Annual Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2008

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

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)	(I.R.S. Employer Identification No.)
600 Travis, Suite 5100 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code

(281) 840-4000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Units Representing Limited Liability Company Interests		The NASDAQ Stock Market LLC

Securities registered pursuant to Section 12(g) of the Act :

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No x

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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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 o Non-accelerated filer o Smaller reporting company o

Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No x

The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $2,717,556,563 on June 30, 2008, based on $24.85 per unit, the last reported sales price of the units on The NASDAQ Global Market on such date.

As of January 30, 2009, there were 114,025,866 units outstanding.

Documents Incorporated By Reference:

Certain information called for in Items 10, 11, 12, 13 and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the annual meeting of unitholders to be held on May 5, 2009.

TABLE OF CONTENTS

		Page

	Glossary of Terms		ii

	Part I
Item 1.	Business		1
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		25
Item 2.	Properties		25
Item 3.	Legal Proceedings		25
Item 4.	Submission of Matters to a Vote of Security Holders		25
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6.	Selected Financial Data		29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		55
Item 8.	Financial Statements and Supplementary Data		56
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		102
Item 9A.	Controls and Procedures		102
Item 9B.	Other Information		102
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance		103
Item 11.	Executive Compensation		103
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		103
Item 13.	Certain Relationships and Related Transactions, and Director Independence		103
Item 14.	Principal Accounting Fees and Services		103
	Part IV
Item 15.	Exhibits and Financial Statement Schedules		104

	Signatures		105

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GLOSSARY OF TERMS

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

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

Bcf. One billion cubic feet.

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

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

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

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

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

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

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

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

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

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within gas.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

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Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved reserves. Proved oil and gas reserves are the estimated quantities of oil, gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Royalty interest. An interest that entitles the owner of such interest to a share of the mineral production from a property or to a share of the proceeds there from. It does not contain the rights and obligations of operating the property and normally does not bear any of the costs of exploration, development and operation of the property.

Standardized measure of discounted future net cash flows. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses or depreciation, depletion and amortization; discounted using an annual discount rate of 10%.

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

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Unproved resources. Resources that are considered less certain to be recovered than proved reserves. Unproved resources may be further sub-classified to denote progressively increasing uncertainty of recoverability.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Maintenance on a producing well to restore or increase production.

iii

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Part I

Item 1 . Business

This Annual Report on Form 10-K contains forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. For more information see “Forward-Looking Statements” included at the end of this Item 1. “Business” and see also Item 1A. “Risk Factors.”

References

When referring to Linn Energy, LLC (“Linn Energy” or the “Company”), the intent is to refer to Linn Energy and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

A reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Part II. Item 8. “Financial Statements and Supplementary Data.”

Overview

Linn Energy is an independent oil and gas company focused on the development and acquisition of long life properties which complement its asset profile in producing basins within the United States. Linn Energy began operations in March 2003 and completed its initial public offering (“IPO”) in January 2006. The Company’s properties are currently located in the Mid-Continent and California.

Proved reserves at December 31, 2008 were 1,660 Bcfe, of which approximately 51% were gas, 31% were oil and 18% were natural gas liquids (“NGL”). Approximately 68% were classified as proved developed, with a total standardized measure of discounted future net cash flows of $1.42 billion. At December 31, 2008, the Company operated 4,453, or 66%, of its 6,716 gross productive wells. Average proved reserves-to-production ratio, or average reserve life, is approximately 21 years.

Strategy

The Company’s primary goal is to provide stability and growth of distributions for the long-term benefit of its unitholders. The following is a summary of the key elements of the Company’s business strategy:

efficiently operate and develop acquired properties;

reduce cash flow volatility through commodity price and interest rate hedging; and

grow through acquisition of long life, high quality properties.

The Company’s business strategy is discussed in more detail below.

Efficiently Operate and Develop Acquired Properties

The Company has aligned the operation of its acquired properties into defined operating regions to minimize operating costs and maximize production and capital efficiency. The Company maintains a large inventory of drilling and optimization projects within each region to achieve organic growth from its capital development program. The Company seeks to be the operator of its properties so that it can develop drilling programs and optimization projects that not only replace production, but add value through reserve and production growth and future operational synergies. The development program is focused on lower risk, repeatable drilling opportunities to maintain and/or grow cash flow. Many of the wells are completed in multiple producing zones with commingled production and long economic lives. The number, types and location of wells drilled varies depending on the Company’s capital budget, the cost of each well, anticipated production and the estimated recoverable reserves attributable to each well. In addition, the Company seeks to deliver attractive financial returns by leveraging its experienced workforce and scalable infrastructure. For 2009, the Company estimates its total drilling and development capital expenditures will be approximately $150.0 million. This estimate is under

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continuous review and is subject to on-going adjustment. The Company expects to fund these capital expenditures with cash flow from operations.

Reduce Cash Flow Volatility Through Commodity Price and Interest Rate Hedging

An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil, gas and NGL. By removing a significant portion of the price volatility associated with future oil, gas and NGL production, the Company expects to mitigate, but not eliminate, the potential effects of declining commodity prices on cash flows from operations for those periods. These transactions are in the form of swap contracts, collars and put options. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor over the floating market price. The Company has derivative contracts in place through 2014 covering a significant portion of forecasted production volumes through 2012 to provide long-term cash flow predictability to pay distributions, service debt and manage its business.

In addition, the Company enters into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. Currently, the Company utilizes London Interbank Offered Rate (“LIBOR”) swaps to convert the borrowing rate on indebtedness under its credit facility from a floating to fixed rate. At January 30, 2009, with the new interest rate swap contracts discussed below in “Recent Developments,” the Company had swapped LIBOR on approximately 88% of debt outstanding under its credit facility at an average fixed rate of 3.80% through January 2014. For additional details about the Company’s interest rate swap agreements and commodity derivative contracts, see Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” See also Note 9 and Note 10.

Grow Through Acquisition of Long Life, High Quality Properties

The Company’s acquisition program targets oil and gas properties which offer long life, high quality production with relatively predictable decline curves, as well as lower risk development opportunities. The Company evaluates acquisitions based on decline profile, reserve life, operational efficiency, field cash flow and development costs. As part of this strategy, the Company continually seeks to optimize its asset portfolio, including divestitures of non-core assets. This allows the Company to redeploy capital into projects to develop lower risk, long life and low decline properties which are better suited to its business strategy.

From inception through the date of this report, the Company has completed 25 acquisitions of working and royalty interests in oil and gas properties and related gathering and pipeline assets. Excluding the Appalachian Basin properties sold in July 2008 (discussed in “Asset Sales” below), total acquired proved reserves were approximately 1.7 Tcfe at an acquisition cost of approximately $2.17 per Mcfe. The Company finances acquisitions with a combination of proceeds from the issuance of its units, bank borrowings and cash flow from operations. See Note 3 for additional details about the Company’s recent acquisitions.

Recent Developments

Asset Sales

During the fourth quarter of 2008, the Company completed a year-long portfolio optimization project. The Company carefully analyzed its asset base to determine which properties best fit the Linn Energy business model with high quality reserves and long life production. During 2008, the Company sold approximately $1.0 billion (contract price) of properties that were non-core to its business strategy, primarily due to high capital requirements and high decline characteristics. The Company strategically capitalized on opportunities to monetize Marcellus Shale acreage in the Appalachian Basin, high-decline acreage in the Verden area in Oklahoma and Woodford Shale acreage in Oklahoma. A summary of these transactions is as follows:

On July 1, 2008, the Company completed the sale of its interests in oil and gas properties located in the Appalachian Basin to XTO Energy, Inc. (“XTO”) for a contract price of $600.0 million. The assets include approximately 197 Bcfe of proved reserves at December 31, 2007. Net proceeds were $566.5 million and

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the carrying value of net assets sold was $405.8 million, resulting in a gain on the sale of $160.7 million. The results of the Company’s Appalachian Basin operations are classified as discontinued operations for all periods presented (see Note 2).

On August 15, 2008, the Company completed the sale of certain properties in the Verden area in Oklahoma to Laredo Petroleum, Inc. (“Laredo”) for a contract price of $185.0 million, subject to closing adjustments. The assets include approximately 50,000 net acres and 45 Bcfe of proved reserves at December 31, 2007. Net proceeds and the carrying value of net assets sold were $169.4 million.

On December 4, 2008, the Company completed the sale of its deep rights in certain central Oklahoma acreage, which includes the Woodford Shale interval, to Devon Energy Production Company, LP (“Devon”) for a contract price of $202.3 million, subject to closing adjustments. The sale included approximately 34,000 net acres and no producing reserves. Net proceeds were $153.2 million and the carrying value of net assets sold was $54.2 million, resulting in a gain on the sale of $99.0 million. In January 2009, certain post closing matters were resolved and the Company received additional proceeds of $11.5 million, which will be reported as a gain in the first quarter of 2009. Pending resolution of title issues, the Company estimates it may receive additional proceeds ranging from $12.0 million to $18.0 million during the first quarter of 2009.

Interest Rate Swap Restructuring

In January 2009, the Company amended and extended its interest rate swap portfolio. The Company canceled, in a cashless transaction, its existing interest rate swap agreements that settled at a fixed rate of 5.06% through 2011 (see Note 9) and entered into new agreements that settle at a fixed rate of 3.80% through 2014. See Note 8 for details about the Company's credit facility and senior notes. The following presents the settlement terms of the interest rate swaps:

	Year 2009			Year 2010			Year 2011			Year 2012			Year 2013			Year 2014 (1)
	(dollars in thousands)

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

(1)	Represents interest rate swaps that settle in January 2014.

Distributions

In January 2009, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the fourth quarter of 2008. The distribution totaled approximately $72.5 million and was paid on February 13, 2009 to unitholders of record as of the close of business on February 6, 2009.

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units. During the year ended December 31, 2008, 1,076,900 units were purchased at an average unit price of $12.09, for a total cost of approximately $13.0 million. All units were subsequently canceled. The Company may purchase units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are purchased at fair market value on the date of purchase.

Credit and Capital Market Disruptions

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markets currently remain constrained. To the extent the Company accesses credit or capital markets in the near term, its ability to obtain terms and pricing similar to its existing terms and pricing may be limited. During 2009, the Company plans to renegotiate its credit facility, which matures in August 2010. Entry into a new credit facility is expected to result in increased interest expense and there can be no assurance that the borrowing base will remain at the current level. In addition, the Company cannot be assured that counterparties to the Company’s derivative contracts will be able to perform under these contracts. For additional information about these and other risk factors that could affect the Company, see Item 1A. “Risk Factors.”

Operating Regions

The Company’s properties are located in three regions in the United States:

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

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

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

Mid-Continent Deep

The Mid-Continent Deep region includes properties in the Deep Granite Wash formation in the Texas Panhandle, which produces at depths ranging from 8,900 feet to 16,000 feet, as well as properties in Oklahoma which produce at depths over 8,000 feet. Mid-Continent Deep proved reserves represented approximately 54% of total proved reserves at December 31, 2008, of which 69% were classified as proved developed reserves. This region produced 136 MMcfe/d, or 64%, of the Company’s 2008 average daily production. During 2008, the Company invested approximately $218.3 million to drill in this region. During 2009, the Company anticipates spending approximately 70% of its total capital budget for development activities in the Mid-Continent Deep region.

Mid-Continent Shallow

The Mid-Continent Shallow region includes properties producing from the Brown Dolomite formation in the Texas Panhandle, which produces at depths of approximately 3,200 feet, as well as properties in Oklahoma which produce at depths under 8,000 feet. Mid-Continent Shallow proved reserves represented approximately 33% of total proved reserves at December 31, 2008, of which 60% were classified as proved developed reserves. This region produced 63 MMcfe/d, or 30%, of the Company’s 2008 average daily production. During 2008, the Company invested approximately $70.7 million to drill in this region. During 2009, the Company anticipates spending approximately 25% of its total capital budget for development activities in the Mid-Continent Shallow region.

In order to more efficiently transport its gas in the Mid-Continent Deep and Mid-Continent Shallow regions to market, the Company owns and operates a network of gas gathering systems comprised of approximately 900 miles of pipeline and associated compression and metering facilities which connect to numerous sales outlets in the Texas Panhandle.

Western

The Western region consists of the Brea Olinda Field of the Los Angeles Basin in California. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation. Western proved reserves represented approximately 13% of total proved reserves at December 31, 2008, of which 87% were classified as proved developed reserves. This region produced 13 MMcfe/d, or 6%, of the Company’s 2008 average daily production. During 2008, the Company invested approximately $3.1 million to drill in this region. During 2009, the Company anticipates spending approximately 5% of its total capital budget for development activities in the Western region.

The Western region also includes the operation of a gas processing facility which processes produced gas from Company and third party wells. Processed gas is utilized to generate electricity which is used in the field to power equipment, resulting in reduced operating costs. Revenues are also generated from the sale of excess power.

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Drilling and Acreage

The following sets forth the wells drilled in the Mid-Continent Deep, Mid-Continent Shallow and Western operating regions during the periods indicated (“gross” refers to the total wells in which the Company had a working interest and “net” refers to gross wells multiplied by its working interest):

	Year Ended December 31,
	2008		2007		2006
Gross wells:
Productive		304		136		3
Non-productive		2		2		1
Total		306		138		4
Net development wells:
Productive		189		112		1
Non-productive		1		2		1
Total		190		114		2
Net exploratory wells:
Productive		—		—		—
Non-productive		—		—		—
Total		—		—		—

The total wells above exclude 45, 115 and 155 gross wells (45, 105 and 150 net wells) drilled in the Appalachian Basin during the years ended December 31, 2008, 2007 and 2006, respectively. The totals above do not include 23 and 25 lateral segments added to existing vertical wellbores in the Mid-Continent Shallow region during the years ended December 31, 2008 and 2007, respectively. At December 31, 2008, the Company had 7 gross (4 net) wells in process.

The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil, gas or NGL, regardless of whether they generate a reasonable rate of return.

The following sets forth information about the Company’s drilling locations and net acres of leasehold interests as of December 31, 2008:

	Total (1)

Proved undeveloped		1,259
Other locations		2,810
Total drilling locations		4,069

Leasehold interests – net acres (in thousands)		737

(1) Does not include optimization projects.

As shown in the table above, as of December 31, 2008, the Company had 1,259 proved undeveloped drilling locations (specific drilling locations as to which the independent engineering firm, DeGolyer and MacNaughton, assigned proved undeveloped reserves as of such date) and the Company had identified 2,810 additional unproved drilling locations (specific drilling locations as to which DeGolyer and MacNaughton has not assigned any proved reserves) on acreage that the Company has under existing leases. As successful development wells frequently result in the reclassification of adjacent lease acreage from unproved to proved, the Company expects that a significant number of its unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations.

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Productive Wells

The following table sets forth information relating to the productive wells in which the Company owned a working interest as of December 31, 2008. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline or other connections to commence deliveries. “Gross” wells refers to the total number of producing wells in which the Company has an interest, and “net” wells refers to the sum of its fractional working interests owned in gross wells. The number of wells below does not include approximately 2,200 productive wells in which the Company owns a royalty interest only.

	Gas Wells				Oil Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net

Operated (1)		1,969		1,647		2,484		2,271		4,453		3,918
Non-operated (2)		1,313		205		950		54		2,263		259
Total		3,282		1,852		3,434		2,325		6,716		4,177

(1)	10 operated wells had multiple completions at December 31, 2008.

(2)	3 non-operated wells had multiple completions at December 31, 2008.

Developed and Undeveloped Acreage

The following sets forth information as of December 31, 2008, relating to leasehold acreage:

Developed

Acreage

Undeveloped

Acreage

Total

Acreage

Gross

Net

Gross

Net

Gross

Net

(in thousands)

Leasehold acreage

1,555

664

116

1,671

737

Production, Price and Cost History

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

The Company’s gas production is primarily sold under market sensitive price contracts, which typically sell at differentials to The New York Mercantile Exchange (“NYMEX”) or Panhandle Eastern Pipeline (“PEPL”) gas prices due to the Btu content and the proximity to major consuming markets. The Company’s gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. By the terms of the percentage-of-proceeds contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residual gas and NGL recovered after transportation and processing of gas. These purchasers sell the residual gas and NGL based primarily on spot market prices. Under percentage-of-index contracts, the price per MMBtu the Company receives for gas is tied to indexes published in Gas Daily or Inside FERC Gas Market Report. Although exact percentages vary daily, as of December 31, 2008, approximately 90% of the Company’s gas and NGL production was sold under short-term contracts at market-sensitive or spot prices. At December 31, 2008, the Company had gas throughput delivery commitments under long-term contracts of approximately 5,797 MMcf, 2,102 MMcf, 1,045 MMcf and 784 MMcf for the years ended December 31, 2009, 2010, 2011 and 2012, respectively.

The Company’s oil production is primarily sold under market sensitive percentage-of-index contracts and percentage-of-proceeds contracts and as of December 31, 2008, approximately 80% of its oil production was sold under short-term contracts. At December 31, 2008, the Company had no delivery commitments for oil production.

As discussed in the “Strategy” section above, the Company enters into derivative contracts in the form of swap contracts, collars and put options to reduce the impact of commodity price volatility on its cash flow from

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operations. By removing price volatility from a significant portion of its production, the Company has mitigated, but not eliminated, potential effects of fluctuating oil, gas and NGL prices on its cash flow from operations for those periods.

The following sets forth information regarding net production of oil, gas and NGL and certain price information for each of the periods indicated:

	Year Ended December 31,
	2008		2007		2006
Average daily production – continuing operations:
Gas (MMcf/d)		124		51		2
Oil (MBbls/d)		9		3		1
NGL (MBbls/d)		6		3		―
Total (MMcfe/d)		212		87		8

Average daily production – discontinued operations:
Total (MMcfe/d)		12		24		22

Weighted average prices (hedged): (1)
Gas (Mcf)	$	8.42	$	8.36	$	―
Oil (Bbl)	$	80.92	$	67.07	$	―
NGL (Bbl)	$	57.86	$	55.51	$	―

Weighted average prices (unhedged): (2)
Gas (Mcf)	$	7.39	$	6.39	$	5.99
Oil (Bbl)	$	92.78	$	66.44	$	49.55
NGL (Bbl)	$	57.86	$	55.51	$	―

Representative NYMEX oil and gas prices:
Gas (MMBtu)	$	9.04	$	6.86	$	7.23
Oil (Bbl)	$	99.65	$	72.34	$	66.21

Costs per Mcfe of production:
Lease operating expenses	$	1.49	$	1.31	$	2.36
Transportation expenses	$	0.23	$	0.17	$	0.01
General and administrative expenses (3)	$	1.00	$	1.61	$	13.61
Depreciation, depletion and amortization	$	2.50	$	2.16	$	1.56
Taxes, other than income taxes	$	0.79	$	0.70	$	0.09

(1)

Includes the effect of realized gains of $9.4 million (excluding $81.4 million realized losses on canceled derivative contracts) and $37.3 million on derivatives for the years ended December 31, 2008 and 2007, respectively. During the year ended December 31, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production primarily associated with properties in the Appalachian Basin and Verden areas resulting in realized losses of $81.4 million. This information is not presented for the year ended December 31, 2006 because it is not meaningful due to the classification of Appalachian Basin results of operations in discontinued operations (see Note 2).

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

(3)

General and administrative expenses for the years ended December 31, 2008, 2007 and 2006 includes approximately $14.6 million, $13.5 million and $21.6 million, respectively, of non-cash unit-based compensation and unit warrant expenses. General and administrative expenses for the year ended December 31, 2006 also includes $2.0 million of IPO bonuses paid to certain executive officers. Excluding these amounts, general and administrative expenses for the years ended December 31, 2008, 2007 and 2006 were $0.81 per Mcfe, $1.19 per Mcfe and $5.14 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company’s performance.

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Reserve Data

Proved Reserves

Proved oil and gas reserves are the estimated quantities of oil, gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices, but not escalations based on future conditions. For additional information regarding estimates of oil, gas and NGL reserves, including estimates of proved and proved developed reserves and the standardized measure of discounted future net cash flows see Supplemental Oil and Gas Data (Unaudited) in Item 8. “Financial Statements and Supplementary Data.”

The following presents estimated net proved oil, gas and NGL reserves and the standardized measure of discounted future net cash flows at December 31, 2008, 2007 and 2006, based on reserve reports prepared by independent engineers DeGolyer and MacNaughton. The standardized measure of discounted future net cash flows is not intended to represent the market value of estimated oil, gas and NGL reserves.

	December 31,
	2008			2007			2006
Reserve data – continuing operations:
Estimated net proved reserves:
Gas (Bcf)		851			833			77
Oil (MMBbls)		84			55			30
NGL (MMBbls)		51			43			—
Total (Bcfe)		1,660			1,419			255
Proved developed (Bcfe)		1,134			1,024			195
Proved undeveloped (Bcfe)		526			395			60
Proved developed reserves as a % of total proved reserves		68	%		72	%		76	%
Standardized measure of discounted future net cash flows (in millions)	$	1,424		$	3,175		$	299

Reserve data – discontinued operations:
Estimated net proved reserves:
Gas (Bcf)		—			195			197
Oil (MMBbls)		—			1			1
Total (Bcfe)		—			197			199
Proved developed (Bcfe)		—			148			119
Proved undeveloped (Bcfe)		—			49			80
Proved developed reserves as a % of total proved reserves		—			75	%		60	%
Standardized measure of discounted future net cash flows (in millions)	$	—		$	283		$	254

Representative NYMEX oil and gas prices at period end:
Gas (MMBtu)	$	5.71		$	6.80		$	5.64
Oil (Bbl)	$	39.22		$	95.92		$	61.05

The data in the above table are estimates. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and gas that are ultimately recovered.

These reserve estimates are reviewed and approved by Company senior engineering staff and management, with final approval by its Chief Operating Officer. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. The independent engineering firms also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, the independent engineering firms did not independently verify the accuracy

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and completeness of information and data furnished by the Company with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention which brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto. Their estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions. The Company has not filed reserve estimates with any federal authority or agency, with the exception of the SEC, since the last fiscal year ended.

Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown. The 10% discount factor required to be used pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”) may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry. The standardized measure of discounted future net cash flows is materially affected by assumptions about the timing of future production, which may prove to be inaccurate.

Operational Overview

General

The Company seeks to be the operator of its properties so that it can control the drilling programs that not only replace production, but add value through the growth of reserves and future operational synergies. Many of the Company’s wells are completed in multiple producing zones with commingled production and long economic lives.

Principal Customers

For the year ended December 31, 2008, sales of oil, gas and NGL to DCP Midstream Partners, LP, ConocoPhillips and Enbridge Energy accounted for approximately 23%, 12% and 11%, respectively, of the Company’s total volumes, or 46% in the aggregate. If the Company were to lose any one of its major oil and gas purchasers, the loss could temporarily cease or delay production and sale of its oil and gas in that particular purchaser’s service area. If the Company were to lose a purchaser, it believes it could identify a substitute purchaser. However, if one or more of these large gas purchasers ceased purchasing oil and gas altogether, it could have a detrimental effect on the oil and gas market in general and on the volume of oil and gas that it is able to sell.

Competition

The oil and gas industry is highly competitive. The Company encounters strong competition from other independent operators and master limited partnerships in acquiring properties, contracting for drilling and other related services and securing trained personnel. The Company is also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. The Company is unable to predict when, or if, such shortages may occur or how they would affect its drilling program.

Operating Hazards and Insurance

The oil and gas industry involves a variety of operating hazards and risks that could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations.

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In addition, the Company may be liable for environmental damages caused by previous owners of property it purchases and leases. As a result, the Company may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds available for acquisitions, development or distributions, or result in the loss of properties.

In accordance with customary industry practices, the Company maintains insurance against some, but not all, potential losses. The Company cannot provide assurance that any insurance it obtains will be adequate to cover any losses or liabilities. The Company cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. The Company has elected to self-insure for trucks and vehicles licensed to operate on public highways and roads. The Company may elect to self-insure for additional items if it is determined that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on the Company’s financial position and results of operations.

The Company participates in wells on a non-operated basis and therefore may be limited in its ability to control the risks associated with oil, gas and NGL operations.

Title to Properties

Prior to the commencement of drilling operations, the Company conducts a thorough title examination and performs curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense prior to commencing drilling operations. Prior to completing an acquisition of producing gas leases, the Company performs title reviews on the most significant leases and, depending on the materiality of properties, the Company may obtain a title opinion or review previously obtained title opinions. As a result, the Company has obtained title opinions on a significant portion of its oil and gas properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the oil and gas industry. Oil and gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which do not materially interfere with the use of or affect the carrying value of the properties.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in regions of the United States that the Company operates in. These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, Company operations in all regions may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.

The demand for gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain gas users utilize gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations. The demand for crude oil is generally determined at a global level, based on supply shortage concerns driven primarily by natural disasters such as hurricanes and by political instability in certain oil producing regions of the world.

Environmental Matters and Regulation

The Company’s operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company’s operations are subject to the same environmental laws and regulations as other companies in the oil and gas industry. These laws and regulations may:

require the acquisition of various permits before drilling commences;

require the installation of expensive pollution control equipment;

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

impose substantial liabilities for pollution resulting from operations; and

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on operating costs.

The environmental laws and regulations applicable to the Company and its operations include, among others, the following United States federal laws and regulations:

Clean Air Act, and its amendments, which governs air emissions;

Clean Water Act, which governs discharges to waters of the United States;

Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);

Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures;

National Environmental Policy Act, which governs oil and gas production activities on federal lands;

Resource Conservation and Recovery Act, which governs the management of solid waste;

Safe Drinking Water Act, which governs the underground injection and disposal of wastewater; and

U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

Various states regulate the drilling for, and the production, gathering and sale of, oil and gas, including imposing production taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. States may regulate rates of production and may establish maximum daily production allowables from gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, gas and NGL that may be produced from the Company’s wells and to limit the number of wells or locations it can drill. The oil and gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal opportunity employment.

The Company believes that it substantially complies with all current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its financial condition or results of operations. Future regulations that could impact the Company include the Environmental Protection Agency’s proposed rule entitled Regulating Greenhouse Gas Emissions Under the Clean Air Act as well as a proposed “cap-and-trade” scheme for greenhouse gas emissions. The Company cannot predict how future environmental laws and regulations may impact its properties or operations. For the year ended December 31, 2008, the Company did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of the Company’s facilities. The Company is not aware of any environmental issues or claims that will require material capital expenditures during 2009 or that will otherwise have a material impact on its financial position or results of operations.

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Executive Officers of the Company

Name	Age	Position with the Company
Michael C. Linn	57	Chairman and Chief Executive Officer
Mark E. Ellis	53	President and Chief Operating Officer
Kolja Rockov	38	Executive Vice President and Chief Financial Officer
David B. Rottino	43	Senior Vice President and Chief Accounting Officer
Charlene A. Ripley	45	Senior Vice President, General Counsel and Corporate Secretary
Arden L. Walker, Jr.	49	Senior Vice President - Operations and Chief Engineer

Michael C. Linn is the Chairman and Chief Executive Officer of the Company and has served in such capacity since December 2007. Prior to that, from June 2006 to December 2007, Mr. Linn served as Chairman, President and Chief Executive Officer and from March 2003 to June 2006, he was the President, Chief Executive Officer and Director. From 2000 to 2003 Mr. Linn was President of Allegheny Interests, Inc., a private oil and gas investment company. From 1980 to 1999, Mr. Linn served as General Counsel (1980-1982), Vice President (1982-1987), President (1987-1990) and Chief Executive Officer (1990-1999) of Meridian Exploration, a private Appalachian Basin oil and gas company that was sold to Columbia Natural Resources in 1999. Both Allegheny Interests and Meridian Exploration were wholly owned by Mr. Linn and his family. Mr. Linn is the immediate past Chairman of the Independent Petroleum Association of America, the largest national trade association of independent oil and gas producers. He currently sits on the Boards of the National Petroleum Council, the American Exploration and Production Council and the National Association of Manufacturers and is a member of the oil and gas industry’s 25 Year Club. He was recently appointed as a Texas representative to the Legal and Regulatory Affairs Committee of the Interstate Oil and Gas Compact Commission. He is also Chairman of the Houston Wildcatters Committee of the Texas Alliance of Energy Producers. Mr. Linn regularly appears on behalf of the industry before state and federal agencies, such as the Department of Energy, Department of the Treasury, Federal Energy Regulatory Commission and the Environmental Protection Agency. In addition, he has testified on behalf of the industry before various committees and subcommittees of the U.S. House of Representatives and the U.S. Senate and is regularly quoted and has published various articles for trade publications and newspapers. He is also a frequent guest on radio and television programs representing the industry. Mr. Linn’s civic affiliations include memberships on the board of the Museum of Fine Arts Houston, as well as the board of Texas Heart Institute and Small Steps Nurturing Center. In addition, he is the Chairman of the Corporate Committee for Capital Campaign of Texas Children’s Hospital and serves on the Board of Trustees for Texas Children’s Hospital. He also serves on the Committee for the Bush-Clinton Coastal Recovery Fund.

Mark E. Ellis is the President and Chief Operating Officer and has served in such capacity since December 2007. From December 2006 to December 2007, Mr. Ellis was the Executive Vice President and Chief Operating Officer of the Company. Mr. Ellis has over 30 years of experience in the oil and gas industry, most recently serving as President, Lower 48 for ConocoPhillips from April 2006 to November 2006. Prior to joining ConocoPhillips, Mr. Ellis served as Senior Vice President of North American Production for Burlington Resources from September 2004 to April 2006. He served as President of Burlington Resources Canada Ltd. in Calgary from October 2000 to September 2004. Mr. Ellis joined Burlington Resources in 1985 and also held the positions of Vice President of the San Juan Division, Vice President and Chief Engineer and Manager of Acquisitions. He began his career at The Superior Oil Company, where he served in several engineering positions in the Onshore and Offshore divisions. Mr. Ellis is a member of the Society of Petroleum Engineers and a past board member of the New Mexico Oil & Gas Association, the Board of Governors of the Canadian Association of Petroleum Producers and served on the Foundation Board of the Alberta Children’s Hospital. Mr. Ellis currently serves on the Board of The Center for Hearing and Speech in Houston, Industry Board of Petroleum Engineering at Texas A&M University, the Visiting Committee of Petroleum Engineering at the Colorado School of Mines and the Houston Museum of Natural Science.

Kolja Rockov is the Executive Vice President and Chief Financial Officer. Mr. Rockov has over 15 years of experience in the oil and gas finance industry. From October 2004 until he joined Linn Energy in March 2005, Mr. Rockov served as a Managing Director in the Energy Group at RBC Capital Markets, where he was primarily responsible for investment banking coverage of the U.S. exploration and production sector. From September 2000 until October 2004, Mr. Rockov was a Director at RBC Capital Markets. Prior to September 2000, Mr. Rockov held

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various senior positions with Dain Rauscher Wessels and Rauscher Pierce Refsnes, Inc., predecessors of RBC Capital Markets.

David B. Rottino is the Senior Vice President and Chief Accounting Officer and has served in that position since June 2008. Mr. Rottino’s career includes over 15 years of oil and gas accounting experience, most recently serving as Vice President and E&P Controller for El Paso Corporation from June 2006 to May 2008. Prior to joining El Paso Corporation, Mr. Rottino served as Assistant Controller for ConocoPhillips from April 2006 to June 2006. He was Vice President and Chief Financial Officer for the Canadian division of Burlington Resources from July 2005 to April 2006 and served as Burlington Resources’ Director of Financial Analysis and Corporate Accounting from August 2000 to July 2005. Mr. Rottino joined Burlington Resources in 1996 and has served in a broad range of accounting and audit positions. Mr. Rottino is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants and Texas Society of Certified Public Accountants. In addition, he currently serves on the Board of the June Rusche Hamrah Camp For All.

Charlene A. Ripley is the Senior Vice President, General Counsel and Corporate Secretary and has served in that position since April 2007. Prior to joining the Company, Ms. Ripley held the position of Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer at Anadarko Petroleum Corporation from 2006 until April 2007 and served as Vice President, General Counsel and Corporate Secretary from 2004 until 2006, Vice President and General Counsel from 2003 to 2004 and Vice President, General Counsel and Secretary of Anadarko Canada Corporation and its predecessor companies since 1998.

Arden L. Walker, Jr. is the Senior Vice President - Operations and Chief Engineer of the Company. Mr. Walker joined the Company in February 2007 to oversee its Western operations, which, at that time, included California, Oklahoma and Texas, and he is currently responsible for oversight of the Company’s operations in all regions. In addition, Mr. Walker serves in the capacity of chief engineer for the Company and is responsible for the Company’s reserve review and booking processes. From April 2006 until he joined the Company in February 2007, Mr. Walker served as Asset Development Manager, San Juan Business Unit for ConocoPhillips Company. From June 2004 to April 2006, Mr. Walker served as General Manager, Asset Development in San Juan Division for Burlington Resources. From January 2002 until June 2004, Mr. Walker served as Business Development Manager in San Juan Division for Burlington Resources. Mr. Walker began his career with El Paso Exploration Company in 1982 and has served in a broad range of engineering, business development and management positions with Burlington Resources since that time. Mr. Walker is a member of the Society of Petroleum Engineers, Independent Petroleum Association of America and California Independent Petroleum Association.

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Employees

As of December 31, 2008, the Company employed approximately 505 personnel. None of the employees are represented by labor unions or covered by any collective bargaining agreement. The Company believes that its relationship with its employees is satisfactory.

Principal Executive Offices

The Company is a Delaware limited liability company with headquarters in Texas. The principal executive offices are located at 600 Travis, Suite 5100, Houston, Texas 77002. The main telephone number is (281) 840-4000.

Company Website

The Company’s internet website is www.linnenergy.com . The Company makes available free of charge on or through its website Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the SEC. Information on the Company’s website should not be considered a part of, or incorporated by reference into, this Annual Report on Form 10-K.

The SEC maintains an internet website that contains these reports at www.sec.gov . Any materials that the Company files with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

Forward-Looking Statements

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

business strategy;

acquisition strategy;

financial strategy;

drilling locations;

oil, gas and NGL reserves;

realized oil, gas and NGL prices;

production volumes;

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

future operating results; and

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in Part I. Item 1. “Business;” Part I. Item 1A. “Risk Factors;” Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. 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 Annual Report on Form 10-K 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 Annual Report on

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Form 10-K are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. 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.

Securities Act Disclaimer

This Form 10-K does not constitute an offer to sell or the solicitation of an offer to buy any securities.

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Item 1A. Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial position, operating results or liquidity and the trading price of our units are described below. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

We may not have sufficient cash flow from operations to pay the quarterly distribution at the current distribution level and future distributions to our unitholders may fluctuate from quarter to quarter.

We may not have sufficient cash flow from operations each quarter to pay the quarterly distribution at the current distribution level. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and any cash reserve amounts that our Board of Directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

produced volumes of oil, gas and NGL;

prices at which oil, gas and NGL production is sold;

level of our operating costs;

payment of interest, which depends on the amount of our indebtedness and the interest payable thereon; and

level of our capital expenditures.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

availability of borrowings under our credit facility to pay distributions;

the costs of acquisitions, if any;

fluctuations in our working capital needs;

timing and collectibility of receivables;

restrictions on distributions contained in our credit facility;

prevailing economic conditions; and

the amount of cash reserves established by our Board of Directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute to our unitholders in any quarter may fluctuate significantly from quarter to quarter and may be significantly less than the current distribution level.

We actively seek to acquire oil and gas properties. Acquisitions involve potential risks that could adversely impact our future growth and our ability to increase or pay distributions.

Any acquisition involves potential risks, including, among other things:

the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

the risk of title defects discovered after closing;

inaccurate assumptions about revenues and costs, including synergies;

significant increases in our indebtedness and working capital requirements;

an inability to transition and integrate successfully or timely the businesses we acquire;

the cost of transition and integration of data systems and processes;

the potential environmental problems and costs;

the assumption of unknown liabilities;

limitations on rights to indemnity from the seller;

the diversion of management’s attention from other business concerns;

increased demands on existing personnel and on our corporate structure;

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customer or key employee losses of the acquired businesses; and

the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future growth and our ability to increase or pay distributions.

If we do not make future acquisitions on economically acceptable terms, then our growth and ability to increase distributions will be limited.

Our ability to grow and to increase distributions to our unitholders is partially dependent on our ability to make acquisitions that result in an increase in available cash flow per unit. We may be unable to make such acquisitions because we are:

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

unable to obtain financing for these acquisitions on economically acceptable terms; or

outbid by competitors.

In any such case, our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will increase available cash flow per unit, these acquisitions may nevertheless result in a decrease in available cash flow per unit.

We have significant indebtedness under our credit facility and senior notes. Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions to our unitholders.

We have significant indebtedness under our credit facility and senior notes. As of January 30, 2009, we had an aggregate of approximately $1.43 billion outstanding under our credit facility and senior notes (with additional borrowing capacity of approximately $415.4 million). As a result of our indebtedness, we will use a portion of our cash flow to pay interest and principal when due, which will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate.

The credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants could result in an event of default, which, if it continues beyond any applicable cure periods, could cause all of our existing indebtedness to be immediately due and payable.

We depend on our credit facility for future capital needs. We have drawn on our credit facility to fund or partially fund quarterly cash distribution payments, since we use operating cash flows for drilling and development of oil and gas properties and acquisitions and borrow as cash is needed. Absent such borrowing, we would have at times experienced a shortfall in cash available to pay our declared quarterly cash distribution amount. If there is an event of default by us under our credit facility that continues beyond any applicable cure period, we would be unable to make borrowings to fund distributions.

Availability under our credit facility is determined semi-annually at the discretion of the lenders and is based in part on oil, gas and NGL prices. Significant declines in oil, gas or NGL prices may result in a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the credit facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the credit facility. Significant declines in our production or significant declines in realized oil, gas or NGL prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.

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Our ability to access the capital and credit markets to raise capital on favorable terms will be affected by our debt level and by disruptions in the capital and credit markets, which could adversely affect our operations and our ability to pay distributions to our unitholders.

The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as some major financial institutions have consolidated and others may consolidate in the future, some lenders may increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. If we are unable to refinance our credit facility on terms that are as favorable as those in our existing credit facility, or at all, our ability to fund our operations and our ability to pay distributions could be affected.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Increases in interest rates could adversely affect the demand for our units.

An increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for yield-based equity investments such as our units. Any such reduction in demand for our units resulting from other more attractive investment opportunities may cause the trading price of our units to decline.

Our commodity derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, gas and NGL, we enter into commodity derivative contracts for a significant portion of our production. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction of our liquidity.

Disruptions in the capital and credit markets as a result of the global financial crisis may adversely affect our derivative positions.

We cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our cash flow, and ability to pay distributions could be impacted.

Commodity prices are volatile, and a significant decline in commodity prices for a prolonged period would reduce our revenues, cash flow from operations and profitability, and we may have to lower our distribution or may not be able to pay distributions at all.

Our revenue, profitability and cash flow depend upon the prices of and demand for oil, gas and NGL. The oil, gas and NGL market is very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in oil, gas and NGL prices have a significant impact on the value of our reserves and on our cash flow. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for them, market uncertainty and a variety of additional factors that are beyond our control, such as:

the domestic and foreign supply of and demand for oil, gas and NGL;

the price and level of foreign imports;

the level of consumer product demand;

weather conditions;

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overall domestic and global economic conditions;

political and economic conditions in oil and gas producing countries, including those in the Middle East and South America;

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain price and production controls;

the impact of the U.S. dollar exchange rates on oil, gas and NGL prices;

technological advances affecting energy consumption;

domestic and foreign governmental regulations and taxation;

the impact of energy conservation efforts;

the proximity and capacity of pipelines and other transportation facilities; and

the price and availability of alternative fuels.

In the past, the prices of oil, gas and NGL have been extremely volatile, and we expect this volatility to continue. If commodity prices decline significantly for a prolonged period, our cash flow from operations will decline, and we may have to lower our distribution or may not be able to pay distributions at all.

Future price declines or downward reserve revisions may result in a write-down of our asset carrying values.

Declines in oil, gas and NGL prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore would require a write-down. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

Producing oil, gas and NGL reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The overall rate of decline for our production will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future oil, gas and NGL reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of oil, gas and NGL in an exact way. Reserve engineering requires subjective estimates of underground accumulations of oil, gas and NGL and assumptions concerning future oil, gas and NGL prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Independent petroleum engineering firms prepare estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future oil, gas and NGL prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, gas and NGL attributable to any particular group of properties, the classifications of reserves based

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on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, gas and NGL we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil, gas and NGL reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:

actual prices we receive for oil, gas and NGL;

the amount and timing of actual production;

the timing and success of development activities;

supply of and demand for oil, gas and NGL; and

changes in governmental regulations or taxation.

In addition, the 10% discount factor, required to be used pursuant to SFAS 69 when calculating discounted future net cash flows, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Our development operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, gas and NGL reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and our financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:

our proved reserves;

the level of oil, gas and NGL we are able to produce from existing wells;

the prices at which we are able to sell our oil, gas and NGL; and

our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our credit facility decrease as a result of lower oil, gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility restricts our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our development operations, which in turn could lead to a possible decline in our reserves.

We may decide not to drill some of the prospects we have identified, and locations that we decide to drill may not yield oil, gas and NGL in commercially viable quantities.

Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, gas and NGL prices, the generation of additional seismic or geological information, the availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects. As a result, we may not be able to increase or maintain our reserves or production, which in turn could have an adverse effect on our business, financial position or results of operations.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, gas and NGL to be commercially viable after drilling, operating and other costs. If we drill

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future wells that we identify as dry holes, our drilling success rate would decline, which could have an adverse effect on our business, financial position or results of operations.

Our business depends on gathering and transportation facilities. Any limitation in the availability of those facilities would interfere with our ability to market the oil, gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, gas and NGL production from our drilling program.

The marketability of our oil, gas and NGL production depends in part on the availability, proximity and capacity of gathering and pipeline systems. The amount of oil, gas and NGL that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, gas and NGL production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would interfere with our ability to market the oil, gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil and gas production from our drilling program.

We depend on certain key customers for sales of our oil, gas and NGL. To the extent these and other customers reduce the volumes they purchase from us or delay payment, our revenues and cash available for distribution could decline. Further, a general increase in non-payment could have an adverse impact on our financial position and results of operations.

For the year ended December 31, 2008, DCP Midstream Partners, LP, ConocoPhillips and Enbridge Energy accounted for approximately 23%, 12% and 11%, respectively, of our total volumes from continuing operations, or 46% in the aggregate. For the year ended December 31, 2007, DCP Midstream Partners, LP and ConocoPhillips accounted for approximately 28% and 17%, respectively, of our total volumes from continuing operations, or 45% in the aggregate. To the extent these and other customers reduce the volumes of oil, gas or NGL that they purchase from us, our revenues and cash available for distribution could decline.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Our key project areas are located in some of the most active drilling areas of the producing basins in the United States. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of reserves in these areas.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2008, we had identified 4,069 drilling locations, of which 1,259 were proved undeveloped locations and 2,810 were other locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil, gas and NGL prices, costs and drilling results. In addition, DeGolyer and MacNaughton has not estimated proved reserves for the 2,810 other drilling locations we have identified and scheduled for drilling, and therefore there may be greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil, gas and NGL from these or any other

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potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing oil, gas and NGL are high risk activities with many uncertainties that could adversely affect our financial position or results of operations and, as a result, our ability to pay distributions to our unitholders.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil, gas and NGL can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

the high cost, shortages or delivery delays of equipment and services;

unexpected operational events;

adverse weather conditions;

facility or equipment malfunctions;

title problems;

pipeline ruptures or spills;

compliance with environmental and other governmental requirements;

unusual or unexpected geological formations;

loss of drilling fluid circulation;

formations with abnormal pressures;

fires;

blowouts, craterings and explosions; and

uncontrollable flows of oil, gas and NGL or well fluids.

Any of these events can cause increased costs or restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling program or significant increase in costs could impact our ability to generate sufficient cash flow to pay quarterly distributions to our unitholders at the current distribution level. Increased costs could include losses from personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. We ordinarily maintain insurance against certain losses and liabilities arising from our operations. However, it is impossible to insure against all operational risks in the course of our business. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial position and results of operations.

Because we handle oil, gas and NGL and other hydrocarbons, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of our wells, gathering systems, turbines, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

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Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells or gathering pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance. For a more detailed discussion of environmental and regulatory matters impacting our business, see Part I. Item 1. “Business - Environmental Matters and Regulation.”

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and gas wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil, gas and NGL we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our ability to pay distributions to our unitholders. For a description of the laws and regulations that affect us, see Part I. Item 1. “Business - Environmental Matters and Regulation.”

Our management may have conflicts of interest with the unitholders. Our limited liability company agreement limits the remedies available to our unitholders in the event unitholders have a claim relating to conflicts of interest.

Conflicts of interest may arise between our management on one hand, and the Company and our unitholders on the other hand, related to the divergent interests of our management. Situations in which the interests of our management may differ from interests of our non-affiliated unitholders include, among others, the following situations:

our limited liability company agreement gives our Board of Directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;

our management team, subject to oversight from our Board of Directors, determines the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of

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additional membership interests and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders; and

affiliates of our directors are not prohibited from investing or engaging in other businesses or activities that compete with the Company.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our limited liability company agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our total revenue apportioned to Texas in the prior year. Imposition of a tax on us by any other state would reduce the amount of cash available for distribution to our unitholders.

Unitholders may be subject to taxable gains upon dispositions of properties.

We may dispose of properties in transactions that result in gains that will be allocated to you, and such gains may be either ordinary gains or capital gains to you. Even where we dispose of properties that are capital assets, what otherwise would be capital gains to you may be recharacterized as ordinary gains in order to “recapture” ordinary deductions that were previously allocated to you related to the same properties. In addition, such an allocation of ordinary or capital gains may increase your taxable income, and you may be required to pay federal income taxes and state and local income taxes, even if we have not made a cash distribution to you subsequent to our disposal of the properties. Your allocable share of the taxable gains also may be greater than your interest in our profits. If you contributed property in exchange for our units, your capital account would have been credited with the fair market value of the property at the time (your “book” basis), which may have exceeded your “tax” basis of property. This could also be the case if you held our units at a time when we issued additional units to other unitholders (resulting in a revaluation of our assets). Gains are required to be allocated to you in order to eliminate this “book-tax disparity.”

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Our unitholders may have more complex tax reporting and may be required to pay taxes on income even if they do not receive any cash distributions from us.

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income. Furthermore, distributions to unitholders in excess of the total net taxable income they were allocated, decreases their tax basis, which will become ordinary taxable income to them if the unit is later sold at a price greater than their tax basis, even if the price received is less than their original cost.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. In 2008, we have done business and owned assets in West Virginia, Virginia, Pennsylvania, New York, Virginia, California, Oklahoma, Kansas, New Mexico, Illinois, Indiana, Arkansas, Colorado, Kentucky, Louisiana, Mississippi, Montana, North Dakota, South Dakota and Texas. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our units.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information concerning proved reserves, production, wells, acreage and related matters are contained in Part I. Item 1. “Business.”

The Company’s obligations under its credit facility are secured by mortgages on its oil and gas properties. See Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 8 for additional information concerning the credit facility.

Offices

The Company’s principal corporate office is located at 600 Travis, Suite 5100, Houston, Texas 77002. The Company maintains additional offices in California, Illinois, Kansas, Louisiana, Oklahoma and Texas.

Item 3. Legal Proceedings

Although the Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Company is not currently a party to any material legal proceedings. In addition, the Company is not aware of any material legal or governmental proceedings against it, or contemplated to be brought against it, under the various environmental protection statutes to which it is subject.

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

None.

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Part II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

The Company’s units are listed on The NASDAQ Global Select Market (“NASDAQ”) under the symbol “LINE” and began trading on January 13, 2006, after pricing of its initial public offering. At the close of business on January 30, 2009, there were approximately 280 unitholders of record.

The following presents the range of high and low last reported sales prices per unit, as reported by NASDAQ, for the quarters indicated. In addition, distributions declared during each quarter are presented.

	Unit Price Range				Cash Distribution Declared
Quarter	High		Low		Per Unit
2008:
October 1 – December 31	$	17.03	$	11.20	$	0.63
July 1 – September 30	$	24.88	$	14.93	$	0.63
April 1 – June 30	$	25.57	$	19.44	$	0.63
January 1 – March 31	$	24.41	$	18.88	$	0.63
2007:
October 1 – December 31	$	30.79	$	22.88	$	0.57
July 1 – September 30	$	37.80	$	31.64	$	0.57
April 1 – June 30	$	39.61	$	32.47	$	0.52
January 1 – March 31	$	35.05	$	30.16	$	0.52

Distributions

The Company’s limited liability company agreement requires it to make quarterly distributions to unitholders of all “available cash.”

Available cash means, for each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash reserves established by the Board of Directors to:

provide for the proper conduct of business (including reserves for future capital expenditures, future debt service requirements, and for anticipated credit needs); and

comply with applicable laws, debt instruments or other agreements;

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.

Working capital borrowings are borrowings that will be made under the Company’s credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders.

See Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” for a discussion on the payment of future distributions.

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Unitholder Return Performance Presentation

The performance graph below compares the total unitholder return on the Company’s units, with the total return of the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Index, a weighted composite of 50 prominent energy master limited partnerships. Total return includes the change in the market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in the Company at the last reported sale price of units as reported by NASDAQ ($22.00) on January 13, 2006 (the day trading of the units commenced), and in the S&P 500 Index and the Alerian MLP Index on the same date. The results shown in the graph below are not necessarily indicative of future performance.

	January 13, 2006		December 31, 2006		December 31, 2007		December 31, 2008

Linn Energy, LLC	$	100	$	153	$	128	$	87
Alerian MLP Index	$	100	$	120	$	136	$	86
S&P 500 Index	$	100	$	112	$	118	$	75

Notwithstanding anything to the contrary set forth in any of the Company’s previous or future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934 that might incorporate this Form 10-K or future filings with the SEC, in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.

Securities Authorized for Issuance Under Equity Compensation Plans

See the information incorporated by reference under Part III. Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” regarding securities authorized for issuance under the Company’s equity compensation plans, which information is incorporated by reference into this Item 5.

Sales of Unregistered Securities

During the year ended December 31, 2008, the Company issued in private transactions: (i) 410,000 units in connection with the termination of certain contractual obligations (equal to a fair value of approximately $8.7 million) and (ii) 600,000 units in connection with the acquisition of certain gas properties (equal to a fair value of approximately $14.7 million). See Note 5 for additional details.

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Issuer Purchases of Equity Securities

The following sets forth information with respect to the Company with respect to repurchases of its units during the fourth quarter of 2008:

Period	Total Number of Units Purchased		Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Units that May Yet be Purchased Under the Plans or Programs (1)
							(in millions)

December 1 – December 31		1,076,900	$	12.09		1,076,900	$	87.0

(1)

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

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Item 6. Selected Financial Data

The selected financial data set forth below should be read in conjunction with Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8. “Financial Statements and Supplementary Data.”

Because of rapid growth through acquisitions and development of properties, the Company’s historical results of operations and period-to-period comparisons of these results and certain other financial data may not be meaningful or indicative of future results. The results of the Company’s Appalachian Basin and Mid Atlantic operations are classified as discontinued operations for all periods presented (see Note 2). Unless otherwise indicated, results of operations information presented herein relates only to Linn Energy’s continuing operations.

	Year Ended December 31,
	2008			2007			2006			2005			2004
	(in thousands, except per unit amounts)
Statement of operations data:
Oil, gas and natural gas liquid sales	$	755,644		$	255,927		$	21,372		$	―		$	―
Gain (loss) on oil and gas derivatives		662,782			(345,537	)		103,308			(76,193	)		(11,004	)
Depreciation, depletion and amortization		194,093			69,081			4,352			―			―
Interest expense		94,517			38,974			5,909			481			124
Income (loss) from continuing operations		825,657			(356,194	)		69,811			(79,311	)		(12,665	)
Income (loss) from discontinued operations, net of taxes (1)		173,959			(8,155	)		9,374			22,960			7,849
Net income (loss)		999,616			(364,349	)		79,185			(56,351	)		(4,816	)
Income (loss) from continuing operations per unit:
Basic		7.23			(5.17	)		2.33			(3.87	)		(0.62	)
Diluted		7.23			(5.17	)		2.30			(3.87	)		(0.62	)
Income (loss) from discontinued operations per unit:
Basic		1.53			(0.12	)		0.31			1.12			0.39
Diluted		1.52			(0.12	)		0.31			1.12			0.39
Net income (loss) per unit:
Basic		8.76			(5.29	)		2.64			(2.75	)		(0.23	)
Diluted		8.75			(5.29	)		2.61			(2.75	)		(0.23	)
Distributions declared per unit		2.52			2.18			1.15			―			―
Weighted average units outstanding		114,140			68,916			28,281			20,518			20,518

Cash flow data:
Net cash provided by (used in):
Operating activities (2)	$	179,515		$	(44,814	)	$	(6,805	)	$	(29,518	)	$	10,351
Investing activities		(35,550	)		(2,892,420	)		(551,631	)		(150,898	)		(61,373	)
Financing activities		(116,738	)		2,932,080			553,990			189,269			31,167

Balance sheet data:
Total assets	$	4,722,020		$	3,807,703		$	905,912		$	280,924		$	105,425
Long-term debt		1,653,568			1,443,830			428,237			207,695			72,750
Unitholders’ capital (deficit)		2,760,686			2,026,641			450,954			(46,831	)		9,520

(1) Includes gain (loss) on sale of assets, net of taxes.

(2) Includes premiums paid for derivatives of approximately $129.5 million, $279.3 million, $49.8 million and $1.6 million for the years ended December 31, 2008, 2007, 2006 and 2005, respectively.

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	Year Ended December 31,
	2008		2007		2006		2005		2004
Production data:
Average daily production – continuing operations:
Gas (MMcf/d)		124		51		2		―		―
Oil (MBbls/d)		9		3		1		―		―
NGL (MBbls/d)		6		3		―		―		―
Total (MMcfe/d)		212		87		8		―		―
Average daily production – discontinued operations:
Total (MMcfe/d)		12		24		22		13		9

Estimated net proved reserves – continuing operations:
Gas (Bcf)		851		833		77		―		―
Oil (MMBbls)		84		55		30		―		―
NGL (MMBbls)		51		43		―		―		―
Total (Bcfe)		1,660		1,419		255		―		―

Estimated net proved reserves – discontinued operations:
Total (Bcfe)		―		197		199		193		120

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial and Operating Data” and the financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in Part I. Item 1A. “Risk Factors.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

A reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.” Certain amounts in the results of operations contained herein have been reclassified to conform to the 2008 presentation. In particular, results of operations includes categories of expense titled “lease operating expenses,” “transportation expenses,” “exploration costs,” “bad debt expenses,” “impairment of goodwill and long-lived assets,” “taxes, other than income taxes” and “(gain) loss on sale of assets, net” which were not reported in prior period presentations. The new categories present expenses in greater detail than was previously reported and all comparative periods presented have been reclassified to conform to the 2008 financial statement presentation. There was no impact to net income (loss) for prior periods.

Executive Overview

Linn Energy is an independent oil and gas company focused on the development and acquisition of long life properties which complement its asset profile in producing basins within the United States. The Company’s properties are currently located in the Mid-Continent and California.

Proved reserves at December 31, 2008 were 1,660 Bcfe, of which approximately 51% were gas, 31% were oil and 18% were NGL. Approximately 68% were classified as proved developed, with a total standardized measure of discounted future net cash flows of $1.42 billion. At December 31, 2008, the Company operated 4,453, or 66%, of its 6,716 gross productive wells. Average proved reserves-to-production ratio, or average reserve life, is approximately 21 years.

From inception through the date of this report, the Company has completed 25 acquisitions of working and royalty interests in oil and gas properties and related gathering and pipeline assets. Excluding the Appalachian Basin properties sold in July 2008 (discussed below), total acquired proved reserves were approximately 1.7 Tcfe at an acquisition cost of approximately $2.17 per Mcfe. The Company finances acquisitions with a combination of proceeds from the issuance of its units, bank borrowings and cash flow from operations. See Note 3 for additional details about the Company’s recent acquisitions.

On July 1, 2008, the Company completed the sale of its interests in oil and gas properties located in the Appalachian Basin to XTO for a contract price of $600.0 million, subject to closing adjustments (see Note 2). The assets include approximately 197 Bcfe of proved reserves at December 31, 2007. Net proceeds were $566.5 million and the carrying value of net assets sold was $405.8 million, resulting in a gain on the sale of $160.7 million, which is recorded in “discontinued operations: gain (loss) on sale of assets, net of taxes” on the consolidated statement of operations. The Company used the net proceeds from the sale to repay loans outstanding under its term loan agreement and reduce indebtedness under its credit facility (see Note 8). Also, in March 2008, the Company exited the drilling and service business in the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic. During the year ended December 31, 2008, the Company recorded a loss on the sale of the Mid Atlantic assets of $1.6 million, which is also recorded in “discontinued operations: gain (loss) on sale of assets, net of taxes” on the consolidated statement of operations.

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

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Results from continuing operations for the year ended December 31, 2008 included the following:

oil, gas and NGL sales of approximately $755.6 million, compared to $255.9 million in 2007;

daily production of 212 MMcfe/d, compared to 87 MMcfe/d in 2007;

capital expenditures of $321.3 million, excluding expenditures for acquisitions and discontinued operations;

306 wells drilled; and

average of 11 operated drilling rigs.

Asset Sales

During the fourth quarter of 2008, the Company completed a year-long portfolio optimization project. The Company carefully analyzed its asset base to determine which properties best fit the Linn Energy business model with high quality reserves and long life production. During 2008, the Company sold approximately $1.0 billion (contract price) of properties that were non-core to its business strategy, primarily due to high capital requirements and high decline characteristics. The Appalachian Basin sale is discussed above. A summary of the other transactions is as follows:

On August 15, 2008, the Company completed the sale of certain properties in the Verden area in Oklahoma to Laredo for a contract price of $185.0 million, subject to closing adjustments. The assets include approximately 50,000 net acres and 45 Bcfe of proved reserves at December 31, 2007. Net proceeds and the carrying value of net assets sold were $169.4 million. The Verden assets were acquired by the Company with its acquisition of oil and gas properties from Dominion in August 2007. The Company used the net proceeds from the sale to reduce indebtedness (see Note 8).

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 for a contract price of $202.3 million, subject to closing adjustments. The sale included approximately 34,000 net acres and no producing reserves. Linn Energy retains the rights to the shallow portion of this acreage. Net proceeds were $153.2 million and the carrying value of net assets sold was $54.2 million, resulting in a gain on the sale of $99.0 million, which is recorded in “(gain) loss on sale of assets, net” on the consolidated statement of operations. In January 2009, certain post closing matters were resolved and the Company received additional proceeds of $11.5 million, which will be reported as a gain in the first quarter of 2009. Pending resolution of title issues, the Company estimates it may receive additional proceeds ranging from $12.0 million to $18.0 million during the first quarter of 2009. These assets were acquired by the Company with its acquisition of oil and gas properties from Dominion in August 2007. The Company used the net proceeds from the sale to reduce indebtedness (see Note 8).

Unit Repurchase Plan

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Interest Rate Swap Restructuring

	Year 2009			Year 2010			Year 2011			Year 2012			Year 2013			Year 2014 (1)
	(dollars in thousands)

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

(1)	Represents interest rate swaps that settle in January 2014.

Canceled Commodity Contracts

During the year ended December 31, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future gas production resulting in realized losses of $81.4 million. The future gas production under the canceled contracts primarily related to properties in the Appalachian Basin and Verden areas (see Note 2). In addition, in September 2008, the Company canceled (before the contract settlement date) all of its commodity derivative contracts with Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) as counterparty and entered into contracts for substantially the same volumes at identical strike prices with another participant in its credit facility for a cost of approximately $67.6 million. As a result, effective September 17, 2008, Lehman Commodity Services was no longer a counterparty to any of the Company’s commodity derivative contracts and the Company’s overall derivative positions are unchanged.

In September and October 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Commodity Services, respectively, filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”). As of December 31, 2008, the Company had a receivable of approximately $67.6 million from Lehman Commodity Services for canceled derivative contracts (see Note 13). The Company is pursuing various legal remedies to protect its interests. Based on market expectations, at December 31, 2008, the Company estimated approximately $6.7 million of the receivable balance to be collectible. The net receivable of approximately $6.7 million is included in “other current assets, net” on the consolidated balance sheet at December 31, 2008. The related expense is included in "gain (loss) on oil and gas derivatives" on the consolidated statement of operations for the year ended December 31, 2008. The Company believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

Credit and Capital Market Disruption

Multiple events during 2008 involving numerous financial institutions have effectively restricted current liquidity within the capital markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations to provide liquidity to the financial sector, capital markets currently remain constrained. To the extent the Company accesses credit or capital markets in the near term, its ability to obtain terms and pricing similar to its existing terms and pricing may be limited. During 2009, the Company plans to renegotiate its credit facility, which matures in August 2010. Entry into a new credit facility is expected to result in increased interest expense and there can be no assurance that the borrowing base will remain at the current level. In addition, the Company cannot be assured that counterparties to the Company’s derivative contracts will be able to perform under these contracts. For additional information about the Company’s credit risk related to derivative contracts see “Fair Value of Financial Instruments” below. In addition, for information about these and other risk factors that could affect the Company, see Part I. Item 1A. “Risk Factors.”

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Operating Regions

The Company’s oil, gas and NGL properties are located in three regions in the United States:

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

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

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

Mid-Continent Deep

Mid-Continent Shallow

Western

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Results of Operations – Continuing Operations

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

	Year Ended December 31,
	2008			2007			Variance
	(in thousands)
Revenues and other:
Gas sales	$	334,214		$	118,343		$	215,871
Oil sales		291,132			82,523			208,609
NGL sales		130,298			55,061			75,237
Total oil, gas and NGL sales		755,644			255,927			499,717
Gain (loss) on oil and gas derivatives		662,782			(345,537	)		1,008,319
Gas marketing revenues		12,846			11,589			1,257
Other revenues		3,759			2,738			1,021
	$	1,435,031		$	(75,283	)	$	1,510,314
Expenses:
Lease operating expenses	$	115,402		$	41,946		$	73,456
Transportation expenses		17,597			5,575			12,022
Gas marketing expenses		11,070			9,100			1,970
General and administrative expenses (1)		77,391			51,374			26,017
Exploration costs		7,603			4,053			3,550
Bad debt expenses		1,436			―			1,436
Depreciation, depletion and amortization		194,093			69,081			125,012
Impairment of goodwill and long-lived assets		50,505			―			50,505
Taxes, other than income taxes		61,435			22,350			39,085
(Gain) loss on sale of assets, net		(98,763	)		1,767			(100,530	)
	$	437,769		$	205,246		$	232,523
Other income and (expenses)	$	(168,893	)	$	(70,877	)	$	(98,016	)
Income (loss) from continuing operations before income taxes	$	828,369		$	(351,406	)	$	1,179,775

Notes to table:

(1)	General and administrative expenses for the years ended December 31, 2008 and 2007 includes approximately $14.6 million and $13.5 million, respectively, of non-cash unit-based compensation and unit warrant expenses.

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	Year Ended December 31,
	2008		2007		Variance
Average daily production – continuing operations:
Gas (MMcf/d)		124		51		143	%
Oil (MBbls/d)		9		3		200	%
NGL (MBbls/d)		6		3		100	%
Total (MMcfe/d)		212		87		144	%

Average daily production – discontinued operations:
Total (MMcfe/d)		12		24		(50	)%

Weighted average prices (hedged): (1)
Gas (Mcf)	$	8.42	$	8.36		1	%
Oil (Bbl)	$	80.92	$	67.07		21	%
NGL (Bbl)	$	57.86	$	55.51		4	%

Weighted average prices (unhedged): (2)
Gas (Mcf)	$	7.39	$	6.39		16	%
Oil (Bbl)	$	92.78	$	66.44		40	%
NGL (Bbl)	$	57.86	$	55.51		4	%

Representative NYMEX oil and gas prices:
Gas (MMBtu)	$	9.04	$	6.86		32	%
Oil (Bbl)	$	99.65	$	72.34		38	%

Costs per Mcfe of production:
Lease operating expenses	$	1.49	$	1.31		14	%
Transportation expenses	$	0.23	$	0.17		35	%
General and administrative expenses (3)	$	1.00	$	1.61		(38	)%
Depreciation, depletion and amortization	$	2.50	$	2.16		16	%
Taxes, other than income taxes	$	0.79