Edgar Filing: LINN ENERGY, LLC

form10qq12010.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the Quarterly Period Ended March 31, 2010

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

for the transition period from _______________ to _______________

Commission File Number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)


Delaware	65-1177591
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

600 Travis, Suite 5100 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

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

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

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

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

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

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

As of March 31, 2010, there were 147,820,443 units outstanding.

TABLE OF CONTENTS

		Page

	Glossary of Terms	ii

	Part I - Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of March 31, 2010, and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2010, and March 31, 2009	2
	Condensed Consolidated Statement of Unitholders’ Capital for the three months ended March 31, 2010	3
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2010, and March 31, 2009	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	36

	Part II - Other Information
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Reserved	38
Item 5.	Other Information	38
Item 6.	Exhibits	39

	Signature	40

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GLOSSARY OF TERMS

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

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

Bcf. One billion cubic feet.

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

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

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

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

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

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

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

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

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

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.

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

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PART I – FINANCIAL INFORMATION

Item 1.Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2010			2009
	(Unaudited)
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	16,129		$	22,231
Accounts receivable – trade, net		126,329			109,311
Derivative instruments		299,136			249,756
Other current assets		24,474			28,162
Total current assets		466,068			409,460

Noncurrent assets:
Oil and natural gas properties (successful efforts method)		4,255,310			4,076,795
Less accumulated depletion and amortization		(509,181	)		(463,413	)
		3,746,129			3,613,382

Other property and equipment		121,607			118,867
Less accumulated depreciation		(26,350	)		(23,583	)
		95,257			95,284

Derivative instruments		126,845			145,457
Other noncurrent assets		120,591			76,673
		247,436			222,130
Total noncurrent assets		4,088,822			3,930,796
Total assets	$	4,554,890		$	4,340,256

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	137,945		$	124,358
Derivative instruments		47,901			51,025
Other accrued liabilities		26,575			33,922
Total current liabilities		212,421			209,305

Noncurrent liabilities:
Credit facility		905,000			1,100,000
Senior notes, net		489,176			488,831
Derivative instruments		54,691			53,923
Other noncurrent liabilities		38,851			36,193
Total noncurrent liabilities		1,487,718			1,678,947

Unitholders’ capital:
147,820,443 units and 129,940,617 units issued and outstanding at March 31, 2010, and December 31, 2009, respectively		2,436,036			2,098,599
Accumulated income		418,715			353,405
		2,854,751			2,452,004
Total liabilities and unitholders’ capital	$	4,554,890		$	4,340,256

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	149,386		$	79,864
Gain on oil and natural gas derivatives		96,003			161,315
Natural gas marketing revenues		1,394			516
Other revenues		253			966
		247,036			242,661
Expenses:
Lease operating expenses		31,222			33,732
Transportation expenses		4,620			2,967
Natural gas marketing expenses		969			340
General and administrative expenses		24,488			23,301
Exploration costs		3,861			1,565
Bad debt expenses		189			—
Depreciation, depletion and amortization		49,191			52,104
Taxes, other than income taxes		10,200			7,567
(Gain) loss on sale of assets and other, net		(322	)		(26,711	)
		124,418			94,865
Other income and (expenses):
Interest expense, net of amounts capitalized		(27,653	)		(14,409	)
Loss on interest rate swaps		(23,162	)		(11,571	)
Other, net		(601	)		(393	)
		(51,416	)		(26,373	)
Income from continuing operations before income taxes		71,202			121,423
Income tax expense		(5,892	)		(136	)
Income from continuing operations		65,310			121,287

Discontinued operations:
Loss on sale of assets, net of taxes		—			(1,048	)
Loss from discontinued operations, net of taxes		—			(838	)
		—			(1,886	)
Net income	$	65,310		$	119,401

Income per unit – continuing operations:
Basic	$	0.50		$	1.06
Diluted	$	0.50		$	1.06
Loss per unit – discontinued operations:
Basic	$	—		$	(0.02	)
Diluted	$	—		$	(0.02	)
Net income per unit:
Basic	$	0.50		$	1.04
Diluted	$	0.50		$	1.04
Weighted average units outstanding:
Basic		129,533			113,473
Diluted		129,922			113,502

Distributions declared per unit	$	0.63		$	0.63

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL

(Unaudited)

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

December 31, 2009		129,941		$	2,098,599		$	353,405	$	―		$	2,452,004
Sale of units, net of underwriting discounts and expenses of $17,633		17,250			413,617			—		—			413,617
Issuance of units		638			434			—		—			434
Cancellation of units		(9	)		(252	)		—		252			—
Purchase of units					—			—		(252	)		(252	)
Distributions to unitholders					(82,274	)		—		—			(82,274	)
Unit-based compensation expenses					4,135			—		—			4,135
Excess tax benefit from unit-based compensation					1,777			—		—			1,777
Net income					—			65,310		—			65,310
March 31, 2010		147,820		$	2,436,036		$	418,715	$	—		$	2,854,751

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Cash flow from operating activities:
Net income	$	65,310		$	119,401
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		49,191			52,104
Unit-based compensation expenses		4,135			4,303
Bad debt expenses		189			—
Amortization and write-off of deferred financing fees and other		8,916			2,487
(Gain) loss on sale of assets, net		(3	)		(24,663	)
Deferred income tax		3,623			―
Mark-to-market on derivatives:
Total gains		(72,841	)		(149,744	)
Cash settlements		54,713			104,430
Cash settlements on canceled derivatives		―			4,257
Premiums paid for derivatives		(14,996	)		—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		(15,161	)		42,371
(Increase) decrease in other assets		1,140			(20,150	)
Increase (decrease) in accounts payable and accrued expenses		3,288			(30,020	)
Decrease in other liabilities		(7,772	)		(9,806	)
Net cash provided by operating activities		79,732			94,970

Cash flow from investing activities:
Acquisition of oil and natural gas properties		(199,539	)		—
Development of oil and natural gas properties		(22,860	)		(67,984	)
Purchases of other property and equipment		(2,089	)		(2,767	)
Proceeds from sale of properties and equipment		3			11,934
Net cash used in investing activities		(224,485	)		(58,817	)

Cash flow from financing activities:
Proceeds from sale of units		431,250			—
Proceeds from borrowings		250,000			75,000
Repayments of debt		(445,000	)		(50,000	)
Distributions to unitholders		(82,274	)		(72,538	)
Financing fees, offering expenses and other, net		(16,850	)		8,075
Excess tax benefit from unit-based compensation		1,777			—
Purchase of units		(252	)		(2,465	)
Net cash provided by (used in) financing activities		138,651			(41,928	)

Net decrease in cash and cash equivalents		(6,102	)		(5,775	)

Cash and cash equivalents:
Beginning		22,231			28,668
Ending	$	16,129		$	22,893

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	Basis of Presentation

Nature of Business

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

Principles of Consolidation and Reporting

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

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Unless otherwise indicated, information about the condensed consolidated statements of operations that is presented herein relates only to continuing operations.

Use of Estimates

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(2)	Acquisitions and Divestitures

Acquisition – 2010

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico, from certain affiliates of Merit Energy Company (“Merit”). The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $152.0 million in cash, including a deposit of $15.5 million paid in November 2009, and recorded a receivable from Merit of $1.0 million, resulting in total consideration for the acquisition of approximately $151.0 million. The transaction was financed with borrowings under the Company’s Credit Facility (as defined in Note 7). The acquisition provided strategic additions to the Company’s positions in the Permian Basin and Mid-Continent.

The Merit acquisition was accounted for under the acquisition method of accounting. Accordingly, the Company conducted an assessment 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 acquisition were expensed as incurred. The initial accounting for the business combination 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 date.

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

Assets:
Current and other assets	$	4,400
Oil and natural gas properties		156,801
Total assets acquired	$	161,201

Liabilities:
Current liabilities	$	7,932
Asset retirement obligations		2,285
Total liabilities assumed	$	10,217
Net assets acquired	$	150,984

Current and other assets include vehicles, natural gas imbalance receivables, natural gas plant and inventory of oil produced but not yet sold. Current liabilities include natural gas imbalance payables, ad valorem taxes payable and environmental liabilities.

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

Acquisitions – Pending

On March 21, 2010, the Company executed a definitive purchase and sale agreement to acquire the outstanding membership interests in two wholly owned subsidiaries of HighMount Exploration &

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Production LLC (“HighMount”) that hold oil and natural gas properties in the Antrim Shale located in northern Michigan, for a contract price of $330.0 million, subject to closing conditions. The Company paid a deposit of $33.0 million to HighMount in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010. The Company anticipates that the acquisition will close April 30, 2010, and will be financed with a portion of the net proceeds from its March 2010 public offering of units (see Note 3). The acquisition will provide the Company with a new operating region in northern Michigan.

On March 28, 2010, the Company executed a definitive purchase and sale agreement to acquire interests of Henry Savings LP and Henry Savings Management LLC (collectively referred to as “Henry”) that are primarily comprised of oil and natural gas properties located in the Permian Basin, for a contract price of $305.0 million, subject to closing conditions. The Company paid a deposit of $30.5 million to Henry in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010. The Company anticipates that the acquisition will close May 27, 2010, and will be financed with borrowings under its Credit Facility. The acquisition will increase the Company’s position in the Permian Basin.

Acquisitions – 2009

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

Divestitures

On December 4, 2008, the Company completed the sale of its deep rights in certain central Oklahoma acreage, which includes the Woodford Shale interval, to Devon Energy Production Company, LP. In the first quarter of 2009, certain post-closing matters were resolved and the Company recorded a gain of $25.4 million, which is recorded in “(gain) loss on sale of assets and other, net” on the condensed consolidated statements of operations for the three months ended March 31, 2009.

On July 1, 2008, the Company completed the sale of its interests in oil and natural gas properties located in the Appalachian Basin to XTO Energy, Inc. In addition, in March 2008, the Company exited the drilling and service business in the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic Well Service, Inc. The results of these operations have been classified as discontinued operations on the condensed consolidated statements of operations for all periods presented. Discontinued operations activity for 2009 primarily represents activity related to post-closing adjustments.

(3)	Unitholders’ Capital

Public Offering of Units

On March 29, 2010, the Company sold 17,250,000 units representing limited liability company interests at $25.00 per unit ($24.00 per unit, net of underwriting discount) for net proceeds (after underwriting discount of $17.3 million and estimated offering expenses of $0.3 million) of approximately $413.6 million. The Company intends to use a portion of the net proceeds to finance the pending acquisition from HighMount

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(see Note 2). Pending the close of the HighMount acquisition, all of the net proceeds were used to repay indebtedness under the Credit Facility.

Issuance and Cancellation of Units

During the three months ended March 31, 2010, the Company purchased 9,055 units for approximately $0.3 million, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan (see Note 6). All units were subsequently canceled.

Distributions

Under the Company’s limited liability company agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the Company during the three months ended March 31, 2010, are presented on the condensed consolidated statement of unitholders’ capital. On April 27, 2010, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the first quarter of 2010. This distribution, totaling approximately $93.2 million, will be paid on May 14, 2010, to unitholders of record as of the close of business on May 7, 2010.

(4)	Oil and Natural Gas Capitalized Costs

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

	March 31, 2010			December 31, 2009
	(in thousands)
Proved properties:
Leasehold acquisition	$	3,556,793		$	3,398,292
Development		624,810			600,436
Unproved properties		73,707			78,067
		4,255,310			4,076,795
Less accumulated depletion and amortization		(509,181	)		(463,413	)
	$	3,746,129		$	3,613,382

(5)	Business and Credit Concentrations

For the three months ended March 31, 2010, the Company’s three largest customers represented 20%, 17% and 14%, respectively, of the Company’s sales. For the three months ended March 31, 2009, the Company’s three largest customers represented 19%, 17% and 16%, respectively, of the Company’s sales.

At March 31, 2010, trade accounts receivable from three customers accounted for more than 10% of the Company’s total trade accounts receivable. At March 31, 2010, trade accounts receivable from these customers represented approximately 20%, 15% and 14%, respectively, of the Company’s receivables. At December 31, 2009, trade accounts receivable from three customers accounted for more than 10% of the Company’s total trade accounts receivable. At December 31, 2009, trade accounts receivable from these customers represented approximately 25%, 15% and 15%, respectively, of the Company’s receivables.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(6)	Unit-Based Compensation

During the three months ended March 31, 2010, the Company granted an aggregate 638,554 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $16.3 million. The restricted units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended March 31,
	2010		2009
	(in thousands)

General and administrative expenses	$	4,014	$	4,201
Lease operating expenses		121		102
Total unit-based compensation expenses	$	4,135	$	4,303
Income tax benefit	$	1,635	$	—

(7)

Debt

The following summarizes debt outstanding:

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

Credit facility	$	905		$	905		3.01	%	$	1,100		$	1,100		2.98	%
11.75% senior notes due 2017		250			285		12.73	%		250			279		12.73	%
9.875% senior notes due 2018		256			274		10.25	%		256			271		10.25	%
Less current maturities		―			―					―			―
		1,411		$	1,464					1,606		$	1,650
Unamortized discount		(17	)							(17	)
Total debt, net of discount	$	1,394							$	1,589

(1)

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

(2)

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

Credit Facility

At March 31, 2010, the Company had a borrowing base of $1.64 billion and a maturity of August 2012 under its Fourth Amended and Restated Credit Agreement (“Credit Facility”). On April 6, 2010, the Company entered into an amendment to its Credit Facility that provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015. In connection with the amendment to its Credit Facility, the Company incurred financing fees and expenses of approximately $14.8 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

consolidated statements of operations. At March 31, 2010, available borrowing capacity was $732.6 million, which includes a $4.9 million reduction in availability for outstanding letters of credit. Subsequent to the Credit Facility amendment and the issuance of the 2020 Notes (as defined below), at April 15, 2010, the Company had approximately $1.37 billion in available borrowing capacity under its Credit Facility, a portion of which the Company anticipates using to fund pending acquisitions (see Note 2).

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

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

Senior Notes Due 2017 and Senior Notes Due 2018

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

Senior Notes Due 2020

On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (“2020 Notes”) at a price of 97.552%. The 2020 Notes were offered and sold to a group of initial purchasers (“Initial Purchasers”) and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds (after deducting the Initial Purchasers’ discounts and estimated offering expenses) of approximately $1.24 billion. The Company used the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility. The excess will be used to fund or partially fund acquisitions and for general corporate purposes. In connection with the 2020 Notes, the Company incurred financing fees and estimated expenses of approximately $26.6 million, which will be amortized over the life of the 2020 Notes. The $31.8 million discount on the 2020 Notes will also be amortized over the life of the 2020 Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

The 2020 Notes were issued under an Indenture dated April 6, 2010, (“Indenture”), mature April 15, 2020, and bear interest at 8.625%. Interest is payable semi-annually beginning October 15, 2010. The 2020 Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries have guaranteed the 2020 Notes on a senior

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

unsecured basis. The Indenture provides that the Company may redeem: (i) on or prior to April 15, 2013, up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 108.625% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to April 15, 2015, all or part of the 2020 Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the Indenture) and accrued and unpaid interest; and (iii) on or after April 15, 2015, all or part of the 2020 Notes at redemption prices equal to 104.313% in 2015, 102.875% in 2016, 101.438% in 2017 and 100% in 2018 and thereafter, in each case, of the principal amount redeemed, plus accrued and unpaid interest. The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2020 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2020 Notes’ Indenture contains covenants substantially similar to those under the Company’s 11.75% senior notes due 2017 and 9.875% senior notes due 2018 that, among other things, limit the Company’s ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of the 2020 Notes.

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

(8)	Derivatives

Commodity Derivatives

The Company sells oil, natural gas and NGL in the normal course of its business and utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company enters into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. Oil puts are also used to economically hedge NGL sales. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 9 for fair value disclosures about oil and natural gas commodity derivatives.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	March 31 – December 31, 2010			2011			2012			2013			2014		2015
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		29,674			31,901			18,300			18,250			18,250		18,250
Average price ($/MMBtu)	$	8.90		$	9.50		$	6.37		$	6.37		$	6.37	$	6.37
Puts:
Hedged volume (MMMBtu)		5,220			6,960			7,064			7,045			—		—
Average price ($/MMBtu)	$	8.50		$	9.50		$	6.25		$	6.25		$	—	$	—
PEPL puts: (1)
Hedged volume (MMMBtu)		7,976			13,259			—			—			—		—
Average price ($/MMBtu)	$	7.85		$	8.50		$	—		$	—		$	—	$	—
Total:
Hedged volume (MMMBtu)		42,870			52,120			25,364			25,295			18,250		18,250
Average price ($/MMBtu)	$	8.66		$	9.25		$	6.33		$	6.33		$	6.37	$	6.37

Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)		1,613			2,073			3,020			3,011			—		—
Average price ($/Bbl)	$	90.00		$	90.00		$	100.00		$	100.00		$	—	$	—
Puts: (3)
Hedged volume (MBbls)		1,687			2,352			—			—			—		—
Average price ($/Bbl)	$	110.00		$	75.00		$	—		$	—		$	—	$	—
Collars:
Hedged volume (MBbls)		187			276			—			—			—		—
Average floor price ($/Bbl)	$	90.00		$	90.00		$	—		$	—		$	—	$	—
Average ceiling price ($/Bbl)	$	112.00		$	112.25		$	—		$	—		$	—	$	—
Total:
Hedged volume (MBbls)		3,487			4,701			3,020			3,011			—		—
Average price ($/Bbl)	$	99.68		$	82.50		$	100.00		$	100.00		$	—	$	—

Natural gas basis differential positions:
PEPL basis swaps: (1)
Hedged volume (MMMBtu)		32,374			35,541			34,066			31,700			—		—
Hedged differential ($/MMBtu)	$	(0.97	)	$	(0.96	)	$	(0.95	)	$	(1.01	)	$	—	$	—

(1)

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

(2)

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

(3)

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

Settled derivatives on natural gas production for the three months ended March 31, 2010, included a volume of 14,290 MMMBtu at an average contract price of $8.66 per MMBtu. Settled derivatives on oil and NGL production for the three months ended March 31, 2010, included a volume of 1,162 MBbls at an average contract price of $99.68 per Bbl. The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or on the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month. The oil derivatives are settled based on the month’s average daily NYMEX price of light oil and settlement occurs on the final day of the production month.

Interest Rate Swaps

The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparty the difference, and conversely, the counterparty is required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not designate the interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 9 for fair value disclosures about interest rate swaps.

The following presents the settlement terms of the interest rate swaps at March 31, 2010:

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

Notional amount	$	1,212,000		$	1,212,000		$	1,212,000		$	1,212,000
Fixed rate		3.85	%		3.85	%		3.85	%		3.85	%

(1)

Actual settlement term is through January 6, 2014.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Balance Sheet Presentation

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

	March 31, 2010		December 31, 2009
	(in thousands)
Assets:
Commodity derivatives	$	674,848	$	549,879
Interest rate swaps		1,209		2,603
	$	676,057	$	552,482
Liabilities:
Commodity derivatives	$	272,341	$	192,573
Interest rate swaps		80,327		69,644
	$	352,668	$	262,217

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current or former participants or affiliates of current or former participants in its Credit Facility (see Note 7), which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $676.1 million at March 31, 2010. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated.

Gain (Loss) on Derivatives

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	62,503		$	119,812
Interest rate swaps		(8,021	)		(10,114	)
Canceled derivatives		—			4,257
	$	54,482		$	113,955
Unrealized gains (losses):
Commodity derivatives	$	33,500		$	37,246
Interest rate swaps		(15,141	)		(1,457	)
	$	18,359		$	35,789
Total gains (losses):
Commodity derivatives	$	96,003		$	161,315
Interest rate swaps		(23,162	)		(11,571	)
	$	72,841		$	149,744

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

(9)	Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity and interest rate derivatives at fair value (see Note 8) on a recurring basis. The fair value of derivative instruments is determined utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity and interest rate derivatives.

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

	March 31, 2010
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	674,848	$	(248,867	)	$	425,981
Interest rate swaps	$	1,209	$	(1,209	)	$	—

Liabilities:
Commodity derivatives	$	272,341	$	(248,867	)	$	23,474
Interest rate swaps	$	80,327	$	(1,209	)	$	79,118

(1)

Represents counterparty netting under agreements governing such derivatives.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

(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 condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligation liability is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the three months ended March 31, 2010); and (iv) a credit-adjusted risk-free interest rate (average of 8.4% for the three months ended March 31, 2010).

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

Asset retirement obligations at December 31, 2009	$	33,135
Liabilities added from acquisitions		2,285
Liabilities added from drilling		42
Current year accretion expense		597
Settlements		(94	)
Asset retirement obligations at March 31, 2010	$	35,965

(11)	Commitments and Contingencies

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

(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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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	Income (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Three months ended March 31, 2010:
Income from continuing operations:
Allocated to units	$	65,310
Allocated to unvested restricted units		(750	)
	$	64,560
Income per unit:
Basic income per unit					129,533	$	0.50
Dilutive effect of unit equivalents					389		—
Diluted income per unit					129,922	$	0.50

Three months ended March 31, 2009:
Income from continuing operations:
Allocated to units	$	121,287
Allocated to unvested restricted units		(1,485	)
	$	119,802
Income per unit:
Basic income per unit					113,473	$	1.06
Dilutive effect of unit equivalents					29		—
Diluted income per unit					113,502	$	1.06

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 0.6 million and 2.0 million unit options and warrants for the three months ended March 31, 2010, and March 31, 2009, respectively.

(13)	Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders. As such, with the exception of the state of Texas, 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. Limited liability companies are subject to state income taxes in Texas and certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Amounts recognized for these taxes are reported in “income tax expense” on the condensed consolidated statements of operations.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

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

	March 31, 2010		December 31, 2009
	(in thousands)

Accrued compensation	$	5,941	$	14,378
Accrued interest		19,263		18,332
Other		1,371		1,212
	$	26,575	$	33,922

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

	Three Months Ended March 31,
	2010			2009
	(in thousands)

Cash payments for interest, net of amounts capitalized	$	21,653		$	20,610
Cash payments for income taxes	$	563		$	1
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	145,911		$	—
Cash paid		(136,039	)		—
Receivable from seller		337			—
Liabilities assumed	$	10,209		$	—

“Acquisition of oil and natural gas properties” presented on the condensed consolidated statements of cash flows includes deposits paid of approximately $63.5 million for pending acquisitions (see Note 2).

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of $2.3 million and $2.1 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010, and December 31, 2009, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

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

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

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

Executive Overview

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

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

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

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

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

Results for the three months ended March 31, 2010, included the following:

oil, natural gas and NGL sales of approximately $149.4 million, compared to $79.9 million in the first quarter of 2009;

average daily production of 213 MMcfe/d, compared to 217 MMcfe/d in the first quarter of 2009;

realized gains on commodity derivatives of approximately $62.5 million, compared to $124.1 million in the first quarter of 2009;

adjusted EBITDA of $151.5 million, compared to $138.2 million in the first quarter of 2009;

adjusted net income of $47.4 million, compared to $55.5 million in the first quarter of 2009;

capital expenditures, excluding acquisitions, of approximately $27.1 million, compared to $73.3 million in the first quarter of 2009; and

13 wells drilled (all successful), compared to 41 wells drilled (40 successful) in the first quarter of 2009.

Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions. The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives and depreciation, depletion and amortization. Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gain) loss on derivatives, realized (gain) loss on canceled derivatives, impairment of goodwill and long-lived assets and (gain)

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Item 2.

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

loss on sale of assets, net. See “Non-GAAP Financial Measures” on page 31 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Acquisitions

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico from Merit for total consideration of approximately $151.0 million. The acquisition was financed with borrowings under the Company’s Credit Facility. The acquisition provided strategic additions to the Company’s positions in the Permian Basin and Mid-Continent, and included approximately 12 MMBoe (73 Bcfe) of proved reserves as of the acquisition date, estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. The majority of the reserves were oil reserves. See Note 2 for additional details.

On March 21, 2010, the Company executed a definitive purchase and sale agreement to acquire the outstanding membership interests in two wholly owned subsidiaries of HighMount that hold oil and natural gas properties in the Antrim Shale located in northern Michigan, for a contract price of $330.0 million, subject to closing conditions. The Company paid a deposit of $33.0 million to HighMount in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010. The Company anticipates that the acquisition will close April 30, 2010, and will be financed with net proceeds from its March 2010 public offering of units (see Note 3). The acquisition will provide the Company with a new operating region in northern Michigan and includes approximately 238 Bcfe of proved reserves as of the acquisition date, estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. Proved reserves as of the effective date, March 1, 2010, estimated using forward strip oil and natural gas prices, were 266 Bcfe. The majority of the reserves are natural gas reserves.

On March 28, 2010, the Company executed a definitive purchase and sale agreement to acquire interests of Henry that are primarily comprised of oil and natural gas properties located in the Permian Basin, for a contract price of $305.0 million, subject to closing conditions. The Company paid a deposit of $30.5 million to Henry in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010. The Company anticipates that the acquisition will close May 27, 2010, and will be financed with borrowings under its Credit Facility. The acquisition will significantly increase the Company’s positions in the Permian Basin and includes approximately 17 MMBoe (102 Bcfe) of proved reserves as of the acquisition date, estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month. Proved reserves as of the effective date, April 1, 2010, estimated using forward strip oil and natural gas prices, were 18 MMBoe (108 Bcfe). The majority of the reserves are oil reserves.

Commodity Derivatives

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

In April 2010, the Company entered into commodity derivative contracts, consisting of oil and natural gas swaps and puts for 2011 through 2015, and paid premiums of approximately $76.0 million. At April 15, 2010, the Company had derivative contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and $83.46 per Bbl for oil and $8.66 per MMBtu and $9.25 per MMBtu for natural gas, respectively. Additionally, the Company has derivative contracts in place covering substantially all of its exposure to the Mid-Continent natural gas basis differential through 2013.

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Item 2.

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

The following table summarizes open positions as of April 15, 2010, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:

	April 15 – December 31, 2010			2011			2012			2013			2014		2015
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		26,377			31,901			31,110			31,025			31,025		31,025
Average price ($/MMBtu)	$	8.90		$	9.50		$	6.25		$	6.25		$	6.25	$	6.25
Puts:
Hedged volume (MMMBtu)		4,640			6,960			25,364			25,295			—		—
Average price ($/MMBtu)	$	8.50		$	9.50		$	6.25		$	6.25		$	—	$	—
PEPL puts: (1)
Hedged volume (MMMBtu)		7,089			13,259			—			—			—		—
Average price ($/MMBtu)	$	7.85		$	8.50		$	—		$	—		$	—	$	—
Total:
Hedged volume (MMMBtu)		38,106			52,120			56,474			56,320			31,025		31,025
Average price ($/MMBtu)	$	8.66		$	9.25		$	6.25		$	6.25		$	6.25	$	6.25

Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)		1,613			2,803			3,386			3,376			—		—
Average price ($/Bbl)	$	90.00		$	89.91		$	98.92		$	98.92		$	—	$	—
Puts: (3)
Hedged volume (MBbls)		1,687			2,352			2,196			2,190			—		—
Average price ($/Bbl)	$	110.00		$	75.00		$	75.00		$	75.00		$	—	$	—
Collars:
Hedged volume (MBbls)		187			276			—			—			—		—
Average floor price ($/Bbl)	$	90.00		$	90.00		$	—		$	—		$	—	$	—
Average ceiling price ($/Bbl)	$	112.00		$	112.25		$	—		$	—		$	—	$	—
Total:
Hedged volume (MBbls)		3,487			5,431			5,582			5,566			—		—
Average price ($/Bbl)	$	99.68		$	83.46		$	89.51		$	89.51		$	—	$	—

Natural gas basis differential positions:
PEPL basis swaps: (1)
Hedged volume (MMMBtu)		28,777			35,541			34,066			31,700			—		—
Hedged differential ($/MMBtu)	$	(0.97	)	$	(0.96	)	$	(0.95	)	$	(1.01	)	$	—	$	—

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

(2)

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

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Item 2.

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

Interest Rate Swap Restructuring

In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of 2020 Notes (see Note 7). The Company canceled (before the contract settlement date) all of its interest rate swap agreements for the remainder of 2010, resulting in realized losses of approximately $35.6 million. In the second quarter of 2010, the Company expects to restructure its interest rate swap portfolio for 2011, 2012 and 2013 based on the balance outstanding under its Credit Facility after closing pending acquisitions (see Note 2).

The following presents the settlement terms of the interest rate swaps at April 15, 2010:

	2011			2012			2013 (1)
	(dollars in thousands)

Notional amount	$	1,212,000		$	1,212,000		$	1,212,000
Fixed rate		3.85	%		3.85	%		3.85	%

(1)	Actual settlement term is through January 6, 2014.

Financing and Liquidity

The Company recently took steps to further strengthen its liquidity and extend its weighted average debt maturities. On April 6, 2010, the Company entered into an amendment to its Credit Facility, which provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015. The Company expects the borrowing base under its Credit Facility to increase to $1.50 billion in the second quarter of 2010 as a result of the anticipated increased value of its oil and natural gas reserves after closing pending acquisitions (see Note 2). On April 6, 2010, the Company also issued $1.30 billion in aggregate principal of 8.625% senior notes due 2020 and used the net proceeds of approximately $1.24 billion to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility. The excess will be used to fund or partially fund acquisitions and for general corporate purposes. In addition, on March 29, 2010, the Company completed a public offering of units for net proceeds of approximately $413.6 million, a portion of which the Company intends to use to finance the pending acquisition from HighMount. At April 15, 2010, the Company had approximately $1.37 billion in available borrowing capacity under its Credit Facility, a portion of which the Company anticipates using to fund pending acquisitions.

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Item 2.

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

Results of Operations – Continuing Operations

Three Months Ended March 31, 2010, Compared to Three Months Ended March 31, 2009

	Three Months Ended March 31,
	2010			2009			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	52,862		$	42,228		$	10,634
Oil sales		65,940			26,770			39,170
NGL sales		30,584			10,866			19,718
Total oil, natural gas and NGL sales		149,386			79,864			69,522
Gain on oil and natural gas derivatives		96,003			161,315			(65,312	)
Natural gas marketing revenues		1,394			516			878
Other revenues		253			966			(713	)
	$	247,036		$	242,661		$	4,375
Expenses:
Lease operating expenses	$	31,222		$	33,732		$	(2,510	)
Transportation expenses		4,620			2,967			1,653
Natural gas marketing expenses		969			340			629
General and administrative expenses (1)		24,488			23,301			1,187
Exploration costs		3,861			1,565			2,296
Bad debt expenses		189			—			189
Depreciation, depletion and amortization		49,191			52,104			(2,913	)
Taxes, other than income taxes		10,200			7,567			2,633
(Gain) loss on sale of assets and other, net		(322	)		(26,711	)		26,389
	$	124,418		$	94,865		$	29,553
Other income and (expenses)	$	(51,416	)	$	(26,373	)	$	(25,043	)
Income from continuing operations before income taxes	$	71,202		$	121,423		$	(50,221	)

Adjusted EBITDA (2)	$	151,509		$	138,161		$	13,348
Adjusted net income (2)	$	47,365		$	55,530		$	(8,165	)

(1)	General and administrative expenses for the three months ended March 31, 2010, and March 31, 2009, include approximately $4.0 million and $4.2 million, respectively, of noncash unit-based compensation expenses.

(2)	This is a non-GAAP measure used by management to analyze Company performance. See “Non-GAAP Financial Measures” on page 31 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

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Item 2.

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

	Three Months Ended March 31,
	2010		2009		Variance
Average daily production:
Natural gas (MMcf/d)		110		133		(17	)%
Oil (MBbls/d)		9.8		8.8		11	%
NGL (MBbls/d)		7.5		5.2		44	%
Total (MMcfe/d)		213		217		(2	)%

Weighted average prices (hedged): (1)
Natural gas (Mcf)	$	9.21	$	7.94		16	%
Oil (Bbl)	$	102.39	$	118.19		(13	)%
NGL (Bbl)	$	45.51	$	23.32		95	%

Weighted average prices (unhedged): (2)
Natural gas (Mcf)	$	5.35	$	3.53		52	%
Oil (Bbl)	$	74.76	$	33.76		121	%
NGL (Bbl)	$	45.51	$	23.32		95	%

Average NYMEX prices:
Natural gas (MMBtu)	$	5.30	$	4.91		8	%
Oil (Bbl)	$	78.72	$	43.08		83	%

Costs per Mcfe of production:
Lease operating expenses	$	1.63	$	1.73		(6	)%
Transportation expenses	$	0.24	$	0.15		60	%
General and administrative expenses (3)	$	1.28	$	1.19		8	%
Depreciation, depletion and amortization	$	2.56	$	2.67		(4	)%
Taxes, other than income taxes	$	0.53	$	0.39		36	%

(1)

Includes the effect of realized gains on derivatives of approximately $62.5 million and $119.8 million (excluding $4.3 million realized gains on canceled contracts) for the three months ended March 31, 2010, and March 31, 2009, respectively. The Company utilizes oil puts to hedge revenues associated with its NGL production; therefore, all realized gains (losses) on oil derivative contracts are included in weighted average oil prices, rather than weighted average NGL prices.

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

(3)

General and administrative expenses for the three months ended March 31, 2010, and March 31, 2009, include approximately $4.0 million and $4.2 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the three months ended March 31, 2010, and March 31, 2009, were $1.07 per Mcfe and $0.98 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company’s performance.

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Item 2.

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $69.5 million, or 87%, to approximately $149.4 million for the three months ended March 31, 2010, from $79.9 million for the three months ended March 31, 2009, due to higher commodity prices. Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $36.2 million, $18.0 million and $14.9 million, respectively.

Average daily production decreased to 213 MMcfe/d during the three months ended March 31, 2010, from 217 MMcfe/d during the three months ended March 31, 2009. Natural gas volume decreases during the three months ended March 31, 2010, resulted in a decrease in natural gas revenues of approximately $7.4 million compared to the three months ended March 31, 2009. Oil and NGL volume increases during the three months ended March 31, 2010, resulted in an increase in oil and NGL revenues of approximately $7.8 million compared to the three months ended March 31, 2009.

	Three Months Ended March 31,
	2010		2009		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		124		142		(18	)	(13	)%
Mid-Continent Shallow		64		61		3		5	%
California		13		14		(1	)	(7	)%
Permian Basin		12		—		12		—
		213		217		(4	)	(2	)%

The 13% decrease in average daily production in the Mid-Continent Deep region primarily reflects natural decline as the three months ended March 31, 2009, benefited from the impact of the Company’s 2008 capital drilling program in the Granite Wash. In addition, weather-related downtime, partially offset by improvements in processing agreement terms, contributed to the decrease in production. The 5% increase in average daily production in the Mid-Continent Shallow region reflects results of the Company’s drilling and optimization programs, partially offset by natural declines. Permian Basin properties were acquired in the first quarter of 2010 and the third quarter of 2009 (see Note 2).

Gain (Loss) on Oil and Natural Gas Derivatives

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk,” Note 8 and Note 9 for additional information about commodity derivatives. During the three months ended March 31, 2010, the Company had commodity derivative contracts for approximately 145% of its natural gas production and 75% of its oil and NGL production, which resulted in realized gains of approximately $62.5 million. During the three months ended March 31, 2009, the Company recorded realized gains of approximately $124.1 million (including realized gains on canceled contracts of approximately $4.3 million). Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives. During the first quarter of 2010 and 2009, expected future oil and natural gas prices decreased, which resulted in unrealized gains on derivatives of approximately $33.5 million and $37.2 million for the three months ended March 31, 2010, and March 31, 2009, respectively. For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

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Item 2.

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

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses decreased by approximately $2.5 million, or 7%, to $31.2 million for the three months ended March 31, 2010, from $33.7 million for the three months ended March 31, 2009. Lease operating expenses per Mcfe also decreased, to $1.63 per Mcfe for the three months ended March 31, 2010, from $1.73 per Mcfe for the three months ended March 31, 2009. Lease operating expenses decreased primarily due to service cost decreases across all operating regions. In addition, the three months ended March 31, 2010, include the receipt of insurance proceeds as reimbursement for costs incurred related to California wildfires in 2008 and an adjustment to transportation rates associated with owned facilities.

Transportation Expenses

Transportation expenses increased by approximately $1.6 million, or 53%, to $4.6 million for the three months ended March 31, 2010, from $3.0 million for the three months ended March 31, 2009, primarily due to increased expenses on nonoperated properties and an adjustment to transportation rates associated with owned facilities.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees and executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $1.2 million, or 5%, to $24.5 million for the three months ended March 31, 2010, from $23.3 million for the three months ended March 31, 2009. General and administrative expenses per Mcfe also increased, to $1.28 per Mcfe for the three months ended March 31, 2010, from $1.19 per Mcfe for the three months ended March 31, 2009. The increase was primarily due to an increase in salaries and benefits expense of approximately $2.2 million, driven primarily by increased employee headcount, and acquisition integration expense of approximately $0.7 million. These increases were partially offset by a decrease in professional service fees.

Exploration Costs

Exploration costs increased by approximately $2.3 million, or 144%, to $3.9 million for the three months ended March 31, 2010, from $1.6 million for the three months ended March 31, 2009. The increase was primarily due to an increase in impairment expense on unproved properties of approximately $2.3 million.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $2.9 million, or 6%, to $49.2 million for the three months ended March 31, 2010, from $52.1 million for the three months ended March 31, 2009. Depreciation, depletion and amortization per Mcfe also decreased to $2.56 per Mcfe for the three months ended March 31, 2010, from $2.67 per Mcfe for the three months ended March 31, 2009. Lower total production levels and lower depletion rates associated with upward year-end oil price-related reserve revisions were the main reasons for the decrease.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, increased by approximately $2.6 million, or 34%, to $10.2 million for the three months ended March 31, 2010, from $7.6 million for the three months ended March 31, 2009. Production taxes, which are a function of revenues generated from production, increased by approximately $2.7 million compared to the three months ended March 31, 2009, primarily due to higher commodity prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased slightly compared to the three months ended March 31, 2009.

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

The Company recorded a gain of approximately $25.4 million from the sale of Woodford Shale assets during the three months ended March 31, 2009, (see Note 2).

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Item 2.

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

Other Income and (Expenses)

	Three Months Ended March 31,
	2010			2009			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(27,653	)	$	(14,409	)	$	(13,244	)
Realized loss on interest rate swaps		(8,021	)		(10,114	)		2,093
Unrealized loss on interest rate swaps		(15,141	)		(1,457	)		(13,684	)
Other, net		(601	)		(393	)		(208	)
	$	(51,416	)	$	(26,373	)	$	(25,043	)

Other income and (expenses) increased by approximately $25.0 million during the three months ended March 31, 2010, compared to the three months ended March 31, 2009, primarily due to increased interest expense resulting from higher interest rates and amortization of financing fees, combined with an increase in unrealized loss on interest rate swaps. The unrealized mark-to-market loss on interest rate swaps increased as the forward curve decreased during the three months ended March 31, 2010, as compared to the three months ended March 31, 2009. This was partially offset by a decrease in realized loss on interest rate swaps during the three months ended March 31, 2010, compared to the three months ended March 31, 2009.

In April 2010, the Company issued $1.30 billion in aggregate principal of 8.625% senior notes due 2020 and used the net proceeds of approximately $1.24 billion to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility. The excess will be used to fund or partially fund acquisitions and for general corporate purposes. Due to the higher interest rate on the 2020 Notes as compared to its Credit Facility, the Company expects interest expense to increase.

Income Tax Expense

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to state income taxes in Texas. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $5.9 million and $0.1 million for the three months ended March 31, 2010, and March 31, 2009, respectively. Income tax expense increased during the three months ended March 31, 2010, primarily due to the timing of tax deductions for unit-based compensation and the partial release of the valuation allowance during the fourth quarter of 2009.

Income From Continuing Operations

Income from continuing operations decreased by approximately $56.0 million, or 46%, to $65.3 million for the three months ended March 31, 2010, from $121.3 million for the three months ended March 31, 2009. Total expenses increased during the three months ended March 31, 2010, primarily as a gain of approximately $25.4 million from the sale of Woodford Shale assets reduced total expenses during the three months ended March 31, 2009, with no comparable item during the three months ended March 31, 2010. In addition, interest expense and unrealized loss on interest rate swaps increased during the three months ended March 31, 2010, compared to the three months ended March 31, 2009, and contributed to the decrease in income from continuing operations.

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Item 2.

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

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $13.3 million, or 10%, to $151.5 million for the three months ended March 31, 2010, from $138.2 million for the three months ended March 31, 2009, primarily due to production revenues resulting from higher oil, natural gas and NGL prices, partially offset by lower realized gains on commodity derivatives. See “Non-GAAP Financial Measures” on page 31 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Liquidity and Capital Resources

The Company utilizes funds from equity and debt offerings, bank borrowings and cash generated from operations for capital resources and liquidity. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties. For the three months ended March 31, 2010, the Company’s capital expenditures, excluding acquisitions, were approximately $27.1 million. For 2010, the Company estimates its capital expenditures, excluding acquisitions, will be approximately $200.0 million. This estimate reflects amounts for the development of properties associated with pending acquisitions (see Note 2) and is under continuous review and subject to ongoing adjustment. The Company expects to fund these capital expenditures primarily with cash flow from operations.

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

Statements of Cash Flows

The following is a comparative cash flow summary:

	Three Months Ended March 31,
	2010			2009			Variance
	(in thousands)
Net cash:
Provided by operating activities (1)	$	79,732		$	94,970		$	(15,238	)
Used in investing activities		(224,485	)		(58,817	)		(165,668	)
Provided by (used in) financing activities		138,651			(41,928	)		180,579
Net decrease in cash and cash equivalents	$	(6,102	)	$	(5,775	)	$	(327	)

(1)	The three months ended March 31, 2010, includes premiums paid for derivatives of approximately $15.0 million.

Operating Activities

Cash provided by operating activities for the three months ended March 31, 2010, was approximately $79.7 million, compared to $95.0 million for the three months ended March 31, 2009. The decrease was primarily due to approximately $15.0 million in premiums paid for derivative contracts during the three months ended March 31, 2010.

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Item 2.

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

Premiums paid were for commodity derivative contracts that hedge future production. These derivative contracts provide the Company long-term cash flow predictability to manage its business, service debt and pay distributions and are primarily funded through the Company’s Credit Facility. The amount of derivative contracts the Company enters into in the future will be directly related to expected future production. See Note 8 and Note 9 for additional details about commodity derivatives.

Investing Activities

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

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties	$	(199,539	)	$	—
Capital expenditures		(24,949	)		(70,751	)
Proceeds from sale of properties and equipment		3			11,934
	$	(224,485	)	$	(58,817	)

The primary use of cash in investing activities is for capital spending, which is offset by proceeds from asset sales. Cash used in investing activities for the three months ended March 31, 2010, includes approximately $136.6 million for the acquisition of properties in the Permian Basin and Mid-Continent and deposits paid of approximately $63.5 million for pending acquisitions. See Note 2 for additional details.

Financing Activities

Cash provided by financing activities was approximately $138.7 million for the three months ended March 31, 2010, compared to cash used in financing activities of $41.9 million for the three months ended March 31, 2009. The increase in financing cash flow was primarily attributable to proceeds from the Company’s March 2010 offering of units (see below), partially offset by increased borrowings to fund acquisitions. The following provides a comparative summary of proceeds from borrowings and repayments of debt:

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Proceeds from borrowings:
Credit facility	$	250,000		$	75,000

Repayments of debt:
Credit facility	$	(445,000	)	$	(50,000	)

Debt

On April 6, 2010, the Company entered into an amendment to its Credit Facility, which provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015. In addition, on April 6, 2010, the Company issued $1.30 billion in aggregate principal of 8.625% senior notes due 2020 and received net proceeds of approximately $1.24 billion. The Company used the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility. The excess will be used to fund or partially fund acquisitions and for general corporate purposes. At April 15, 2010, the Company had approximately $1.37 billion in available borrowing capacity under its Credit Facility, a portion of which the Company anticipates

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Item 2.

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

using to fund pending acquisitions. The Company also has outstanding $250.0 million in aggregate principal amount of 11.75% senior notes due 2017, $255.9 million in aggregate principal amount of 9.875% senior notes due 2018 and $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020. For additional information about the Company’s debt instruments, such as interest rates and covenants, see Note 7. The Company is in compliance with all financial and other covenants of the Credit Facility and senior notes.

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

Counterparty Credit Risk

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

Public Offering of Units

Distributions

Under the Company’s limited liability company agreement, unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. The following provides a summary of distributions paid by the Company during the three months ended March 31, 2010:

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

February 2010	October 1 – December 31, 2009	$	0.63	$	82.3

On April 27, 2010, the Company’s Board of Directors declared a cash distribution of $0.63 per unit, or $2.52 per unit on an annualized basis, with respect to the first quarter of 2010. This distribution, totaling approximately $93.2 million, will be paid on May 14, 2010, to unitholders of record as of the close of business on May 7, 2010.

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Item 2.

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

Off-Balance Sheet Arrangements

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

Contingencies

During the three months ended March 31, 2010, and March 31, 2009, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in a table of contractual obligations in the 2009 Annual Report on Form 10-K. With the exception of: (i) an amendment to the Company’s Credit Facility that provides a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015; and (ii) the issuance of $1.30 billion in aggregate principal of 8.625% senior notes due 2020, there have been no significant changes to the Company’s contractual obligations from December 31, 2009. See Note 7 for additional information about the Company’s debt instruments.

Non-GAAP Financial Measures

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

Adjusted EBITDA (Non-GAAP Measure)

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

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

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

Interest expense;

Depreciation, depletion and amortization;

Impairment of goodwill and long-lived assets;

Write-off of deferred financing fees and other;

(Gain) loss on sale of assets, net;

Unrealized (gain) loss on commodity derivatives;

Unrealized (gain) loss on interest rate derivatives;

Realized (gain) loss on interest rate derivatives;

Realized (gain) loss on canceled derivatives;

Unit-based compensation expenses;

Exploration costs; and

Income tax (benefit) expense.

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Item 2.

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

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

	Three Months Ended March 31,
	2010			2009
	(in thousands)

Income from continuing operations	$	65,310		$	121,287
Plus:
Net operating cash flow from acquisitions and divestitures, effective date through closing date		5,391			—
Interest expense, cash		21,752			20,610
Interest expense, noncash		5,901			(6,201	)
Depreciation, depletion and amortization		49,191			52,104
(Gain) loss on sale of assets, net		414			(25,711	)
Unrealized gain on commodity derivatives		(33,500	)		(37,246	)
Unrealized loss on interest rate derivatives		15,141			1,457
Realized loss on interest rate derivatives		8,021			10,114
Realized gain on canceled derivatives		—			(4,257	)
Unit-based compensation expenses		4,135			4,303
Exploration costs		3,861			1,565
Income tax expense		5,892			136
Adjusted EBITDA from continuing operations	$	151,509		$	138,161

Net cash provided by operating activities for the three months ended March 31, 2010, was approximately $79.7 million and includes cash interest payments of approximately $21.7 million, cash settlements on interest rate derivatives of approximately $11.1 million, premiums paid for commodity derivatives of approximately $15.0 million and other items totaling approximately $24.0 million that are not included in adjusted EBITDA. Net cash provided by operating activities for the three months ended March 31, 2009, was approximately $95.0 million and includes cash interest payments of approximately $20.6 million, cash settlements on interest rate derivatives of approximately $9.0 million, realized gains on canceled derivatives of approximately $(4.3) million and other items totaling approximately $17.9 million that are not included in adjusted EBITDA.

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Item 2.

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

Adjusted Net Income (Non-GAAP Measure)

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

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

	Three Months Ended March 31,
	2010			2009
	(in thousands, except per unit amounts)

Income from continuing operations	$	65,310		$	121,287
Plus:
Unrealized gain on commodity derivatives		(33,500	)		(37,246	)
Unrealized loss on interest rate derivatives		15,141			1,457
Realized gain on canceled derivatives		—			(4,257	)
(Gain) loss on sale of assets, net		414			(25,711	)
Adjusted net income from continuing operations	$	47,365		$	55,530

Income from continuing operations per unit – basic	$	0.50		$	1.06
Plus, per unit:
Unrealized gain on commodity derivatives		(0.26	)		(0.33	)
Unrealized loss on interest rate derivatives		0.12			0.01
Realized gain on canceled derivatives		—			(0.04	)
(Gain) loss on sale of assets, net		—			(0.22	)
Adjusted net income from continuing operations per unit – basic	$	0.36		$	0.48

Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards Not Yet Adopted

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

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Item 2.

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

Cautionary Statement

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

business strategy;

acquisition strategy;

financial strategy;

drilling locations;

oil, natural gas and NGL reserves;

realized oil, natural gas and NGL prices;

production volumes;

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

future operating results; and

plans, objectives, expectations and intentions.

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

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Commodity Price Risk

The Company enters into derivative contracts with respect to a portion of its projected production through various transactions that provide an economic hedge of the risk related to the future prices received. The Company does not enter into derivative contracts for trading purposes (see Note 8). At March 31, 2010, the fair value of contracts that settle during the next 12 months was an asset of approximately $272.6 million and a liability of $7.9 million for a net asset of approximately $264.7 million. A 10% increase in the index oil and natural gas prices above the March 31, 2010, prices for the next 12 months would result in a net asset of approximately $189.4 million which represents a decrease in the fair value of approximately $75.3 million; conversely, a 10% decrease in the index oil and natural gas prices would result in a net asset of approximately $341.8 million which represents an increase in the fair value of approximately $77.1 million.

Interest Rate Risk

At March 31, 2010, the Company had long-term debt outstanding under its Credit Facility of approximately $905.0 million, which incurred interest at floating rates (see Note 7). A 1% increase in LIBOR would result in an estimated $9.1 million increase in annual interest expense. The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates (see Note 8).

Counterparty Credit Risk

The Company accounts for its commodity and interest rate derivatives at fair value on a recurring basis (see Note 9). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.

At March 31, 2010, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 3.72%. A 1% increase in the average public bond yield spread would result in an estimated $2.1 million increase in net income for the three months ended March 31, 2010. At March 31, 2010, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 1.62%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $1.4 million decrease in net income for the three months ended March 31, 2010.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2010.

Changes in the Company’s Internal Control Over Financial Reporting

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

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

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

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

General

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

Environmental

The Company expects to enter into a settlement agreement with the South Coast Air Quality Management District under which the Company anticipates it will pay penalties and fees for improper natural gas flaring under its current permit. The Company has not been cited for violation of emission standards associated with this activity and it is taking appropriate steps to remedy the situation. The Company estimates that total penalties associated with this matter will be approximately $100,000 and it has accrued this amount at March 31, 2010. The Company does not expect this matter to have a material adverse impact on its financial condition or results of operations.

Item 1A. Risk Factors

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

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

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

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

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

Issuer Purchases of Equity Securities

The following sets forth information with respect to the Company’s repurchases of its units during the first quarter of 2010:

Period

Total Number

of Units

Purchased

Average Price

Paid Per Unit

Total Number of Units

Purchased as Part of

Publicly Announced

Plans or Programs

Approximate Dollar

Value of Units that

May Yet be Purchased

Under the Plans or

Programs (2)

(in millions)

January 1 – 31 (1)

9,055

27.88

―

85.4

(1)	The units purchased were related to units received by the Company for the payment of withholding taxes due on units issued under its equity compensation plan.

(2)

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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Reserved

Item 5. Other Information

The Company’s Annual Meeting of Unitholders was held on April 27, 2010. Set forth below are descriptions of the matters voted on at the meeting and the results of the votes taken at the meeting.

1.	To elect six directors to the Company’s Board of Directors to serve until the 2011 Annual Meeting of Unitholders.

Name of Director	Votes For		Votes Withheld

Michael C. Linn		37,170,969		1,141,153
Mark E. Ellis		37,845,529		466,593
George A. Alcorn		32,555,790		5,756,332
Terrence S. Jacobs		32,615,189		5,696,933
Joseph P. McCoy		33,613,026		4,699,096
Jeffrey C. Swoveland		32,895,426		5,416,696

2.	To ratify the appointment of KPMG LLP as independent auditor of the Company for the fiscal year ending December 31, 2010.

Votes For		Votes Against		Abstentions

	106,624,409		1,561,527		291,045

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Item 6. Exhibits

Exhibit Number			Description
2	.1†*	—	Agreement for Purchase and Sale of Assets, dated March 21, 2010, between Linn Energy Holdings, LLC, as purchaser, and HighMount Exploration & Production LLC, as seller
2	.2†*	—	Agreement for Purchase and Sale of Assets, dated March 28, 2010, between Linn Energy Holdings, LLC, as purchaser, and James C. Henry, Jamie Henry Mitros, Beverly Henry Curci, and James David Henry, as sellers
4	.1	—	Indenture, dated April 6, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed April 9, 2010)
4	.2	—	Registration Rights Agreement, dated April 6, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed April 9, 2010)
10	.1	—	Second Amendment, dated April 6, 2010, to Fourth Amended and Restated Credit Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto (incorporated herein by reference to Exhibit 4.3 to Current Report on Form 8-K filed April 9, 2010)
31	.1†	—	Section 302 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
31	.2†	—	Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32	.1†	—	Section 906 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
32	.2†	—	Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC

†	Filed herewith.

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

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SIGNATURE

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

	LINN ENERGY, LLC
	(Registrant)


Date: April 29, 2010	/s/ David B. Rottino
	David B. Rottino
	Senior Vice President and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)