbl)	$	97.93		$	98.44		$	95.39		$	98.25		$	—
Natural gas basis differential positions:
PEPL basis swaps: (2)
Hedged volume (MMMBtu)		37,735			38,854			42,194			42,194			—
Hedged differential ($/MMBtu)	$	(0.89	)	$	(0.89	)	$	(0.39	)	$	(0.39	)	$	—
Oil timing differential positions:
Trade month roll swaps: (3)
Hedged volume (MBbls)		5,982			6,315			6,315			840			—
Hedged differential ($/Bbl)	$	0.21		$	0.21		$	0.21		$	0.17		$	—

(1) As presented in the table above, the Company has certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2016, December 31, 2017, and December 31, 2018, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(2) 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.

(3) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent Deep, Mid-Continent Shallow and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the year ended December 31, 2011, the Company entered into commodity derivative contracts consisting of oil and natural gas swaps for certain years through 2016 and oil trade month roll swaps for October 2011 through December 2015. In September 2011, the Company canceled its oil and natural gas swaps for the year 2016 and used the realized gains of approximately $27 million to increase prices on its existing oil and natural gas swaps for the year 2012. Also, in September 2011, the Company paid premiums of approximately $33 million to increase prices

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

on its existing oil puts for the years 2012 and 2013. In addition, during the fourth quarter of 2011, the Company paid premiums of approximately $52 million for put options and approximately $22 million to increase prices on its existing oil puts for 2012 and 2013, respectively.

Settled derivatives on natural gas production for the year ended December 31, 2011, included volumes of 64,457 MMMBtu at an average contract price of $8.24. Settled derivatives on oil production for the year ended December 31, 2011, included volumes of 7,917 MBbls at an average contract price of $85.70. Settled derivatives on natural gas production for the year ended December 31, 2010, included volumes of 57,160 MMMBtu at an average contract price of $8.66. Settled derivatives on oil production for the year ended December 31, 2010, included volumes of 4,650 MBbls at an average contract price of $99.68. The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or 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 crude oil and settlement occurs on the final day of the production month.

Interest Rate Swaps

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

In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of the 2020 Senior Notes (see Note 6). In conjunction with the repayment of borrowings under its Credit Facility with proceeds from the issuance of 2020 Senior Notes, the Company canceled (before the contract settlement date) certain interest rate swap agreements for 2010 through 2013, resulting in realized losses of approximately $74 million. In September 2010, the Company canceled (before the contract settlement date) all of its remaining interest rate swap agreements in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of 2021 Senior Notes (see Note 6). The cancellation of the interest rate swap agreements in September 2010 resulted in a realized loss of approximately $50 million. At December 31, 2011, and December 31, 2010, the Company had no outstanding interest rate swap agreements.

Balance Sheet Presentation

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

	December 31,
	2011		2010
	(in thousands)
Assets:
Commodity derivatives	$	880,175	$	637,836
Liabilities:
Commodity derivatives	$	320,835	$	398,902

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, when applicable, 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 participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its

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Credit Facility at the time it originally entered into the derivatives. The Credit Facility 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 receive 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 $880 million at December 31, 2011. 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 derivatives and, when applicable, its interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives, including realized and unrealized gains and losses, are reported on the consolidated statements of operations in “gains (losses) on oil and natural gas derivatives” and “losses on interest rate swaps.” 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.

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

	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	230,237	$	307,587		$	400,968
Interest rate swaps		—		(8,021	)		(42,881	)
Canceled derivatives		26,752		(123,865	)		48,977
	$	256,989	$	175,701		$	407,064
Unrealized gains (losses):
Commodity derivatives	$	192,951	$	(232,376	)	$	(591,379	)
Interest rate swaps		—		63,978			16,588
	$	192,951	$	(168,398	)	$	(574,791	)
Total gains (losses):
Commodity derivatives	$	449,940	$	75,211		$	(141,374	)
Interest rate swaps		—		(67,908	)		(26,353	)
	$	449,940	$	7,303		$	(167,727	)

During the year ended December 31, 2011, the Company canceled (before the contract settlement date) its oil and natural gas swaps for the year 2016 and used the realized gains of approximately $27 million to increase prices on its existing oil and natural gas swaps for the year 2012. During the year ended December 31, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements resulting in realized losses of approximately $124 million.

During the year ended December 31, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized net gains of approximately $49 million. Of this amount, realized net gains of approximately $45 million, along with an incremental premium payment of approximately $49 million, were used to reposition the Company’s commodity derivative portfolio in July 2009, when the Company canceled oil and natural gas derivative contracts for years 2012 through 2014 to raise prices for oil and natural gas derivative contracts in years 2010 and 2011.

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Note 8 – Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives and, when applicable, its interest rate derivatives at fair value (see Note 7) on a recurring basis. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives and, when applicable, its interest rate derivatives.

Fair Value Hierarchy

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

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

Level 1 Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2 Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives and interest rate swaps).

Level 3 Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

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

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

	Fair Value Measurements on a Recurring Basis December 31, 2011
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	880,175	$	(303,272	)	$	576,903
Liabilities:
Commodity derivatives	$	320,835	$	(303,272	)	$	17,563

⁽¹⁾  Represents counterparty netting under agreements governing such derivatives.

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Note 9 – Other Property and Equipment

Other property and equipment consists of the following:

	December 31,
	2011			2010
	(in thousands)
Natural gas compression plant and pipeline	$	129,863		$	96,624
Buildings and leasehold improvements		16,158			10,874
Vehicles		13,653			10,127
Drilling and other equipment		3,645			1,827
Furniture and office equipment		29,972			17,529
Land		3,944			2,922
		197,235			139,903
Less accumulated depreciation		(48,024	)		(35,151	)
	$	149,211		$	104,752

Note 10 – 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 consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the 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 each of the years in the three-year period ended December 31, 2011); and (iv) a credit-adjusted risk-free interest rate (average of 7.5%, 8.6% and 9.6% for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively).

The following presents a reconciliation of the Company’s asset retirement obligations:

	December 31,
	2011			2010
	(in thousands)
Asset retirement obligations at beginning of year	$	42,945		$	33,135
Liabilities added from acquisitions		19,853			6,976
Liabilities added from drilling		1,277			309
Current year accretion expense		4,140			2,694
Settlements		(2,218	)		(169	)
Revision of estimates		5,145			—
Asset retirement obligations at end of year	$	71,142		$	42,945

Note 11 – Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits and is involved in various other disputes arising in the ordinary course of business, including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Discovery in this dispute is ongoing and is not complete. As a result, the Company is unable to

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estimate a possible loss, or range of possible loss, if any. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

On September 15, 2008, and October 3, 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”), respectively, filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. At December 31, 2011, and December 31, 2010, the Company had a net receivable of approximately $7 million from Lehman Commodity Services related to canceled derivative contracts, which is included in “other current assets” on the consolidated balance sheets. The value of the receivable was estimated based on market expectations. In March 2011, the Company, Lehman Holdings and Lehman Commodity Services entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman Holdings and Lehman Commodity Services in the amount of $51 million each, provided that the aggregate value of the distributions to the Company on account of both such claims will not exceed $51 million (collectively, the “Company Claim”). On December 6, 2011, a Chapter 11 Plan (“Plan”) was approved by the Bankruptcy Court. Initial distributions under the Plan to creditors, including the Company, are expected to occur after January 31, 2012. Based on the recovery estimates described in the approved disclosure statement relating to the Plan, the Company expects to ultimately receive a substantial portion of the Company Claim.

Note 12 – Earnings Per Unit

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

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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)
Year ended December 31, 2011:
Income from continuing operations:
Allocated to units	$	438,439
Allocated to unvested restricted units		(4,739	)
	$	433,700
Income per unit:
Basic income per unit					172,004	$	2.52
Dilutive effect of unit equivalents					725		(0.01	)
Diluted income per unit					172,729	$	2.51
Year ended December 31, 2010:
Loss from continuing operations:
Allocated to units	$	(114,288	)
Allocated to unvested restricted units		—
	$	(114,288	)
Loss per unit:
Basic loss per unit					142,535	$	(0.80	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					142,535	$	(0.80	)
Year ended December 31, 2009:
Loss from continuing operations:
Allocated to units	$	(295,841	)
Allocated to unvested restricted units		—
	$	(295,841	)
Loss per unit:
Basic loss per unit					119,307	$	(2.48	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					119,307	$	(2.48	)

There were no anti-dilutive unit equivalents for the year ended December 31, 2011. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 2 million unit options and warrants for each of the years ended December 31, 2010, and December 31, 2009. All equivalent units were anti-dilutive for the years ended December 31, 2010, and December 31, 2009, respectively.

Note 13 – Operating Leases

The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2019. The Company recognized expense under operating leases of approximately $5 million, $5 million, and $4 million, for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

30

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

As of December 31, 2011, future minimum lease payments were as follows (in thousands):

2012	$	5,652
2013		4,769
2014		4,598
2015		4,455
2016		2,950
Thereafter		9,053
	$	31,477

Note 14 – 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 its 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, except as set forth in the tables below.

The Company’s taxable income or loss, which may vary substantially from the net income or net loss reported in the consolidated statements of operations, is includable in the federal and state income tax returns of each unitholder. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholder’s tax attributes.

Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax benefit (expense) from continuing operations consisted of the following:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Current taxes:
Federal	$	(4,551	)	$	(65	)	$	(1,063	)
State		(605	)		(1,088	)		(678	)
Deferred taxes:
Federal		1,148			(2,862	)		5,307
State		(1,458	)		(226	)		655
	$	(5,466	)	$	(4,241	)	$	4,221

As of December 31, 2011, the Company’s taxable entities had approximately $8 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2031.

31

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Income tax benefit (expense) differed from amounts computed by applying the federal income tax rate of 35% to pre-tax income (loss) from continuing operations as a result of the following:

	Year Ended December 31,
	2011			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%
State, net of federal tax benefit		0.5			(1.2	)		—
Loss excluded from nontaxable entities		(34.4	)		(37.5	)		(34.3	)
Other items		0.1			(0.1	)		0.7
Effective rate		1.2	%		(3.8	)%		1.4	%

Significant components of the deferred tax assets and liabilities were as follows:

	December 31,
	2011			2010
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	159		$	717
Unit-based compensation		9,146			6,234
Other		3,606			3,513
Valuation allowance		—			(217	)
Total deferred tax assets		12,911			10,247
Deferred tax liabilities:
Other accruals		—			(2,755	)
Property and equipment principally due to differences in depreciation		(8,226	)		(4,323	)
Other		(1,646	)		179
Total deferred tax liabilities		(9,872	)		(6,899	)
Net deferred tax assets	$	3,039		$	3,348

Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:

	December 31,
	2011			2010
	(in thousands)
Deferred tax assets	$	8,279		$	5,265
Deferred tax liabilities		(589	)		(3,105	)
Other current assets	$	7,690		$	2,160
Deferred tax assets	$	4,632		$	4,982
Deferred tax liabilities		(9,283	)		(3,794	)
Other noncurrent assets (liabilities)	$	(4,651	)	$	1,188

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2011, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

32

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

In accordance with the applicable accounting standard, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2011, and December 31, 2010.

Note 15 – Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows

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

	December 31,
	2011		2010
	(in thousands)
Accrued compensation	$	19,581	$	18,931
Accrued interest		55,170		62,999
Other		1,147		509
	$	75,898	$	82,439

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

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	247,217		$	128,807		$	73,861
Cash payments for income taxes	$	487		$	1,797		$	1,282
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follow:
Fair value of assets acquired	$	1,523,466		$	1,375,010		$	117,717
Cash paid		(1,500,193	)		(1,351,033	)		(115,285	)
Receivable from seller		3,557			9,976			636
Payables to sellers		(4,847	)		—			—
Liabilities assumed	$	21,983		$	33,953		$	3,068

For purposes of the 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 approximately $4 million and $3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2011, and December 31, 2010, respectively, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility. At December 31, 2011, approximately $54 million was included in “accounts payable and accrued expenses” on the consolidated balance sheet which represents reclassified net outstanding checks. There was no such balance at December 31, 2010. The Company presents these net outstanding checks as cash flows from financing activities on the consolidated statements of cash flows.

33

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 16 – Subsidiary Guarantors

The 2019 Senior Notes, the 2010 Issued Notes and the Original Senior Notes are guaranteed by all of the Company’s material subsidiaries. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

34

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)

The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” The Company’s Appalachian Basin and Mid Atlantic operations are classified as discontinued operations on the consolidated statements of operations for the period ended December 31, 2009 (see Note 2). Where applicable, the following supplemental oil and natural gas data present continuing operations separately from discontinued operations.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Property acquisition costs: (1)
Proved	$	1,328,328	$	1,290,826	$	115,929
Unproved		188,409		65,604		947
Exploration costs		80		74		337
Development costs		639,395		244,834		140,521
Asset retirement costs		2,427		748		371
Total costs incurred	$	2,158,639	$	1,602,086	$	258,105

⁽¹⁾  See Note 2 for details about the Company’s acquisitions.

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:

	December 31,
	2011			2010
	(in thousands)
Proved properties:
Leasehold acquisition	$	6,040,239		$	4,695,704
Development		1,484,486			840,175
Unproved properties		310,925			128,624
		7,835,650			5,664,503
Less accumulated depletion and amortization		(1,033,617	)		(719,035	)
	$	6,802,033		$	4,945,468

35

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued

Results of Oil and Natural Gas Producing Activities

The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:

	Year Ended December 31,
	2011			2010		2009
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	1,162,037		$	690,054	$	408,219
Gains (losses) on oil and natural gas derivatives		449,940			75,211		(141,374	)
		1,611,977			765,265		266,845
Production costs:
Lease operating expenses		232,619			158,382		132,647
Transportation expenses		28,358			19,594		18,202
Severance and ad valorem taxes		78,458			45,114		28,687
		339,435			223,090		179,536
Other costs:
Exploration costs		2,390			5,168		7,169
Depletion and amortization		320,096			226,552		191,314
Impairment of long-lived assets		—			38,600		—
Texas margin tax expense		1,599			657		490
Gains on sale of assets and other, net		(1,001	)		—		(25,710	)
		323,084			270,977		173,263
Results of continuing operations	$	949,458		$	271,198	$	(85,954	)
Results of discontinued operations	$	—		$	—	$	(238	)

There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to state income taxes in Texas and Michigan (see Note 14). Discontinued operations for 2009 primarily represent activity related to post-closing adjustments for the sale of properties in the Appalachian Basin in 2008 (see Note 2).

36

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued

Proved Oil, Natural Gas and NGL Reserves

The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with SEC regulations, reserves at December 31, 2011, December 31, 2010, and December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below:

	Year Ended December 31, 2011
	Natural Gas (Bcf)			Oil (MMBbls)			NGL (MMBbls)			Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year		1,233			156.4			70.9			2,597
Revisions of previous estimates		(71	)		(9.2	)		0.9			(121	)
Purchase of minerals in place		337			39.3			1.0			579
Extensions, discoveries and other additions		240			10.3			24.6			450
Production		(64	)		(7.8	)		(3.9	)		(135	)
End of year		1,675			189.0			93.5			3,370
Proved developed reserves:
Beginning of year		805			103.0			39.9			1,662
End of year		998			124.8			47.8			2,034
Proved undeveloped reserves:
Beginning of year		428			53.4			31.0			935
End of year		677			64.2			45.7			1,336

	Year Ended December 31, 2010
	Natural Gas (Bcf)			Oil (MMBbls)			NGL (MMBbls)			Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year		774			102.1			54.2			1,712
Revisions of previous estimates		22			3.9			5.2			77
Purchase of minerals in place		369			49.1			1.2			671
Extensions, discoveries and other additions		118			6.1			13.3			234
Production		(50	)		(4.8	)		(3.0	)		(97	)
End of year		1,233			156.4			70.9			2,597
Proved developed reserves:
Beginning of year		549			77.9			33.9			1,220
End of year		805			103.0			39.9			1,662
Proved undeveloped reserves:
Beginning of year		225			24.2			20.3			492
End of year		428			53.4			31.0			935

37

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued

	Year Ended December 31, 2009
	Natural Gas (Bcf)			Oil (MMBbls)			NGL (MMBbls)			Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year		851			84.1			50.7			1,660
Revisions of previous estimates		(69	)		10.9			4.0			20
Purchase of minerals in place		7			8.8			0.4			62
Extensions, discoveries and other additions		31			1.6			1.5			50
Production		(46	)		(3.3	)		(2.4	)		(80	)
End of year		774			102.1			54.2			1,712
Proved developed reserves:
Beginning of year		585			61.9			29.6			1,134
End of year		549			77.9			33.9			1,220
Proved undeveloped reserves:
Beginning of year		266			22.2			21.1			526
End of year		225			24.2			20.3			492

The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents at a rate of one barrel per six Mcf.

Proved reserves increased by approximately 773 Bcfe to approximately 3,370 Bcfe for the year ended December 31, 2011, from 2,597 Bcfe for the year ended December 31, 2010. The year ended December 31, 2011, includes 121 Bcfe in negative revisions of previous estimates, due primarily to 153 Bcfe in negative revisions due to asset performance. These negative revisions were partially offset by 32 Bcfe in positive revisions primarily due to higher oil prices. Twelve acquisitions during the year ended December 31, 2011, increased proved reserves by approximately 579 Bcfe. In addition, extensions and discoveries, primarily from 292 productive wells drilled during the year, contributed approximately 450 Bcfe to the increase in proved reserves.

Proved reserves increased by approximately 885 Bcfe to approximately 2,597 Bcfe for the year ended December 31, 2010, from 1,712 Bcfe for the year ended December 31, 2009. The year ended December 31, 2010, includes 77 Bcfe in positive revisions of previous estimates, due primarily to higher oil and natural gas prices, which contributed approximately 155 Bcfe. These positive revisions were partially offset by 78 Bcfe in negative revisions primarily due to asset performance. Eleven acquisitions during the year ended December 31, 2010, increased proved reserves by approximately 671 Bcfe. In addition, extensions and discoveries, primarily from 138 productive wells drilled during the year, contributed approximately 234 Bcfe to the increase in proved reserves.

Proved reserves increased by approximately 52 Bcfe to approximately 1,712 Bcfe for the year ended December 31, 2009. The year ended December 31, 2009, includes 20 Bcfe in positive revisions of previous estimates, due primarily to higher asset performance, which contributed approximately 39 Bcfe, most significantly related to well reactivations and waterflood optimization work in the Mid-Continent Shallow region. These positive revisions were partially offset by 19 Bcfe in negative revisions primarily due to decreases in natural gas prices. Two acquisitions during the year ended December 31, 2009, increased proved reserves by approximately 62 Bcfe. In addition, extensions and discoveries, primarily from 72 productive wells drilled during the year, contributed approximately 50 Bcfe to the increase in proved reserves.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to state income taxes in Texas and Michigan; however, these amounts are not material (see Note 14).

38

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued

	December 31,
	2011			2010			2009
	(in thousands)
Future estimated revenues	$	29,319,369		$	20,160,275		$	10,093,876
Future estimated production costs		(9,464,319	)		(6,825,147	)		(4,200,091	)
Future estimated development costs		(2,848,497	)		(1,733,929	)		(816,577	)
Future net cash flows		17,006,553			11,601,199			5,077,208
10% annual discount for estimated timing of cash flows		(10,391,693	)		(7,377,667	)		(3,353,926	)
Standardized measure of discounted future net cash flows	$	6,614,860		$	4,223,532		$	1,723,282
Representative NYMEX prices: (1)
Natural gas (MMBtu)	$	4.12		$	4.38		$	3.87
Oil (Bbl)	$	95.84		$	79.29		$	61.05

⁽¹⁾  In accordance with SEC regulations, reserves at December 31, 2011, December 31, 2010, and December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The price used to estimate reserves is held constant over the life of the reserves.

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Sales and transfers of oil, natural gas and NGL produced during the period	$	(822,602	)	$	(466,964	)	$	(228,683	)
Changes in estimated future development costs		27,236			(56,001	)		54,141
Net change in sales and transfer prices and production costs related to future production		784,308			886,438			254,036
Purchase of minerals in place		1,452,169			1,277,134			128,779
Extensions, discoveries, and improved recovery		552,704			329,642			25,888
Previously estimated development costs incurred during the period		306,827			42,947			52,699
Net change due to revisions in quantity estimates		(292,343	)		164,999			23,672
Accretion of discount		422,353			172,328			142,437
Changes in production rates and other		(39,324	)		149,727			(154,054	)
Change – continuing operations	$	2,391,328		$	2,500,250		$	298,915

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

39

LINN ENERGY, LLC

SUPPLEMENTAL QUARTERLY DATA (Unaudited)

The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”

Quarterly Financial Data

	Quarters Ended
	March 31			June 30		September 30		December 31
	(in thousands, except per unit amounts)
2011:
Oil, natural gas and natural gas liquid sales	$	240,707		$	302,390	$	292,482	$	326,458
Gains (losses) on oil and natural gas derivatives	$	(369,476	)	$	205,515	$	824,240	$	(210,339	)
Total revenues and other	$	(126,473	)	$	510,571	$	1,119,483	$	118,873
Total expenses (1)	$	165,625		$	195,672	$	211,254	$	240,353
Losses on sale of assets and other, net	$	614		$	977	$	279	$	1,646
Net income (loss)	$	(446,682	)	$	237,109	$	837,627	$	(189,615	)
Net income (loss) per unit:
Basic	$	(2.75	)	$	1.34	$	4.74	$	(1.09	)
Diluted	$	(2.75	)	$	1.33	$	4.72	$	(1.09	)

⁽¹⁾  Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, bad debt, depreciation, depletion and amortization and taxes, other than income taxes.

	Quarters Ended
	March 31			June 30			September 30		December 31
	(in thousands, except per unit amounts)
2010:
Oil, natural gas and natural gas liquid sales	$	149,386		$	153,195		$	177,306	$	210,167
Gains (losses) on oil and natural gas derivatives	$	96,003		$	123,791		$	43,505	$	(188,088	)
Total revenues and other	$	247,036		$	278,404		$	222,361	$	24,479
Total expenses (1)	$	124,740		$	135,980		$	145,978	$	200,508
(Gains) losses on sale of assets and other, net	$	(322	)	$	(52	)	$	6,073	$	837
Net income (loss)	$	65,310		$	59,786		$	4,143	$	(243,527	)
Net income (loss) per unit:
Basic	$	0.50		$	0.41		$	0.03	$	(1.64	)
Diluted	$	0.50		$	0.40		$	0.03	$	(1.64	)

⁽¹⁾  Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, bad debt, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

40