10-K

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, 2009

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 Global Select Market

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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o     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  oSmaller 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 $2,303,614,114 on June 30, 2009, based on $19.57 per unit, the last reported sales price of the units on The NASDAQ Global Select Market on such date.

As of January 29, 2010, there were 130,566,930 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 April 27, 2010.

TABLE OF CONTENTS

		Page
	Glossary of Terms	ii
	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	26
Item 2.	Properties	26
Item 3.	Legal Proceedings	26
Item 4.	Submission of Matters to a Vote of Security Holders	26
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6.	Selected Financial Data	32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	64
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	113
Item 9A.	Controls and Procedures	113
Item 9B.	Other Information	113
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	114
Item 11.	Executive Compensation	114
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
Item 13.	Certain Relationships and Related Transactions, and Director Independence	114
Item 14.	Principal Accounting Fees and Services	114
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	115
	Signatures	116

i

GLOSSARY OF TERMS

As commonly used in the oil and natural 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 natural gas to one Bbl of oil, condensate or natural gas liquids.

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

Development well.  A well drilled within the proved area of a 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 natural gas to one Bbl of oil, condensate or natural gas liquids.

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

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

MMBtu.  One million British thermal units.

MMcf.  One million cubic feet.

MMcf/d. MMcf per day.

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

MMcfe/d. MMcfe per day.

MMMBtu.  One billion British thermal units.

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

ii

GLOSSARY OF TERMS - Continued

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

Proved developed reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.  Additional reserves 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.  Reserves that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  In accordance with Securities and Exchange Commission regulations, reserves at December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  In accordance with Securities and Exchange Commission regulations, reserves for all prior years were estimated using year-end prices.

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 directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  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 projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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 natural gas and/or oil 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 regulations of the Securities and Exchange Commission, 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%.

iii

GLOSSARY OF TERMS - Continued

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

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, natural gas and NGL regardless of whether such acreage contains proved reserves.

Unproved reserves.  Reserves that are considered less certain to be recovered than proved reserves.  Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.

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.

iv

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 Item 8. “Financial Statements and Supplementary Data.”

Overview

LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering (“IPO”) in January 2006.  The Company’s properties are located in the United States, primarily in the Mid-Continent, California and the Permian Basin.

Proved reserves at December 31, 2009, were 1,712 Bcfe, of which approximately 36% were oil, 45% were natural gas and 19% were natural gas liquids (“NGL”).  Approximately 71% were classified as proved developed, with a total standardized measure of discounted future net cash flows of $1.72 billion.  At December 31, 2009, the Company operated 4,688, or 68%, of its 6,931 gross productive wells and had an average proved reserve-life index of approximately 22 years, based on the December 31, 2009, reserve report and annualized production for the three months ended December 31, 2009.

In January 2010, the Company completed an acquisition of oil and natural gas properties in the Anadarko and Permian Basins for a contract price of $154.5 million.  See “Recent Developments” below for additional details.  On a pro forma basis, including this acquisition, total proved reserves at December 31, 2009, were 1,785 Bcfe, of which approximately 37% were oil, 44% were natural gas and 19% were NGL.

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:

· grow through acquisition of long-life, high quality properties;

· efficiently operate and develop acquired properties; and

· reduce cash flow volatility through commodity price and interest rate hedging.

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

Grow Through Acquisition of Long-Life, High Quality Properties

The Company’s acquisition program targets oil and natural gas properties that are financially accretive and offer stable, 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, development costs and rate of return.  As part of this strategy, the Company continually

1

Item 1.             Business - - Continued

seeks to optimize its asset portfolio, which may include the divestiture of noncore assets.  This allows the Company to redeploy capital into projects to develop lower-risk, long-life and low-decline properties that are better suited to its business strategy.

From inception through the date of this report, excluding 15 acquisitions comprising the Appalachian Basin properties sold in July 2008, the Company has completed 13 acquisitions of working and royalty interests in oil and natural gas properties and related gathering and pipeline assets.  Total acquired proved reserves were approximately 1.8 Tcfe at the time of acquisition at an acquisition cost of approximately $2.15 per Mcfe.  The Company finances acquisitions with a combination of funds from equity and debt offerings, bank borrowings and cash generated from operations.  See Note 2 for additional details about the Company’s acquisitions and divestitures.

Efficiently Operate and Develop Acquired Properties

The Company has centralized 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.  In addition, the Company seeks to deliver attractive financial returns by leveraging its experienced workforce and scalable infrastructure.  For 2010, the Company estimates its capital expenditures, excluding acquisitions, will be between $150.0 million and $175.0 million.  This estimate is under continuous review and is subject to ongoing adjustment.  The Company expects to fund these capital expenditures with cash flow from operations.

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

These transactions are primarily in the form of swap contracts, put options and collars that are designed to provide a fixed price (swap contracts), fixed price floor with opportunity for upside (put options) or range of prices between a price floor and a price ceiling (collars) that the Company will receive as compared to floating market prices.  The Company has derivative contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and $82.50 per Bbl for oil and $8.66 per MMBtu and $9.25 per MMBtu for natural gas, respectively.  Additionally, the Company has derivative contracts in place covering substantially all of its exposure to the Mid-Continent natural gas basis differential.

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 (as defined in Note 6) from a floating rate to a fixed rate.  At January 29, 2010, the Company had LIBOR swaps in place at an average fixed rate of 3.85% through January 2014.  For additional details about the Company’s interest rate swap agreements and commodity derivative contracts, see 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 7 and Note 8.

2

Item 1.             Business - - Continued

Recent Developments

Commodity Derivatives

In February 2010, the Company entered into fixed price oil swaps on an additional 5,250 Bbls per day at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013, bringing the Company’s total such fixed price oil swaps to swaps on 7,250 Bbls per day.  The Company has derivative contracts that extend the swaps for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional details.

Acquisitions

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico, from certain affiliates of Merit Energy Company (“Merit”) for a contract price of $154.5 million.  The transaction was financed with borrowings under the Company’s Credit Facility.  The acquisition provides a strategic addition to the Company’s asset portfolio in the Permian Basin and Mid-Continent, and includes approximately 12 MMBoe (73 Bcfe) of proved reserves as of the acquisition date, primarily oil.

On August 31, 2009, and September 30, 2009, the Company completed the acquisitions of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian Corporation (collectively referred to as “Forest”).  The Company paid $114.4 million in cash, net of cash received from Forest post-closing, and recorded a receivable from Forest, resulting in total consideration for the acquisitions of approximately $113.7 million.  The transactions were financed with borrowings under the Company’s Credit Facility.  The acquisitions represent a strategic entry into the Permian Basin for the Company, and include approximately 10 MMBoe (62 Bcfe) of proved reserves, primarily oil.

Distributions

On January 27, 2010, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the fourth quarter of 2009.  The distribution, totaling approximately $82.3 million, was paid on February 12, 2010, to unitholders of record as of the close of business on February 5, 2010.

Operating Regions

Inclusive of the properties acquired from Merit in January 2010 (see “Acquisitions” above), the Company’s properties are located in four regions in the United States:

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

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

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

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

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 and Kansas, which produce at depths of more than 8,000 feet.  Mid-Continent Deep proved reserves represented approximately 47% of total proved reserves at December 31, 2009, of which 71% were classified as proved developed reserves.

3

Item 1.             Business - - Continued

This region produced 135 MMcfe/d, or 62%, of the Company’s 2009 average daily production.  During 2009, the Company invested approximately $99.3 million to drill in this region.  During 2010, the Company anticipates spending approximately 60% 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 and properties in Oklahoma, Louisiana and Illinois, which produce at depths of less than 8,000 feet.  Mid-Continent Shallow proved reserves represented approximately 38% of total proved reserves at December 31, 2009, of which 66% were classified as proved developed reserves.  This region produced 67 MMcfe/d, or 31%, of the Company’s 2009 average daily production.  During 2009, the Company invested approximately $21.0 million to drill in this region.  During 2010, the Company anticipates spending approximately 20% of its total capital budget for development activities in the Mid-Continent Shallow region.

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

California

The California region consists of the Brea Olinda Field of the Los Angeles Basin.  The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths of 1,000 feet to 7,500 feet.  California proved reserves represented approximately 11% of total proved reserves at December 31, 2009, of which 94% were classified as proved developed reserves.  This region produced 14 MMcfe/d, or 6%, of the Company’s 2009 average daily production.

Permian Basin

The Permian Basin is one of the largest and most prolific oil and natural gas basins in the United States.  The Company’s properties are located in West Texas and Southeast New Mexico and produce at depths ranging from 2,000 feet to 9,000 feet.  Permian Basin proved reserves represented approximately 4% of total proved reserves at December 31, 2009, of which 53% were classified as proved developed reserves.  The properties that comprise this region as of December 31, 2009, were acquired in the third quarter of 2009 (see “Acquisitions” above).  This region produced 2 MMcfe/d, or 1%, of the Company’s 2009 average daily production.  During 2009, the Company invested approximately $0.1 million to drill in this region.  During 2010, the Company anticipates spending approximately 20% of its total capital budget for development activities in the Permian Basin region.

4

Item 1.             Business - - Continued

Drilling and Acreage

The following sets forth the wells drilled in the Mid-Continent Deep, Mid-Continent Shallow, California and Permian Basin 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,
	2009		2008		2007
Gross wells:
Productive		72		304		136
Dry		1		2		2
		73		306		138
Net development wells:
Productive		35		189		112
Dry		1		1		2
		36		190		114
Net exploratory wells:
Productive		—		—		—
Dry		—		—		—
		—		—		—

The totals above do not include 25, 23 and 25 lateral segments added to existing vertical wellbores in the Mid-Continent Shallow region during the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively.  The total wells above exclude 45 and 115 gross wells (45 and 105 net wells) drilled in the Appalachian Basin during the years ended December 31, 2008, and December 31, 2007, respectively.  The Company sold its Appalachian Basin properties in July 2008.  At December 31, 2009, the Company had one gross (one net) well in process (no wells were temporarily suspended).

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 and the quantities or economic value of reserves found.  Productive wells are those that produce commercial quantities of oil, natural 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, 2009:

	Total (1)
Proved undeveloped		1,241
Other locations		3,050
Total drilling locations		4,291
Leasehold interests – net acres (in thousands)		702

(1)      Does not include optimization projects.

As shown in the table above, as of December 31, 2009, the Company had 1,241 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 3,050 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

5

Item 1.             Business - - Continued

number of its unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations.

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, 2009.  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 2,100 productive wells in which the Company owns a royalty interest only.

	Natural Gas Wells				Oil Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Operated (1)		1,947		1,534		2,741		2,523		4,688		4,057
Nonoperated (2)		1,201		207		1,042		72		2,243		279
		3,148		1,741		3,783		2,595		6,931		4,336

(1) 10 operated wells had multiple completions at December 31, 2009.

(2) Three nonoperated wells had multiple completions at December 31, 2009.

Developed and Undeveloped Acreage

The following sets forth information as of December 31, 2009, relating to leasehold acreage:

Developed Acreage

Undeveloped Acreage

Total Acreage

Gross

Net

Gross

Net

Gross

Net

(in thousands)

Leasehold acreage

1,462

648

90

54

1,552

702

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 for additional information).  Unless otherwise indicated, results of operations information presented herein relates only to continuing operations.

The Company’s natural gas production is primarily sold under market sensitive price contracts, which typically sell at a differential to New York Mercantile Exchange (“NYMEX”), Panhandle Eastern Pipeline (“PEPL”), or El Paso Permian Basin natural gas prices due to the Btu content and the proximity to major consuming markets.  The Company’s natural 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 natural gas and NGL recovered after transportation and processing of natural gas.  These purchasers sell the residual natural gas and NGL based primarily on spot market prices.  Under percentage-of-index contracts, the price per MMBtu the Company receives for natural gas is tied to indexes published in Gas Daily or Inside FERC Gas Market Report. Although exact percentages vary daily, as of December 31, 2009, approximately 80% of the Company’s natural gas and NGL production was sold under short-term contracts at market-sensitive or spot prices.  At December 31, 2009, the Company had natural gas throughput delivery commitments under long-term contracts of approximately 2,102 MMcf, 1,045 MMcf and 784 MMcf for the years ended December 31, 2010, December 31, 2011, and December 31, 2012, respectively.

6

Item 1.             Business - - Continued

The Company’s oil production is primarily sold under market sensitive contracts, which typically sell at a differential to NYMEX, and as of December 31, 2009, approximately 75% of its oil production was sold under short-term contracts. At December 31, 2009, the Company had no delivery commitments for oil production.

As discussed in the “Strategy” section above, the Company enters into derivative contracts primarily in the form of swap contracts, put options and collars to reduce the impact of commodity price volatility on its cash flow from operations.  By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow due to fluctuations in commodity prices.

The following sets forth information regarding average daily production, average prices and average costs, from continuing operations, for each of the periods indicated:

	Year Ended December 31,
	2009		2008		2007
Average daily production:
Natural gas (MMcf/d)		125		124		51
Oil (MBbls/d)		9.0		8.6		3.4
NGL (MBbls/d)		6.5		6.2		2.7
Total (MMcfe/d)		218		212		87
Weighted average prices (hedged): (1)
Natural gas (Mcf)	$	8.27	$	8.42	$	8.36
Oil (Bbl)	$	110.94	$	80.92	$	67.07
NGL (Bbl)	$	28.04	$	57.86	$	55.51
Weighted average prices (unhedged): (2)
Natural gas (Mcf)	$	3.51	$	7.39	$	6.39
Oil (Bbl)	$	55.25	$	92.78	$	66.44
NGL (Bbl)	$	28.04	$	57.86	$	55.51
Average NYMEX prices:
Natural gas (MMBtu)	$	3.99	$	9.04	$	6.86
Oil (Bbl)	$	61.94	$	99.65	$	72.34
Costs per Mcfe of production:
Lease operating expenses	$	1.67	$	1.49	$	1.31
Transportation expenses	$	0.23	$	0.23	$	0.17
General and administrative expenses (3)	$	1.08	$	1.00	$	1.61
Depreciation, depletion and amortization	$	2.53	$	2.50	$	2.16
Taxes, other than income taxes	$	0.35	$	0.79	$	0.70

(1) Includes the effect of realized gains on derivatives of $401.0 million (excluding $49.0 million realized net gains on canceled contracts), $9.4 million (excluding $81.4 million realized losses on canceled contracts) and $37.3 million for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively.  The Company utilizes oil puts to hedge revenues associated with its NGL production; therefore, all realized gains on oil derivative contracts are included in weighted average oil prices, rather than weighted average NGL prices.

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

(3) General and administrative expenses for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, include approximately $14.7 million, $14.6 million and $13.5 million, respectively, of noncash unit-based compensation expenses.  Excluding these amounts, general and administrative expenses for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, were $0.90 per Mcfe, $0.81 per Mcfe and $1.19 per Mcfe, respectively.  This measure is not in accordance with United States Generally Accepted Accounting Principles (“GAAP”) and thus is a non-GAAP measure, used by management to analyze the Company’s performance.

7

Item 1.             Business - - Continued

Reserve Data

Modernization of Oil and Natural Gas Reporting Requirements

Effective for fiscal years ending on or after December 31, 2009, the Securities and Exchange Commission (“SEC”) approved revisions designed to modernize reserve reporting requirements for oil and natural gas companies.  In addition, effective for the same period, the Financial Accounting Standards Board issued Accounting Standards Codification Update 2010-03, “Extractive Activities – Oil and Gas (Topic 932) – Oil and Gas Reserve Estimation and Disclosures,” to provide consistency with the new SEC rules.  The Company adopted the new requirements effective December 31, 2009.  The most significant amendments to the requirements include the following:

· commodity prices – economic producibility of reserves estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions;

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

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

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

· nontraditional resources– the definition of oil and natural gas producing activities were expanded and focus on the marketable product rather than the method of extraction.

Proved Reserves

The following sets forth estimated proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows at December 31, 2009, based on reserve reports prepared by independent engineers DeGolyer and MacNaughton:

Estimated proved developed reserves:
Natural gas (Bcf)		549
Oil (MMBbls)		78
NGL (MMBbls)		34
Total (Bcfe)		1,220
Estimated proved undeveloped reserves: (1)
Natural gas (Bcf)		225
Oil (MMBbls)		24
NGL (MMBbls)		20
Total (Bcfe)		492
Estimated total proved reserves (Bcfe)		1,712
Proved developed reserves as a percentage of total proved reserves		71	%
Standardized measure of discounted future net cash flows (in millions) (2)	$	1,723
Representative NYMEX prices: (3)
Natural gas (MMBtu)	$	3.87
Oil (Bbl)	$	61.05

(1) During the year ended December 31, 2009, the Company incurred approximately $52.7 million in capital expenditures to convert 33 Bcfe of reserves previously classified as proved undeveloped into proved developed reserves at December 31, 2009.

(2) This measure is not intended to represent the market value of estimated reserves.

8

Item 1.             Business - - Continued

(3) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGL 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, natural gas and NGL that are ultimately recovered.  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 under the provisions of applicable accounting standards 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 natural 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.

The reserve estimates reported herein were prepared by independent engineers DeGolyer and MacNaughton.  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, based in part on data provided by the Company.  When preparing the reserve estimates, the independent engineering firm did not independently verify the accuracy and completeness of information and data furnished by the Company with respect to ownership interests, 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 that 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.  The 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.  The independent engineering firm 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 SEC staff interpretations and guidance.

The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations.  The preparation of reserve estimates was overseen by the Company’s Reservoir Engineering Advisor, who has Master of Petroleum Engineering and Master of Business Administration degrees and more than 25 years of oil and natural gas industry experience.  The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Senior Vice President and Chief Operating Officer.  For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.”

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, 2009, sales of oil, natural gas and NGL to DCP Midstream Partners, LP, Enbridge Energy Partners, L.P. and ConocoPhillips accounted for approximately 25%, 19% and 12%, respectively, of the Company’s total volumes, or 56% in the aggregate.  If the Company were to lose any one of its major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of its oil and natural gas in that

9

Item 1.             Business - - Continued

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 purchasers ceased purchasing oil and natural gas altogether, it could have a detrimental effect on the oil and natural gas market in general and on the volume of oil and natural gas that the Company is able to sell.

Competition

The oil and natural 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 natural 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 natural 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.  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 addition, the Company participates in wells on a nonoperated basis and therefore may be limited in its ability to control the risks associated with the operation of such wells.

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 has elected to self-insure for certain items for which it has 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.  For more information about potential risks that could affect the Company see Item 1A. “Risk Factors.”

Title to Properties

Prior to the commencement of drilling operations, the Company conducts a 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 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 properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the industry.  Oil and natural 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 in which the Company operates.  These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel,

10

Item 1.             Business - - Continued

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 natural gas typically decreases during the summer months and increases during the winter months.  Seasonal anomalies sometimes lessen this fluctuation.  In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.

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 natural gas industry.  These laws and regulations may:

· require the acquisition of various permits before drilling commences;

· require the installation of expensive pollution control equipment;

· 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, natural gas and NGL production below the rate that would otherwise be possible.  The regulatory burden on the 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 cleanup requirements for the oil and natural 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 and excavations within the 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 natural 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

· United States 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, natural gas and NGL, 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 resources.  States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based

11

Item 1.             Business - - Continued

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, natural 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 natural 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 regulatory issues that could impact the Company include new rules or legislation regulating greenhouse gas emissions to address climate change, such as a proposed cap-and-trade program and the Environmental Protection Agency’s (“EPA”) recent endangerment finding regarding several greenhouse gases, including carbon dioxide, as well as regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process.

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill.  The United States Senate’s version, The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been introduced, but has not passed.  Although these bills include several differences that require reconciliation before becoming law, both bills contain the basic feature of establishing a cap-and-trade system for restricting greenhouse gas emissions in the United States.  Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission allowances corresponding to their annual emissions of greenhouse gases.  The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals.  As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.  The ultimate outcome of this legislative initiative remains uncertain.  In addition to the pending climate legislation, the EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter.  Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations.  The EPA has proposed regulation that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules this year.  Any laws or regulations that may be adopted to restrict or reduce emissions of United States greenhouse gases could require the Company to incur increased operating costs, and could have an adverse effect on demand for oil and natural gas.

The Company cannot predict how future environmental laws and regulations may impact its properties or operations.  For the year ended December 31, 2009, 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 2010 or that will otherwise have a material impact on its financial position or results of operations.

Employees

As of December 31, 2009, the Company employed approximately 550 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,

12

Item 1.             Business - - Continued

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, natural gas and NGL reserves;

· realized oil, natural gas and NGL prices;

· production volumes;

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

· future operating results; and

· plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements.  These forward-looking statements may be found in Item 1. “Business;” Item 1A. “Risk Factors;” 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 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.

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.

13

Item 1A.          Risk Factors - Continued

We may not have sufficient cash flow from operations to pay the quarterly distribution at the current distribution level, or at all, 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, natural gas and NGL;

· prices at which oil, natural 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;

· access to credit or capital markets;

· renegotiation of our Credit Facility at existing terms and pricing; 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, or the distribution may be suspended.

We actively seek to acquire oil and natural gas properties.  Acquisitions involve potential risks that could adversely impact our future growth and our ability to increase or pay distributions at the current level, or at all.

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;

· customer or key employee losses of the acquired businesses; and

· the failure to realize expected growth or profitability.

14

Item 1A.          Risk Factors - Continued

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, 2017 Notes and 2018 Notes (each as defined in Note 6).  Our Credit Facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.

We have significant indebtedness under our Credit Facility, 2017 Notes and 2018 Notes.  As of January 29, 2010, we had an aggregate of approximately $1.7 billion outstanding under our Credit Facility, 2017 Notes and 2018 Notes (with additional borrowing capacity of approximately $422.0 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, enter into commodity and interest rate derivative contracts 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 flow for drilling and development of oil and natural 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.  In addition, we may finance acquisitions through borrowings under our Credit Facility or the incurrence of additional debt.  To the extent that we are unable to incur additional debt under our Credit Facility or otherwise because we are not in compliance with the financial covenants in the Credit Facility, we may not be able to complete acquisitions, which could adversely affect our ability to maintain or increase distributions.

Availability under our Credit Facility is determined semi-annually at the discretion of the lenders and is based in part on oil, natural gas and NGL prices.  Significant declines in oil, natural 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

15

Item 1A.          Risk Factors - Continued

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, natural 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.

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, our ability to make acquisitions 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 and we are unable to effectively hedge our interest rate risk, 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, natural gas and NGL, we enter into commodity derivative contracts for a significant portion of our production.  Commodity derivative arrangements expose us to the risk of financial loss in some circumstances, including situations when the other party to the contract defaults on its contract or production is less than expected.  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, which may adversely affect our ability to pay distributions to our unitholders.

Disruptions in the capital and credit markets 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.

16

Item 1A.          Risk Factors - Continued

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, natural gas and NGL.  The oil, natural 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, natural 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, natural gas and NGL;

· the price and level of foreign imports;

· the level of consumer product demand;

· weather conditions;

· overall domestic and global economic conditions;

· political and economic conditions in oil and natural 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 United States dollar exchange rates on oil, natural 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, natural 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, which could adversely affect our results of operations and limit our ability to borrow funds.

Declines in oil, natural 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 noncash charge to earnings, the carrying value of our properties for impairments.  We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method.  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, natural 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, natural gas and NGL

17

Item 1A.          Risk Factors - Continued

reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing 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, natural gas and NGL in an exact way.  Reserve engineering requires subjective estimates of underground accumulations of oil, natural gas and NGL and assumptions concerning future oil, natural 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, natural 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, natural gas and NGL attributable to any particular group of properties, the classifications of reserves based 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, natural 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, natural gas and NGL reserves.  We base the estimated discounted future net cash flows from our proved reserves on an unweighted average of the first-day-of-the month price for each month during the 12-month calendar year and year-end costs.  However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

· actual prices we receive for oil, natural gas and NGL;

· the amount and timing of actual production;

· the timing and success of development activities;

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

· changes in governmental regulations or taxation.

In addition, the 10% discount factor, required to be used under the provisions of applicable accounting standards 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 natural 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 natural 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, natural 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, natural gas and NGL we are able to produce from existing wells;

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

18

Item 1A.          Risk Factors - Continued

· 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, natural 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, natural 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, natural 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.  In addition, the SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.  At December 31, 2009, we had 1,241 proved undeveloped drilling locations.  To the extent that we do not drill these prospects within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may be required to reclassify such reserves as unproved reserves.  The reclassification of such reserves could also have a negative effect on the borrowing base under our Credit Facility.

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, natural gas and NGL to be commercially viable after drilling, operating and other costs.  If we drill 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, natural gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.

The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of gathering and pipeline systems.  The amount of oil, natural 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, natural 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, natural gas and NGL we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.

19

Item 1A.          Risk Factors - Continued

We depend on certain key customers for sales of our oil, natural 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 nonpayment could have an adverse impact on our financial position and results of operations.

For the year ended December 31, 2009, DCP Midstream Partners, LP, Enbridge Energy Partners, L.P. and ConocoPhillips accounted for approximately 25%, 19% and 12%, respectively, of our total volumes, or 56% in the aggregate.  For the year ended December 31, 2008, DCP Midstream Partners, LP, ConocoPhillips and Enbridge Energy Partners, L.P. accounted for approximately 23%, 12% and 11%, respectively, of our total volumes from continuing operations, or 46% in the aggregate.  To the extent these and other customers reduce the volumes of oil, natural 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, 2009, we had identified 4,291 drilling locations, of which 1,241 were proved undeveloped locations and 3,050 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, natural gas and NGL prices, costs and drilling results.  In addition, DeGolyer and MacNaughton has not estimated proved reserves for the 3,050 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, natural gas and NGL from these or any other 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, natural 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, natural 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;

20

Item 1A.          Risk Factors - Continued

· unusual or unexpected geological formations;

· loss of drilling fluid circulation;

· formations with abnormal pressures;

· fires;

· blowouts, craterings and explosions; and

· uncontrollable flows of oil, natural 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, natural 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.

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, and these costs may not be

21

Item 1A.          Risk Factors - Continued

recoverable from insurance.  For a more detailed discussion of environmental and regulatory matters impacting our business, see 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 natural 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, natural 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 Item 1. “Business - Environmental Matters and Regulation.”

We may issue additional units without unitholder approval, which would dilute existing ownership interests.

We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.

The issuance of additional units or other equity securities may have the following effects:

· an individual unitholder’s proportionate ownership interest in us may decrease;

· the relative voting strength of each previously outstanding unit may be reduced;

· the amount of cash available for distribution per unit may decrease; and

· the market price of the units may decline.

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 nonaffiliated 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

22

Item 1A.          Risk Factors - Continued

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 Internal Revenue Service (“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%.  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.  Any modification to current law or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the requirements for partnership status, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our units.

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.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the cost of an IRS contest will reduce our cash available for distribution to our unitholders.

The IRS may adopt tax positions that differ from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take.  A court may not agree with some or all of the positions we take.  Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade.  In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

23

Item 1A.          Risk Factors - Continued

Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us, even if they do not receive any cash distributions from us.  A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.

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.  For example, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale.

A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof.  Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.

A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits.  This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange.

A unitholder’s taxable gain or loss on the disposition of our units could be more or less than expected.

If unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units.  Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a unit, which decreases their tax basis, will become taxable income to our unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price received is less than their original cost.

A substantial portion of the amount realized, whether or not representing gain, may be ordinary income.  In addition, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.  If the IRS successfully contests some positions we take, unitholders could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and other retirement plans, and non-U.S. persons raises issues unique to them.  For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.  Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income.

We treat each purchaser of units as having the same tax benefits without regard to the units purchased.  The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of our units to a purchaser of units.  We take depletion, depreciation and amortization positions that are intended to maintain such uniformity.  These depletion, depreciation and amortization positions may not conform with all aspects of existing Treasury regulations.  A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders.  It also could affect the timing of these tax

24

Item 1A.          Risk Factors - Continued

benefits or the amount of gain from unitholders’ sale of units and could have a negative impact on the value of our units or result in audit adjustments to unitholder tax returns.

The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the deemed termination of our tax partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.  Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.  If this occurs, our unitholders will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholders with respect to that period.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (or in some cases for periods shorter than a month) based upon the ownership of our units on the first day of each month (or shorter period), instead of on the basis of the date a particular unit is transferred.  The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (or in some cases for periods shorter than a month)based upon the ownership of our units on the first day of each month (or shorter period), instead of on the basis of the date a particular unit is transferred.  The use of this proration method may not be permitted under existing Treasury regulations.  If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units.  If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income.  Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Unitholders may be subject to state and local taxes and return filing requirements in states and jurisdictions where they do not live as a result of investing in our units.

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 2009, we have done business and owned assets in West Virginia, Virginia, Pennsylvania, 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.

25

Item 1A.          Risk Factors - Continued

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

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

The adoption of derivatives legislation by the United States Congress could have an adverse impact on our ability to hedge risks associated with our business.

Several proposals for derivative reform have been developed by committees in the United States House of Representatives and the United States Senate.  These proposals are focused on expanding federal regulation surrounding the use of financial derivative instruments, including credit default swaps, commodity derivatives and other over-the-counter derivatives.  Among the recommendations included in the proposals are the requirements for centralized clearing or settling of such derivatives as well as the expansion of collateral margin requirements for certain derivative-market participants.  Depending on the ultimate form of legislation, our derivatives utilization could be adversely affected with: (i) greater administrative burden; (ii) limitations on the form and use of derivatives; and (iii) expanded collateral margin requirements.

Although it is not possible at this time to predict when the United States Congress may act on derivatives legislation, any laws or regulations that may be adopted that subject us to additional restrictions on our commodity derivative positions could have an adverse effect on our ability to hedge.

Item 1B.          Unresolved Staff Comments

None.

Item 2.             Properties

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

The Company’s obligations under its Credit Facility are secured by mortgages on its oil and natural gas properties.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 6 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

There were no matters submitted to a vote of security holders during the three months ended December 31, 2009.

26

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

Executive Officers of the Company

Name	Age	Position with the Company
Michael C. Linn	58	Executive Chairman of the Board of Directors
Mark E. Ellis	54	President and Chief Executive Officer and Director
Kolja Rockov	39	Executive Vice President and Chief Financial Officer
Charlene A. Ripley	46	Senior Vice President, General Counsel and Corporate Secretary
David B. Rottino	44	Senior Vice President and Chief Accounting Officer
Arden L. Walker, Jr.	50	Senior Vice President and Chief Operating Officer

Michael C. Linn is the Executive Chairman of the Board of Directors of the Company and has served in such capacity since January 2010.  He served as Chairman and Chief Executive Officer from December 2007 to January 2010; Chairman, President and Chief Executive Officer from June 2006 to December 2007; and President, Chief Executive Officer and Director of the Company from March 2003 to June 2006.  Mr. Linn serves on the National Petroleum Council and American Exploration and Production Council.  He serves on the boards of America’s Natural Gas Alliance and the Independent Petroleum Association of America (“IPAA”).  He is also Chairman of the IPAA Political Action Committee and past Chairman of IPAA.  He serves as the Texas Representative for the Legal and Regulatory Affairs Committee of the Interstate Oil and Gas Compact Commission.  He previously served as Chairman of the National Gas Council and Director of the Natural Gas Supply Association.  He is former President of the Independent Oil and Gas Associations of New York, Pennsylvania and West Virginia.  Mr. Linn regularly appears on behalf of the oil and natural gas industry before state and federal agencies, United States Congress and national broadcast media.  His civic affiliations include serving on the boards of the Texas Heart Institute, Museum of Fine Arts Houston and Houston Police Foundation.  In addition, he is the Chairman of the Texas Children’s Hospital Corporate Committee Capital Campaign.  He also serves on the Advisory Board of Houston Children’s Charity and is a member of the Dean’s Executive Advisory Board for the University of Houston C.T. Bauer College of Business.  Mr. Linn graduated cum laude from Villanova University in 1974 with a BA in Political Science cum laude from the University of Baltimore School of Law in 1977.  Following graduation, Mr. Linn went on to practice law for the law firm of Ecker, Ecker, Zofer and Rome.  In 1980, he became General Counsel for Meridian Exploration, where he ultimately served as President and Chief Executive Officer until its sale in 1999.  He served as President of Allegheny Interests, Inc. from 2000 to 2003.

Mark E. Ellis is the President and Chief Executive Officer and a Director of the Company and has served in such capacity since January 2010.  From December 2007 to January 2010, Mr. Ellis served as President and Chief Operating Officer and from December 2006 to December 2007, Mr. Ellis served as Executive Vice President and Chief Operating Officer of the Company.  Mr. Ellis has more than 30 years of experience in the oil and natural 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, a past board member of the New Mexico Oil & Gas Association and previously served on 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, Houston Museum of Natural Science, the Cynthia Woods Mitchell Pavilion, Industry Board of Petroleum Engineering at Texas A&M University and the Visiting Committee of Petroleum Engineering at the Colorado School of Mines.

Kolja Rockov is the Executive Vice President and Chief Financial Officer.  Mr. Rockov has more than 15 years of experience in the oil and natural 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 United States exploration and production sector.  Prior

27

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

to October 2004, Mr. Rockov held various senior positions with RBC Capital Markets and its predecessor companies.

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.  Ms. Ripley served as Vice President, General Counsel and Secretary of Anadarko Canada Corporation and its predecessor companies since 1998.

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 more than 15 years of oil and natural 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.

Arden L. Walker, Jr. is the Senior Vice President and Chief Operating Officer of the Company and has served in such capacity since January 2010.  Mr. Walker joined the Company in February 2007 as Senior Vice President - Operations and Chief Engineer to oversee its Texas, Oklahoma and California operations, 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.  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.

28

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 29, 2010, there were approximately 372 unitholders of record.

The following sets forth 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
2009:
October 1 – December 31	$	28.00	$	22.18	$	0.63
July 1 – September 30	$	23.96	$	18.66	$	0.63
April 1 – June 30	$	20.42	$	14.77	$	0.63
January 1 – March 31	$	16.65	$	12.95	$	0.63
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

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 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.

29

 Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued

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 date 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		December 31, 2009
LINN Energy	$	100	$	153	$	128	$	87	$	185
Alerian MLP Index	$	100	$	120	$	136	$	86	$	151
S&P 500 Index	$	100	$	112	$	118	$	75	$	94

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 Annual Report on 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 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.

30

Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued

Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases.  The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time.  The Company did not repurchase any units during the three months ended December 31, 2009.  At December 31, 2009, approximately $85.4 million was available for unit repurchase under the program.

31

Item 6.             Selected Financial Data

The selected financial data set forth below should be read in conjunction with 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 continuing operations.

	At or for the Year Ended December 31,
	2009			2008			2007			2006			2005
	(in thousands, except per unit amounts)
Statement of operations data:
Oil, natural gas and natural gas liquid sales	$	408,219		$	755,644		$	255,927		$	21,372		$	―
Gain (loss) on oil and natural gas derivatives		(141,374	)		662,782			(345,537	)		103,308			(76,193	)
Depreciation, depletion and amortization		201,782			194,093			69,081			4,352			―
Interest expense, net of amounts capitalized		92,701			94,517			38,974			5,909			481
Income (loss) from continuing operations		(295,841	)		825,657			(356,194	)		69,811			(79,311	)
Income (loss) from discontinued operations, net of taxes (1)		(2,351	)		173,959			(8,155	)		9,374			22,960
Net income (loss)		(298,192	)		999,616			(364,349	)		79,185			(56,351	)
Income (loss) per unit – continuing operations: (2)
Basic		(2.48	)		7.18			(5.17	)		2.30			(3.87	)
Diluted		(2.48	)		7.18			(5.17	)		2.28			(3.87	)
Income (loss) per unit – discontinued operations: (2)
Basic		(0.02	)		1.52			(0.12	)		0.31			1.12
Diluted		(0.02	)		1.52			(0.12	)		0.31			1.12
Net income (loss) per unit: (2)
Basic		(2.50	)		8.70			(5.29	)		2.61			(2.75	)
Diluted		(2.50	)		8.70			(5.29	)		2.59			(2.75	)
Distributions declared per unit		2.52			2.52			2.18			1.15			―
Weighted average units outstanding		119,307			114,140			68,916			28,281			20,518
Cash flow data:
Net cash provided by (used in):
Operating activities (3)	$	426,804		$	179,515		$	(44,814	)	$	(6,805	)	$	(29,518	)
Investing activities		(282,273	)		(35,550	)		(2,892,420	)		(551,631	)		(150,898	)
Financing activities		(150,968	)		(116,738	)		2,932,080			553,990			189,269
Balance sheet data:
Total assets	$	4,340,256		$	4,722,020		$	3,807,703		$	905,912		$	280,924
Long-term debt		1,588,831			1,653,568			1,443,830			428,237			207,695
Unitholders’ capital (deficit)		2,452,004			2,760,686			2,026,641			450,954			(46,831	)

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

(2) Effective January 1, 2009, the Company adopted an accounting standard requiring unvested restricted units to be included in the computation of earnings per unit under the two-class method.  The adoption required retrospective adjustment of all prior period earnings per unit data.  The impact of the adoption was a reduction to income from continuing operations per unit – diluted and net income per unit – diluted, of $0.05 per unit and $0.02 per unit for the years ended December 31, 2008, and December 31, 2006, respectively.  There was no impact for the years ended December 31, 2007, or December 31, 2005.

32

Item 6.             Selected Financial Data - Continued

(3) Includes premiums paid for derivatives of approximately $93.6 million, $129.5 million, $279.3 million, $49.8 million and $1.6 million for the years ended December 31, 2009, December 31, 2008, December 31, 2007, December 31, 2006, and December 31, 2005, respectively.

	At or for the Year Ended December 31,
	2009		2008		2007		2006		2005
Production data:
Average daily production – continuing operations:
Natural gas (MMcf/d)		125		124		51		2		―
Oil (MBbls/d)		9.0		8.6		3.4		0.9		―
NGL (MBbls/d)		6.5		6.2		2.7		―		―
Total (MMcfe/d)		218		212		87		8		―
Average daily production – discontinued operations:
Total (MMcfe/d)		―		12		24		22		13
Estimated proved reserves – continuing operations: (1)
Natural gas (Bcf)		774		851		833		77		―
Oil (MMBbls)		102		84		55		30		―
NGL (MMBbls)		54		51		43		―		―
Total (Bcfe)		1,712		1,660		1,419		255		―
Estimated proved reserves – discontinued operations: (1)
Total (Bcfe)		―		―		197		199		193

(1) In accordance with SEC regulations, reserves at December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  In accordance with SEC regulations, reserves for all prior years were estimated using year-end prices.

33

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 “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”  The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance.  The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control.  The Company’s actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in 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.”

Executive Overview

LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its IPO in January 2006.  The Company’s properties are located in the United States, primarily in the Mid-Continent, California and the Permian Basin.

Proved reserves at December 31, 2009, were 1,712 Bcfe, of which approximately 36% were oil, 45% were natural gas and 19% were NGL.  Approximately 71% were classified as proved developed, with a total standardized measure of discounted future net cash flows of $1.72 billion.  At December 31, 2009, the Company operated 4,688, or 68%, of its 6,931gross productive wells and had an average proved reserve-life index of approximately 22 years, based on the December 31, 2009, reserve report and annualized production for the three months ended December 31, 2009.

In January 2010, the Company completed an acquisition of oil and natural gas properties in the Anadarko and Permian Basins for a contract price of $154.5 million.  See “Acquisitions” below for additional details.  On a pro forma basis, including this acquisition, total proved reserves at December 31, 2009, were 1,785 Bcfe, of which approximately 37% were oil, 44% were natural gas and 19% were NGL.  For additional information regarding estimates of reserves, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data” and see also Item 1. “Business.”

From inception through the date of this report, excluding 15 acquisitions comprising the Appalachian Basin properties sold in July 2008, the Company has completed 13 acquisitions of working and royalty interests in oil and natural gas properties and related gathering and pipeline assets.  Total acquired proved reserves were approximately 1.8 Tcfe at the time of acquisition at an acquisition cost of approximately $2.15 per Mcfe.  The Company finances acquisitions with a combination of funds from equity and debt offerings, bank borrowings and cash generated from operations.  See Note 2 for additional details about the Company’s acquisitions and divestitures.

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 continuing operations.

Results from continuing operations for the year ended December 31, 2009, included the following:

· oil, natural gas and NGL sales of approximately $408.2 million, compared to $755.6 million in 2008;

· average daily production of 218 MMcfe/d, compared to 212 MMcfe/d in 2008;

34

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

· realized gains on commodity derivatives of approximately $450.0 million, compared to realized losses of $72.0 million in 2008;

· adjusted EBITDA of $566.2 million, compared to $514.5 million in 2008;

· adjusted net income of $206.9 million, compared to $174.7 million in 2008;

· capital expenditures, excluding acquisitions, of approximately $149.5 million, compared to $321.3 million in 2008; and

· 73 wells drilled (72 successful), compared to 306 wells drilled (304 successful) in 2008.

Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance.  Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions.  The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives and depreciation, depletion and amortization.  Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to derivative gains and losses, impairment of goodwill and long-lived assets and (gain) loss on sale of assets, net.  See “Non-GAAP Financial Measures” on page 56 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Acquisitions

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico, from Merit for a contract price of $154.5 million.  The transaction was financed with borrowings under the Company’s Credit Facility.  The acquisition provides a strategic addition to the Company’s asset portfolio in the Permian Basin and Mid-Continent, and includes approximately 12 MMBoe (73 Bcfe) of proved reserves as of the acquisition date, primarily oil.

On August 31, 2009, and September 30, 2009, the Company completed the acquisitions of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from Forest.  The Company paid $114.4 million in cash, net of cash received from Forest post-closing, and recorded a receivable from Forest, resulting in total consideration for the acquisitions of approximately $113.7 million.  The transactions were financed with borrowings under the Company’s Credit Facility.  The acquisitions represent a strategic entry into the Permian Basin for the Company, and include approximately 10 MMBoe (62 Bcfe) of proved reserves, primarily oil.

Commodity Derivatives

In February 2010, the Company entered into fixed price oil swaps on an additional 5,250 Bbls per day at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013, bringing the Company’s total such fixed price oil swaps to swaps on 7,250 Bbls per day as presented in the table below.  The Company has derivative contracts that extend the swaps for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.

35

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

The following table summarizes open positions as of February 24, 2010, and represents, as of such date, derivatives in place through December 31, 2013, on annual production volumes:

	February 24 – December 31, 2010			Year 2011			Year 2012			Year 2013
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		32,971			31,901			—			—
Average price ($/MMBtu)	$	8.90		$	9.50		$	—		$	—
Puts:
Hedged volume (MMMBtu)		5,800			6,960			—			—
Average price ($/MMBtu)	$	8.50		$	9.50		$	—		$	—
PEPL puts: (1)
Hedged volume (MMMBtu)		8,862			13,259			—			—
Average price ($/MMBtu)	$	7.85		$	8.50		$	—		$	—
Total:
Hedged volume (MMMBtu)		47,633			52,120			—			—
Average price ($/MMBtu)	$	8.66		$	9.25		$	—		$	—
Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)		1,971			2,073			2,654			2,646
Average price ($/Bbl)	$	90.00		$	90.00		$	100.00		$	100.00
Puts: (3)
Hedged volume (MBbls)		2,062			2,352			—			—
Average price ($/Bbl)	$	110.00		$	75.00		$	—		$	—
Collars:
Hedged volume (MBbls)		229			276			—			—
Average floor price ($/Bbl)	$	90.00		$	90.00		$	—		$	—
Average ceiling price ($/Bbl)	$	112.00		$	112.25		$	—		$	—
Total:
Hedged volume (MBbls)		4,262			4,701			2,654			2,646
Average price ($/Bbl)	$	99.68		$	82.50		$	100.00		$	100.00
Natural gas basis differential positions:
PEPL basis swaps: (1)
Hedged volume (MMMBtu)		35,972			35,541			34,066			31,700
Hedged differential ($/MMBtu)	$	(0.97	)	$	(0.96	)	$	(0.95	)	$	(1.01	)

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

(2) As presented in the table above, the Company has outstanding fixed price oil swaps on 7,250 Bbls per day at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013.  The Company has derivative contracts that extend the swaps for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.

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

36

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

Liquidity and Debt

During 2009, the Company took several steps to strengthen its liquidity and extend its weighted average debt maturities.  In April 2009, the Company amended and restated its existing Credit Facility to extend the maturity to August 2012, and at January 29, 2010, the Company had $422.0 million in available borrowing capacity under the Credit Facility.  In addition, in May 2009, the Company issued $250.0 million in aggregate principal of 11.75% senior notes due 2017 and used the net proceeds of approximately $230.8 million to reduce indebtedness under its Credit Facility.  In May 2009 and October 2009, the Company completed public offerings of units for aggregate net proceeds of approximately $279.3 million, which was used to reduce indebtedness under the Credit Facility.

The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil, natural gas and NGL and provide long-term cash flow predictability to pay distributions, service debt and manage its business.  By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices.  The Company has derivative contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and $82.50 per Bbl for oil and $8.66 per MMBtu and $9.25 per MMBtu for natural gas, respectively.  Additionally, the Company has derivative contracts in place covering substantially all of its exposure to the Mid-Continent natural gas basis differential.

Operating Regions

Inclusive of the properties acquired from Merit in January 2010 (see “Acquisitions” above), the Company’s properties are located in four regions in the United States:

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

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

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

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

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 and Kansas , which produce at depths of more than 8,000 feet.  Mid-Continent Deep proved reserves represented approximately 47% of total proved reserves at December 31, 2009, of which 71% were classified as proved developed reserves.  This region produced 135 MMcfe/d, or 62%, of the Company’s 2009 average daily production.  During 2009, the Company invested approximately $99.3 million to drill in this region.  During 2010, the Company anticipates spending approximately 60% 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 and properties in Oklahoma, Louisiana and Illinois, which produce at depths of less than 8,000 feet.  Mid-Continent Shallow proved reserves represented approximately 38% of total proved reserves at December 31, 2009, of which 66% were classified as proved developed reserves.  This region produced 67 MMcfe/d, or 31%, of the Company’s 2009 average daily production.  During 2009, the Company invested approximately $21.0 million to drill in this region.  During 2010, the Company anticipates spending approximately 20% of its total capital budget for development activities in the Mid-Continent Shallow region.

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

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

California

The California region consists of the Brea Olinda Field of the Los Angeles Basin.  The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths of 1,000 feet to 7,500 feet.  California proved reserves represented approximately 11% of total proved reserves at December 31, 2009, of which 94% were classified as proved developed reserves.  This region produced 14 MMcfe/d, or 6%, of the Company’s 2009 average daily production.

Permian Basin

The Permian Basin is one of the largest and most prolific oil and natural gas basins in the United States.  The Company’s properties are located in West Texas and Southeast New Mexico and produce at depths ranging from 2,000 feet to 9,000 feet.  Permian Basin proved reserves represented approximately 4% of total proved reserves at December 31, 2009, of which 53% were classified as proved developed reserves.  The properties that comprise this region as of December 31, 2009, were acquired in the third quarter of 2009 (see “Acquisitions” above).  This region produced 2 MMcfe/d, or 1%, of the Company’s 2009 average daily production.  During 2009, the Company invested approximately $0.1 million to drill in this region.  During 2010, the Company anticipates spending approximately 20% of its total capital budget for development activities in the Permian Basin region.

38

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

Results of Operations – Continuing Operations

Year Ended December 31, 2009, Compared to Year Ended December 31, 2008

	Year Ended December 31,
	2009			2008			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	160,470		$	334,214		$	(173,744	)
Oil sales		181,619			291,132			(109,513	)
NGL sales		66,130			130,298			(64,168	)
Total oil, natural gas and NGL sales		408,219			755,644			(347,425	)
Gain (loss) on oil and natural gas derivatives (1)		(141,374	)		662,782			(804,156	)
Natural gas marketing revenues		4,380			12,846			(8,466	)
Other revenues		1,924			3,759			(1,835	)
	$	273,149		$	1,435,031		$	(1,161,882	)
Expenses:
Lease operating expenses	$	132,647		$	115,402		$	17,245
Transportation expenses		18,202			17,597			605
Natural gas marketing expenses		2,154			11,070			(8,916	)
General and administrative expenses (2)		86,134			77,391			8,743
Exploration costs		7,169			7,603			(434	)
Bad debt expenses		401			1,436			(1,035	)
Depreciation, depletion and amortization		201,782			194,093			7,689
Impairment of goodwill and long-lived assets		—			50,505			(50,505	)
Taxes, other than income taxes		27,605			61,435			(33,830	)
(Gain) loss on sale of assets and other, net		(24,598	)		(98,763	)		74,165
	$	451,496		$	437,769		$	13,727
Other income and (expenses)	$	(121,715	)	$	(168,893	)	$	47,178
Income (loss) from continuing operations before income taxes	$	(300,062	)	$	828,369		$	(1,128,431	)
Adjusted EBITDA (3)	$	566,235		$	514,487		$	51,748
Adjusted net income (3)	$	206,922		$	174,663		$	32,259

(1) During the year ended December 31, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized net gains of approximately $49.0 million, primarily associated with the Company’s commodity derivative repositioning in July 2009 (see Note 7).  During the year ended December 31, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future natural gas production primarily associated with properties in the Appalachian Basin and Verden areas (see Note 2) resulting in realized losses of approximately $81.4 million.

(2) General and administrative expenses for the years ended December 31, 2009, and December 31, 2008, include approximately $14.7 million and $14.6 million, respectively, of noncash unit-based compensation expenses.

(3) This is a non-GAAP measure used by management to analyze Company performance.  See “Non-GAAP Financial Measures” on page 56 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

39

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

	Year Ended December 31,
	2009		2008		Variance
Average daily production:
Natural gas (MMcf/d)		125		124		1	%
Oil (MBbls/d)		9.0		8.6		5	%
NGL (MBbls/d)		6.5		6.2		5	%
Total (MMcfe/d)		218		212		3	%
Weighted average prices (hedged): (1)
Natural gas (Mcf)	$	8.27	$	8.42		(2	)%
Oil (Bbl)	$	110.94	$	80.92		37	%
NGL (Bbl)	$	28.04	$	57.86		(52	)%
Weighted average prices (unhedged): (2)
Natural gas (Mcf)	$	3.51	$	7.39		(53	)%
Oil (Bbl)	$	55.25	$	92.78		(40	)%
NGL (Bbl)	$	28.04	$	57.86		(52	)%
Average NYMEX prices:
Natural gas (MMBtu)	$	3.99	$	9.04		(56	)%
Oil (Bbl)	$	61.94	$	99.65		(38	)%
Costs per Mcfe of production:
Lease operating expenses	$	1.67	$	1.49		12	%
Transportation expenses	$	0.23	$	0.23		—
General and administrative expenses (3)	$	1.08	$	1.00		8	%
Depreciation, depletion and amortization	$	2.53	$	2.50		1	%
Taxes, other than income taxes	$	0.35	$	0.79		(56	)%

(1) Includes the effect of realized gains on derivatives of approximately $401.0 million (excluding $49.0 million realized net gains on canceled contracts) and $9.4 million (excluding $81.4 million realized losses on canceled contracts) for the years ended December 31, 2009, and December 31, 2008, respectively.  The Company utilizes oil puts to hedge revenues associated with its NGL production; therefore, all realized gains (losses) on oil derivative contracts are included in weighted average oil prices, rather than weighted average NGL prices.

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

(3) General and administrative expenses for the years ended December 31, 2009, and December 31, 2008, include approximately $14.7 million and $14.6 million, respectively, of noncash unit-based compensation expenses.  Excluding these amounts, general and administrative expenses for the years ended December 31, 2009, and December 31, 2008, were $0.90 per Mcfe and $0.81 per Mcfe, respectively.  This is a non-GAAP measure used by management to analyze the Company’s performance.

40

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales decreased by approximately $347.4 million, or 46%, to approximately $408.2 million for the year ended December 31, 2009, from $755.6 million for the year ended December 31, 2008, due to lower commodity prices.  Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $123.3, $177.6 million and $70.3 million, respectively.

Average daily production increased to 218 MMcfe/d during the year ended December 31, 2009, from 212 MMcfe/d during the year ended December 31, 2008.  Volume increases during the year ended December 31, 2009, resulted in an increase in total oil, natural gas and NGL revenues of approximately $23.8 million compared to the year ended December 31, 2008.

The following sets forth average daily production by region:

	Year Ended December 31,
	2009		2008		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		135		136		(1	)	(1	)%
Mid-Continent Shallow		67		63		4		6	%
California		14		13		1		8	%
Permian Basin		2		—		2		—
		218		212		6		3	%

The 1% decrease in average daily production in the Mid-Continent Deep region primarily reflects the Company’s sale of assets in Oklahoma in August 2008 (see Note 2), its decision to suspend completions on recent wells drilled in the Granite Wash and shut-in production on certain wells.  The 6% increase in average daily production in the Mid-Continent Shallow region reflects results of the Company’s drilling and optimization programs, partially offset by natural declines.  The California region consists of a low-decline asset base and continues to produce at levels consistent with the prior year.  The Permian Basin properties were acquired in the third quarter of 2009 (see Note 2).

Gain (Loss) on Oil and Natural Gas Derivatives

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for additional information about commodity derivatives.  During the year ended December 31, 2009, the Company had commodity derivative contracts for approximately 113% of its natural gas production and 80% of its oil and NGL production, which resulted in realized gains of approximately $450.0 million (including realized net gains on canceled contracts of approximately $49.0 million).  During the year ended December 31, 2009, the Company repositioned its commodity derivative portfolio to help protect against sustained weakness in commodity prices.  The Company canceled oil and natural gas derivative contracts for years 2012 through 2014 and used the realized net gains of approximately $44.8 million, along with an incremental premium payment of approximately $48.8 million, to raise prices for oil and natural gas derivative contracts in years 2010 and 2011.  During the year ended December 31, 2008, the Company recorded realized losses of approximately $72.0 million (including realized losses on canceled contracts of approximately $81.4 million).  Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives.  During 2009, expected future oil and natural gas prices increased, which resulted in unrealized losses on derivatives of approximately $591.4 million for the year ended December 31, 2009.  During the second half of 2008, expected future oil and natural gas prices decreased, which resulted in unrealized gains on derivatives of approximately $734.7 million for the year ended December 31, 2008.  For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

41

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

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses.  Lease operating expenses increased by approximately $17.2 million, or 15%, to $132.6 million for the year ended December 31, 2009, from $115.4 million for the year ended December 31, 2008.  Lease operating expenses per Mcfe also increased, to $1.67 per Mcfe for the year ended December 31, 2009, from $1.49 per Mcfe for the year ended December 31, 2008.  Lease operating expenses increased primarily due to costs associated with properties acquired in the first quarter of 2008 in the Mid-Continent Shallow region and the third quarter of 2009 in the Permian Basin region (see Note 2).  Lease operating expenses are generally higher for oil properties than for natural gas properties.  Materials and service cost increases across all operating regions and higher chemical and treating costs associated with certain wells drilled in late 2008 also contributed to the increase.

Transportation Expenses

Transportation expenses increased by approximately $0.6 million, or 3%, to $18.2 million for the year ended December 31, 2009, from $17.6 million for the year ended December 31, 2008, primarily due to increased production volumes.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees and executive officers, related benefits, office leases and professional fees.  General and administrative expenses increased by approximately $8.7 million, or 11%, to $86.1 million for the year ended December 31, 2009, from $77.4 million for the year ended December 31, 2008.  General and administrative expenses per Mcfe also increased, to $1.08 per Mcfe for the year ended December 31, 2009, from $1.00 per Mcfe for the year ended December 31, 2008.  The increase was primarily due to an increase in salaries and benefits expense of approximately $7.3 million, driven primarily by an increase in employee headcount.

Exploration Costs

Exploration costs decreased by approximately $0.4 million, or 5%, to $7.2 million for the year ended December 31, 2009, from $7.6 million for the year ended December 31, 2008.  The decrease was primarily due to a decrease in 3-D seismic and data library expense of approximately $2.2 million, partially offset by an increase in impairment expense on unproved properties of approximately $1.8 million.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $7.7 million, or 4%, to $201.8 million for the year ended December 31, 2009, from $194.1 million for the year ended December 31, 2008.  Higher total production levels were the main reason for the increase.  Depreciation, depletion and amortization per Mcfe increased to $2.53 per Mcfe for the year ended December 31, 2009, from $2.50 per Mcfe for the year ended December 31, 2008.

Impairment of Goodwill and Long-Lived Assets

During the year ended December 31, 2008, the Company recorded impairment expense of approximately $50.5 million of which approximately $20.3 million was associated with impairment of goodwill and approximately $30.2 million was associated with impairment of proved oil and natural gas properties.  The Company recorded no impairment for the year ended December 31, 2009.  See Note 1 and “Critical Accounting Policies and Estimates” below for additional information.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, decreased by approximately $33.8 million, or 55%, to $27.6 million for the year ended December 31, 2009, from $61.4 million for the year ended December 31, 2008.  Production taxes, which are a function of revenues generated from production, decreased by approximately $30.2 million compared to the year ended December 31, 2008, primarily due to lower commodity prices.  Tax credits related to incentive programs for deep wells and marketing deductions

42

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

also contributed to the decrease.  Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased slightly compared to the year ended December 31, 2008.

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

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

Other Income and (Expenses)

	Year Ended December 31,
	2009			2008			Variance
	(in thousands)
Interest expense, net of amounts capitalized	$	(92,701	)	$	(94,517	)	$	1,816
Realized loss on interest rate swaps		(42,941	)		(16,036	)		(26,905	)
Unrealized gain (loss) on interest rate swaps		16,588			(50,638	)		67,226
Other, net		(2,661	)		(7,702	)		5,041
	$	(121,715	)	$	(168,893	)	$	47,178

Other income and (expenses) decreased by approximately $47.2 million during the year ended December 31, 2009, compared to the year ended December 31, 2008.  Interest expense decreased, driven by lower interest rates on the Credit Facility due to lower LIBOR rates.  The unrealized mark-to-market change on interest rate swaps was a positive impact, as the forward rate curve decreased less during the year ended December 31, 2009, than it did during the year ended December 31, 2008.  This was partially offset by increased realized losses on interest rate swaps during the year ended December 31, 2009, compared to the year ended December 31, 2008.  In addition, the Company wrote off deferred financing fees of approximately $6.7 million during the year ended December 31, 2008.

Income Tax Benefit (Expense)

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders.  Limited liability companies are subject to state income taxes in Texas.  In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  The Company recognized income tax benefit of approximately $4.2 million and income tax expense of approximately $2.7 million for the years ended December 31, 2009, and December 31, 2008, respectively.  Income tax benefit for the year ended December 31, 2009, is primarily due to a release of the valuation allowance on a significant portion of deferred tax assets.  Income tax expense for the year ended December 31, 2008, primarily represents Texas margin tax expense.

Income (Loss) From Continuing Operations

Income (loss) from continuing operations was loss of approximately $295.8 million for the year ended December 31, 2009, and income of approximately $825.7 million for the year ended December 31, 2008, due to lower oil, natural gas and NGL revenues as a result of lower commodity prices during the year ended December 31, 2009, combined with the impact of unrealized losses on commodity derivatives.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $51.7 million, or 10%, to $566.2 million for the year ended December 31, 2009, from $514.5 million for the year ended December 31, 2008,

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

primarily due to increased realized gains on commodity derivatives, offset by lower oil, natural gas and NGL revenues due to lower commodity prices.  See “Non-GAAP Financial Measures” on page 56 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.

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

	Year Ended December 31,
	2008			2007			Variance
	(in thousands)
Revenues and other:
Natural 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, natural gas and NGL sales		755,644			255,927			499,717
Gain (loss) on oil and natural gas derivatives (1)		662,782			(345,537	)		1,008,319
Natural 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
Natural gas marketing expenses		11,070			9,100			1,970
General and administrative expenses (2)		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 and other, 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
Adjusted EBITDA (3)	$	514,487		$	257,732		$	256,755
Adjusted net income (3)	$	174,663		$	57,908		$	116,755

(1) During the year ended December 31, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future natural gas production primarily associated with properties in the Appalachian Basin and Verden areas (see Note 2) resulting in realized losses of approximately $81.4 million.

(2) General and administrative expenses for the years ended December 31, 2008, and December 31, 2007, include approximately $14.6 million and $13.5 million, respectively, of noncash unit-based compensation expenses.

(3) This is a non-GAAP measure used by management to analyze Company performance.  See “Non-GAAP Financial Measures” on page 56 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

44

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

	Year Ended December 31,
	2008		2007		Variance
Average daily production:
Natural gas (MMcf/d)		124		51		143	%
Oil (MBbls/d)		8.6		3.4		153	%
NGL (MBbls/d)		6.2		2.7		130	%
Total (MMcfe/d)		212		87		144	%
Weighted average prices (hedged): (1)
Natural 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)
Natural gas (Mcf)	$	7.39	$	6.39		16	%
Oil (Bbl)	$	92.78	$	66.44		40	%
NGL (Bbl)	$	57.86	$	55.51		4	%
Average NYMEX prices:
Natural 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	$	0.70		13	%

(1) Includes the effect of realized gains on derivatives of approximately $9.4 million (excluding $81.4 million losses on canceled contracts) and $37.3 million for the years ended December 31, 2008, and December 31, 2007, respectively.  The Company utilizes oil puts to hedge revenues associated with its NGL production; therefore, all realized gains (losses) on oil derivative contracts are included in weighted average oil prices, rather than weighted average NGL prices.

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

(3) General and administrative expenses for the years ended December 31, 2008, and December 31, 2007, include approximately $14.6 million and $13.5 million, respectively, of noncash unit-based compensation expenses.  Excluding these amounts, general and administrative expenses for the years ended December 31, 2008, and December 31, 2007, were $0.81 per Mcfe and $1.19 per Mcfe, respectively.  This is a non-GAAP measure used by management to analyze the Company’s performance.

45

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $499.7 million, or 195%, to approximately $755.6 million for the year ended December 31, 2008, from $255.9 million for the year ended December 31, 2007.  Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $82.6 million, $45.5 million and $5.3 million, respectively.

Average daily production increased to 212 MMcfe/d during the year ended December 31, 2008, from 87 MMcfe/d during the year ended December 31, 2007.  Volume increases during the year ended December 31, 2008, resulted in an increase in total oil, natural gas and NGL revenues of approximately $366.3 million compared to the year ended December 31, 2007.

The following sets forth average daily production by region:

	Year Ended December 31,
	2008		2007		Variance
Average daily production (MMcfe/d):
Mid-Continent Deep		136		47		89	189	%
Mid-Continent Shallow		63		28		35	125	%
California		13		12		1	8	%
		212		87		125	144	%

The 189% increase in average daily production in the Mid-Continent Deep region is primarily due to the Company’s acquisition of properties in August 2007, which contributed approximately 126 MMcfe per day during 2008.  The 125% increase in average daily production in the Mid-Continent Shallow region is primarily due to the Company’s acquisition of properties in January 2008, which contributed approximately 24 MMcfe per day during 2008.  The California region consists of a low-decline asset base and continues to produce at levels consistent with the prior year.

Gain (Loss) on Oil and Natural Gas Derivatives

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  See Note 7 and Note 8 for additional information about commodity derivatives.  During the year ended December 31, 2008, the Company had commodity derivative contracts for approximately 112% of its natural gas production and 82% of its oil and NGL production, which resulted in realized losses of approximately $72.0 million (including realized losses on canceled contracts of approximately $81.4 million).  During the year ended December 31, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future natural gas production primarily associated with properties in the Appalachian Basin and Verden areas (see Note 2) resulting in realized losses of $81.4 million.  During the year ended December 31, 2007, the Company recorded realized gains of approximately $37.3 million.  Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives.  During the second half of 2008, expected future oil and natural gas prices decreased, which resulted in unrealized gains on derivatives of approximately $734.7 million for the year ended December 31, 2008.  During 2007, expected future oil and natural gas prices increased, which resulted in unrealized losses on derivatives of approximately $382.8 million for the year ended December 31, 2007.  For information about the Company’s credit risk related to derivative contracts see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.

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

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses.  Lease operating expenses increased by approximately $73.5 million, or 175%, to $115.4 million for the year ended December 31, 2008, from $41.9 million for the year ended December 31, 2007.  Lease operating expenses per Mcfe also increased, to $1.49 per Mcfe for the year ended December 31, 2008, from $1.31 per Mcfe for the year ended December 31, 2007.  Lease operating expenses increased primarily due to higher production and costs associated with the 2007 and 2008 acquisitions in the Mid-Continent Deep and Mid-Continent Shallow regions.

Transportation Expenses

Transportation expenses increased by approximately $12.0 million, or 214%, to $17.6 million for the year ended December 31, 2008, from $5.6 million for the year ended December 31, 2007, primarily due to increased production from the 2007 and 2008 acquisitions in the Mid-Continent Deep and Mid-Continent Shallow regions.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and include costs of employees and executive officers, related benefits, office leases and professional fees.  General and administrative expenses increased by approximately $26.0 million, or 51%, to $77.4 million for the year ended December 31, 2008, from $51.4 million for the year ended December 31, 2007.  The increase in general and administrative expenses was primarily due to costs incurred to support the Company’s increased size and infrastructure growth, including the addition of a regional operating office in Oklahoma.  Salaries and benefits expense and employee unit-based compensation expense increased approximately $17.2 million and $2.5 million, respectively, during the year ended December 31, 2008, compared to the year ended December 31, 2007.  Information technology costs, such as software, data administration and data conversion costs increased by approximately $3.6 million during the year ended December 31, 2008, compared to the year ended December 31, 2007.  In addition, control of well insurance expense increased by approximately $2.7 million during the year ended December 31, 2008, primarily for properties in the Mid-Continent Deep region acquired in August 2007.  The increase in general and administrative expenses was partially offset by lower professional service fees, unit warrant expenses and recovery of expenses under a transition services agreement.

Although total general and administrative expenses increased, expenses per equivalent unit of production decreased to $1.00 per Mcfe for the year ended December 31, 2008, compared to $1.61 per Mcfe for the year ended December 31, 2007, due to increases in production, cost efficiencies and economies of scale provided by acquired properties.

Exploration Costs

Exploration costs increased by approximately $3.5 million, or 85%, to $7.6 million for the year ended December 31, 2008, from $4.1 million for the year ended December 31, 2007, primarily due to increased impairment expense on unproved properties acquired in the Mid-Continent Deep region in August 2007.

Bad Debt Expenses

During the year ended December 31, 2008, the Company recorded bad debt expense of approximately $1.4 million associated with accounts receivable from a customer that filed for bankruptcy.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $125.0 million, or 181%, to $194.1 million for the year ended December 31, 2008, from $69.1 million for the year ended December 31, 2007.  Higher total production levels, primarily due to the Company’s acquisitions in the Mid-Continent Deep and Mid-Continent Shallow regions in 2007 and 2008, were the main reason for the increase.  Depreciation, depletion and amortization per Mcfe increased to $2.50 per Mcfe for the year ended December 31, 2008, from $2.16 per Mcfe for the year

47

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

ended December 31, 2007, primarily due to higher depletion rates on properties acquired in the Mid-Continent Deep region in August 2007, as compared to the Company’s other properties.

Impairment of Goodwill and Long-Lived Assets

During the year ended December 31, 2008, the Company recorded impairment expense of approximately $50.5 million of which approximately $20.3 million was associated with impairment of goodwill and approximately $30.2 million was associated with impairment of proved oil and natural gas properties.  See Note 1 and “Critical Accounting Policies and Estimates” below for additional information.

Taxes, Other Than Income Taxes

Taxes, other than income taxes, which consist primarily of production and ad valorem taxes, increased by approximately $39.0 million, or 174%, to $61.4 million for the year ended December 31, 2008, from $22.4 million for the year ended December 31, 2007.  Production taxes, which are a function of revenues generated from production, increased by approximately $32.4 million compared to the year ended December 31, 2007.  Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $6.9 million compared to 2007.

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

The Company recorded a gain of approximately $99.0 million from the sale of Woodford Shale assets during the year ended December 31, 2008, (see Note 2).

Other Income and (Expenses)

	Year Ended December 31,
	2008			2007			Variance
	(in thousands)
Interest expense, net of amounts capitalized	$	(94,517	)	$	(38,974	)	$	(55,543	)
Realized gain (loss) on interest rate swaps		(16,036	)		1,467			(17,503	)
Unrealized loss on interest rate swaps		(50,638	)		(29,548	)		(21,090	)
Other, net		(7,702	)		(3,822	)		(3,880	)
	$	(168,893	)	$	(70,877	)	$	(98,016	)

Other income and (expenses) increased by approximately $98.0 million, primarily due to an increase in interest expense of approximately $55.5 million related to higher debt levels associated with borrowings to fund acquisitions and drilling.  In addition, total losses on interest rate swaps increased by approximately $38.6 million over the year ended December 31, 2007.  The changes in fair values of these instruments were recorded as unrealized losses of approximately $50.6 million and $29.5 million for the years ended December 31, 2008, and December 31, 2007, respectively.

Income Tax Expense

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders.  Limited liability companies are subject to state income taxes in Texas.  In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  Income tax expense was approximately $2.7 million and $4.8 million for the years ended December 31, 2008, and December 31, 2007, respectively.  Income tax expense for the year ended December 31, 2008, primarily represents Texas margin tax expense.  Tax expense for the year ended December 31, 2007, relates primarily to 2006 expense recovery.  The Company’s taxable subsidiaries generated net operating losses for the year ended December 31, 2006.  During the year ended December 31, 2007, expenses were recovered by Linn Operating, Inc. through an

48

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

intercompany charge for services to LINN Energy, which resulted in income tax expense for LINN Energy for the year ended December 31, 2007.

Income (Loss) From Continuing Operations

Income (loss) from continuing operations was income of approximately $825.7 million for the year ended December 31, 2008, and loss of approximately $356.2 million for the year ended December 31, 2007, due to increased production revenues during the year ended December 31, 2008, resulting from the Company’s acquisition of properties in August 2007 and January 2008, and to higher oil, natural gas and NGL prices.

Adjusted EBITDA

Adjusted EBITDA (a non-GAAP financial measure) increased by approximately $256.8 million, or 100%, to $514.5 million for the year ended December 31, 2008, from $257.7 million for the year ended December 31, 2007, primarily due to increased production revenues resulting from the Company’s acquisition of properties in August 2007 and January 2008, and to higher oil, natural gas and NGL prices.  See “Non-GAAP Financial Measures” on page 56 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Reserve Replacement Metrics

The Company calculates two primary reserve metrics: (i) reserve replacement cost and (ii) reserve replacement ratio, to measure its ability to establish a long-term trend of adding reserves at a reasonable cost.  The reserve replacement cost calculation provides an assessment of the cost of adding reserves that is ultimately included in depreciation, depletion and amortization expense.  The reserve replacement ratio is an indicator of the Company’s ability to replenish annual production volumes and grow reserves.  The metrics are calculated as follows:

Reserve replacement cost per Mcfe	=	Oil and natural gas capital costs expended (1)
		Sum of reserve additions (2)
Reserve replacement ratio	=	Sum of reserve additions (2)
		Annual production

(1) Oil and natural gas capital costs expended include the costs of property acquisition, exploration and development activities conducted to add reserves and exclude asset retirement obligation costs.  The Company expects to incur development costs in the future for proved undeveloped reserves; such future costs are excluded from costs expended and are not considered in the reserve replacement metrics presented herein.

(2) Reserve additions include proved reserves (developed and undeveloped) and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities.

The reserve replacement metrics are presented separately, both: (i) including and excluding the impact of price revisions on reserves, to demonstrate the effectiveness of the Company’s drilling program exclusive of economic factors (such as price) outside of its control and (ii) including and excluding acquisitions, to demonstrate the Company’s ability to add reserves through its drilling program and through acquisitions.  Reserve replacement cost and reserve replacement ratio are non-GAAP financial measures.  The methods used by the Company to calculate these measures may differ from methods used by other companies to compute similar measures.  As a result, the Company’s measures may not be comparable to similar measures provided by other companies.  The Company believes that providing such measures is useful in evaluating the cost to add proved reserves; however, these measures should not be considered in isolation or as a substitute for GAAP measures.  The reserve replacement cost per Mcfe and reserve replacement ratio are statistical indicators that have limitations, including their predictive and comparative value.  The reserve replacement ratio is limited because it may vary widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions.  In addition, since the reserve replacement

49

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

ratio does not consider the development cost or timing of future production of new reserves, it should not be used as a measure of value creation.

The following presents reserve replacement cost and reserve replacement ratio from continuing operations, including and excluding the effect of price revisions on reserves:

	Including Price Revisions									Excluding Price Revisions
	Year Ended December 31,									Year Ended December 31,
	2009			2008			2007			2009			2008			2007
Costs per Mcfe of production:
Reserve replacement cost, including acquisitions	$	1.96		$	2.44		$	2.23		$	1.71		$	1.53		$	2.38
Reserve replacement cost, excluding acquisitions (finding and development cost)	$	2.03		NM (1)			$	1.16		$	1.59		$	1.44		$	2.74
Percentage of production:
Reserve replacement ratio, including acquisitions		165	%		475	%		3,745	%		189	%		756	%		3,521	%
Reserve replacement ratio, excluding acquisitions		88	%	NM (1)				389	%		112	%		282	%		165	%

(1) Not meaningful due to the impact of a significant decrease in year-end commodity prices, primarily oil, at December 31, 2008, compared to December 31, 2007, which offset reserve additions.

Amounts used in these calculations reflect continuing operations only and are derived directly from the table presented in “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.”  The following provides a reconciliation of oil and natural gas capital costs used in these calculations to its most directly comparable financial measure calculated and presented in accordance with GAAP:

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Costs incurred in oil and natural gas property acquisition, exploration and development – continuing operations	$	258,105		$	900,256		$	2,674,439
Less:
Asset retirement obligation costs		(371	)		(680	)		(3,868	)
Property acquisition costs		(115,929	)		(584,630	)		(2,525,772	)
Oil and natural gas capital costs expended, excluding acquisitions – continuing operations	$	141,805		$	314,946		$	144,799

Liquidity and Capital Resources

The Company utilizes funds from equity and debt offerings, bank borrowings and cash generated from operations for capital resources and liquidity.  To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties.  For the year ended December 31, 2009, the Company’s capital expenditures, excluding acquisitions, were approximately $149.5 million.  For 2010, the Company estimates its capital expenditures, excluding acquisitions, will be between $150.0 million and $175.0 million.  This estimate is under continuous review and is subject to ongoing adjustment.  The Company expects to fund these capital expenditures with cash flow from operations.

As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures.  The Company’s future success in growing reserves and production

50

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

will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves.  The Company actively reviews acquisition opportunities on an ongoing basis.  If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts, if available, or obtain additional debt or equity financing.  The Company’s Credit Facility and other borrowings impose certain restrictions on the Company’s ability to obtain additional debt financing.

During 2009, the Company took several steps to strengthen its liquidity and extend its weighted average debt maturities.  In April 2009, the Company amended and restated its existing Credit Facility to extend the maturity to August 2012, and at January 29, 2010, the Company had $422.0 million in available borrowing capacity under the Credit Facility.  In addition, in May 2009, the Company issued $250.0 million in aggregate principal of 11.75% senior notes due 2017 and used the net proceeds of approximately $230.8 million to reduce indebtedness under its Credit Facility.  In May 2009 and October 2009, the Company completed public offerings of units for aggregate net proceeds of approximately $279.3 million, which were used to reduce indebtedness under the Credit Facility.  Based upon current expectations the Company believes liquidity and capital resources will be sufficient for the conduct of its business and operations.

Statements of Cash Flows

The following is a comparative cash flow summary:

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Net cash:
Provided by (used in) operating activities (1)	$	426,804		$	179,515		$	(44,814	)
Used in investing activities		(282,273	)		(35,550	)		(2,892,420	)
Provided by (used in) financing activities		(150,968	)		(116,738	)		2,932,080
Net increase (decrease) in cash and cash equivalents	$	(6,437	)	$	27,227		$	(5,154	)

(1) The years ended December 31, 2009, December 31, 2008, and December 31, 2007, include premiums paid for derivatives of approximately $93.6 million, $129.5 million and $279.3 million, respectively.

Operating Activities

Cash provided by operating activities for the year ended December 31, 2009, was approximately $426.8 million, compared to $179.5 million for the year ended December 31, 2008.  The increase was primarily due to higher realized gains from oil and natural gas derivatives, offset by reduced revenues associated with lower commodity prices in 2009.

In comparison, cash used in operating activities was $44.8 million for the year ended December 31, 2007.  The use of cash for operating activities was impacted by premiums paid for commodity derivatives of approximately $279.3 million during the year ended December 31, 2007, compared to $129.5 million during the year ended December 31, 2008.  These commodity derivatives were utilized by the Company to achieve a more predictable cash flow by reducing exposure to price fluctuations and were funded through the Company’s Credit Facility.

Premiums paid during 2009, 2008 and 2007, noted in the table above, were for commodity derivative contracts that hedge future production.  These derivative contracts provide the Company long-term cash flow predictability to manage its business, service debt and pay distributions and are primarily funded through the Company’s Credit Facility.  The amount of derivative contracts the Company enters into in the future will be directly related to expected future production.  See Note 7 and Note 8 for additional details about commodity derivatives.

51

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

Investing Activities

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties	$	(130,735	)	$	(593,412	)	$	(2,677,575	)
Capital expenditures		(178,242	)		(339,724	)		(219,383	)
Proceeds from sale of properties and equipment		26,704			897,586			4,538
	$	(282,273	)	$	(35,550	)	$	(2,892,420	)

The primary use of cash in investing activities is for capital spending, which is offset by proceeds from asset sales.  Cash used in investing activities was approximately $282.3 million for the year ended December 31, 2009, compared to $35.6 million for the year ended December 31, 2008.  Cash used in investing activities for the year ended December 31, 2009, includes approximately $114.4 million for the acquisition of Permian Basin properties in the Mid-Continent Shallow region (see Note 2).

Cash used in investing activities for the year ended December 31, 2008, includes approximately $510.6 million for the acquisition of properties in the Mid-Continent Shallow region and proceeds from asset sales totaling approximately $897.6 million, primarily from the sale of properties in the Appalachian Basin, the Verden area in Oklahoma, and the Woodford Shale interval in Oklahoma (see Note 2).  In comparison, cash used in investing activities was approximately $2.89 billion for the year ended December 31, 2007, and includes approximately $2.03 billion for the acquisition of properties in the Mid-Continent Deep region and $555.5 million for the acquisition of properties in the Mid-Continent Shallow region.

Financing Activities

Cash used in financing activities was approximately $151.0 million for the year ended December 31, 2009, compared to $116.7 million for the year ended December 31, 2008.  The change in financing cash flow was primarily due to increased operating cash flow and decreased acquisition and development activity during 2009, which resulted in lower net borrowings compared to 2008.  In comparison, cash provided by financing activities was $2.93 billion for the year ended December 31, 2007, primarily due to $2.09 billion received from the sale of units in private placement transactions (see Note 3).  The following provides a comparative summary of proceeds from borrowings and repayments of debt:

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Proceeds from borrowings:
Credit facility	$	401,500		$	809,000		$	1,298,000
Senior notes		237,703			250,000			—
Term loan		—			400,000			—
	$	639,203		$	1,459,000		$	1,298,000
Repayments of debt:
Credit facility	$	(704,893	)	$	(848,608	)	$	(280,750	)
Term loan		—			(400,000	)		—
Notes payable		—			(1,564	)		(2,358	)
	$	(704,893	)	$	(1,250,172	)	$	(283,108	)

52

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

Debt

On April 28, 2009, the Company entered into an amended and restated Credit Facility, with an initial borrowing base of $1.75 billion and a maturity of August 2012, which amended and restated the Company’s existing credit facility, which had a maturity of August 2010.  The terms of the Credit Facility required that, upon the issuance of the 2017 Notes in May 2009 (see below) and cancellation of certain commodity derivatives in July 2009 (see Note 7), the borrowing base be decreased by approximately $62.5 million and $45.0 million, respectively, to $1.64 billion, which remained the borrowing base at January 29, 2010.  At January 29, 2010, available borrowing capacity was $422.0 million, which includes a $5.5 million reduction in availability for outstanding letters of credit.

In May 2009, the Company issued $250.0 million in aggregate principal amount of the Company’s 11.75% senior notes due 2017.  The Company used the net proceeds of approximately $230.8 million to reduce indebtedness under its Credit Facility.  In addition, in 2008, the Company issued $255.9 million in aggregate principal amount of the Company’s 9.875% senior notes due 2018.  The Company used the net proceeds of approximately $243.6 million to repay an outstanding term loan.  For additional information about the Company’s debt instruments, such as interest rates and covenants, see Note 6.  The Company is in compliance with all financial and other covenants of the Credit Facility and senior notes.

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

Counterparty Credit Risk

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

Public Offering of Units

In October 2009, the Company sold 8,625,000 units representing limited liability company interests at $21.90 per unit ($21.024 per unit, net of underwriting discount) for net proceeds of approximately $181.1 million.  In addition, in May 2009, the Company sold 6,325,000 units representing limited liability company interests at $16.25 per unit ($15.60 per unit, net of underwriting discount) for net proceeds of approximately $98.2 million.  The Company used the net proceeds from each offering to reduce indebtedness under the Credit Facility.  See Note 3 for additional information about the equity offerings.

53

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

Distributions

Under the limited liability company agreement, unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses.  The following provides a summary of distributions paid by the Company during the year ended December 31, 2009:

Date Paid	Period Covered by Distribution	Distribution Per Unit		Total Distribution
				(in millions)
November 2009	July 1 – September 30, 2009	$	0.63	$	81.9
August 2009	April 1 – June 30, 2009	$	0.63		76.4
May 2009	January 1 – March 31, 2009	$	0.63		72.5
February 2009	October 1 – December 31, 2008	$	0.63		72.5
				$	303.3

On January 27, 2010, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the fourth quarter of 2009.  The distribution, totaling approximately $82.3 million, was paid on February 12, 2010, to unitholders of record as of the close of business on February 5, 2010.

Off-Balance Sheet Arrangements

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

Contingencies

In 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code.  At December 31, 2009, and December 31, 2008, the Company had a net receivable of approximately $6.7 million from Lehman Commodity Services for canceled derivative contracts, which is included in “other current assets” on the consolidated balance sheets.  The value of the receivable was estimated based on market expectations.  The Company is pursuing various legal remedies to protect its interests and believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

During the years ended December 31, 2009, December 31, 2008, and December 31, 2007, the Company made no significant payments to settle any legal, environmental or tax proceedings.  The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters, as necessary.  Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

54

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

Commitments and Contractual Obligations

The following summarizes, as of December 31, 2009, certain long-term contractual obligations that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes thereto:

	Payments Due
Contractual Obligations	Total		2010		2011 – 2012		2013 – 2014		2015 and Beyond
	(in thousands)
Long-term debt obligations:
Credit facility	$	1,100,000	$	—	$	1,100,000	$	—	$	—
Senior notes		505,927		—		—		—		505,927
Interest (1)		516,141		87,428		161,197		109,296		158,220
Operating lease obligations:
Office, property and equipment leases		29,965		3,954		7,811		6,526		11,674
Other noncurrent liabilities:
Asset retirement obligations		33,135		—		—		—		33,135
Other:
Commodity derivatives		45,654		8,185		5,787		14,271		17,411
Interest rate swaps		69,386		42,839		26,547		—		—
Services agreement		1,845		1,165		680		—		—
Charitable contributions		750		250		500		—		—
Executive severance		185		185		—		—		—
	$	2,302,988	$	144,006	$	1,302,522	$	130,093	$	726,367

(1) Represents interest on the Credit Facility computed at the weighted average LIBOR of 2.98% through maturity in August 2012 and interest on the 2017 Notes and 2018 Notes computed at fixed rates of 11.75% and 9.875% through maturity in May 2017 and July 2018, respectively.

Capital Structure

The Company’s capitalization is presented below:

	December 31,
	2009		2008
	(in thousands)
Cash and cash equivalents	$	22,231	$	28,668
Credit facility	$	1,100,000	$	1,403,393
Senior notes due 2017, net		238,275		―
Senior notes due 2018, net		250,556		250,175
		1,588,831		1,653,568
Total unitholders’ capital		2,452,004		2,760,686
	$	4,040,835	$	4,414,254

55

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

Non-GAAP Financial Measures

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

Adjusted EBITDA (Non-GAAP Measure)

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

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

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

· Interest expense;

· Depreciation, depletion and amortization;

· Impairment of goodwill and long-lived assets;

· Write-off of deferred financing fees and other;

· (Gain) loss on sale of assets, net;

· Unrealized (gain) loss on commodity derivatives;

· Unrealized (gain) loss on interest rate derivatives;

· Realized (gain) loss on interest rate derivatives;

· Realized (gain) loss on canceled derivatives;

· Unit-based compensation expenses;

· Exploration costs; and

· Income tax (benefit) expense.

56

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

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Income (loss) from continuing operations	$	(295,841	)	$	825,657		$	(356,194	)
Plus:
Net operating cash flow from acquisitions and divestitures, effective date through closing date (1)		3,708			3,436			67,417
Interest expense, cash		74,185			81,704			35,974
Interest expense, noncash		18,516			12,813			3,000
Depreciation, depletion and amortization		201,782			194,093			69,081
Impairment of goodwill and long-lived assets		—			50,505			—
Write-off of deferred financing fees and other		204			6,728			3,460
(Gain) loss on sale of assets, net		(23,051	)		(98,763	)		1,767
Unrealized (gain) loss on commodity derivatives		591,379			(734,732	)		388,733
Reclassification of derivative settlements (2)		—			—			(5,946	)
Unrealized (gain) loss on interest rate derivatives		(16,588	)		50,638			29,548
Realized (gain) loss on interest rate derivatives (3)		42,881			16,036			(1,467	)
Realized (gain) loss on canceled derivatives		(48,977	)		81,358			—
Unit-based compensation expenses		15,089			14,699			13,518
Exploration costs		7,169			7,603			4,053
Income tax (benefit) expense		(4,221	)		2,712			4,788
Adjusted EBITDA from continuing operations	$	566,235		$	514,487		$	257,732

(1) Includes net operating cash flow from acquisitions and divestitures.

(2) During 2008, the Company revised its classification of realized and unrealized gains (losses) on natural gas derivative contracts in order to match realized gains (losses) with the related production.  Amounts reported in adjusted EBITDA for all prior periods have been reclassified to conform to current period presentation.  This reclassification had no effect on the Company’s reported net income.

(3) During 2009, the Company revised its definition of adjusted EBITDA to include realized (gains) losses on interest rate derivatives in order to match the related interest expense.  Amounts reported in adjusted EBITDA for all prior periods have been reclassified to conform to current period presentation.  This reclassification had no effect on the Company’s reported net income.

Net cash provided by operating activities for the year ended December 31, 2009, was approximately $426.8 million and includes cash interest payments of approximately $73.9 million, premiums paid for commodity derivatives of approximately $93.6 million, cash settlements on interest rate derivatives of approximately $41.7 million, realized gains on canceled derivatives of approximately $(49.0) million and other items of approximately $(20.8) million that are not included in adjusted EBITDA.  Net cash provided by operating activities for the year ended December 31, 2008, was approximately $179.5 million and includes cash interest payments of approximately $95.0 million, premiums paid for commodity derivatives of approximately $129.5 million, cash settlements on interest rate derivatives of approximately $13.9 million, realized losses on canceled derivatives of approximately $81.4 million and other items of approximately $15.2 million that are not included in adjusted EBITDA.  Net cash used in operating activities for the year ended December 31, 2007, was approximately $(44.8) million and includes cash interest payments of approximately $57.3 million, premiums paid for commodity derivatives of approximately $279.3 million and other items of approximately $(34.1) million that are not included in adjusted EBITDA.

57

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

Adjusted Net Income (Non-GAAP Measure)

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

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands, except per unit amounts)
Income (loss) from continuing operations	$	(295,841	)	$	825,657		$	(356,194	)
Plus:
Unrealized (gain) loss on commodity derivatives		591,379			(734,732	)		388,733
Reclassification of derivative settlements		—			—			(5,946	)
Unrealized (gain) loss on interest rate derivatives		(16,588	)		50,638			29,548
Realized (gain) loss on canceled derivatives		(48,977	)		81,358			—
Impairment of goodwill and long-lived assets		—			50,505			—
(Gain) loss on sale of assets, net		(23,051	)		(98,763	)		1,767
Adjusted net income from continuing operations	$	206,922		$	174,663		$	57,908
Income (loss) from continuing operations per unit – basic	$	(2.48	)	$	7.18		$	(5.17	)
Plus, per unit:
Unrealized (gain) loss on commodity derivatives		4.95			(6.39	)		5.64
Reclassification of derivative settlements		—			—			(0.09	)
Unrealized (gain) loss on interest rate derivatives		(0.14	)		0.44			0.43
Realized (gain) loss on canceled derivatives		(0.41	)		0.71			—
Impairment of goodwill and long-lived assets		—			0.44			—
(Gain) loss on sale of assets, net		(0.19	)		(0.86	)		0.03
Adjusted net income from continuing operations per unit – basic	$	1.73		$	1.52		$	0.84

58

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

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with United States generally accepted accounting principles (“GAAP”).  The preparation of the consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events.  These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.  The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and NGL, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, fair values of commodity and interest rate derivatives, and fair values of assets acquired and liabilities assumed.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions.  As future events and their effects cannot be determined with precision, actual results could differ from these estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Below, the Company has provided expanded discussion of its more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of financial statements.  See Note 1 for details about additional accounting policies and estimates made by Company management.

Oil and Natural Gas Reserves

Proved reserves are based on the quantities of oil, natural gas and NGL that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.  The independent engineering firm DeGolyer and MacNaughton prepared a reserve and economic evaluation of all of the Company properties on a well-by-well basis as of December 31, 2009, and the reserve estimates reported herein were prepared by DeGolyer and MacNaughton.  The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Senior Vice President and Chief Operating Officer.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations.  As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates.  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, based in part on data provided by the Company.  The 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.

The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.  In addition, reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results.  As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and NGL eventually recovered.  For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data” and see also Item 1. “Business.”

59

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

Oil and Natural Gas Properties

Proved Properties

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

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable.  The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value.  The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.  Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.  The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.  Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently.  Gains or losses from the disposal of other properties are recognized currently.  Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred.  Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.  The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells.  Interest is capitalized only during the periods in which these assets are brought to their intended use.  The Company capitalized interest costs from continuing operations of $0.3 million, $0.9 million and $0.5 million for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively.

Unproved Properties

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

Impairment

Based on the analysis described above, the Company recorded noncash impairment of proved properties of approximately $30.2 million before and after tax for the year ended December 31, 2008, which is included in “impairment of goodwill and long-lived assets” on the consolidated statements of operations.  The Company recorded no impairment of proved properties in continuing operations for the years ended December 31, 2009, or December 31, 2007.  The Company recorded noncash impairment of unproved properties of approximately $6.3 million and $4.5 million for the years ended December 31, 2009, and December 31, 2008, which is included in

60

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

“exploration costs” on the consolidated statements of operations.  The Company recorded no such impairment for the year ended December 31, 2007.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs.  The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Revenue Recognition

Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.

The Company has elected the entitlements method to account for natural gas production imbalances.  Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production.  In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability.  If the Company receives less than its entitled share, the underproduction is recorded as a receivable.  At December 31, 2009, and December 31, 2008, the Company had natural gas production imbalance receivables of approximately $16.4 million and $17.1 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $8.8 million and $9.9 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements.  As such, the Company separately reports third-party marketing sales and natural gas marketing expenses.  Marketing margins related to the Company’s production are included in oil, natural gas and NGL sales.

Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations.  Estimated asset retirement costs are recognized when the obligation is incurred, and are amortized over proved developed reserves using the units of production method.  Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations.  The fair values of additions to the asset retirement obligation liability are estimated using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate.  Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations (see Note 10).

Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil, natural gas and NGL.  By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices.  These transactions are primarily in the form of swap contracts, put options and collars.  A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap

61

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

price and the market price.  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 price floor over the market price at the settlement date.  A collar specifies the range of prices that the Company will receive as compared to floating market prices and on the settlement date offers the Company the opportunity to receive up to the price ceiling while protecting against downside risk below the price floor.  In addition, the Company enters into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates.

Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities.  The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  The Company determines the fair value of its derivative financial instruments utilizing pricing models for significantly similar instruments.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.  See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for sensitivity analysis regarding the Company’s derivative financial instruments.

Acquisition Accounting

The Company accounts for business combinations under the acquisition method of accounting in accordance with an accounting standard adopted by the Company effective January 1, 2009, (see Note 2).  Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values.  Transaction and integration costs associated with business combinations are expensed as incurred.

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.  The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.  The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors.  To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.  In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties within the same regions, and uses that data as a proxy for fair market value; i.e., the amount a willing buyer and seller would enter into in exchange for such properties.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill while any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain.  Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities.  Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

While the estimated fair values of the assets acquired and liabilities assumed have no effect on cash flow, they can have an effect on future results of operations.  Generally, higher fair values assigned to oil and natural gas properties result in higher future depreciation, depletion and amortization expense, which results in decreased future net earnings.  Also, a higher fair value assigned to oil and natural gas properties, based on higher future estimates of commodity prices, could increase the likelihood of impairment in the event of lower commodity prices or higher operating costs than those originally used to determine fair value.  The recording of impairment expense has no effect on cash flow but results in a decrease in net income for the period in which the impairment is recorded.

62

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

Unit-Based Compensation

The Company recognizes expense for unit-based compensation over the requisite service period, in an amount equal to the fair value of unit-based payments granted to employees and nonemployee directors.  See Note 1 and Note 5 for additional details about the Company’s accounting for unit-based compensation.

New Accounting Standards

See Note 12 and Note 17 for details regarding the Company’s implementation of new accounting standards.

63

Item 7A.     Quantitative and Qualitative Disclosures About Market Risk

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

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Annual Report on Form 10-K.  A reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”

Commodity Price Risk

The Company enters into derivative contracts with respect to a portion of its projected production through various transactions that provide an economic hedge of the risk related to the future prices received.  The Company does not enter into derivative contracts for trading purposes (see Note 7).  At December 31, 2009, the fair value of contracts that settle during the next 12 months was an asset of approximately $227.6 million and a liability of $8.1 for a net asset of approximately $219.5 million.  A 10% increase in the index oil and natural gas prices above the December 31, 2009, prices for the next 12 months would result in a net asset of approximately $130.7 million which represents a decrease in the fair value of approximately $88.8 million; conversely, a 10% decrease in the index oil and natural gas prices would result in a net asset of approximately $310.3 million which represents an increase in the fair value of approximately $90.8 million.

Interest Rate Risk

At December 31, 2009, the Company had long-term debt outstanding under its Credit Facility of approximately $1.10 billion, which incurred interest at floating rates (see Note 6).  A 1% increase in LIBOR would result in an estimated $11.0 million increase in annual interest expense.  The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates (see Note 7).

Counterparty Credit Risk

The Company accounts for its commodity and interest rate derivatives at fair value on a recurring basis (see Note 8).  The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.

At December 31, 2009, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 4.25%.  A 1% increase in the average public bond yield spread would result in an estimated $2.1 million increase in net income for the year ended December 31, 2009.  At December 31, 2009, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 1.35%.  A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $3.3 million decrease in net income for the year ended December 31, 2009.

64

Item 8.             Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page
Management’s Report on Internal Control Over Financial Reporting	66
Report of Independent Registered Public Accounting Firm (Financial Statements)	67
Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting)	68
Consolidated Balance Sheets, as of December 31, 2009, and December 31, 2008	69
Consolidated Statements of Operations, for the years ended December 31, 2009, December 31, 2008, and December 31, 2007	70
Consolidated Statements of Unitholders’ Capital, for the years ended December 31, 2009, December 31, 2008, and December 31, 2007	71
Consolidated Statements of Cash Flows, for the years ended December 31, 2009, December 31, 2008, and December 31, 2007	72
Notes to Consolidated Financial Statements	73
Supplemental Oil and Natural Gas Data (Unaudited)	105
Supplemental Quarterly Data (Unaudited)	111

65

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended.  Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

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

As of December 31, 2009, our management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2009, based on those criteria.  KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, which is included herein.

/s/ Linn Energy, LLC

66

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders

Linn Energy, LLC:

We have audited the accompanying consolidated balance sheets of Linn Energy, LLC and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, unitholders’ capital, and cash flows for each of the years in the three-year period ended December 31, 2009.  These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Linn Energy, LLC and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Linn Energy, LLC’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2010, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 25, 2010

67

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders

Linn Energy, LLC:

We have audited Linn Energy, LLC’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Linn Energy, LLC’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audit also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

In our opinion, Linn Energy, LLC maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Linn Energy, LLC and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, unitholders’ capital and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 25, 2010, expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 25, 2010

68

LINN ENERGY, LLC

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009			2008
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	22,231		$	28,668
Accounts receivable – trade, net		109,311			138,983
Derivative instruments		249,756			368,951
Other current assets		28,162			27,329
Total current assets		409,460			563,931
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		4,076,795			3,831,183
Less accumulated depletion and amortization		(463,413	)		(278,805	)
		3,613,382			3,552,378
Other property and equipment		118,867			111,459
Less accumulated depreciation		(23,583	)		(13,171	)
		95,284			98,288
Derivative instruments		145,457			493,705
Other noncurrent assets		76,673			13,718
		222,130			507,423
Total noncurrent assets		3,930,796			4,158,089
Total assets	$	4,340,256		$	4,722,020
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	124,358		$	163,662
Derivative instruments		51,025			47,005
Other accrued liabilities		33,922			27,163
Total current liabilities		209,305			237,830
Noncurrent liabilities:
Credit facility		1,100,000			1,403,393
Senior notes, net		488,831			250,175
Derivative instruments		53,923			39,350
Other noncurrent liabilities		36,193			30,586
Total noncurrent liabilities		1,678,947			1,723,504
Unitholders’ capital:
129,940,617 units and 114,079,533 units issued and outstanding at December 31, 2009, and December 31, 2008, respectively		2,098,599			2,109,089
Accumulated income		353,405			651,597
		2,452,004			2,760,686
Total liabilities and unitholders’ capital	$	4,340,256		$	4,722,020

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

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LINN ENERGY, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2009			2008			2007
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	408,219		$	755,644		$	255,927
Gain (loss) on oil and natural gas derivatives		(141,374	)		662,782			(345,537	)
Natural gas marketing revenues		4,380			12,846			11,589
Other revenues		1,924			3,759			2,738
		273,149			1,435,031			(75,283	)
Expenses:
Lease operating expenses		132,647			115,402			41,946
Transportation expenses		18,202			17,597			5,575
Natural gas marketing expenses		2,154			11,070			9,100
General and administrative expenses		86,134			77,391			51,374
Exploration costs		7,169			7,603			4,053
Bad debt expenses		401			1,436			―
Depreciation, depletion and amortization		201,782			194,093			69,081
Impairment of goodwill and long-lived assets		―			50,505			―
Taxes, other than income taxes		27,605			61,435			22,350
(Gain) loss on sale of assets and other, net		(24,598	)		(98,763	)		1,767
		451,496			437,769			205,246
Other income and (expenses):
Interest expense, net of amounts capitalized		(92,701	)		(94,517	)		(38,974	)
Loss on interest rate swaps		(26,353	)		(66,674	)		(28,081	)
Other, net		(2,661	)		(7,702	)		(3,822	)
		(121,715	)		(168,893	)		(70,877	)
Income (loss) from continuing operations before income taxes		(300,062	)		828,369			(351,406	)
Income tax benefit (expense)		4,221			(2,712	)		(4,788	)
Income (loss) from continuing operations		(295,841	)		825,657			(356,194	)
Discontinued operations:
Gain (loss) on sale of assets, net of taxes		(158	)		159,045			936
Income (loss) from discontinued operations, net of taxes		(2,193	)		14,914			(9,091	)
		(2,351	)		173,959			(8,155	)
Net income (loss)	$	(298,192	)	$	999,616		$	(364,349	)
Income (loss) per unit – continuing operations:
Basic	$	(2.48	)	$	7.18		$	(5.17	)
Diluted	$	(2.48	)	$	7.18		$	(5.17	)
Income (loss) per unit – discontinued operations:
Basic	$	(0.02	)	$	1.52		$	(0.12	)
Diluted	$	(0.02	)	$	1.52		$	(0.12	)
Net income (loss) per unit:
Basic	$	(2.50	)	$	8.70		$	(5.29	)
Diluted	$	(2.50	)	$	8.70		$	(5.29	)
Weighted average units outstanding:
Basic		119,307			114,140			68,916
Diluted		119,307			114,158			68,916
Distributions declared per unit	$	2.52		$	2.52		$	2.18

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

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LINN ENERGY, LLC

CONSOLIDATED STATEMENTS OF UNITHOLDERS’ CAPITAL

	Units			Unitholders’ Capital			Accumulated Income (Deficit)			Treasury Units (at Cost)			Total Unitholders’ Capital
	(in thousands)
December 31, 2006		42,803		$	434,624		$	16,330		$	―		$	450,954
Sale of units, net of expenses of $34,334		69,874			2,085,666			―			―			2,085,666
Issuance of units		1,366			2,811			―			―			2,811
Cancellation of units		(227	)		(7,399	)		―			7,399			―
Purchase of units					―			―			(7,399	)		(7,399	)
Distributions to unitholders					(154,963	)		―			―			(154,963	)
Unit-based compensation expenses					13,921			―			―			13,921
Net loss					―			(364,349	)		―			(364,349	)
December 31, 2007		113,816			2,374,660			(348,019	)		―			2,026,641
Issuance of units		1,435			23,483			―			―			23,483
Cancellation of units		(1,171	)		(14,998	)		―			14,998			―
Purchase of units					―			―			(14,998	)		(14,998	)
Distributions to unitholders					(289,915	)		―			―			(289,915	)
Unit-based compensation expenses					15,677			―			―			15,677
Reclassification of distributions paid on forfeited restricted units					182			―			―			182
Net income					―			999,616			―			999,616
December 31, 2008		114,080			2,109,089			651,597			―			2,760,686
Sale of units, net of underwriting discounts and expenses of $12,369		14,950			279,299			―			―			279,299
Issuance of units		1,098			494			―			―			494
Cancellation of units		(187	)		(2,696	)		―			2,696			―
Purchase of units					―			―			(2,696	)		(2,696	)
Distributions to unitholders					(303,316	)		―			―			(303,316	)
Unit-based compensation expenses					15,089			―			―			15,089
Reclassification of distributions paid on forfeited restricted units					63			―			―			63
Excess tax benefit from unit-based compensation					577			―			―			577
Net loss					―			(298,192	)		―			(298,192	)
December 31, 2009		129,941		$	2,098,599		$	353,405		$	―		$	2,452,004

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

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LINN ENERGY, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(298,192	)	$	999,616		$	(364,349	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		201,782			200,306			94,200
Impairment of goodwill and long-lived assets		―			50,505			3,343
Unit-based compensation expenses		15,089			15,677			13,921
Bad debt expenses		401			1,436			―
Amortization and write-off of deferred financing fees and other		21,824			17,024			5,746
(Gain) loss on sale of assets, net		(23,243	)		(257,808	)		831
Deferred income tax		(6,436	)		―			3,360
Mark-to-market on derivatives:
Total (gains) losses		167,727			(596,108	)		373,618
Cash settlements		362,936			(20,901	)		40,784
Cash settlements on canceled derivatives		48,977			(81,358	)		―
Premiums paid for derivatives		(93,606	)		(129,520	)		(279,313	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		29,117			9,572			(117,361	)
(Increase) decrease in other assets		(3,051	)		(8,455	)		3,286
Increase (decrease) in accounts payable and accrued expenses		(4,675	)		(36,451	)		161,844
Increase in other liabilities		8,154			15,980			15,276
Net cash provided by (used in) operating activities		426,804			179,515			(44,814	)
Cash flow from investing activities:
Acquisition of oil and natural gas properties		(130,735	)		(593,412	)		(2,677,575	)
Development of oil and natural gas properties		(170,458	)		(330,615	)		(185,534	)
Purchases of other property and equipment		(7,784	)		(9,109	)		(33,849	)
Proceeds from sale of properties and equipment		26,704			897,586			4,538
Net cash used in investing activities		(282,273	)		(35,550	)		(2,892,420	)
Cash flow from financing activities:
Proceeds from sale of units		291,668			―			2,120,000
Purchase of units		(2,696	)		(14,998	)		(7,399	)
Proceeds from borrowings		639,203			1,459,000			1,298,000
Repayments of debt		(704,893	)		(1,250,172	)		(283,108	)
Distributions to unitholders		(303,316	)		(289,915	)		(154,963	)
Financing fees, offering expenses and other, net		(70,934	)		(20,653	)		(40,450	)
Net cash provided by (used in) financing activities		(150,968	)		(116,738	)		2,932,080
Net increase (decrease) in cash and cash equivalents		(6,437	)		27,227			(5,154	)
Cash and cash equivalents:
Beginning		28,668			1,441			6,595
Ending	$	22,231		$	28,668		$	1,441

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

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Basis of Presentation and Significant Accounting Policies

(a)          Nature of Business

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005.  The Company completed its initial public offering (“IPO”) in January 2006 and its units representing limited liability company interests (“units”) are listed on The NASDAQ Global Select Market under the symbol “LINE.”  LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  The Company’s properties are located in the United States, primarily in the Mid-Continent, California and the Permian Basin.

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

(b)          Principles of Consolidation and Reporting

The Company presents its financial statements in accordance with United States generally accepted accounting principles (“GAAP”).  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.  All significant intercompany transactions and balances have been eliminated upon consolidation.  Subsequent events were evaluated through the issuance date of the financial statements.

(c)          Discontinued Operations

The Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. (“Mid Atlantic”) operations have been classified as discontinued operations on the consolidated statements of operations for all periods presented.  Unless otherwise indicated, information about the consolidated statements of operations that is presented in the notes to consolidated financial statements relates only to continuing operations.

(d)          Use of Estimates

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events.  These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.  The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, fair values of commodity and interest rate derivatives, and fair values of assets acquired and liabilities assumed.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions.  As future events and their effects

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

cannot be determined with precision, actual results could differ from these estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

(e)          Cash Equivalents

For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.

(f)           Accounts Receivable – Trade, Net

Trade accounts receivable are recorded at the invoiced amount and do not bear interest.  The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio.  In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data.  The Company reviews its allowance for doubtful accounts monthly.  Past due balances over 90 days and over a specified amount are reviewed individually for collectibility.  Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote.  The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1.7 million and $1.5 million at December 31, 2009, and December 31, 2008, respectively.

(g)          Inventories

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

(h)          Oil and Natural Gas Properties

Proved Properties

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

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable.  The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value.  The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.  Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.  The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.  Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently.  Gains or losses from the disposal of other properties are recognized currently.  Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred.  Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.  The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells.  Interest is capitalized only during the periods in which these assets are

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

brought to their intended use.  The Company capitalized interest costs from continuing operations of $0.3 million, $0.9 million and $0.5 million for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively.

Unproved Properties

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

Impairment

Based on the analysis described above, the Company recorded noncash impairment of proved properties of approximately $30.2 million before and after tax for the year ended December 31, 2008, which is included in “impairment of goodwill and long-lived assets” on the consolidated statements of operations.  The Company recorded no impairment of proved properties in continuing operations for the years ended December 31, 2009, or December 31, 2007.  The Company recorded noncash impairment of unproved properties of approximately $6.3 million and $4.5 million for the years ended December 31, 2009, and December 31, 2008, which is included in “exploration costs” on the consolidated statements of operations.  The Company recorded no such impairment for the year ended December 31, 2007.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs.  The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

(i)           Other Property and Equipment

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

(j)           Goodwill Impairment

Goodwill represents the excess of the cost of an acquired business over the net amounts assigned to assets acquired and liabilities assumed.  The Company recorded goodwill in conjunction with its August 2007 acquisition in the Mid-Continent Deep region, all of which was allocated to the

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Mid-Continent Deep reporting unit.  At December 31, 2007, the Company had $64.4 million of goodwill recorded.  During the year ended December 31, 2008, the Company recorded adjustments to goodwill related to the sales of Verden and Woodford Shale assets and post closing adjustments.  These adjustments reduced the balance of goodwill by approximately $44.1 million.

The Company performed its annual goodwill impairment review in the fourth quarter of 2008.  During the fourth quarter of 2008, there were disruptions in credit markets and reductions in global economic activity that had adverse impacts on stock markets and commodity prices, both of which contributed to a decline in the Company’s unit price and corresponding market capitalization.  For most of the fourth quarter of 2008, the Company’s market capitalization value was below the recorded net book value of its consolidated balance sheet, including goodwill.  Because quoted market prices for the Company’s reporting units were not available, management used judgment in estimating the fair value of its reporting units for purposes of performing the annual goodwill impairment test.  All available information was used to make these fair value determinations, including the present values of expected future cash flows using prices, costs and discount factors consistent with those used for internal decision making.  The accounting principles regarding goodwill acknowledge that the observed market prices of individual trades of a company’s stock (and thus its computed market capitalization) may not be representative of the fair value of the company as a whole.  Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity.  Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual common stock.  In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest; therefore, a control premium was added to the Company’s fair value calculations.  This control premium was judgmental and based on observations of acquisitions in the industry.

At December 31, 2008, based on its impairment analysis, the Company concluded that impairment of the entire amount of recorded goodwill for the Mid-Continent Deep reporting unit was required.  A $20.3 million before and after tax noncash impairment of goodwill was recorded during the year ended December 31, 2008, which is included in “impairment of goodwill and long-lived assets” on the consolidated statements of operations.  The Company had no goodwill recorded on its consolidated balance sheets at December 31, 2009, or December 31, 2008.

(k)          Revenue Recognition

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

The Company has elected the entitlements method to account for natural gas production imbalances.  Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production.  In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability.  If the Company receives less than its entitled share, the underproduction is recorded as a receivable.  At December 31, 2009, and December 31, 2008, the Company had natural gas production imbalance receivables of approximately $16.4 million and $17.1 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production

76

LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

imbalance payables of approximately $8.8 million and $9.9 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements.  As such, the Company separately reports third-party marketing sales and natural gas marketing expenses.  Marketing margins related to the Company’s production are included in oil, natural gas and NGL sales.

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

(l)           Restricted Cash

Restricted cash of $2.1 million and $1.3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2009, and December 31, 2008, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

(m)         Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil, natural gas and NGL.  By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices.  These transactions are primarily in the form of swap contracts, put options and collars.  In addition, the Company enters into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates.

Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities.  The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  The Company determines the fair value of its derivative financial instruments utilizing pricing models for significantly similar instruments.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.

(n)          Unit-Based Compensation

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

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

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LINN ENERGY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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

(o)          Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt (see Note 6).  At December 31, 2009, and December 31, 2008, net deferred financing fees of approximately $57.6 million and $11.9 million, respectively, are included in “other noncurrent assets” on the consolidated balance sheets.  These debt issuance costs are amortized over the life of the debt agreement.  For the years ended December 31, 2009, December 31, 2008, and December 31, 2007, amortization expense of $13.7 million, $5.2 million and $1.5 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

(p)          Fair Value of Financial Instruments

The carrying values of the Company’s receivables, payables and Credit Facility (as defined in Note 6) are estimated to be substantially the same as their fair values at December 31, 2009, and December 31, 2008.  See Note 6 for fair value disclosures related to the Company’s other outstanding debt.  As noted above, the Company carries its derivative financial instruments at fair value.  See Note 8 for details about the fair value of the Company’s derivative financial instruments.

(q)          Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders.  As such, with the exception of the state of Texas, it is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below.

Limited liability companies are subject to state income taxes in Texas.  In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  See Note 14 for detail of amounts recorded in the consolidated financial statements.

(2) Acquisitions, Divestitures and Discontinued Operations

Acquisitions – 2009

On August 31, 2009, and September 30, 2009, the Company completed the acquisitions of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian Corporation (collectively referred to as “Forest”).  The results of operations of these properties have been included in the consolidated financial statements since these dates.  The Company paid $114.4 million in cash, net of cash received from Forest post-closing, and recorded a receivable from Forest, resulting in total consideration for the acquisitions of approximately $113.7 million.  The

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transactions were financed with borrowings under the Company’s Credit Facility.  The acquisitions represent a strategic entry into the Permian Basin for the Company.

The acquisitions were accounted for under the acquisition method of accounting in accordance with an accounting standard adopted by the Company effective January 1, 2009, (see Note 17).  Accordingly, the Company conducted an assessment of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred.

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

Assets:
Current and other assets	$	840
Oil and natural gas properties		115,798
Total assets acquired	$	116,638
Liabilities:
Current liabilities	$	1,568
Asset retirement obligations		1,350
Total liabilities assumed	$	2,918
Net assets acquired	$	113,720

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

The fair values of oil and natural gas properties and asset retirement obligation liabilities were measured using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.  Significant inputs to the valuation of asset retirement obligation liabilities include estimates of: (i) plug and abandon costs per well; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate.

Acquisitions – 2008 and 2007

Acquisitions completed prior to January 1, 2009, were accounted for under the purchase method of accounting.  The following is a summary of certain significant acquisitions completed by the Company during the years ended December 31, 2008, and December 31, 2007:

· January 31, 2008, acquisition of certain oil and natural gas properties located primarily in the Mid-Continent Shallow region, primarily in Oklahoma, from Lamamco Drilling Company for approximately $542.2 million

· August 31, 2007, acquisition of certain oil and natural gas properties in the Mid-Continent Deep region, in Oklahoma, Kansas and the Texas Panhandle, from Dominion Resources, Inc. for approximately $2.11 billion

· June 12, 2007, acquisition of certain oil and natural gas properties in the Mid-Continent Shallow region, in the Texas Panhandle, for approximately $89.7 million

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· February 1, 2007, acquisition of certain oil and natural gas properties in the Mid-Continent Shallow region, in the Texas Panhandle, from Stallion Energy LLC, acting as general partner for Cavallo Energy, LP, for approximately $415.6 million

Acquisition – Subsequent Event

On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico, from certain affiliates of Merit Energy Company (“Merit”) for a contract price of $154.5 million.  The transaction was financed with borrowings under the Company’s Credit Facility and included a deposit of $15.5 million paid by the Company to Merit in November 2009.  At December 31, 2009, this amount is reported in “other noncurrent assets” on the consolidated balance sheets.  The acquisition provides an addition to the Company’s asset portfolio in the Permian Basin and Mid-Continent.  The initial accounting for the business combination is not complete pending detailed analyses of the facts and circumstances that existed as of the acquisition date.

Divestitures

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

On August 15, 2008, the Company completed the sale of certain properties in the Verden area in Oklahoma to Laredo Petroleum, Inc.  During 2008, the Company received net proceeds equal to the carrying value of net assets sold of $169.4 million.

On July 1, 2008, the Company completed the sale of its interests in oil and natural gas properties located in the Appalachian Basin to XTO Energy, Inc.  During 2008, the Company received net proceeds of $566.5 million.  The carrying value of net assets sold was $405.8 million, resulting in a gain on the sale of $160.7 million  In addition, in March 2008, the Company exited the drilling and service business in the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic and recorded a loss on the sale of $1.6 million.  The gain and loss from these divestitures are recorded in “discontinued operations: (gain) loss on sale of assets, net of taxes” on the consolidated statements of operations for the year ended December 31, 2008.  The Company used the net proceeds from all divestitures to reduce indebtedness.

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Discontinued Operations

The Company’s Appalachian Basin and Mid Atlantic operations (see “Divestitures” above) have been classified as discontinued operations on the consolidated statements of operations for all periods presented.  The following summarizes the Appalachian Basin and Mid Atlantic amounts included in “income (loss) from discontinued operations, net of taxes” on the consolidated statements of operations:

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Total revenues and other	$	(1,216	)	$	50,601		$	67,110
Total operating expenses		(977	)		(23,677	)		(54,260	)
Interest expense		—			(13,401	)		(23,156	)
Income (loss) from discontinued operations		(2,193	)		13,523			(10,306	)
Income tax benefit		—			1,391			1,215
Income (loss) from discontinued operations, net of taxes	$	(2,193	)	$	14,914		$	(9,091	)

Discontinued operations activity for 2009 primarily represents activity related to post-closing adjustments.  The Company computed interest expense related to discontinued operations for 2008 and 2007 based on debt required to be repaid as a result of the disposal transaction.

(3) Unitholders’ Capital

Public Offering of Units

In October 2009, the Company sold 8,625,000 units representing limited liability company interests at $21.90 per unit ($21.024 per unit, net of underwriting discount) for net proceeds (after underwriting discount of $7.6 million and offering expenses of $0.2 million) of approximately $181.1 million, which was used to reduce indebtedness under the Credit Facility.

In May 2009, the Company sold 6,325,000 units representing limited liability company interests at $16.25 per unit ($15.60 per unit, net of underwriting discount) for net proceeds (after underwriting discount of $4.1 million and offering expenses of $0.4 million) of approximately $98.2 million, which was used to reduce indebtedness under the Credit Facility.

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100.0 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases.  During the year ended December 31, 2009, 123,800 units were repurchased at an average unit price of $12.99, for a total cost of approximately $1.6 million.  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.  At December 31, 2009, approximately $85.4 million was available for unit repurchase under the program.  The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements.  The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time.  Units are repurchased at fair market value on the date of repurchase.

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Issuance and Cancellation of Units

During the year ended December 31, 2009, the Company purchased 63,031 units for approximately $1.1 million, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan (see Note 5).  All units were subsequently canceled.

During the year ended December 31, 2008, the Company issued 410,000 units in connection with the termination of certain contractual obligations (equal to a fair value of approximately $8.7 million).  In addition, during the year ended December 31, 2008, the Company issued 600,000 units in connection with the acquisition of certain natural gas properties (equal to a fair value of approximately $14.7 million).  During the year ended December 31, 2008, the Company purchased 94,521 units for approximately $2.0 million, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan.  All units were subsequently canceled.

During the year ended December 31, 2007, the Company issued 77,381 units in connection with the acquisition of royalty interests in certain oil and natural gas properties.  In addition, during the year ended December 31, 2007, the Company purchased 226,561 units for approximately $7.4 million, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan.  All units were subsequently canceled.

Private Placements

In August 2007, the Company closed its private placement of $1.5 billion of units to a group of institutional investors, consisting of 34,997,005 Class D units at a price of $30.97 per unit, and 12,999,989 units at a price of $32.00 per unit.  Proceeds, net of expenses, were $1.48 billion and were used to fund the acquisition of oil and natural gas properties.  The Class D units were converted to units on a one-for-one basis in November 2007.

In June 2007, the Company closed its private placement of $260.0 million of units to a group of institutional investors, consisting of 7,761,194 units at a price of $33.50 per unit.  Proceeds, net of expenses, were $255.2 million and were used to reduce indebtedness.

In February 2007, the Company closed its private placement of $360.0 million of units to a group of institutional investors, consisting of 7,465,946 Class C units at a price of $25.06 per unit, and 6,650,144 units at a price of $26.00 per unit.  Proceeds, net of expenses, were $353.1 million and were used to fund the acquisition of oil and natural gas properties.  The Class C units were converted into units on a one-for-one basis in April 2007.

Registration Statements covering all the units issued through the private placements noted above were filed and declared effective by the Securities and Exchange Commission (“SEC”) during December 2007.  In December 2007, the Company was required to pay purchasers in the June 2007 private placement approximately $0.7 million in liquidated damages as specified in the registration rights agreement because the registration effectiveness deadline in the agreement was not achieved.  This payment is included in “general and administrative expenses” on the consolidated statements of operations for the year ended December 31, 2007.

Distributions

Under the Agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses.  Distributions paid by the Company are presented on the consolidated statements of unitholders’ capital.  On January 27, 2010, the Company’s Board of Directors declared a cash distribution

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of $0.63 per unit with respect to the fourth quarter of 2009.  The distribution, totaling approximately $82.3 million, was paid February 12, 2010, to unitholders of record as of the close of business February 5, 2010.

(4) Business and Credit Concentrations

Cash

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

Revenue and Trade Receivables

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

For the year ended December 31, 2009, the Company’s three largest customers represented 22%, 18% and 15%, respectively, of the Company’s sales.  For the year ended December 31, 2008, the Company’s three largest customers represented 21%, 18% and 10%, respectively, of the Company’s sales.  For the year ended December 31, 2007, the Company’s two largest customers represented 27% and 22%, respectively, of the Company’s sales.

At December 31, 2009, trade accounts receivable from three customers accounted for more than 10% of the Company’s total trade accounts receivable.  At December 31, 2009, trade accounts receivable from these customers represented approximately 25%, 15% and 15%, respectively, of the Company’s receivables.  At December 31, 2008, trade accounts receivable from two customers accounted for more than 10% of the Company’s total trade accounts receivable.  At December 31, 2008, trade accounts receivable from these customers represented approximately 20% and 16%, respectively, of the Company’s receivables.

(5) Unit-Based Compensation and Other Benefit Plans

Incentive Plan Summary

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

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

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

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

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

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

Phantom Units/Unit Appreciation Rights  These awards may be settled in units, cash or a combination thereof.  Such grants contain terms as determined by the Compensation Committee, including the period or terms over which phantom units vest.  If a grantee’s employment or service relationship terminates for any reason, the grantee’s phantom units or unit appreciation rights will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise.  While phantom units require no payment from the grantee, unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant.  At December 31, 2009, the Company had 36,784 phantom units issued and outstanding.  To date, the Company has not issued unit appreciation rights.

Securities Authorized for Issuance Under the Plan

As of December 31, 2009, approximately 1.9 million units were issuable under the Plan pursuant to outstanding award or other agreements, and 6.8 million additional units were reserved for future issuance under the Plan.

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Accounting for Unit-Based Compensation

Activities and balances presented in this Note 5 include amounts associated with discontinued operations for the years ended December 31, 2008, and December 31, 2007, (see Note 2).  The Company recognizes as expense, beginning at the grant date, the fair value of unit options and other equity-based compensation issued to employees and nonemployee directors.  The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations.  A summary of unit-based compensation expenses included on the consolidated statements of operations is presented below:

	Year Ended December 31,
	2009		2008		2007
	(in thousands)
General and administrative expenses	$	14,743	$	14,590	$	12,118
Lease operating expenses		346		109		—
Income (loss) from discontinued operations, net of taxes		―		978		403
Total unit-based compensation expenses	$	15,089	$	15,677	$	12,521
Income tax benefit	$	5,968	$	―	$	―

Restricted/Unrestricted Units

The fair value of unrestricted unit grants and restricted units issued is determined based on the fair market value of the Company units on the date of grant.  A summary of the status of the nonvested units as of December 31, 2009, is presented below:

	Number of Nonvested Units			Weighted  Average Grant-Date Fair Value
Nonvested units at December 31, 2008		835,004		$	27.01
Granted		1,115,255		$	16.11
Vested		(409,227	)	$	27.43
Forfeited		(41,244	)	$	17.09
Nonvested units at December 31, 2009		1,499,788		$	19.07

The weighted average grant-date fair value of unrestricted unit grants and restricted units granted during the years ended December 31, 2008, and December 31, 2007, was $23.82 and $31.16, respectively.

As of December 31, 2009, there was approximately $16.1 million of unrecognized compensation cost related to nonvested restricted units.  The cost is expected to be recognized over a weighted average period of approximately 1.33 years.  The total fair value of units that vested was approximately $11.2 million, $14.0 million and $19.4 million for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively.

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Changes in Unit Options and Unit Options Outstanding

The following provides information related to unit option activity for the year ended December 31, 2009:

	Number of Units Underlying Options			Weighted Average Exercise Price Per Unit		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Contractual Life in Years
Outstanding at December 31, 2008		1,590,438		$	24.04	$	3.76		8.23
Granted		382,405		$	15.95	$	0.55
Exercised		(25,000	)	$	19.74	$	3.75
Outstanding at December 31, 2009		1,947,843		$	22.51	$	3.13		7.43
Exercisable at December 31, 2009		1,147,705		$	24.44	$	4.21		6.65

The weighted average grant-date fair value of options granted during the years ended December 31, 2008, and December 31, 2007, was $2.58 and $4.59, respectively.  The total intrinsic value of options exercised during the years ended December 31, 2009, December 31, 2008, and December 31, 2007, was approximately $124,000, $4,000 and $95,000, respectively.  The Company received $0.5 million from the exercise of options during the year ended December 31, 2009.  No options were forfeited during the year ended December 31, 2009.

As of December 31, 2009, there was approximately $0.6 million of total unrecognized compensation cost related to nonvested unit options.  The cost is expected to be recognized over a weighted average period of approximately 1.04 years.  In addition, the exercisable unit options at December 31, 2009, have an aggregate intrinsic value of approximately $4.7 million and all outstanding unit options have an aggregate intrinsic value of approximately $11.5 million.  The total fair value of all options that vested during the years ended December 31, 2009, December 31, 2008, and December 31, 2007, was approximately $1.7 million, $2.1 million and $1.5 million, respectively.  No options expired during the years ended December 31, 2009, December 31, 2008, or December 31, 2007.

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

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

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curve in effect at the time of grant.  The fair values of the unit option grants were based upon the following assumptions:

	2009						2008						2007
Expected volatility	30.59%						30.59	%		–	34.57	%	30.40	%		–	35.58	%
Expected distributions	15.80	%		–	16.79	%	10.13	%		–	12.32	%	6.51	%		–	10.67	%
Risk-free rate	1.24	%		–	1.91	%	2.66	%		–	3.41	%	3.53	%		–	5.18	%
Expected term			5 years						5 years						5 years

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

In January 2010, the Company granted 638,554 restricted units as part of its annual review of employee and executive compensation.

Nonemployee Grants

During the year ended December 31, 2007, the Company granted an aggregate 150,000 unit warrants to certain individuals in connection with an acquisition transition services agreement.  The unit warrants have an exercise price of $25.50 per unit warrant, are fully exercisable at December 31, 2009, and expire 10 years from issuance.  The Company computed the fair value of the unit warrants using a Black-Scholes pricing model.  The expense of approximately $1.4 million is included in “general and administrative expenses” on the consolidated statements of operations for the year ended December 31, 2007.

Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan for eligible employees.  Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 4% of eligible compensation contributed by the employee on a before-tax basis for each of the years in the three year period ending December 31, 2009.  Effective January 1, 2010, the Company contribution was equal to 100% of the first 6% of eligible employee compensation.  The Company contributed approximately $1.7 million, $1.6 million and $0.8 million during the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively, to the 401(k) plan’s trustee account.  The 401(k) plan funds are held in a trustee account on behalf of the plan participants.

(6) Debt

The following summarizes debt outstanding:

	December 31, 2009				December 31, 2008
	Carrying Value		Fair Value (1)		Carrying Value		Fair Value (1)
	(in thousands)
Credit facility (2)	$	1,100,000	$	1,100,000	$	1,403,393	$	1,403,393
Senior notes due 2017, net (3)		238,275		279,375		―		―
Senior notes due 2018, net (4)		250,556		270,803		250,175		147,268
Less current maturities		―		―		―		―
	$	1,588,831	$	1,650,178	$	1,653,568	$	1,550,661

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

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(2) Variable interest rate of 2.98% at December 31, 2009, and 2.47% at December 31, 2008.

(3) Fixed interest rate of 11.75% and effective interest rate of 12.73%.  Amount is net of unamortized discount of approximately $11.7 million at December 31, 2009.

(4) Fixed interest rate of 9.875% and effective interest rate of 10.25%.  Amount is net of unamortized discount of approximately $5.4 million and $5.8 million at December 31, 2009, and December 31, 2008, respectively.

Credit Facility

On April 28, 2009, the Company entered into a Fourth Amended and Restated Credit Agreement (“Credit Facility”), with an initial borrowing base of $1.75 billion and a maturity of August 2012, which amended and restated the Company’s existing credit facility, which had a maturity of August 2010.  The terms of the Credit Facility required that, upon the issuance of the senior notes due 2017 in May 2009 (see below) and cancellation of certain commodity derivatives in July 2009 (see Note 7), the borrowing base be decreased by approximately $62.5 million and $45.0 million, respectively, to $1.64 billion at December 31, 2009.  At December 31, 2009, available borrowing capacity was $537.0 million, which includes a $5.5 million reduction in availability for outstanding letters of credit.  In connection with the amended and restated Credit Facility, during the year ended December 31, 2009, the Company paid approximately $52.7 million in financing fees and expenses, which were deferred and will be amortized over the life of the Credit Facility.

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

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.50% and 3.25% per annum or the alternate base rate (“ABR”) plus an applicable margin between 1.00% and 1.75% per annum.  Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans.  The Company is required to pay a fee of 0.5% per annum on the unused portion of the borrowing base under the Credit Facility.

The Credit Facility contains various covenants, substantially similar to those included prior to the amendment and restatement, which limit the Company’s ability to: (i) incur indebtedness; (ii) enter into commodity and interest rate swaps; (iii) grant certain liens; (iv) make certain loans, acquisitions, capital expenditures and investments; (v) make distributions other than from available cash; and (vi) merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of its assets.  The Credit Facility also contains covenants, substantially similar to those included prior to the amendment and restatement, which require the Company to maintain adjusted earnings to interest expense and current liquidity financial ratios.  The Company is in compliance with all financial and other covenants of the Credit Facility.

Senior Notes Due 2017

On May 12, 2009, the Company entered into a purchase agreement with a group of initial purchasers (“Initial Purchasers”) pursuant to which the Company agreed to issue $250.0 million in aggregate principal amount of the Company’s senior notes due 2017 (“2017 Notes”).  The 2017 Notes were offered and sold to the Initial Purchasers and then resold to qualified institutional buyers, each in transactions exempt from the

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registration requirements of the Securities Act of 1933, as amended (the “Securities Act”).  The Company used the net proceeds (after deducting the Initial Purchasers’ discounts and offering expenses) of approximately $230.8 million to reduce indebtedness under its Credit Facility.  In connection with the 2017 Notes, the Company incurred financing fees and expenses of approximately $6.9 million, which will be amortized over the life of the 2017 Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.  The $12.3 million discount on the 2017 Notes will be amortized over the life of the 2017 Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

The 2017 Notes were issued under an Indenture dated May 18, 2009, (“Indenture”), mature May 15, 2017, and bear interest at 11.75%.  Interest is payable semi-annually beginning November 15, 2009.  The 2017 Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness.  Each of the Company’s material subsidiaries guaranteed the 2017 Notes on a senior unsecured basis.  The Indenture provides that the Company may redeem: (i) on or prior to May 15, 2011, up to 35% of the aggregate principal amount of the 2017 Notes at a redemption price of 111.75% of the principal amount, plus accrued and unpaid interest; (ii) prior to May 15, 2013, all or part of the 2017 Notes at a redemption price equal to the principal amount, plus a make-whole premium (as defined in the Indenture) and accrued and unpaid interest; and (iii) on or after May 15, 2013, all or part of the 2017 Notes at redemption prices equal to 105.875% in 2013, 102.938% in 2014 and 100% in 2015 and thereafter.  The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2017 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

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

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

Senior Notes Due 2018

On June 24, 2008, the Company entered into a purchase agreement with a group of initial purchasers (“Initial Purchasers”) pursuant to which the Company agreed to issue $255.9 million in aggregate principal amount of the Company’s senior notes due 2018 (“2018 Notes”).  The 2018 Notes were offered and sold to the Initial Purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act.  The Company used the net proceeds (after deducting the

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Initial Purchasers’ discounts and offering expenses) of approximately $243.6 million to repay an outstanding term loan.  In connection with the 2018 Notes, the Company incurred financing fees and expenses of approximately $7.8 million, which will be amortized over the life of the 2018 Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.  The $5.9 million discount on the 2018 Notes will be amortized over the life of the 2018 Notes; the expense is recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

The 2018 Notes were issued under an Indenture dated June 27, 2008, (“Indenture”), mature July 1, 2018, and bear interest at 9.875%.  Interest is payable semi-annually beginning January 1, 2009.  The 2018 Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness.  Each of the Company’s material subsidiaries guaranteed the 2018 Notes on a senior unsecured basis.  The Indenture provides that the Company may redeem: (i) on or prior to July 1, 2011, up to 35% of the aggregate principal amount of the 2018 Notes at a redemption price of 109.875% of the principal amount, plus accrued and unpaid interest; (ii) prior to July 1, 2013, all or part of the 2018 Notes at a redemption price equal to the principal amount, plus a make-whole premium (as defined in the Indenture) and accrued and unpaid interest; and (iii) on or after July 1, 2013, all or part of the 2018 Notes at redemption prices equal to 104.938% in 2013, 103.292% in 2014, 101.646% in 2015 and 100% in 2016 and thereafter.  The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2018 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2018 Notes’ Indenture contains covenants that, among other things, limit the Company’s ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.  The Company is in compliance with all financial and other covenants of the 2018 Notes.  In June 2009, the Company instructed the trustee to remove the restrictive legend from the 2018 Notes making them freely tradable (other than with respect to persons that are affiliates of the Company).  This terminated the Company’s obligations under a registration rights agreement entered into in connection with issuance of the 2018 Notes.

(7) Derivatives

Commodity Derivatives

The Company sells oil, natural gas and NGL in the normal course of its business and utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements.  The Company enters into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales.  Oil puts are also used to economically hedge NGL sales.  The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

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

	Year 2010			Year 2011			Year 2012			Year 2013
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		39,566			31,901			—			—
Average price ($/MMBtu)	$	8.90		$	9.50		$	—		$	—
Puts:
Hedged volume (MMMBtu)		6,960			6,960			—			—
Average price ($/MMBtu)	$	8.50		$	9.50		$	—		$	—
PEPL puts: (1)
Hedged volume (MMMBtu)		10,634			13,259			—			—
Average price ($/MMBtu)	$	7.85		$	8.50		$	—		$	—
Total:
Hedged volume (MMMBtu)		57,160			52,120			—			—
Average price ($/MMBtu)	$	8.66		$	9.25		$	—		$	—
Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)		2,150			2,073			732			730
Average price ($/Bbl)	$	90.00		$	90.00		$	100.00		$	100.00
Puts: (3)
Hedged volume (MBbls)		2,250			2,352			—			—
Average price ($/Bbl)	$	110.00		$	75.00		$	—		$	—
Collars:
Hedged volume (MBbls)		250			276			—			—
Average floor price ($/Bbl)	$	90.00		$	90.00		$	—		$	—
Average ceiling price ($/Bbl)	$	112.00		$	112.25		$	—		$	—
Total:
Hedged volume (MBbls)		4,650			4,701			732			730
Average price ($/Bbl)	$	99.68		$	82.50		$	100.00		$	100.00
Natural gas basis differential positions:
PEPL basis swaps: (1)
Hedged volume (MMMBtu)		43,166			35,541			34,066			31,700
Hedged differential ($/MMBtu)	$	(0.97	)	$	(0.96	)	$	(0.95	)	$	(1.01	)

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

(2) As presented in the table above, the Company has outstanding fixed price oil swaps on 2,000 Bbls per day at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013.  The Company has derivative contracts that extend the swaps for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.

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

Settled derivatives on natural gas production for the year ended December 31, 2009, included a volume of 51,880 MMMBtu at an average contract price of $8.32.  Settled derivatives on oil and NGL production for the year ended December 31, 2009, included a volume of 4,530 MBbls at an average contract price of

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$102.21.  The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or on the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month.  The oil derivatives are settled based on the month’s average daily NYMEX price of light oil and settlement occurs on the final day of the production month.

In February 2010, the Company entered into fixed price oil swaps on an additional 5,250 Bbls per day at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013.  The Company has derivative contracts that extend the swaps for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.

Interest Rate Swaps

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

The following presents the settlement terms of the interest rate swaps at December 31, 2009:

	Year 2010			Year 2011			Year 2012			Year 2013 (1)
	(dollars in thousands)
Notional amount	$	1,212,000		$	1,212,000		$	1,212,000		$	1,212,000
Fixed rate		3.85	%		3.85	%		3.85	%		3.85	%

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

Outstanding Notional Amounts

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

	December 31,
	2009		2008
Outstanding notional amounts of natural gas contracts (MMMBtu)		109,280		196,756
Maximum number of months natural gas contracts outstanding		24		48
Outstanding notional amounts of oil contracts (MBbls)		10,813		21,229
Maximum number of months oil contracts outstanding		48		72
Outstanding notional amount of interest rate swaps (in thousands)	$	1,212,000	$	1,212,000
Maximum number of months interest rate swaps outstanding		48		24

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Balance Sheet Presentation

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

	December 31,
	2009		2008
	(in thousands)
Assets:
Commodity derivatives	$	549,879	$	977,847
Interest rate swaps		2,603		―
	$	552,482	$	977,847
Liabilities:
Commodity derivatives	$	192,573	$	119,124
Interest rate swaps		69,644		82,422
	$	262,217	$	201,546

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk.  The Company’s counterparties are participants or affiliates of participants in its Credit Facility (see Note 6), which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral.  The Company does not require collateral from its counterparties.  The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $552.5 million at December 31, 2009.  The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated.

Gain (Loss) on Derivatives

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

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	400,968		$	9,408		$	37,250
Interest rate swaps		(42,881	)		(16,036	)		1,467
Canceled derivatives		48,977			(81,358	)		―
	$	407,064		$	(87,986	)	$	38,717
Unrealized gains (losses):
Commodity derivatives	$	(591,379	)	$	734,732		$	(382,787	)
Interest rate swaps		16,588			(50,638	)		(29,548	)
	$	(574,791	)	$	684,094		$	(412,335	)
Total gains (losses):
Commodity derivatives	$	(141,374	)	$	662,782		$	(345,537	)
Interest rate swaps		(26,353	)		(66,674	)		(28,081	)
	$	(167,727	)	$	596,108		$	(373,618	)

During the year ended December 31, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized net gains of approximately $49.0 million.  Of this amount, realized net gains of approximately $44.8 million, along with an incremental premium payment of approximately $48.8 million, were used to reposition the Company’s commodity derivative portfolio in July 2009 when the Company canceled oil and natural gas derivative contracts for years 2012 through 2014 to raise prices for oil and natural gas derivative contracts in years 2010 and 2011.

During the year ended December 31, 2008, the Company canceled (before the contract settlement date) derivative contracts on estimated future natural gas production resulting in realized losses of approximately $81.4 million.  The future natural gas production under the canceled contracts primarily related to properties in the Appalachian Basin and Verden areas (see Note 2).

(8) Fair Value Measurements on a Recurring Basis

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

Fair Value Hierarchy

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

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

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

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

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

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

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

	Fair Value Measurements on a Recurring Basis December 31, 2009
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	549,879	$	(154,666	)	$	395,213
Interest rate swaps	$	2,603	$	(2,603	)	$	—
Liabilities:
Commodity derivatives	$	192,573	$	(154,666	)	$	37,907
Interest rate swaps	$	69,644	$	(2,603	)	$	67,041

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

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(9) Other Property and Equipment

Other property and equipment consists of the following:

	December 31,
	2009			2008
	(in thousands)
Natural gas compression plant and pipeline	$	88,765		$	87,133
Buildings and leasehold improvements		9,213			7,734
Vehicles		7,005			5,840
Drilling and other equipment		1,313			1,566
Furniture and office equipment		11,929			8,338
Land		642			848
		118,867			111,459
Less accumulated depreciation		(23,583	)		(13,171	)
	$	95,284		$	98,288

(10) Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets, are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the consolidated balance sheets.  Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations.  The fair value of additions to the asset retirement obligation liability is estimated using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for each of the years in the three-year period ended December 31, 2009); and (iv) a credit-adjusted risk-free interest rate (average of 9.6%, 7.8% and 7.0% for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively).

Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement amounts, timing of settlement, and changes in legal, regulatory, environmental and political environments.  To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment is made to the asset balance.

The following presents a reconciliation of the asset retirement obligation liability:

	December 31,
	2009			2008
	(in thousands)
Asset retirement obligations at beginning of year	$	28,922		$	29,073
Liabilities added from acquisitions		1,350			5,398
Liabilities added from drilling		66			541
Liabilities associated with assets sold		―			(8,020	)
Current year accretion expense		2,324			1,967
Settlements		(577	)		(37	)
Revision of estimates		1,050			―
Asset retirement obligations at end of year	$	33,135		$	28,922

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(11) Commitments and Contingencies

On September 15, 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) with the United States Bankruptcy Court for the Southern District of New York (the “Court”).  On October 3, 2008, Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) also filed a voluntary petition for reorganization under Chapter 11 with the Court.  At December 31, 2009, and December 31, 2008, the Company had a net receivable of approximately $6.7 million from Lehman Commodity Services for canceled derivative contracts, which is included in “other current assets” on the consolidated balance sheets.  The value of the receivable was estimated based on market expectations.  The Company is pursuing various legal remedies to protect its interests and believes that the ultimate disposition of this matter will not have a material adverse effect on its business, financial position, results of operations or liquidity.

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

(12) Earnings Per Unit

Effective January 1, 2009, the Company adopted an accounting standard that requires unvested restricted units to be included in the computation of earnings per unit under the two-class method.  The adoption required retrospective adjustment of all prior period earnings per unit data.  The impact of the adoption was a reduction to income from continuing operations per unit – diluted and net income per unit – diluted, of $0.05 per unit for the year ended December 31, 2008.  There was no impact for the year ended December 31, 2007.

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

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

	Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Year ended December 31, 2009:
Loss from continuing operations:
Allocated to units	$	(295,841	)
Allocated to unvested restricted units		—
	$	(295,841	)
Loss per unit:
Basic loss per unit					119,307	$	(2.48	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					119,307	$	(2.48	)
Year ended December 31, 2008:
Income from continuing operations:
Allocated to units	$	825,657
Allocated to unvested restricted units		(5,610	)
	$	820,047
Income per unit:
Basic income per unit					114,140	$	7.18
Dilutive effect of unit equivalents					18		—
Diluted income per unit					114,158	$	7.18
Year ended December 31, 2007:
Loss from continuing operations:
Allocated to units	$	(356,194	)
Allocated to unvested restricted units		—
	$	(356,194	)
Loss per unit:
Basic loss per unit					68,916	$	(5.17	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					68,916	$	(5.17	)

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 2.1 million, 1.7 million and 1.2 million unit options and warrants for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively.  All equivalent units were anti-dilutive for the years ended December 31, 2009, and December 31, 2007.

(13) Operating Leases

The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2019.  The Company recognized expense under operating leases of approximately $3.6 million, $3.2 million and $1.2 million for the years ended December 31, 2009, December 31, 2008, and December 31, 2007, respectively.

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As of December 31, 2009, future minimum lease payments were as follows (in thousands):

2010	$	3,954
2011		4,084
2012		3,727
2013		3,251
2014		3,275
Thereafter		11,674
	$	29,965

(14) Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders.  Limited liability companies are subject to state income taxes in Texas.  As such, with the exception of the state of Texas, it is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company, except as set forth in the tables below.

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

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Current taxes:
Federal	$	(1,063	)	$	(1,184	)	$	(1,355	)
State		(678	)		(1,528	)		(283	)
Deferred taxes:
Federal		5,307			—			(3,066	)
State		655			—			(84	)
	$	4,221		$	(2,712	)	$	(4,788	)

As of December 31, 2009, the Company’s taxable entities had approximately $3.0 million of net operating loss carryforwards for federal income tax purposes, which will begin expiring in 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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

	Year Ended December 31,
	2009			2008			2007
Federal statutory rate		35.0	%		35.0	%		35.0	%
State, net of federal tax benefit		—			0.1			(0.1	)
Income or loss excluded from nontaxable entities		(34.3	)		(34.9	)		(35.3	)
Nondeductible compensation		—			—			(0.3	)
Other items		0.7			0.1			(0.7	)
Effective rate		1.4	%		0.3	%		(1.4	)%

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

	December 31,
	2009			2008
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	1,175		$	2,767
Unit-based compensation		7,166			5,617
Other		1,924			897
Valuation allowance		(1,223	)		(7,132	)
Total deferred tax assets		9,042			2,149
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation		(2,284	)		(2,149	)
Other		(322	)		—
Total deferred tax liabilities		(2,606	)		(2,149	)
Net deferred tax assets (liabilities)	$	6,436		$	—

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

	December 31,
	2009			2008
	(in thousands)
Other current assets – deferred tax assets	$	5,372		$	—
Deferred tax assets	$	3,670		$	2,149
Deferred tax liabilities		(2,606	)		(2,149	)
Other noncurrent assets	$	1,064		$	—

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.  Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.  Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the

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Company will realize the benefits of the majority of these deductible differences at December 31, 2009.  The Company has recorded a valuation allowance against certain deferred tax assets.  The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

In accordance with the applicable accounting standard, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority.  In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position.  It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense.  The Company had no material uncertain tax positions at December 31, 2009, or December 31, 2008.

(15) Related Party Transactions

Lehman Holdings

During the year ended December 31, 2008 (through July 3, 2008), and the year ended December 31, 2007, on an aggregate basis, a group of certain direct or indirect wholly owned subsidiaries of Lehman Holdings owned over 10% of the Company’s outstanding units.  As such, Lehman Holdings was considered a related party during that time frame.  Lehman Holdings’ subsidiaries provided certain services to the Company, including participation in the Company’s Credit Facility, offering of 2018 Notes (see Note 6), sale of Appalachian Basin assets (see Note 2) and sale of commodity derivative instruments (see Note 7), which were all consummated on terms equivalent to those that prevail in arm’s-length transactions.  A reference to “Lehman” hereafter in this footnote refers to Lehman Holdings or one or more of its subsidiaries, as applicable.  See Note 11 for details about Lehman’s Chapter 11 filings.

During the year ended December 31, 2008 (through July 3), the Company paid Lehman interest on borrowings of approximately $2.2 million and financing fees of approximately $1.8 million.  During the year ended December 31, 2007, the Company paid Lehman interest on borrowings of approximately $2.1 million and financing fees of approximately $0.1 million.

During the year ended December 31, 2007, in conjunction with its private placements of units, the Company paid Lehman underwriting fees of approximately $13.5 million.  Lehman was a participant in the private placements and the Company received approximately $378.7 million of proceeds from Lehman in relation to these transactions during the year ended December 31, 2007.

During the year ended December 31, 2008 (through July 3), the Company paid distributions on units to Lehman of approximately $18.5 million.  During the year ended December 31, 2007, the Company paid distributions on units to Lehman of approximately $15.2 million.  During the year ended December 31, 2008 (through July 3), the Company paid Lehman approximately $18.8 million, on settled commodity derivative contracts.  During the year ended December 31, 2007, Lehman paid the Company approximately $8.2 million on settled commodity derivative contracts.  During the year ended December 31, 2008 (through July 3), the Company purchased approximately $1.3 million of deal contingent commodity swap contracts from Lehman.  In addition, during the year ended December 31, 2007, the Company paid Lehman approximately $226.3 million for commodity derivative contracts.

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Other

During the years ended December 31, 2008, and December 31, 2007, the Company made payments of approximately $0.3 million and $0.2 million to a company owned by a member of its Board of Directors.  The payments primarily reflect purchases of natural gas and are primarily included in “natural gas marketing expenses” on the consolidated statements of operations.  The transactions were consummated on terms equivalent to those that prevail in arm’s-length transactions.

Eric P. Linn, brother of the Company’s Executive Chairman, served as President of one of the Company’s wholly owned subsidiaries.  Effective March 31, 2008, Mr. Linn’s employment with the Company terminated and he executed a Severance Agreement and Release.  During the year ended December 31, 2008, the Company made payments of approximately $0.2 million to Mr. Linn under the Severance Agreement and Release.  The payments are included in “income (loss) from discontinued operations, net of taxes” on the consolidated statements of operations.  The transaction was consummated on terms equivalent to those that prevail in arm’s-length transactions.

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

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

	December 31,
	2009		2008
	(in thousands)
Accrued compensation	$	14,378	$	11,366
Accrued interest		18,332		14,232
Other		1,212		1,565
	$	33,922	$	27,163

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	73,861		$	94,958		$	57,348
Cash payments for income taxes	$	1,282		$	452		$	―
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	117,717		$	602,858		$	2,710,417
Cash paid		(115,285	)		(593,412	)		(2,649,965	)
Receivable from seller		636			―			―
Liabilities assumed	$	3,068		$	9,446		$	60,452
Noncash financing activities:
Units issued in connection with the acquisition of oil and natural gas properties	$	―		$	23,455		$	2,600

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(17) Recently Issued Pronouncements

Codification

In June 2009, the Financial Accounting Standards Board (“FASB”) approved the FASB Accounting Standards Codification (“Codification” or “ASC”), effective for financial statements for interim or annual reporting periods ending after September 15, 2009.  The Codification is the single source of authoritative nongovernmental GAAP, superseding existing FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force and related literature.  References herein to prior GAAP standards that were used to create the Codification have been replaced or supplemented with references to the relevant section of the Codification and are identified as “FASB ASC” or “ASC Update.”

Accounting Standards

In August 2009, the FASB issued ASC Update 2009-5, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value,” which includes amendments to Subtopic 820-10, “Fair Value Measurements and Disclosures – Overall,” for the fair valuemeasurement of liabilities and provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, an entity is required to measure fair value using one or more of the techniques provided for in this update, including the quoted price of the liability when traded as an asset.  The guidance in this update is effective for interim and annual periods ending after September 30, 2009, and the Company adopted it effective October 1, 2009.  The adoption did not have a material impact on the Company’s results of operations or financial position.

In May 2009, the FASB issued FASB ASC 855, “Subsequent Events,” and in February 2010, the FASB issued ASC Update 2010-09, “Subsequent Events (Topic 855) – Amendments to Certain Recognition and Disclosure Requirements,” which establishes standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued.  Under this standard, entities that file or furnish financial statements with the SEC, such as the Company, are required to use an issued date in evaluating subsequent events.  This standard, as updated, is effective February 24, 2010, and the Company adopted it at that date.  The adoption did not have a material impact on the Company’s results of operations or financial position.

In April 2009, the FASB issued three related standards to clarify the application of FASB ASC 820 “Fair Value Measurements and Disclosures,” to fair value measurements in the current economic environment, modify the recognition of other-than-temporary impairments of debt securities, and require companies to disclose the fair value of financial instruments in interim periods.  The final standards are effective for interim and annual periods ending after June 15, 2009, and the Company adopted the new standards effective June 30, 2009.  The adoption did not have a material impact on the Company’s results of operations or financial position.  The three related standards are as follows:

FASB ASC 820-10-65-4, “Transition Related to FASB Staff Position FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” provides guidance on how to determine the fair value of assets and liabilities under FASB ASC 820 in the current economic environment and reemphasizes that the objective of a fair value measurement remains the price that would be received to sell an asset or paid to transfer a liability at the measurement date.

FASB ASC 320-10-65-1, “Transition Related to FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments,” modifies the requirements for recognizing other-than-temporarily impaired debt securities and significantly changes the existing impairment model for such securities.  It also modifies the presentation of other-than-temporary impairment

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losses and increases the frequency of and expands already required disclosures about other-than-temporary impairment for debt and equity securities.

FASB ASC 825-10-65-1, “Transition Related to FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments,” requires disclosures of the fair value of financial instruments within the scope of FASB ASC 825, “Financial Instruments,” in interim financial statements, adding to the current requirement to make those disclosures in annual financial statements.  It also requires that companies disclose the method or methods and significant assumptions used to estimate the fair value of financial instruments and a discussion of changes, if any, in the method or methods and significant assumptions during the period.

FASB ASC 805, “Business Combinations,” issued in December 2007, with additional guidance issued in April 2009, requires an acquiring entity to recognize all assets acquired and liabilities assumed at fair value with limited exceptions.  Assets acquired and liabilities assumed that arise from contingencies are to be recognized at fair value if fair value can be reasonably estimated.  If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability should generally be recognized in accordance with FASB ASC 450, “Contingencies.”  This standard changes the accounting treatment for certain specific items, including acquisition costs, which are expensed as incurred, and also includes new disclosure requirements.  This standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period on or after December 15, 2008.  The Company adopted this standard effective January 1, 2009, (see Note 2).

FASB ASC 820, “Fair Value Measurements and Disclosures,” issued in September 2006, provides guidance for using fair value to measure assets and liabilities.  This standard applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the mark-to-market value.  The Company adopted the provisions of this standard related to financial assets and liabilities and nonfinancial assets and liabilities measured on a recurring basis effective January 1, 2008, and related to nonfinancial assets and liabilities measured on a nonrecurring basis effective January 1, 2009, (see Note 2 and Note 10).  There was no impact from the adoption related to items measured on a nonrecurring basis.

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SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)

The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”  The Company’s Appalachian Basin and Mid Atlantic operations have been classified as discontinued operations on the consolidated statements of operations for all periods presented (see Note 2).  Unless otherwise indicated, information presented in the following supplemental oil and natural gas data has been recast to present continuing operations separately from discontinued operations.

(A) Modernization of Oil and Natural Gas Reporting Requirements

Effective for fiscal years ending on or after December 31, 2009, the SEC approved revisions designed to modernize reserve reporting requirements for oil and natural gas companies.  In addition, effective for the same period, the FASB issued ASC Update 2010-03, “Extractive Activities – Oil and Gas (Topic 932) – Oil and Gas Reserve Estimation and Disclosures,” to provide consistency with the new SEC rules.  The most significant amendments to the requirements include the following:

· commodity prices – economic producibility of reserves estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions;

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

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

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

· nontraditional resources – the definition of oil and natural gas producing activities were expanded and focus on the marketable product rather than the method of extraction.

The Company adopted the new requirements effective December 31, 2009.  The adoption did not have a material impact on the Company’s results of operations or financial position.  The impact of adoption due to the estimation of reserves using the average price instead of the year-end price was a material reduction in estimated quantity and value of reserves at December 31, 2009, of approximately 195 Bcfe, or $1.50 billion.  There were no other significant impacts of adoption.

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

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

	Year Ended December 31,
	2009		2008		2007
	(in thousands)
Property acquisition costs: (1)
Proved	$	115,929	$	595,795	$	2,422,983
Unproved		947		4,111		148,284
Exploration costs		337		—		—
Development costs		140,892		332,557		189,466
Total costs incurred	$	258,105	$	932,463	$	2,760,733
Costs incurred – continuing operations	$	258,105	$	900,256	$	2,674,439
Costs incurred – discontinued operations	$	—	$	32,207	$	86,294

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

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(C) Oil and Natural Gas Capitalized Costs

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

	December 31,
	2009			2008
	(in thousands)
Proved properties:
Leasehold acquisition	$	3,398,292		$	3,278,155
Development		600,436			460,730
Unproved properties		78,067			92,298
		4,076,795			3,831,183
Less accumulated depletion and amortization		(463,413	)		(278,805	)
	$	3,613,382		$	3,552,378

(D) Results of Oil and Natural Gas Producing Activities

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	408,219		$	755,644		$	255,927
Gain (loss) on oil and natural gas derivatives		(141,374	)		662,782			(345,537	)
		266,845			1,418,426			(89,610	)
Production costs:
Lease operating expenses		132,647			115,402			41,946
Transportation expenses		18,202			17,597			5,575
Production and ad valorem taxes		28,687			59,598			20,295
		179,536			192,597			67,816
Other costs:
Exploration costs		7,169			7,603			4,053
Depletion and amortization		191,314			185,857			64,857
Impairment of goodwill and long-lived assets		―			50,505			―
Texas margin tax expense		490			920			―
(Gain) loss on sale of assets and other, net		(25,710	)		(99,050	)		―
		173,263			145,835			68,910
Results of continuing operations	$	(85,954	)	$	1,079,994		$	(226,336	)
Results of discontinued operations	$	(238	)	$	190,915		$	19,111

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

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(E) Proved Oil, Natural Gas and NGL Reserves

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

	Year Ended December 31, 2009
	Natural Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			Total (MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		851,232			84,144			50,722			1,660,428
Revisions of previous estimates		(69,347	)		10,868			3,904			19,280
Purchase of minerals in place		6,825			8,757			386			61,684
Extensions, discoveries and other additions		31,479			1,648			1,508			50,416
Production		(45,710	)		(3,287	)		(2,358	)		(79,580	)
End of year		774,479			102,130			54,162			1,712,228
Proved developed reserves:
Beginning of year		585,071			61,884			29,600			1,133,976
End of year		549,218			77,878			33,898			1,219,876
Proved undeveloped reserves:
Beginning of year		266,161			22,260			21,122			526,452
End of year		225,261			24,252			20,264			492,352

	Year Ended December 31, 2008
	Natural Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			Total Continuing Operations (MMcfe)			Total Discontinued Operations (MMcfe)			Total (MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		833,390			54,469			43,124			1,418,947			197,160			1,616,107
Revisions of previous estimates		(122,138	)		(16,223	)		(1,427	)		(228,036	)		—			(228,036	)
Purchase of minerals in place		72,817			46,099			3,121			368,136			5,340			373,476
Sales of minerals in place		(47,467	)		(270	)		(11	)		(49,154	)		(199,711	)		(248,865	)
Extensions, discoveries and other additions		159,836			3,207			8,167			228,083			1,757			229,840
Production		(45,206	)		(3,138	)		(2,252	)		(77,548	)		(4,546	)		(82,094	)
End of year		851,232			84,144			50,722			1,660,428			—			1,660,428
Proved developed reserves:
Beginning of year		616,109			42,509			25,546			1,024,440			147,702			1,172,142
End of year		585,071			61,884			29,600			1,133,976			—			1,133,976
Proved undeveloped reserves:
Beginning of year		217,281			11,960			17,578			394,507			49,458			443,965
End of year		266,161			22,260			21,122			526,452			—			526,452

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SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued

	Year Ended December 31, 2007
	Natural Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			Total Continuing Operations (MMcfe)			Total Discontinued Operations (MMcfe)			Total (MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		77,275			29,639			—			255,109			198,957			454,066
Revisions of previous estimates		(7,375	)		6,555			162			32,923			(18,392	)		14,531
Purchase of minerals in place		714,026			17,823			41,741			1,071,409			23,558			1,094,967
Sales of minerals in place		—			—			—			—			(1,511	)		(1,511	)
Extensions, discoveries and other additions		67,994			1,694			2,213			91,437			3,196			94,633
Production		(18,530	)		(1,242	)		(992	)		(31,931	)		(8,648	)		(40,579	)
End of year		833,390			54,469			43,124			1,418,947			197,160			1,616,107
Proved developed reserves:
Beginning of year		49,383			24,304			—			195,206			118,851			314,057
End of year		616,109			42,509			25,546			1,024,440			147,702			1,172,142
Proved undeveloped reserves:
Beginning of year		27,892			5,335			—			59,903			80,106			140,009
End of year		217,281			11,960			17,578			394,507			49,458			443,965

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

The Company sold its interests in properties located in the Appalachian Basin during the year ended December 31, 2008, and the “total discontinued operations” column in the tables above reports the information for these properties.  Other property sales during the year ended December 31, 2008, include the sale of assets in the Verden area of Oklahoma.  See Note 2 for additional details about the Company’s acquisitions and divestitures.

Proved reserves increased by approximately 52 Bcfe, to approximately 1,712 Bcfe for the year ended December 31, 2009, from 1,660 Bcfe for the year ended December 31, 2008.  The year ended December 31, 2009, includes 19 Bcfe in positive revisions of previous estimates, due primarily to higher asset performance, which contributed approximately 38 Bcfe, most significantly related to well reactivations and waterflood optimization work in the Mid-Continent Shallow region.  These positive revisions were partially offset by 19 Bcfe in negative revisions primarily due to decreases in natural gas prices.  Two acquisitions during the year ended December 31, 2009, increased proved reserves by approximately 62 Bcfe.  In addition, extensions and discoveries, primarily from 72 productive wells drilled during the year, contributed approximately 50 Bcfe to the increase in proved reserves.

Proved reserves related to continuing operations increased by approximately 241 Bcfe, to approximately 1,660 Bcfe for the year ended December 31, 2008, from 1,419 Bcfe for the year ended December 31, 2007.  Substantially all of the 228 Bcfe in negative revisions of previous estimates was due to decreases in oil and natural gas prices.  Four acquisitions during the year ended December 31, 2008, increased proved reserves by approximately 368 Bcfe.  In addition, extensions and discoveries, primarily from 304 productive wells drilled during the year, contributed approximately 228 Bcfe to the increase in proved reserves.  The sale of properties located in the Verden area of Oklahoma decreased proved reserves by approximately 49 Bcfe.

Proved reserves related to continuing operations increased by approximately 1,164 Bcfe, to approximately 1,419 Bcfe for the year ended December 31, 2007, from 255 Bcfe for the year ended December 31, 2006.  Six acquisitions during the year ended December 31, 2007, increased proved reserves by approximately 1,071 Bcfe.  In addition, extensions and discoveries, primarily from 136 productive wells drilled during the year, contributed approximately 91 Bcfe to the increase in proved reserves.

108

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued

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

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

	December 31,
	2009			2008			2007
	(in thousands)
Future estimated revenues	$	10,093,876		$	8,261,234		$	12,565,382
Future estimated production costs		(4,200,091	)		(3,410,684	)		(3,052,847	)
Future estimated development costs		(816,577	)		(896,625	)		(582,890	)
Future net cash flows		5,077,208			3,953,925			8,929,645
10% annual discount for estimated timing of cash flows		(3,353,926	)		(2,529,558	)		(5,754,798	)
Standardized measure of discounted future net cash flows – continuing operations	$	1,723,282		$	1,424,367		$	3,174,847
Standardized measure of discounted future net cash flows – discontinued operations	$	—		$	—		$	283,392
Representative NYMEX prices: (1)
Natural gas (MMBtu)	$	3.87		$	5.71		$	6.80
Oil (Bbl)	$	61.05		$	39.22		$	95.92

(1) In accordance with SEC regulations, reserves at December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  In accordance with SEC regulations, reserves for all prior years were estimated using year-end prices.

109

LINN ENERGY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued

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

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Sales and transfers of oil, natural gas and NGL produced during the period	$	(228,683	)	$	(563,047	)	$	(188,111	)
Changes in estimated future development costs		54,141			32,006			6,271
Net change in sales and transfer prices and production costs related to future production		254,036			(2,837,262	)		81,654
Purchase of minerals in place		128,779			1,066,615			2,438,178
Sale of minerals in place		―			(102,437	)		―
Extensions, discoveries, and improved recovery		25,888			383,017			172,989
Previously estimated development costs incurred during the period		52,699			76,150			69,221
Net change due to revisions in quantity estimates		23,672			(69,044	)		56,154
Accretion of discount		142,437			317,485			29,876
Changes in production rates and other		(154,054	)		(53,963	)		209,855
Change – continuing operations	$	298,915		$	(1,750,480	)	$	2,876,087
Change – discontinued operations	$	―		$	(283,392	)	$	29,892

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

110

LINN ENERGY, LLC

SUPPLEMENTAL QUARTERLY DATA (Unaudited)

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

(A) Quarterly Financial Data

	Quarters Ended
	March 31			June 30			September 30			December 31
	(in thousands, except per unit amounts)
2009:
Oil, natural gas and natural gas liquid sales	$	79,864		$	91,906		$	102,989		$	133,460
Gain (loss) on oil and natural gas derivatives	$	161,315		$	(232,775	)	$	(14,065	)	$	(55,849	)
Total revenues and other	$	242,661		$	(139,045	)	$	90,425		$	79,108
Total expenses (1)	$	121,576		$	117,295		$	116,339		$	120,884
(Gain) loss on sale of assets and other, net	$	(26,711	)	$	(5	)	$	1,999		$	119
Income (loss) from continuing operations	$	121,287		$	(268,701	)	$	(82,462	)	$	(65,965	)
Income (loss) from discontinued operations, net of taxes (2)	$	(1,886	)	$	229		$	(1,247	)	$	553
Net income (loss)	$	119,401		$	(268,472	)	$	(83,709	)	$	(65,412	)
Income (loss) per unit – continuing operations:
Basic	$	1.06		$	(2.31	)	$	(0.69	)	$	(0.52	)
Diluted	$	1.06		$	(2.31	)	$	(0.69	)	$	(0.52	)
Income (loss) per unit – discontinued operations:
Basic	$	(0.02	)	$	0.01		$	(0.01	)	$	0.01
Diluted	$	(0.02	)	$	0.01		$	(0.01	)	$	0.01
Net income (loss) per unit:
Basic	$	1.04		$	(2.30	)	$	(0.70	)	$	(0.51	)
Diluted	$	1.04		$	(2.30	)	$	(0.70	)	$	(0.51	)

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

(2) Includes discontinued operations’ gain (loss) on sale of assets, net of taxes.

111

LINN ENERGY, LLC

SUPPLEMENTAL QUARTERLY DATA (Unaudited) - Continued

	Quarters Ended
	March 31			June 30			September 30		December 31
	(in thousands, except per unit amounts)
2008:
Oil, natural gas and natural gas liquid sales (1)	$	175,872		$	255,586		$	240,634	$	83,552
Gain (loss) on oil and natural gas derivatives	$	(268,794	)	$	(870,804	)	$	845,818	$	956,562
Total revenues and other	$	(89,627	)	$	(610,983	)	$	1,091,660	$	1,043,981
Total expenses (2)	$	104,274		$	118,521		$	132,889	$	180,848
(Gain) loss on sale of assets and other, net	$	―		$	―		$	―	$	(98,763	)
Income (loss) from continuing operations	$	(258,959	)	$	(725,381	)	$	921,943	$	888,054
Income (loss) from discontinued operations, net of taxes (3)	$	(400	)	$	13,239		$	160,668	$	452
Net income (loss)	$	(259,359	)	$	(712,142	)	$	1,082,611	$	888,506
Income (loss) per unit – continuing operations: (4)
Basic	$	(2.28	)	$	(6.35	)	$	8.01	$	7.72
Diluted	$	(2.28	)	$	(6.35	)	$	8.01	$	7.72
Income per unit – discontinued operations: (4)
Basic	$	―		$	0.12		$	1.39	$	―
Diluted	$	―		$	0.12		$	1.39	$	―
Net income (loss) per unit: (4)
Basic	$	(2.28	)	$	(6.23	)	$	9.40	$	7.72
Diluted	$	(2.28	)	$	(6.23	)	$	9.40	$	7.72

(1) Oil, natural gas and natural gas liquid sales decreased during the quarter ended December 31, 2008, primarily due to lower commodity prices.  In addition, nonoperated accrual estimate revisions associated with prior quarters of approximately $14.1 million contributed to the decrease.

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

(3) Includes discontinued operations’ gain (loss) on sale of assets, net of taxes.

(4) Effective January 1, 2009, the Company adopted an accounting standard requiring unvested restricted units to be included in the computation of earnings per unit under the two-class method.  The adoption required retrospective adjustment of all prior period earnings per unit data.  The impact of the adoption was a reduction to income from continuing operations per unit – diluted and net income per unit – diluted, of $0.04 per unit and $0.06 per unit, respectively, for the quarter ended September 30, 2008, and $0.04 for the quarter ended December 31, 2008.  There was no impact for the quarters ended March 31, 2008, or June 30, 2008.

112

Item 9.             Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.          Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report.  Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2009.

Management’s Annual Report on Internal Control Over Financial Reporting

See “Management’s Report on Internal Control Over Financial Reporting” in Item 8. “Financial Statements and Supplementary Data.”

Changes in the Company’s Internal Control Over Financial Reporting

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

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

There were no changes in the Company’s internal controls over financial reporting during the fourth quarter of 2009 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B.          Other Information

None.

113

Part III

Item 10.           Directors, Executive Officers and Corporate Governance

A list of the Company’s executive officers and biographical information appears in Part I in this Annual Report on Form 10-K under the caption “Executive Officers of the Company.”  Information about Company Directors may be found under the caption “Election of Directors” of the Proxy Statement for the Annual Meeting of Unitholders to be held on April 27, 2010 (the “2010 Proxy Statement”).  That information is incorporated herein by reference.

The information in the 2010 Proxy Statement set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.

The information required by this item regarding audit committee related matters, codes of ethics and committee charters is incorporated by reference from the 2010 Proxy Statement under the caption “Corporate Governance.”

Item 11.           Executive Compensation

Information required by this item is incorporated herein by reference to the 2010 Proxy Statement.

Item 12.           Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this item is incorporated herein by reference to the 2010 Proxy Statement.

Securities Authorized for Issuance Under Equity Compensation Plans

The following summarizes information regarding the number of units that are available for issuance under all of the Company’s equity compensation plans as of December 31, 2009:

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Unit Options, Warrants and Rights		Weighted Average Exercise Price of Outstanding Unit Options, Warrants and Rights			Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plan  (Excluding Securities Reflected in Column (a))
		(a)		(b)			(c)
Equity compensation plans approved by security holders		1,947,843		$	22.51		6,822,795
Equity compensation plans not approved by security holders		—			—		—
		1,947,843		$	22.51		6,822,795

Item 13.          Certain Relationships and Related Transactions, and Director Independence

Information required by this item is incorporated herein by reference to the 2010 Proxy Statement.

Item 14.          Principal Accounting Fees and Services

Information required by this item is incorporated herein by reference to the 2010 Proxy Statement.

114

Part IV

Item 15.          Exhibits and Financial Statement Schedules

(a) - 2.  Financial Statement Schedules:

All schedules are omitted for the reason that they are not required or the information is otherwise supplied in Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.

(a) - 3.  Exhibits Filed:

The exhibits required to be filed by this Item 15 are set forth in the “Index to Exhibits” accompanying this report.

115

SIGNATURES

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

	LINN ENERGY, LLC
Date:  February 25, 2010	By:	/s/ Mark E. Ellis
		Mark E. Ellis
		President and Chief Executive Officer
Date:  February 25, 2010	By:	/s/ David B. Rottino
		David B. Rottino
		Senior Vice President and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

	Signature		Title		Date
/s/ Michael C. Linn		Executive Chairman		February  25, 2010
Michael C. Linn
/s/ Mark E. Ellis		President and Chief Executive Officer (Principal Executive Officer)		February  25, 2010
Mark E. Ellis
/s/ Kolja Rockov		Executive Vice President and Chief Financial Officer (Principal Financial Officer)		February 25, 2010
Kolja Rockov
/s/ David B. Rottino		Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)		February 25, 2010
David B. Rottino
/s/ George A. Alcorn		Independent Director		February 25, 2010
George A. Alcorn
/s/ Terrence S. Jacobs		Independent Director		February 25, 2010
Terrence S. Jacobs
/s/ Joseph P. McCoy		Independent Director		February 25, 2010
Joseph P. McCoy
/s/ Jeffrey C. Swoveland		Independent Director		February 25, 2010
Jeffrey C. Swoveland

116

INDEX TO EXHIBITS

Exhibit Number				Description
2	.1†*	—	Asset Purchase and Sale Agreement, dated November 25, 2009, between Linn Energy Holdings, LLC and Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P. and Merit Energy Partners F-III, L.P.
3	.1	—		Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)
3	.2	—		Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)
3	.3	—		Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated January 19, 2006, (incorporated herein by reference to Exhibit 3.3 to Annual Report on Form 10-K for the year ended December 31, 2006, filed on March 30, 2007)
3	.4	—		Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated October 24, 2006, (incorporated herein by reference to Exhibit 3.4 to Annual Report on Form 10-K for the year ended December 31, 2006, filed on March 30, 2007)
3	.5	—		Amendment No. 2 to Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated February 1, 2007, (incorporated herein by reference to Exhibit 3.5 to Annual Report on Form 10-K for the year ended December 31, 2006, filed on March 30, 2007)
3	.6	—		Amendment No. 3 to Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated August 31, 2007, (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K, filed on September 5, 2007)
4	.1	—		Form of specimen unit certificate for the units of Linn Energy, LLC (incorporated herein by reference to Exhibit 4.1 to Annual Report on Form 10-K for the year ended December 31, 2005, filed on May 31, 2006)
4	.2	—		Indenture, dated as of June 27, 2008, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 30, 2008)
4	.3	—		Indenture, dated May 18, 2009, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 18, 2009)
4	.4	—		Registration Rights Agreement, dated May 18, 2009, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on May 18, 2009)
10	.1**	—		Linn Energy, LLC Amended and Restated Long-Term Incentive Plan (incorporated herein by reference to Annex A to the Proxy Statement for 2008 Annual Meeting, filed on April 21, 2008)
10	.2**	—		Amendment No. 1 to Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, dated February 4, 2009, (incorporated herein by reference to Exhibit 10.2 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.3**	—		Form of Executive Unit Option Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.3 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.4**	—		Form of Executive Restricted Unit Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.4 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)

117

INDEX TO EXHIBITS - Continued

Exhibit Number			Description
10	.5**	—	Form of Phantom Unit Grant Agreement for Independent Directors pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 9, 2006)
10	.6**	—	Form of Director Restricted Unit Grant Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.6 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.7**	—	Third Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Michael C. Linn (incorporated herein by reference to Exhibit 10.7 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.8**	—	Third Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Kolja Rockov (incorporated herein by reference to Exhibit 10.8 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.9**	—	Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Mark E. Ellis (incorporated herein by reference to Exhibit 10.9 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.10**	—	Amended and Restated Employment Agreement, dated effective December 17, 2008, between Linn Operating, Inc. and Charlene A. Ripley (incorporated herein by reference to Exhibit 10.10 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.11**	—	Amended and Restated Employment Agreement, dated effective December 17, 2008, between Linn Operating, Inc. and Arden L. Walker, Jr. (incorporated herein by reference to Exhibit 10.11 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.12**	—	Second Amended and Restated Employment Agreement, dated December 17, 2008, between Linn Operating, Inc. and David B. Rottino (incorporated herein by reference to Exhibit 10.12 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.13**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and George A. Alcorn (incorporated herein by reference to Exhibit 10.15 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.14**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Joseph P. McCoy (incorporated herein by reference to Exhibit 10.16 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.15**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Terrence S. Jacobs (incorporated herein by reference to Exhibit 10.17 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.16**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Jeffrey C. Swoveland (incorporated herein by reference to Exhibit 10.18 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.17**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Michael C. Linn (incorporated herein by reference to Exhibit 10.19 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.18**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Mark E. Ellis (incorporated herein by reference to Exhibit 10.20 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.19**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Kolja Rockov (incorporated herein by reference to Exhibit 10.21 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.20**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Charlene A. Ripley (incorporated herein by reference to Exhibit 10.22 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)

118

INDEX TO EXHIBITS - Continued

Exhibit Number			Description
10	.21**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and David B. Rottino (incorporated herein by reference to Exhibit 10.23 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.22**	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Arden L. Walker, Jr. (incorporated herein by reference to Exhibit 10.24 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10	.23**	—	Separation Agreement, dated effective May 8, 2008, between Linn Operating, Inc. and Thomas A. Lopus (incorporated herein by reference to Exhibit 10.4 to Quarterly Report on Form 10-Q filed on August 7, 2008)
10	.24	—	Fourth Amended and Restated Credit Agreement dated as of April 28, 2009, among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on May 7, 2009)
10	.25	—	First Amendment, dated May 15, 2009, to Fourth Amended and Restated Credit Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on August 6, 2009)
10	.26	—	Fourth Amended and Restated Guaranty and Pledge Agreement, dated as of April 28, 2009, made by Linn Energy, LLC and each of the other Obligors in favor of BNP Paribas, as Administrative Agent (incorporated herein by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q filed on May 7, 2009)
10	.27	—	Linn Energy, LLC Change of Control Protection Plan, dated as of April 25, 2009, (incorporated herein by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q filed on May 7, 2009)
10	.28†**	—	Amendment No. 1, dated effective as of January 1, 2010, to Third Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Michael C. Linn
10	.29†**	—	Amendment No. 1, dated effective as of January 1, 2010, to Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Mark E. Ellis
21	.1†	—	Significant Subsidiaries of Linn Energy, LLC
23	.1†	—	Consent of KPMG LLP
23	.2†	—	Consent of DeGolyer and MacNaughton
31	.1†	—	Section 302 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
31	.2†	—	Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32	.1†	—	Section 906 Certification of Mark E. Ellis, President and Chief Executive Officer of Linn Energy, LLC
32	.2†	—	Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
99	.1†	—	2009 Report of DeGolyer and MacNaughton

† Filed herewith.

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

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

119

EX-2.1

Exhibit 2.1

PURCHASE AND SALE AGREEMENT

BY AND AMONG

MERIT MANAGEMENT PARTNERS I, L.P., MERIT MANAGEMENT PARTNERS II, L.P., MERIT MANAGEMENT PARTNERS III, L.P., MERIT ENERGY PARTNERS III, L.P., MERIT ENERGY PARTNERS D-III, L.P., MERIT ENERGY PARTNERS E-III, L.P. and MERIT ENERGY PARTNERS F-III, L.P.

AS SELLER

AND

LINN ENERGY HOLDINGS, LLC

AS PURCHASER

Executed on November 25, 2009

TABLE OF CONTENTS

ARTICLE 1	PURCHASE AND SALE		1
Section 1.1		Purchase and Sale	1
Section 1.2		Assets	1
Section 1.3		Excluded Assets	3
Section 1.4		Effective Time; Proration of Costs and Revenues	4
Section 1.5		Delivery and Maintenance of Records	5
ARTICLE 2	PURCHASE PRICE		5
Section 2.1		Purchase Price	6
Section 2.2		Adjustments to Purchase Price	6
Section 2.3		Deposit	8
Section 2.4		Allocation of Purchase Price	8
ARTICLE 3	TITLE MATTERS		8
Section 3.1		Seller’s Title	8
Section 3.2		Definition of Defensible Title	8
Section 3.3		Definition of Permitted Encumbrances	10
Section 3.4		Notice of Title Defect Adjustments	11
Section 3.5		Casualty or Condemnation Loss	16
Section 3.6		Limitations on Applicability	17
ARTICLE 4	ENVIRONMENTAL MATTERS		17
Section 4.1		Assessment	18
Section 4.2		NORM, Wastes and Other Substances	19
Section 4.3		Environmental Defects	20
Section 4.4		Inspection Indemnity	21
Section 4.5		Exclusive Remedy	21
ARTICLE 5	REPRESENTATIONS AND WARRANTIES OF SELLER		21
Section 5.1		Generally	21
Section 5.2		Existence and Qualification	22
Section 5.3		Power	22
Section 5.4		Authorization and Enforceability	22
Section 5.5		No Conflicts	22
Section 5.6		Liability for Brokers’ Fees	23
Section 5.7		Litigation	23
Section 5.8		Taxes and Assessments	23
Section 5.9		Compliance with Laws	24
Section 5.10		Contracts	24

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Section 5.11		Payments for Hydrocarbon Production		24
Section 5.12		Governmental Authorizations		24
Section 5.13		Outstanding Capital Commitments		25
Section 5.14		Imbalances		25
Section 5.15		Condemnation		25
Section 5.16		Bankruptcy		25
Section 5.17		Affiliated Contracts		25
Section 5.18		Foreign Person		25
Section 5.19		Seller Affiliate Obligations		25
Section 5.20		Abandoned Wells	26
Section 5.21		Accuracy of Information	26
Section 5.22		Payout Balances	26
Section 5.23		Operations	26
ARTICLE 6	REPRESENTATIONS AND WARRANTIES OF PURCHASER			26
Section 6.1		Existence and Qualification		26
Section 6.2		Power		27
Section 6.3		Authorization and Enforceability		27
Section 6.4		No Conflicts		27
Section 6.5		Liability for Brokers’ Fees		27
Section 6.6		Litigation		27
Section 6.7		Financing		27
Section 6.8		Limitation		28
Section 6.9		SEC Disclosure		28
Section 6.10		Bankruptcy		28
Section 6.11		Qualification		28
Section 6.12		Knowledge of Title Defects and Environmental Defects		28
Section 6.13		Independent Evaluation		28
ARTICLE 7	COVENANTS OF THE PARTIES			29
Section 7.1		HSR Act		29
Section 7.2		Government Reviews		29
Section 7.3		Notification of Breaches		29
Section 7.4		Letters-in-Lieu; Assignments; Operatorship		30
Section 7.5		Public Announcements		30
Section 7.6		Operation of Business		31
Section 7.7		Preference Rights and Transfer Requirements		31
Section 7.8		Tax Matters		33
Section 7.9		Further Assurances		34
Section 7.10		Performance Bond		34

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Section 7.11		Insurance		34
Section 7.12		No Solicitation of Transactions		34
Section 7.13		Record Retention		34
Section 7.14		Bonds, Letters of Credit and Guarantees		35
Section 7.15		Cure of Misrepresentations Guarantees		35
Section 7.16		Cooperation with Respect to Seller Retained Litigation, Etc.		35
Section 7.17		Plugging, Abandonment, Decommissioning and Other Costs		35
Section 7.18		Employee Matters	35
ARTICLE 8	CONDITIONS TO CLOSING			37
Section 8.1		Conditions of Seller to Closing		37
Section 8.2		Conditions of Purchaser to Closing		39
ARTICLE 9	CLOSING			40
Section 9.1		Time and Place of Closing		40
Section 9.2		Obligations of Seller at Closing		41
Section 9.3		Obligations of Purchaser at Closing		41
Section 9.4		Closing Adjustments and Closing Payments		41
ARTICLE 10	TERMINATION			43
Section 10.1		Termination		44
Section 10.2		Effect of Termination		44
Section 10.3		Distribution of Deposit Upon Termination		44
ARTICLE 11	POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS; DISCLAIMERS AND WAIVERS			45
Section 11.1		Assumed Seller Obligations		45
Section 11.2		Survival		46
Section 11.3		Indemnification by Seller		46
Section 11.4		Indemnification by Purchaser		47
Section 11.5		Indemnification Proceedings		47
Section 11.6		Limitations on Indemnities		49
Section 11.7		Release		49
Section 11.8		Disclaimers		50
Section 11.9		Recording		51
Section 11.10		Non-Compensatory Damages		51
Section 11.11		Disclaimer of Application of Anti-Indemnity Statutes		52
Section 11.12		Tax Indemnification	52
ARTICLE 12	MISCELLANEOUS			53
Section 12.1		Counterparts		53
Section 12.2		Notices		54
Section 12.3		Sales or Use Tax Recording Fees and Similar Taxes and Fees		54

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Section 12.4	Expenses	54
Section 12.5	Change of Name	55
Section 12.6	Governing Law and Venue	55
Section 12.7	Captions	55
Section 12.8	Waivers	55
Section 12.9	Assignment	55
Section 12.10	Entire Agreement	56
Section 12.11	Amendment	56
Section 12.12	No Third-Party Beneficiaries	56
Section 12.13	References	56
Section 12.14	Construction	57
Section 12.15	Conspicuousness	57
Section 12.16	Severability	57
Section 12.17	Time of Essence	57
Section 12.18	Limitation on Damages	57
Section 12.19	Access for Financial Reporting Purposes	57

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EXHIBITS

Exhibit “A”	Leases
Exhibit “A-1”	Wells and Units
Exhibit “B”	Form of Assignment, Conveyance and Bill of Sale
Exhibit “C”	Form of Title Indemnity Agreement
Exhibit “D”	Form of Transition Services Agreement
Exhibit “E”	Certificate of Non-Foreign Status

SCHEDULES

Schedule 1.2(d)	Contracts
Schedule 1.2(e)	Easements
Schedule 1.2(k)	Vehicles and Vessels
Schedule 1.2(l)	Geologic Data
Schedule 1.3(e)	Excluded Assets
Schedule 3.3(m)	Permitted Encumbrances
Schedule 3.4(a)	Allocated Values
Schedule 5.7	Litigation
Schedule 5.8	Taxes and Assessments
Schedule 5.9	Compliance with Laws
Schedule 5.10	Contracts
Schedule 5.11	Hydrocarbon Production Payments
Schedule 5.12	Governmental Authorizations
Schedule 5.15	Outstanding Capital Commitments
Schedule 5.16	Imbalances
Schedule 5.20	Abandoned Wells
Schedule 5.21	Seller Affiliate Obligations
Schedule 7.6	Operation of Business
Schedule 7.7	Preference Rights and Transfer Requirements
Schedule 7.14	Bonds Required

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DEFINITIONS

“Adjustment Period” means the period between the Effective Time and the Closing Date.

“Adjusted Purchase Price” shall mean the Purchase Price after calculating and applying the adjustments set forth in Section 2.2.

“AFE” means authority for expenditure.

“Affected Well” has the meaning set forth in Section 3.4(g)(v).

“Affiliates” with respect to any Person, means any Person that directly or indirectly controls, is controlled by or is under common control with such Person.  The concept of control, controlling or controlled as used in the aforesaid context means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise.  No Person shall be deemed an Affiliate of any Person by reason of the exercise or existence of rights, interests or remedies under this Agreement.

“Agreed Interest Rate” means the rate of interest published in the Wall Street Journal from time to time, as the one month London Interbank Offered Rate (LIBOR) plus 75 basis points, with adjustments in that rate to be made on the same day as any change in that rate.

“Agreement” means this Purchase and Sale Agreement.

“Allocated Value” has the meaning set forth in Section 3.4(a).

“Applicable Contracts” means all Contracts by which the Properties and other Assets are bound or that primarily relate to the Properties or other Assets and (in each case) that will be binding on the Assets or Purchaser after the Closing, including, without limitation; farmin and farmout agreements; bottomhole agreements; crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements; hydrocarbon storage agreements; acreage contribution agreements; operating agreements; balancing agreements; pooling declarations or agreements; unitization agreements; processing agreements; saltwater disposal agreements; facilities or equipment leases; crossing agreements; letters of no objection; platform use agreements; production handling agreements; and other similar contracts and agreements, of Seller and primarily related to the Properties or other Assets, but exclusive of any master service agreements.

“Assessment” has the meaning set forth in Section 4.1(b).

“Assets” has the meaning set forth in Section 1.2.

“Assumed Seller Obligations” has the meaning set forth in Section 11.1.

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“Bond” has the meaning set forth in Section 7.10(a).

“Business Day” means each calendar day except Saturdays, Sundays, and Federal holidays.

“Business Employees” means those full time and part time employees (hourly and salaried) of Seller as identified by Seller at least fifteen (15) Business Days prior to the Closing Date.

“Claim” or “Claims” means any demand, claim or notice sent or given by a Person to another Person in which the former asserts that it has suffered a Loss or has become party to a Proceeding that is the responsibility of the latter Person.

“Claim Notice” has the meaning set forth in Section 11.3(b).

“Closing” has the meaning set forth in Section 9.1(a).

“Closing Date” has the meaning set forth in Section 9.1(b).

“Closing Payment” has the meaning set forth in Section 9.4(a).

“Closing Statements” means the Preliminary Closing Statement and the Final Closing Statement.

“Code” means the Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” has the meaning set forth in Section 4.1(g).

“Contracts” has the meaning set forth in Section 1.2(d).

“Conveyances” has the meaning set forth in Section 3.1(b).

“Cure Period” has the meaning set forth in Section 3.4(b).

“Customary Post-Closing Consents” means the consents and approvals for the assignment of the Assets to Purchaser that are customarily obtained after the assignment of properties similar to the Assets.

“Defective Support Property” has the meaning set forth in Section 3.4(g)(v).

“Defensible Title” has the meaning set forth in Section 3.2.

“Deposit” has the meaning set forth in Section 2.4.

“DOJ” shall mean the Department of Justice.

 “Easements” has the meaning set forth in Section 1.2(e).

“Effective Time” has the meaning set forth in Section 1.4(a).

“Environmental Claim Date” has the meaning set forth in Section 4.3.

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“Environmental Defect” has the meaning set forth in Section 4.3.

“Environmental Defect Amount” has the meaning set forth in Section 4.3.

“Environmental Defect Deductible” has the meaning set forth in Section 4.3.

Environmental Defect Notice” has the meaning set forth in Section 4.3.

“Environmental Laws” means, as the same may have been amended, superseded or replaced, any federal, state or local statute, law, regulation, ordinance, rule, order or decree including any rule of common law, relating to (i) the control of any potential pollutant or protection of the environment, including air, water or land, (ii) the generation, handling, treatment, storage, disposal or transportation of waste materials, or (iii) the regulation of or exposure to Hazardous Materials alleged to be harmful, including, but not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq. (“CERCLA”); the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq. (“RCRA”); the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq. the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Federal Insecticide, Fungicide and Rodenticide Act, 7 U.S.C. § 136 et seq.; the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq.; the Atomic Energy Act, 42 U.S.C. § 2011 et seq.; and all applicable related law, whether local, state, territorial, or national, of any Governmental Body having jurisdiction over the property in question addressing pollution or protection of human health, safety, natural resources or the environment and all regulations implementing the foregoing.  The term “Environmental Laws” includes all judicial and administrative decisions, orders, directives, and decrees issued by a Governmental Body pursuant to the foregoing.

“Environmental Liabilities” shall mean any and all environmental response costs (including costs of remediation), damages, natural resource damages, settlements, consulting fees, expenses, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, attorneys’ fees, and other liabilities incurred or imposed (i) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar act (including settlements) by any Governmental Body to the extent arising out of any violation of, or remedial obligation under, any Environmental Laws which are attributable to the ownership or operation of the Assets prior to, on or after the Effective Time or (ii) pursuant to any claim or cause of action by a Governmental Body or other Person for personal injury, property damage, damage to natural resources, remediation or response costs to the extent arising out of any exposure to Hazardous Materials, any violation of, or any remediation or obligation under, any Environmental Laws which is attributable to the ownership or operation of the Assets prior to, on or after the Effective Time.

“Equipment” has the meaning set forth in Section 1.2(f).

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“Excluded Assets” has the meaning set forth in Section 1.3.

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“Excluded Seller Obligations” has the meaning set forth in Section 11.1.

“Final Closing Statement” has the meaning set forth in Section 9.4(b).

“Final Determination” means, with respect to any Taxes, (i) the expiration of the statute of limitations on both assessments and refunds of such Taxes, or (ii) the final settlement of Taxes through agreement of the parties or by an administrative or judicial decision from which no appeal can be taken or for which the time for taking any such appeal has expired.

“FTC” shall mean the Federal Trade Commission.

“Fundamental Representations” has the meaning set forth in Section 11.2(a).

“Geologic Data” means all (i) seismic, geological, geochemical or geophysical data (including cores and other physical samples of materials from wells or tests) belonging to Seller or licensed from third parties relating to the Properties that can be transferred without additional consideration to such third parties (or including such licensed data in the event Purchaser agrees to pay such additional consideration), and (ii) interpretations of seismic, geological, geochemical or geophysical data belonging to Seller or licensed from third parties that can be transferred without additional consideration to such third parties (or including such licensed data in the event Purchaser agrees to pay such additional consideration).

“Governmental Authorizations” has the meaning set forth in Section 5.12.

“Governmental Body” or “Governmental Bodies” means any federal, state, local, municipal, or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal.

“Hazardous Material” means (i) any “hazardous substance,” as defined by CERCLA, (ii) any “hazardous waste” or “solid waste,” in either case as defined by RCRA, and any analogous state statutes, and any regulations promulgated thereunder, (iii) any solid,  hazardous, dangerous or toxic chemical, material, waste or substance, within the meaning of and regulated by any applicable Environmental Laws, (iv) any radioactive material, including any naturally occurring radioactive material, and any source, special or byproduct material as defined in 42 U.S.C. 2011 et seq. and any amendments or authorizations thereof, (v) any regulated asbestos-containing materials in any form or condition, (vi) any regulated polychlorinated biphenyls in any form or condition, and (vii) petroleum, petroleum hydrocarbons or any fraction or byproducts thereof.

“HSR Act” means the Hart-Scott Rodino Antitrust Improvements Act of 1976.

“Hydrocarbons” means oil, gas, casinghead gas, condensate and other gaseous and liquid hydrocarbons or any combination thereof and sulphur and other minerals extracted from or produced with the foregoing.

“Imbalance” or “Imbalances” means any over-production, under-production, over-delivery, under-delivery or similar imbalance of Hydrocarbons produced from or allocated to the Assets,

Page x

regardless of whether such over-production, under-production, over-delivery under-delivery or similar imbalance arises at the platform, wellhead, pipeline, gathering system, transportation system, processing plant or other location.

“Indemnified Party” has the meaning set forth in Section 11.3(a).

“Indemnifying Party” has the meaning set forth in Section 11.3(a).

“Indemnity Agreement” has the meaning set forth in Section 3.4(d)(ii).

“Independent Expert” has the meaning set forth in Section 4.3.

“Individual Benefit Threshold” has the meaning set forth in Section 3.4(j).

“Individual Environmental Threshold” has the meaning set forth in Section 4.3.

“Individual Title Threshold” has the meaning set forth in Section 3.4(g).

“Invasive Activity” has the meaning set forth in Section 4.1(b).

“Lands” has the meaning set forth in Section 1.2(a).

“Laws” means all statutes, laws, rules, regulations, ordinances, orders, and codes of Governmental Bodies.

“Leases” has the meaning set forth in Section 1.2(a).

“Losses” means any and all debts, obligations and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), diminution in value, monetary damages, fines, fees, Taxes, penalties, interest obligations, deficiencies, losses and expenses (including amounts paid in settlement, interest, court costs, costs of investigators, reasonable fees and expenses of attorneys, accountants, financial advisors and other experts, and other actual out of pocket expenses incurred in investigating and preparing for or in connection with any Proceeding).

“Lowest Cost Response” means the response required or allowed under Environmental Laws that addresses the condition present at the lowest cost (considered as a whole taking into consideration any material negative impact such response may have on the operations of the relevant assets and any potential material additional costs or liabilities that may likely arise as a result of such response) as compared to any other response that is required or allowed under Environmental Laws.

“Material Adverse Effect” means any effect that is material and adverse to the ownership, operation or value of the Assets, taken as a whole, and as currently operated; provided, however, that “Material Adverse Effect” shall not include (i) any effect resulting from entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (ii) any effect resulting from changes in general market, economic, financial or political conditions or any outbreak of hostilities or war, (iii) any effect that affects the Hydrocarbon exploration,

Page xi

production, development, processing, gathering and/or transportation industry generally (including changes in commodity prices or general market prices in the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally), and (iv) any effect resulting from a change in Laws or regulatory policies.

“Material Environmental Defect” means an uncured Environmental Defect that exceeds the Individual Environmental Threshold.

“Material Title Benefit” means a Title Benefit that exceeds the Individual Benefit Threshold.

“Material Title Defect” means an uncured Title Defect that exceeds the Individual Title Threshold.

“Net Revenue Interest” has the meaning set forth in Section 3.2(a).

“NORM” means naturally occurring radioactive material.

“Notice Period” has the meaning set forth in Section 11.5(a).

“P&A Obligations” has the meaning set forth in Section 7.16.

“Permitted Encumbrances” has the meaning set forth in Section 3.3.

“Person” means any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Body or any other entity.

“Pipelines” has the meaning set forth in Section 1.2(g).

“Pre-Closing Period” means any Tax period ending on or before the Closing Date.

“Preference Property” has the meaning set forth in Section 7.7(b).

“Preference Right” means any right or agreement that enables any Person to purchase or acquire any Asset or any interest therein or portion thereof as a result of or in connection with (i) the sale, assignment or other transfer of any Asset or any interest therein or portion thereof or (ii) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Preliminary Closing Statement” has the meaning set forth in Section 9.4(a).

“Proceeding” has the meaning set forth in Section 5.7.

“Properties” has the meaning set forth in Section 1.2(c).

“Property Costs” has the meaning set forth in Section 1.4(b).

“Property Taxes” means ad valorem taxes, real property taxes, personal property taxes and similar obligations.

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“Purchase Price” has the meaning set forth in Section 2.1.

“Purchaser” has the meaning set forth in the preamble hereto.

“Purchaser Indemnified Persons” has the meaning set forth in Section 11.3.

“Purchaser’s Representatives” has the meaning set forth in Section 4.1(a).

“Records” has the meaning set forth in Section 1.2(j).

“REGARDLESS OF FAULT” means WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY CLAIM, INCLUDING, WITHOUT LIMITATION, EVEN THOUGH A CLAIM IS CAUSED IN WHOLE OR IN PART BY:

OTHER THAN GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), STRICT LIABILITY, OR OTHER FAULT OF THE SELLER INDEMNIFIED PERSONS; AND/OR

A PRE-EXISTING DEFECT, WHETHER PATENT OR LATENT, OF THE PREMISES OF PURCHASER’S PROPERTY OR SELLER’S PROPERTY (INCLUDING WITHOUT LIMITATION THE ASSETS), INVITEES AND/OR THIRD PARTIES; AND/OR

THE UNSEAWORTHINESS OF ANY VESSEL OR UNAIRWORTHINESS OF ANY AIRCRAFT OF A PARTY WHETHER CHARTERED, OWNED, OR PROVIDED BY THE PURCHASER INDEMNIFIED PERSONS, SELLER INDEMNIFIED PERSONS, INVITEES AND/OR THIRD PARTIES.

“Retained Asset” has the meaning set forth in Section 7.7(c).

“Retained Employee Liabilities” shall mean any liabilities of Seller or any of its Affiliates (i) to employees of Seller or any of its Affiliates arising under the Worker Adjustment and Retraining Notification Act of 1988, as amended (or similar state or local law), as a result of actions taken by Seller or any of its Affiliates on or prior to the Closing, (ii) arising out of claims by or on behalf of employees of Seller or any of its Affiliates with respect to events that occur on or prior to the Closing and that relate to their employment with, or the terminations of their employment from, Seller, (iii) with respect to employees of Seller or any of its Affiliates arising under any “employee benefit plan” (as defined in Section 3(3) of ERISA) that is or has been sponsored by, contributed to, or maintained by, Seller or any of its Affiliates, or (iv) arising under ERISA for which Purchaser may have any liability under ERISA solely as a result of the consummation of the transaction contemplated by this Agreement.

“Security Replacements” has the meaning set forth in Section 7.14.

“Seller Operated Assets” shall mean Assets operated by Seller.

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“Straddle Period” means any Tax period beginning on or before and ending after the Effective Date.

“Tax Proceeding” shall mean any audit, litigation or other proceeding.

“Tax Return” shall mean any return, declaration or report relating to Taxes due, any information return with respect to Taxes, or other similar report, statement, declaration or document required to be filed under the Code or other Laws in respect of Taxes, any amendment to any of the foregoing, any claim for refund of Taxes paid, and any attachments, amendments or supplements to any of the foregoing.

“Taxes” shall mean any federal, state, county, local, or foreign tax (including Transfer Taxes), charge, fee, levy, impost, duty, or other assessment, including income, gross receipts, excise, employment, sales, use, transfer, recording, license, payroll, franchise, severance, documentary, stamp, occupation, windfall profits, environmental, highway use, commercial rent, customs duty, capital stock, paid-up capital, profits, withholding, Social Security, single business, unemployment, disability, real property, personal property, registration, ad valorem, value added, alternative or add-on minimum, estimated, margin, or other tax or governmental fee of any kind whatsoever, imposed or required to be withheld by any Governmental Body, including any estimated payments relating thereto, any interest, penalties, and additions imposed thereon or with respect thereto, whether disputed or not, and including liability for taxes of another person under Treas. Reg. Section 1.1502-6 or similar provision of state, local or foreign law, or as a transferee, indemnitor, or successor, by contract or otherwise.

“Taxing Authority” shall mean any Governmental Body having jurisdiction over the assessment, determination, collection, or other imposition of any Taxes.

“Title Arbitrator” has the meaning set forth in Section 3.4(f).

“Title Benefit Deductible” has the meaning set forth in Section 3.4(j).

“Title Claim Date” has the meaning set forth in Section 3.4(a).

“Title Defect” has the meaning set forth in Section 3.2.

“Title Defect Amount” has the meaning set forth in Section 3.4(c)(i).

“Title Defect Deductible” has the meaning set forth in Section 3.4(g).

“Title Defect Notice” has the meaning set forth in Section 3.4(a).

“Title Defect Property” has the meaning set forth in Section 3.4(a).

“Transferred Employee” has the meaning set forth in Section 7.18(b).

“Transition Services Agreement” has the meaning set forth in Section 9.2(e).

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“Transfer Requirement” means any consent, approval, authorization or permit of, or filing with or notification to, any Person which is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Asset or any interest therein; provided, however, that “Transfer Requirement” shall not include any consent of, notice to, filing with, or other action by any Governmental Body in connection with the sale or conveyance of oil and/or gas leases or interests therein or Easements or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Easements or interests or they are customarily obtained subsequent to the sale or conveyance (including consents from state agencies).

“Units” has the meaning set forth in Section 1.2(c).

“Wells” has the meaning set forth in Section 1.2(b).

Page xv

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (this “Agreement”) is executed on November 25, 2009, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., Merit Energy Partners F-III, L.P. (collectively, “Seller”), and Linn Energy Holdings, LLC, a Delaware limited liability company (“Purchaser”).

RECITALS

A.          Seller owns various oil and gas properties, either of record or beneficially, more fully described in the exhibits hereto.

B.           Seller desires to sell to Purchaser and Purchaser desires to purchase from Seller the properties and rights of Seller hereafter described, in the manner and upon the terms and conditions hereafter set forth.

C.           Capitalized terms used herein shall have the meanings ascribed to them in this Agreement as such terms are identified and/or defined in the preceding Definitions Section hereof.

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound by the terms hereof, agree as follows:

ARTICLE 1

PURCHASE AND SALE

Section 1.1                      Purchase and Sale.

At the Closing, and upon the terms and subject to the conditions of this Agreement, Seller agrees to sell, transfer and convey the Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the Assets and to assume the obligations attributable to the Assets (including, without limitation the Assumed Seller Obligations).

Section 1.2                      Assets.

As used herein, the term “Assets” means, subject to the terms and conditions of this Agreement, all of Seller’s right, title, interest and estate, real or personal, recorded or unrecorded, movable or immovable, tangible or intangible, in and to the following (but excluding the Excluded Assets):

(a)           All of (i) the oil and gas leases; subleases and other leaseholds; net profits interests; carried interests; farmout rights; options; and other properties and interests described on Exhibit A (collectively, the “Leases”), together with each and every kind and character of

right, title, claim, and interest that Seller has in and to the lands covered by the Leases or the lands currently pooled, unitized, communitized or consolidated therewith (the “Lands”);

(b)           All oil, gas, water, disposal or injection wells located on the Lands, whether producing, shut-in, or abandoned, including the wells shown on Exhibit A-1, whether producing, shut-in, or temporarily abandoned (even to the extent not located on the Lands) (collectively, the “Wells”);

(c)           All interest of Seller derived from the Leases in or to any pools or units which include any Lands or all or a part of any Leases or include any Wells, including those pools or units shown on Exhibit A-1 (the “Units”; the Units, together with the Leases, Lands and Wells, being hereinafter referred to as the “Properties”), and including all interest of Seller derived from the Leases in production of Hydrocarbons from any such Unit, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease, and all tenements, hereditaments and appurtenances belonging to the Leases and Units;

(d)           All contracts, agreements and instruments by which the Properties are bound, or that relate to or are otherwise applicable to the Properties, only to the extent applicable to the Properties rather than Seller’s other properties, including but not limited to, operating agreements, unitization, pooling and communitization agreements, declarations and orders, joint venture agreements, farmin and farmout agreements, exploration agreements, participation agreements, exchange agreements, transportation or gathering agreements, agreements for the sale and purchase of oil, gas, casinghead gas or processing agreements to the extent applicable to the Properties or the production of Hydrocarbons produced in association therewith from the Properties, including those identified on Schedule 1.2(d) (hereinafter collectively referred to as “Contracts”), but excluding any master service agreements and any contracts, agreements and instruments to the extent transfer is restricted by third-party agreement or applicable Law and the necessary consents to transfer are not obtained pursuant to Section 7.7 and provided that “Contracts” shall not include the instruments constituting the Leases;

(e)           All easements, permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (“Easements”) appurtenant to, and used or held for use in connection with the Properties (including those identified on Schedule 1.2(e)), but excluding any permits and other rights to the extent transfer is restricted by third-party agreement or applicable Law and the necessary consents to transfer are not obtained pursuant to Section 7.7;

(f)           All equipment, machinery, fixtures and other tangible personal property and improvements located on the Properties owned by Seller and used or held for use primarily in connection with the operation of the Properties (other than vehicles or vessels which are addressed specifically by Section 1.2(k)) (collectively, “Equipment”);

(g)           All flow lines, pipelines, gathering systems and appurtenances thereto located on the Properties or used, or held for use, in connection with the operation of the Properties (“Pipelines” and, together with the Equipment and Wells, “Personal Property”);

(h)           All Hydrocarbons produced from or attributable to the Leases, Lands, and Wells from and after the Effective Time;

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(i)           All Imbalances;

(j)           All lease files; land files; well files; gas and oil sales contract files; gas processing files; division order files; abstracts; title opinions; land surveys; logs; maps; engineering data and reports; interpretive data, technical evaluations and technical outputs; and other books, records, data, files, and accounting records, in each case to the extent related to the Assets, or used or held for use in connection with the maintenance or operation thereof, but excluding (i) any books, records, data, files, logs, maps, evaluations, outputs, and accounting records to the extent disclosure or transfer would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not satisfied pursuant to Section 7.7, (ii) computer or communications software or intellectual property (including tapes, codes, data and program documentation and all tangible manifestations and technical information relating thereto), (iii) attorney-client privileged communications and work product of Seller’s or any of its Affiliates’ legal counsel (other than title opinions), (iv) reserve studies and evaluations, and (v) records relating to the negotiation and consummation of the sale of the Assets (subject to such exclusions, the “Records”); provided, however, that Seller may retain the originals of such Records as Seller has reasonably determined may be required for existing litigation, tax, accounting, and auditing purposes;

(k)           Those vehicles and vessels specifically listed on Schedule 1.2(k); and

(l)           All Geological Data specifically listed on Schedule 1.2(l).

Section 1.3                      Excluded Assets.

Notwithstanding the foregoing, the Assets shall not include, and there is excepted, reserved and excluded from the purchase and sale contemplated hereby (collectively, the “Excluded Assets”):

(a)           all corporate, partnership, limited liability company, financial, income and franchise tax and legal records of Seller that relate to Seller’s business generally (whether or not relating to the Assets), and all books, records and files that relate to the Excluded Assets and those records retained by Seller pursuant to Section 1.2(j) and copies of any other Records retained by Seller pursuant to Section 1.5;

(b)           All reserve estimates, economic estimates, and, to the extent excluded from Section 1.2(i), all logs, interpretive data, technical evaluations and technical outputs;

(c)           all rights to any refund of Taxes or other costs or expenses borne by Seller or Seller’s predecessors in interest and title attributable to periods prior to the Effective Time;

(d)           Seller’s area-wide bonds, permits and licenses or other permits, licenses or authorizations used in the conduct of Seller’s business generally;

(e)           those items listed in Schedule 1.3(e);

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(f)           all trade credits, account receivables, note receivables, take-or-pay amounts receivable, and other receivables attributable to the Assets with respect to any period of time prior to the Effective Time;

(g)           all claims and causes of action (including any claims for insurance proceeds) arising from acts, omissions or events or damage to or destruction of property with respect to all periods prior to the Effective Time;

(h)           except to the extent specifically provided in Section 1.2(k), all right, title and interest of Seller in and to vehicles or vessels used in connection with the Assets;

(i)           all rights, titles, claims and interests of Seller or any Affiliate of Seller (i) to or under any policy or agreement of insurance or any insurance proceeds; except to the extent provided in Section 3.5, and (ii) to or under any bond or bond proceeds;

(j)           any patent, patent application, logo, service mark, copyright, trade name, trademark or other intellectual property of or associated with Seller or any Affiliate of Seller or any business of Seller or of any Affiliate of Seller;

(k)           all personal computers and associated peripherals and all radio and telephone equipment;

(l)           all proprietary and other computer software;

(m)           all documents and instruments of Seller that may be protected by an attorney-client privilege other than with respect to title opinions;

(n)           except to the extent specifically provided in Section 1.2(l), all Geologic Data; and

(o)           any offices, office leases or personal property that are not directly related to the Assets.

Section 1.4                      Effective Time; Proration of Costs and Revenues.

(a)           Subject to Section 1.5, possession of the Assets shall be transferred from Seller to Purchaser at the Closing, but for purposes of the adjustments made to the Closing Statements certain financial benefits and burdens of the Assets shall be transferred effective as of 7:00 A.M., local time, on November 1, 2009 (the “Effective Time”), as described below.

(b)            “Earned” and “incurred”, as used in this Agreement, shall be interpreted in accordance with generally accepted accounting principles and Council of Petroleum Accountants Society (COPAS) standards, as applicable. “Property Costs” means all costs attributable to the ownership and operation of the Assets (including without limitation costs of insurance relating specifically to the Assets, royalties and overriding royalties payable on account of production from the Assets, Property Taxes, and severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom, but excluding any other Taxes) and capital expenditures incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable,

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in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to the Assets under the relevant operating agreement or unit agreement, if any, by unaffiliated third parties and, with respect to Assets operated by Seller, $250,000 per month (pro rated for any partial months as applicable), but excluding without limitation liabilities, losses, costs, and expenses attributable to (i) claims for personal injury or death, property damage or violation of any Law, (ii) obligations to plug wells or dismantle, abandon and salvage facilities, (iii) obligations to remediate any contamination of groundwater, surface water, soil, Equipment or Pipelines under applicable Environmental Laws, (iv) obligations to furnish make-up gas according to the terms of applicable gas sales, gathering or transportation contracts, (v) gas balancing obligations and (vi) obligations to pay working interests, royalties, overriding royalties or other interests held in suspense, all of which are addressed in Article 11 or elsewhere in this Agreement.  Determination of whether Property Costs are attributable to the period before or after the Effective Time for purposes of the adjustments in the Closing Statements shall be based on when services are rendered, when the goods are delivered, or when the work is performed.  For clarification, the date an item or work is ordered is not the date of a transaction for settlement purposes in the Closing Statements, but rather the date on which the item ordered is delivered to the job site, or the date on which the work ordered is performed, shall be the relevant date.  For purposes of allocating Hydrocarbon production (and accounts receivable with respect thereto), (i) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Leases, Units and Wells when they pass through the pipeline connecting into the storage facilities into which they are run and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Leases, Units and Wells when they pass through the delivery point sales meters on the pipelines through which they are transported. Seller shall utilize reasonable interpolative procedures to arrive at an allocation of Hydrocarbon production when exact meter readings or gauging and strapping data is not available. Seller shall provide to Purchaser, no later than three (3) Business Days prior to Closing, all data necessary to support any estimated allocation, for purposes of establishing the adjustment to the Purchase Price pursuant to Section 2.2 hereof that will be used to determine the Closing Payment for purposes of the Preliminary Closing Statement (as defined in Section 9.4(a)).

(c)           Property Taxes with respect to the Assets, right-of-way fees with respect to the Assets, insurance premiums with respect to the Assets and any other Property Costs that are paid periodically shall be prorated based on the number of days in the applicable period falling before and the number of days in the applicable period falling at or after the Effective Time, except that Hydrocarbon production, severance and similar Taxes shall be prorated based on the number of units actually produced, purchased or sold or proceeds of sale, as applicable, before, and at or after, the Effective Time.   Except as otherwise provided in this Agreement (including, without limitation Article 11), Seller is responsible for all Taxes, right-of-way fees, insurance premiums and the Property Costs allocable to the period falling before the Effective Time and  Purchaser is responsible for all Taxes, right-of-way fees, insurance premiums and the Property Costs allocable to the period falling at or after the Effective Time..

Section 1.5                      Delivery and Maintenance of Records.

Seller, at Purchaser’s sole cost and expense, shall deliver the Records to Purchaser within sixty (60) days following Closing; provided, however, that Seller shall be entitled to retain those original Records necessary to comply with its obligations under any Transition Services

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Agreement (if applicable) for so long as is reasonably necessary to comply with its obligations thereunder and Seller, at Purchaser’s sole expense, shall provide Purchaser with copies of any such original Records retained by Seller as soon as reasonably practicable.  Other than any original Records retained by Seller pursuant to Section 1.2(i), Purchaser shall be entitled to all original Records maintained by Seller.  Seller shall be entitled to keep a copy or copies of all Records; provided, however, that Seller shall not sell or otherwise allow third parties to review, copy or otherwise use (for any purpose) any Records retained by Seller for their own account.  Purchaser shall preserve the Records for a period of seven (7) years following the Closing and will allow Seller and its representatives, consultants and advisors reasonable access, during normal business hours and upon reasonable notice, to the Records for any legitimate business reason of Seller, including in order for Seller to comply with a Tax or other legally required reporting obligation or Tax or legal dispute; provided, however, that Purchaser shall not be required to grant access to Seller or any of its representatives, consultants or advisors, to any Records that are subject to an attorney/client or attorney work product privilege or that would cause Purchaser to violate any obligation to any third party or breach any restriction legally binding on Purchaser.  Any such access shall be at the sole cost and expense of Seller.  Unless otherwise consented to in writing by Seller, for a period of seven (7) years following the Closing Date, Purchaser shall not and shall cause its Affiliates not to, destroy, alter or otherwise dispose of the Records, or any portions thereof, without first giving at least thirty (30) days prior written notice to Seller and offering to surrender to Seller the Records or such portions thereof.

ARTICLE 2

PURCHASE PRICE

Section 2.1                      Purchase Price.

The purchase price for the Assets (the “Purchase Price”) shall be One Hundred Fifty Four Million Five Hundred Thousand Dollars ($154,500,000) payable in United States currency by wire transfer in same day funds as and when provided in this Agreement and as adjusted as provided in Section 2.2.

Section 2.2                      Adjustments to Purchase Price.

For purposes of the Closing Statements, the Purchase Price for the Assets shall be adjusted as follows (with such adjustments being made so as not to give any duplicative effect) with all such amounts being determined in accordance with generally accepted accounting principles and Council of Petroleum Accountants Society (COPAS) standards:

(a)           Reduced by the aggregate amount of the following proceeds actually received by Seller: (i) proceeds from the sale of Hydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out of Hydrocarbon production, gathering, processing and transportation costs and any Hydrocarbon production, severance, sales or excise Taxes not reimbursed to Seller by the purchaser of Hydrocarbon production) produced from or attributable to the Properties during the period between the Effective Time and the date the Final Closing Statement is executed by Seller and Purchaser, and (ii) other proceeds earned with respect to the

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Assets during the period between the Effective Time and the date the Final Closing Statement is executed by Seller and Purchaser;

(b)           Increased by the aggregate amount of the following proceeds actually received by Purchaser: (i) proceeds from the sale of Hydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out of Hydrocarbon production, gathering, processing and transportation costs and any Hydrocarbon production, severance, sales or excise Taxes not reimbursed to Purchaser by the purchaser of of Hydrocarbon production) produced from or attributable to the Properties for periods prior to the Effective Time, and (ii) other proceeds earned with respect to the Assets for periods prior to the Effective Time;

(c)           Reduced to the extent provided in Section 7.7 with respect to Preference Rights and Retained Assets;

(d)           (i) If Seller makes the election under Section 3.4(d)(i) (or if Section 3.4(d)(i) is otherwise implicated by reason of Section 3.4(d)(iv)) with respect to a Material Title Defect, subject to the Title Defect Deductible, reduced by the Title Defect Amount with respect to such Material Title Defect for which the Title Defect Amount has been determined and (ii) subject to the Title Benefit Deductible, increased by the Title Benefit Amount with respect to each Material Title Benefit for which the Title Benefit Amount has been determined;

(e)           Subject to the Environmental Defect Deductible, reduced by the Environmental Defect Amount with respect to each Material Environmental Defect if the Environmental Defect Amount has been determined;

(f)           Increased by the amount of all Property Costs and other costs attributable to the ownership and operation of the Assets which are actually paid by Seller and incurred by Seller (including any overhead costs under Section 1.4 deemed charged to the Assets with respect to the Adjustment Period even though not actually paid), except any Property Costs and other such costs already deducted in the determination of proceeds in Section 2.2(a);

(g)           Reduced to the extent provided in Section 3.4(d)(iii) for any Properties excluded from the Assets pursuant to Section 3.4(d)(iii);

(h)           Increased or reduced as agreed upon in writing by Seller and Purchaser;

(i)           Increased by the value of the amount of merchantable Hydrocarbons stored in tanks and pipelines attributable to the ownership and operation of the Assets that belong to Seller as of the Effective Time (which value shall be computed at the applicable third-party contract prices for the month of November 2009 for such stored Hydrocarbons); and

(j)           Reduced by the actual net aggregate Imbalances, if any, owed by Seller to third-parties, as of the Effective Time or increased by the actual net aggregate Imbalances, if any, owed by third parties to Seller as of the Effective Time, in each case multiplied by a price of $4.47 per MMBtu.

Each adjustment made pursuant to Section 2.2(a) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s entitlement to Hydrocarbon production from or attributable to the

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Properties during the Adjustment Periods, and to the value of other income, proceeds, receipts and credits earned with respect to the Assets during the Adjustment Period, and as such, Purchaser shall not have any separate rights to receive any Hydrocarbon production or income, proceeds, receipts and credits with respect to which an adjustment has been made. Similarly, the adjustment described in Section 2.2(f) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s obligation to pay Property Costs and other costs attributable to the ownership and operation of the Assets which are incurred during the Adjustment Period, and as such, notwithstanding anything in this Agreement to the contrary, Purchaser shall not be separately obligated to pay for any Property Costs or other such costs with respect to which an adjustment has been made.

Section 2.3                      Deposit.

On or before 5:00 p.m. CST on November 27, Purchaser shall have paid to Seller an earnest money deposit in an amount equal to ten percent (10%) of the Purchase Price (the “Deposit”).  The Deposit shall be non-interest bearing and applied against the Purchase Price if the Closing occurs or shall be otherwise distributed in accordance with the terms of this Agreement.

Section 2.4                      Allocation of Purchase Price.

On or before December 31, 2010, Seller shall prepare and deliver to Purchaser a proposed allocation of the Final Purchase Price among each of the Assets, consistent with the principles of Section 1060 of the Code and the Treasury Regulations thereunder.  Seller shall afford Purchaser and its representatives the opportunity to review such proposed allocation.  Each party shall cooperate fully and promptly with the other and their respective representatives in such examination with respect to all reasonable requests related thereto.  After completion of its review of the proposed allocation prepared and delivered by Seller and if Purchaser is in agreement with the proposed allocation of the Final Purchase Price prepared by Seller, Purchaser and Seller shall use the allocated values as the basis for reporting asset values and other items for purposes of all federal, state, and local Tax Returns, including without limitation Internal Revenue Service Form 8594, if required, or any similar statement of such allocation that may be required.  After completion of its review of the proposed allocation prepared and delivered by Seller, if Purchaser disagrees with the proposed allocation of the Final Purchase Price prepared by Seller, Purchaser and Seller shall work together in good faith to resolve any disagreed items.  If Purchaser and Seller are not able to resolve all disagreed items, the parties will agree to proceed as if the Agreement were silent with respect to an allocation of the Final Purchase Price among each of the Assets.

.

ARTICLE 3

TITLE MATTERS

Section 3.1                      Seller’s Title.

(a)           Except for the special warranty of title referenced in Section 3.1(b) and without limiting Purchaser’s right to adjust the Purchase Price by operation of this Article 3, Seller

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makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, and Purchaser hereby acknowledges and agrees that the sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets (i) before Closing, shall be as set forth in Section 3.4(d) and (ii) after Closing, shall be pursuant to the special warranty of title referenced in Section 3.1(b).

(b)           The conveyance covering the Assets to be delivered by Seller to Purchaser shall be substantially in the form of Exhibits B (the “Conveyance”).  The Conveyance shall contain a special warranty of Defensible Title by, through and under Seller and its Affiliates, but not otherwise, to the Units, and Wells shown on Exhibit A-1, subject to the Permitted Encumbrances, but shall otherwise be without warranty of title of any kind, express, implied or statutory or otherwise.

(c)           Purchaser shall not be entitled to protection under Seller’s special warranty of title in the Conveyance against any Title Defect reported by Purchaser under Section 3.4(a).

(d)           Notwithstanding anything herein provided to the contrary, if a Title Defect under this Article 3 results from any matter which could also result in the breach of any representation or warranty of Seller set forth in Article 5, then Purchaser shall only be entitled to assert such matter before Closing as a Title Defect to the extent permitted by this Article 3, and shall be precluded from also asserting such matter as the basis of the breach of any such representation or warranty other than the special warranty of title referenced in Section 3.1(b).

Section 3.2                      Definition of Defensible Title.

As used in this Agreement, the term “Defensible Title” means the title of Seller with respect to the Units, Wells or other Assets shown in Exhibit A-1 that, except for and subject to Permitted Encumbrances:

(a)           Entitles Seller to receive a share of the Hydrocarbons produced, saved and marketed from any Unit, Well or other Asset shown in Exhibit A-1 throughout the duration of the productive life of such Unit, Well or other Asset (after satisfaction of all royalties, overriding royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons) (a “Net Revenue Interest”), of not less than the Net Revenue Interest shown in Exhibit A-1 for such Unit, Well or other Asset, except (solely to the extent that such actions do not cause a breach of Seller’s covenants under Section 7.6) for decreases in connection with those operations in which Seller may from and after the Effective Time become a non-consenting co-owner, decreases resulting from the establishment or amendment from and after the Effective Time of pools or units, decreases in connection with any payouts of non-consent penalties as reflected in Exhibit A-1, and decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under deliveries, and except as stated in such Exhibit A-1;

(b)           Obligates Seller to bear a percentage of the costs and expenses for the maintenance and development of, and operations relating to, (i) any Unit, Well or other Asset shown in Exhibit A-1 not greater than the “working interest” shown in Exhibit A-1 for such Unit, Well or other Asset without increase throughout the productive life of such Unit, Well or

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other Asset, except as stated in Exhibit A-1 and except for increases resulting from contribution requirements with respect to non-consenting co-owners under applicable operating agreements and increases that are accompanied by at least a proportionate increase in Seller’s Net Revenue Interest; and

(c)           Is free and clear of liens, encumbrances, obligations, security interests, irregularities, pledges, or other defects (other than Permitted Encumbrances).

(d)           As used in this Agreement, the term “Title Defect” means any lien, charge, encumbrance, obligation (including contract obligation), defect, or other matter (including without limitation a discrepancy in Net Revenue Interest or working interest) that causes Seller not to have Defensible Title in and to the Units, Wells or other Assets shown on Exhibit A-1 as of the Effective Time and the Closing. As used in this Agreement, the term “Title Benefit” shall mean any right, circumstance or condition that operates to increase the Net Revenue Interest of Seller in any Unit, Well or other Asset shown on Exhibit A-1, without causing a greater than proportionate increase in Seller’s working interest above that shown in Exhibit A-1 as of the Effective Time. Notwithstanding the foregoing, the following shall not be considered Title Defects:

(i) defects based solely on (1) lack of information in Seller’s files, or (2) references to a document(s) if such document(s) is not in Seller’s files;

(ii) defects arising out of lack of corporate or other entity authorization unless Purchaser provides affirmative evidence that the action was not authorized and results in another Person’s superior claim of title to the relevant Asset;

(iii) defects based on failure to record Leases issued by any state or federal Governmental Body, or any assignments of such Leases, in the real property, conveyance or other records of the county or parish in which such Property is located (provided such Leases are recorded in the state or federal records in a manner sufficient to provide adequate notice thereof);

(iv) defects that have been cured by applicable Laws of limitation or prescription;

(v) defects arising out of a lack of survey, unless a survey is expressly required by applicable Laws; and

(vi) defects disclosed herein (including on any Schedule or Exhibit hereto; provided that to the extent such disclosure is contained on Exhibit “A” Leases it must be express and not simply implied based on the listing of the Lease itself).

Section 3.3                      Definition of Permitted Encumbrances.

As used herein, the term “Permitted Encumbrances” means any or all of the following:

(a)           Royalties and any overriding royalties, reversionary interests and other burdens on production, to the extent that any such burden does not reduce Seller’s Net Revenue Interest

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below that shown in Exhibit A-1 or increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in the Net Revenue Interest;

(b)           All Leases, unit agreements, pooling agreements, operating agreements, Hydrocarbon production sales contracts, division orders and other contracts, agreements and instruments applicable to the Assets, to the extent that they do not, individually or in the aggregate, (i) reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1 or increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in the Net Revenue Interest, and (ii) interfere in any material respect with the use, ownership or operation of, the Assets subject thererto or affected thereby (as currently used, owned or operated);

(c)           Preference Rights applicable to this or any future transaction disclosed in Schedule 7.7;

(d)           Transfer Requirements applicable to this or any future transaction disclosed in Schedule 7.7;

(e)           Liens for current Taxes or assessments not yet delinquent or, if delinquent, are identified on Schedule 5.8 as being contested in good faith in the normal course of business;

(f)Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s and other similar liens or charges arising in the ordinary course of business for amounts not yet delinquent (including any amounts being withheld as provided by Law);

(g)           All rights to consent by, required notices to, filings with, or other actions by Governmental Bodies in connection with the sale or conveyance of the Assets or interests therein pursuant to this or to any future transaction if they are not required or customarily obtained prior to the sale or conveyance;

(h)           Rights of reassignment arising upon final intention to abandon or release the Assets, or any of them;

(i)Easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, to the extent that they do not (i) reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1, (ii) increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in Net Revenue Interest, or (iii) detract in any material respect from the value of, or interfere in any material respect with the use, ownership or operation of, the Assets subject thereto or affected thereby (as currently used, owned and operated) and which would be acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

(j)           Calls on Hydrocarbon production under existing Contracts that are listed on Schedule 1.2(d);

(k)           All rights reserved to or vested in any Governmental Body to control or regulate any of the Assets in any manner, and all obligations and duties under all applicable Laws or under any franchise, grant, license or permit issued by any such Governmental Body;

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(l)Any encumbrance on or affecting the Assets which is discharged by Seller at or prior to Closing;

(m)          Any matters shown on Schedule 3.3(m);

(n)           Any other liens, charges, encumbrances, defects or irregularities which do not, individually or in the aggregate, detract in any material respect from the value of, or interfere in any material respect with the use or ownership of, the Assets subject thereto or affected thereby (as currently used or owned), which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties, and which do not reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1, or increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in Net Revenue Interest;

(o)           Matters that would otherwise be considered Title Defects but that do not meet the Individual Title Threshold set forth in Section 3.4(j);

(p)           Imbalances associated with the Assets;

(q)           Liens granted under applicable standard joint operating agreements; and

(r)            Such Title Defects as Purchaser may have waived expressly in writing.

Section 3.4                      Notice of Title Defect Adjustments.

(a)           To assert a claim of a Title Defect prior to Closing, Purchaser must deliver claim notices to Seller (each a “Title Defect Notice”) on or before January 18, 2009 (the “Title Claim Date”); provided, however, that Purchaser agrees that it shall  use commercially reasonable efforts to furnish Seller periodic preliminary notices of  any alleged Title Defect(s) discovered by Purchaser.  Each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect(s), (ii) the Units, Wells or other Assets in Exhibit A-1 affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents reasonably necessary for Seller (as well as any title attorney or examiner hired by Seller) to verify the existence of the alleged Title Defect(s), and (v) the amount by which Purchaser reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations and information upon which Purchaser’s belief is based. Notwithstanding any other provision of this Agreement to the contrary, but subject to Purchaser’s rights in connection with the special warranty of title referenced in Section 3.1(b), Purchaser shall be deemed to have waived its right to assert Title Defects of which Seller has not been given notice on or before the Title Claim Date.  For purposes hereof, the “Allocated Value” of an Asset shall mean the portion of the Purchase Price that has been allocated to a particular Unit or Well in Schedule 3.4(a).

(b)           Seller shall have the right, but not the obligation, to deliver to Purchaser on or before the Title Claim Date, with respect to each Title Benefit, a notice (a “Title Benefit Notice”) including (i) a description of the Title Benefit, (ii) the Units, Wells or other Assets in Exhibit A-1 affected, (iii) the Allocated Values of the Units, Wells or other Assets in Exhibit A-1 subject to such Title Benefit and (iv) the amount by which Seller reasonably believes the Allocated

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Value of those Units, Wells or other Assets is increased by the Title Benefit, and the computations and information upon which Seller’s belief is based. Seller shall be deemed to have waived all Title Benefits of which it has not given notice to Purchaser on or before the Title Claim Date.

(c)           Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure or remove at any time prior to Closing (the “Cure Period”), unless the parties otherwise agree, any Title Defects of which it has been advised in writing by Purchaser.

(d)           In the event that any Title Defect is not waived by Purchaser or cured on or before Closing, subject to the parties’ rights under Section 3.4(i), Purchaser and Seller shall mutually elect to have one of the following remedies apply:

(i) subject to the Individual Title Threshold and the Title Defect Deductible, have the Purchase Price reduced by an amount agreed upon ("Title Defect Amount") pursuant to Section 3.4(g) by Purchaser and Seller as being the value of such Title Defect, taking into consideration the Allocated Value of the Property subject to such Title Defect, the portion of the Property subject to such Title Defect and the legal effect of such Title Defect on the Property affected thereby; provided, however, that the methodology, terms and conditions of Section 3.4(g) shall control any such determination;

(ii) indemnify Purchaser against all liability, loss, cost and expense resulting from such Title Defect pursuant to an indemnity agreement (the "Indemnity Agreement") in the form attached hereto as Exhibit C;

(iii) have Seller retain the entirety of the Property that is subject to such Title Defect, together with all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Property; or

(iv) at Closing, have Purchaser deposit into escrow the full Allocated Value of the Property that is subject to such Title Defect.  Seller shall then have 180 days after Closing in which to cure the Title Defect.  Any Property so held back from the initial Closing will be conveyed to Purchaser at a delayed Closing within ten (10) days following the date that the Title Defect is cured, at which time Seller shall be entitled to withdraw the full Allocated Value of the Property from escrow, and provided further that if multiple delayed Closings are contemplated as a result of this provision and/or Section 7.7(c), the delayed Closings may be consolidated on dates mutually agreeable to the parties.  In the event that Seller is unable to cure the Title Defect within 180 days of the initial Closing, then the remedy set forth in subsection (i) shall be the sole remedy for such Title Defect.  All other provisions of Section 3.4(i) shall apply as written and the Title Expert shall be selected within fifteen (15) Business Days of the end of the 180 day cure period.

In the event that Purchaser and Seller cannot mutually agree upon one of the foregoing remedies with respect to a Title Defect asserted by Purchaser pursuant to Section 3.4(a) prior to

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Closing, then Seller shall, at its sole election, select the remedy set forth in subsection (i), (iii) or (iv) above as the remedy for such Title Defect.

(e)           With respect to each Unit, Well or other Asset in Exhibit A-1 affected by Title Benefits reported under Section 3.4(b), subject to the Individual Benefit Threshold and the Title Benefit Deductible, the Purchase Price shall be increased by an amount (the “Title Benefit Amount”) equal to the increase in the Allocated Value for such Unit, Well or other Asset in Exhibit A-1 caused by such Title Benefits, as determined pursuant to Section 3.4(h).

(f)           Section 3.4(d) shall be the exclusive right and remedy of Purchaser with respect to Title Defects asserted by Purchaser pursuant to Section 3.4(a).  Section 3.4(e) shall be the exclusive right and remedy of Seller with respect to Title Benefits asserted by Seller pursuant to Section 3.4(b).

(g)           The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(i) if Purchaser and Seller agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(ii) if the Title Defect is a lien, encumbrance or other charge which is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii) if the Title Defect represents a discrepancy between (A) the Net Revenue Interest for any Title Defect Property and (B) the Net Revenue Interest stated on Exhibit A-1, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest stated on Exhibit A-1;

(iv) if the Title Defect represents an obligation, encumbrance, burden or charge upon or other defect in title to the Title Defect Property of a type not described in subsections (i), (ii) or (iii) above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Purchaser and Seller and such other factors as are necessary to make a proper evaluation; provided, however, that if such Title Defect is reasonably capable of being cured, the Title Defect Amount shall not be greater than the reasonable cost and expense of curing such Title Defect;

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(v) if (A) the Title Defect Property is not a Well (or specified zone(s) therein, (B) such title Defect Property does not have an Allocated Value, (C) the Title Defect with respect to such Title Defect Property causes a loss of title to such Title Defect Property and (D) the loss of such title to such Title Defect Property will prevent the continued operation or production of a Well (or one or more specified zone(s) therein) shown in Exhibit A-1 (such Well or the specified zone(s) therein being referred to as the “Affected Well”) and the other Assets are not capable of providing an alternative means to support, in all material respects, the continued operation or production of the Affected Well, then such Title Defect Property (a “Defective Support Property”) and such Affected Well(s) shall collectively be considered a single Title Defect Property for purposes of this Section 3.4(g); provided, however, that the Title Defect Amount resulting from the Title Defect affecting such Defective Support Property shall be the lesser of (1) the reasonable cost to replace such Defective Support Property, if such Defective Support Property is reasonably capable of being replaced, (2) the reasonable cost of providing an alternative means to support in all material respects the continued operation or production of the Affected Well, or (3) the Title Defect Amount that would otherwise be applicable to such Title Defect under this Section 3.4(g);

(vi) the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(vii) notwithstanding anything to the contrary in this Article 3, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of the Title Defect Property.

(h)                      Title Benefit Amount.  The Title Benefit Amount resulting from a Title Benefit shall be determined in accordance with the following methodology, terms and conditions:

(i)           if Purchaser and Seller agree on the Title Benefit Amount, then that amount shall be the Title Benefit Amount; and

(ii)           if the Title Benefit represents a benefit in title of a type not described above, the Title Benefit Amount shall be determined by taking into account the Allocated Value of the affected property, the portion of the subject property affected by the Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of the subject property, the values placed upon the Title Benefit by Purchaser and Seller and such other reasonable factors as are necessary to make a proper evaluation.

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(i)           Seller and Purchaser shall attempt in good faith to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts prior to Closing.  If Seller and Purchaser are unable to agree by Closing, the Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 3.4(i). There shall be a single arbitrator, who shall be a title attorney with at least ten (10) years experience in oil and gas titles involving properties in the regional area in which the Properties are located, as selected by mutual agreement of Purchaser and Seller within fifteen (15) Business Days after the end of the Cure Period, and absent such mutual agreement, by the Dallas office of the American Arbitration Association (the “Title Arbitrator”). The arbitration proceeding shall be held in Dallas, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section. The Title Arbitrator’s determination shall be made within fifteen (15) Business Days after submission of the matters in dispute and shall be final and binding upon both parties, without right of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set forth in Section 3.4(g) and Section 3.4(h) and may consider such other matters as in the opinion of the Title Arbitrator are necessary or helpful to make a proper determination. Additionally, the Title Arbitrator may consult with and engage disinterested third parties to advise the arbitrator, including without limitation petroleum engineers.  The Title Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts submitted by either party and may not award damages, interest or penalties to either party with respect to any matter. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case.  Each party shall bear one-half of the costs and expenses of the Title Arbitrator, including any costs incurred by the Title Arbitrator that are attributable to such third party consultation.  Within ten (10) days after the Title Arbitrator delivers written notice to Purchaser and Seller of his award with respect to a Title Defect Amount or a Title Benefit Amount, (i) Purchaser shall pay to Seller the amount, if any, so awarded by the Title Arbitrator to Seller, plus interest payable on such amount at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date on which such amount is paid to Seller and (ii) Seller shall pay to Purchaser the amount, if any, so awarded by the Title Arbitrator to Purchaser, plus interest payable on such amount at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date on which such amount is paid to Purchaser.

(j)           Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any individual uncured Title Defect for which the Title Defect Amount therefor does not exceed $50,000 (“Individual Title Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for uncured Title Defects unless the aggregate Title Defect Amounts attributable to all uncured Material Title Defects exceeds a deductible in an amount equal to Two and One-Half Percent (2.5%) of the Purchase Price (the “Title Defect Deductible”), after which point adjustments to the Purchase Price or other remedies shall be made or available to Purchaser only to the extent the aggregate Title Defect Amounts with respect to uncured Material Title Defects are in excess of such Title Defect Deductible.  Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual Title Benefit for which the Title Benefit Amount does not exceed $50,000 (“Individual Benefit Threshold”); and (ii) in no event shall there be any

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adjustments to the Purchase Price for any Title Benefit unless (i) the excess of the aggregate Title Benefit Amounts attributable to all Material Title Benefits exceeds a deductible in an amount equal to Two and One-Half Percent (2.5%) of the Purchase Price (“Title Benefit Deductible”), after which point adjustments to the Purchase Price shall be made only to the extent the aggregate Title Benefit Amounts with respect to such Material Title Benefits exceed the Title Benefit Deductible.

Section 3.5                      Casualty or Condemnation Loss.

(a)           Notwithstanding anything herein to the contrary, from and after the Effective Time, but subject to the provisions of Section 3.5(b) and (c) and below, Purchaser shall assume all risk of loss with respect to and any change in the condition of the Assets and for production of Hydrocarbons through normal depletion (including but not limited to the watering out of any Well, collapsed casing or sand infiltration of any Well) and the depreciation of personal property due to ordinary wear and tear with respect to the Assets.

(b)           If, after the date of this Agreement but prior to the Closing Date, any portion of the Assets is destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain, and the aggregate amount of any such loss or taking exceeds Twenty Percent (20%) of the Purchase Price, either party shall have the right to terminate this Agreement and Purchaser shall promptly receive back the Deposit.  If the aggregate amount of any such loss or taking is Twenty Percent (20%) or less of the Purchase Price, Purchaser shall be required to close.  If the loss as a result of such individual casualty or taking exceeds $25,000 and the parties proceed to Closing, Seller and Buyer shall elect either (i) to cause the Assets affected by such casualty or taking to be repaired or restored to at least its condition prior to such casualty or taking, at Seller’s sole cost, as promptly as reasonably practicable (which work may extend after the Closing Date), or (ii) to indemnify Purchaser through a document reasonably acceptable to Seller and Purchaser against any costs or expenses that Purchaser reasonably incurs to repair the Assets subject to such casualty or taking or (iii) remove the affected Assets from the Closing and reduce the Purchase Price by the Allocated Value associated with the removed Assets,or (iv) Seller, at Closing, shall pay to Purchaser all sums paid or payable to Seller by Third Parties by reason of such casualty or taking insofar as with respect to the Assets and shall assign, transfer and set over to Purchaser or subrogate Purchaser to all of Seller’s right, title and interest (if any) in insurance claims, unpaid awards and other rights against Third Parties (excluding any Liabilities, other than insurance claims, of or against any Seller Indemnified Parties) arising out of such casualty or taking insofar as with respect to the Assets; provided, however, that in the case of (iv), Seller shall reserve and retain (and Purchaser shall assign to Seller) all rights, title, interests and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to the Closing Date in pursuing or asserting any such insurance claims or other rights against Third Parties or in defending or asserting rights in such condemnation or eminent domain action with respect to the Assets.  In the case of (i) - (iii), Seller shall retain all rights to insurance, condemnation awards and other claims against third parties with respect to the casualty or taking except to the extent the parties otherwise agree in writing.  If Seller and Purchaser are unable to agree on one of the foregoing remedies prior to Closing, then clause (iii) shall apply.

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(c)           If any action for condemnation or taking under right of eminent domain is pending or threatened with respect to any Asset or portion thereof after the date of this Agreement, but no taking of such Asset or portion thereof occurs prior to the Closing Date, Purchaser shall nevertheless be required to close and Seller, at Closing, shall assign, transfer and set over to Purchaser or subrogate Purchaser to all of Seller’s right, title and interest (if any) in such condemnation or eminent domain action, including any future awards therein, insofar as they are attributable to the Assets threatened to be taken, except that Seller shall reserve and retain (and Purchaser shall assign to Seller) all rights, titles, interests and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to the Closing in defending or asserting rights in such action with respect to the Assets.

Section 3.6                      Limitations on Applicability.

Subject to the following sentence, the right of Purchaser to assert a Title Defect under this Agreement shall terminate as of the Title Claim Date, provided there shall be no termination of Purchaser’s or Seller’s rights under Section 3.4 with respect to any bona fide Title Defect properly reported in a Title Defect Notice or bona fide Title Benefit Claim properly reported in a Title Benefit Notice on or before the Title Claim Date. Thereafter, Purchaser’s sole and exclusive rights and remedies with regard to title to the Assets shall be as set forth in, and arising under, the Conveyance transferring the Assets from Seller to Purchaser.

ARTICLE 4

ENVIRONMENTAL MATTERS

Section 4.1                      Assessment.

(a)           From and after the date hereof and up to and including the Closing Date (or earlier termination of this Agreement) but subject to (i) applicable Laws, (ii) the other provisions of this Section 4.1 and (iii) obtaining any required consents of Third Parties, including Third Party operators of the Assets (with respect to which consents Seller shall use commercially reasonable efforts to obtain), Seller shall afford to Purchaser and its officers, employees, agents, accountants, attorneys, investment bankers and other authorized representatives (“Purchaser’s Representatives”) full access, during normal business hours and upon reasonable notice, to the Assets and all Records and other documents in Seller’s or any their respective Affiliates’ possession relating primarily to the Assets.  Seller shall also make available to Purchaser and Purchaser’s Representatives, upon reasonable notice during normal business hours, Seller’s personnel knowledgeable with respect to the Assets in order that Purchaser may make such diligence investigation as Purchaser considers necessary or appropriate.  All investigations and due diligence conducted by Purchaser or any Purchaser’s Representative shall be conducted at Purchaser’s sole cost, risk and expense and any conclusions made from any examination done by Purchaser or any Purchaser’s Representative shall result from Purchaser’s own independent review and judgment.

(b)           Upon reasonable notice to Seller, Purchaser shall have the right to conduct an environmental assessment of all or any portion of the Properties (the "Assessment"), to be conducted by Purchaser or Purchaser’s agent, consultant or contractor (provided Seller

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shall be provided with written notice identifying any such agent, consultant or contractor), but only to the extent that Seller may grant such right without violating any obligations to any third party (provided that Seller shall use its commercially reasonable efforts to obtain any necessary third party consents to any Assessment to be conducted by Purchaser). The Assessment shall be conducted at the sole cost and expense of Purchaser, and shall be subject to the indemnity provisions of Section 4.4. Prior to conducting any sampling, boring, drilling or other invasive investigative activity with respect to the Properties ("Invasive Activity"), Purchaser shall furnish for Seller's review a proposed scope of such Invasive Activity, including a description of the activities to be conducted and a description of the approximate locations of such activities. If any of the proposed activities may unreasonably interfere with normal operation of the Properties, Seller may require an appropriate modification of the proposed Invasive Activity. Seller shall have the right to be present during any Assessment of the Properties and shall have the right, at its option and expense, to split samples with Purchaser.

(c)            Notwithstanding anything herein to the contrary, Purchaser shall not have access to, and shall not be permitted to conduct any environmental due diligence with respect to any Assets where Seller does not have the authority to grant access for such due diligence; provided, however, Seller shall use its commercially reasonable efforts to obtain permission from any Third Party operator to allow Purchaser and Purchaser’s Representatives such access, it being understood by Purchaser that the execution by Purchaser of a customary access agreement may be a condition of such access.

(d)           Purchaser shall coordinate its environmental site assessments and physical inspections of the Assets with Seller to minimize any inconvenience to or interruption of the conduct of business by Seller.  Purchaser shall abide by Seller’s, and any Third Party operator’s, safety rules, regulations and operating policies while conducting its due diligence evaluation of the Assets including any environmental or other inspection or assessment of the Assets.

(e)           Upon completion of Purchaser’s due diligence, Purchaser shall at its sole cost and expense and without any cost or expense to Seller or its Affiliates, (i) repair all damage done to the Assets in connection with Purchaser’s due diligence in accordance with recognized industry standards or requirements of Third Party operators, (ii) restore the Assets to the approximate same or better condition than existed prior to commencement of Purchaser’s due diligence, to the full extent of any damage related to Purchaser’s due diligence, and (iii) remove all equipment, tools or other property brought onto the Assets in connection with Purchaser’s due diligence.  Any disturbance to the Assets (including, without limitation, any real property, platform or other fixtures associated with such Assets) resulting from Purchaser’s due diligence will be promptly corrected by Purchaser.

(f)           During all periods that Purchaser, and/or any of Purchaser’s Representatives are on the Assets, Purchaser shall maintain, at its sole expense insurance that is reasonable and customary in the industry..  Purchaser shall provide evidence of such insurance to Seller prior to entering upon the Assets.

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(g)           All information obtained by Purchaser and its representatives pursuant to this Section 4.1 shall be subject to the terms of that certain confidentiality agreement dated September 24, 2009, but effective as of October 8, 2009, by and between Merit Energy Company, LLC and Purchaser (the “Confidentiality Agreement”); provided that Purchaser is permitted to disclose the proposed acquisition and any details relating thereto to any Governmental Bodies as reasonably necessary to allow Purchaser to conduct its due diligence hereunder (although nothing herein shall be construed as permitting Purchaser to disclose any results from any such due diligence without Seller’s prior written consent).

Section 4.2                      NORM, Wastes and Other Substances.

Purchaser acknowledges that the Assets have been used for the exploration, development, and production of Hydrocarbons and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under the Properties or associated with the Assets.  Equipment and sites included in the Assets may contain Hazardous Materials, including NORM.  NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms.  The wells, materials, and equipment located on the Properties or included in the Assets may contain Hazardous Materials, including NORM.  Hazardous Materials, including NORM, may have come in contact with various environmental media, including without limitation, water, soils or sediment.  Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media and Hazardous Materials, including NORM, from the Assets.

Section 4.3                      Environmental Defects.

If, as a result of its investigation pursuant to Section 4.1, Purchaser determines that with respect to the Assets, there exists a violation of an Environmental Law (other than with respect to NORM and other than with respect to any issues disclosed herein or on any Exhibit or Schedule hereto or any other matter with respect to which Purchaser has knowledge prior to entering into this Agreement) (in each case, an “Environmental Defect”), then on or prior to January 18, 2009 (the “Environmental Claim Date”), Purchaser may notify Seller in writing of such Environmental Defect (an “Environmental Defect Notice”).  For all purposes of this Agreement, Purchaser shall be deemed to have waived any Environmental Defect which Purchaser fails to assert as an Environmental Defect by an Environmental Defect Notice received by Seller on or before the Environmental Claim Date.  To be effective, each such notice shall set forth (i) a description of the matter constituting the alleged Environmental Defect, (ii) the Units/Wells and associated Assets affected by the Environmental Defect, (iii) the estimated Lowest Cost Response to eliminate the Environmental Defect in question (the “Environmental Defect Amount”), and (iv) supporting documents reasonably necessary for Seller to verify the existence of the alleged Environmental Defect and the Environmental Defect Amount.  Purchaser shall use commercially reasonable efforts to furnish Seller periodic preliminary notices of any alleged Environmental Defect discovered by Purchaser.  Seller shall have the right, but not the obligation, to cure any Environmental Defect before Closing or, provided that the parties shall have agreed to the general plan of remediation with respect to such Environmental Defect and the time period by which such remediation shall take place, after Closing.  If Seller disagrees with any of Purchaser’s assertions with respect to the existence of an Environmental Defect or the

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Environmental Defect Amount, Purchaser and Seller will attempt to resolve the dispute prior to Closing.  If the dispute cannot be resolved within ten (10) days of the first meeting of Purchaser and Seller, either party may submit the dispute to an environmental consultant approved in writing by Seller and Purchaser that is experienced in environmental corrective action at oil and gas properties in the relevant jurisdiction and that shall not have performed professional services for either party or any of their respective Affiliates during the previous five years (the “Independent Expert”).  The Independent Expert may elect to conduct the dispute resolution proceeding by written submissions from Purchaser and Seller with exhibits, including interrogatories, supplemented with appearances by Purchaser and Seller, if necessary, as the Independent Expert may deem necessary.  After the parties and Independent Expert have had the opportunity to review all such submissions, the Independent Expert shall call for a final, written offer of resolution from each party.  The Independent Expert shall render its decision within twenty (20) Business Days of receiving such offers by selecting one or the other of the offers. The Independent Expert may not award damages, interest or penalties to either party with respect to any matter.  The decision of the Independent Expert shall be final and binding upon both parties, without right of appeal.  Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case to the Independent Expert. Each party shall bear one-half of the costs and expenses of the Independent Expert.  The parties shall adjust the Purchase Price to reflect the Environmental Defect Amounts, as agreed by the parties or as determined by the Independent Expert, for all uncured Environmental Defects; provided, that notwithstanding anything to the contrary, (a) in no event shall there be any adjustments to the Purchase Price for any individual uncured Environmental Defect for which the Environmental Defect Amount therefor does not exceed $50,000 (“Individual Environmental Threshold”); and (b) in no event shall there be any adjustments to the Purchase Price for any uncured Environmental Defect unless the aggregate Environmental Defect Amount attributable to all Material Environmental Defects exceeds the Two and One-Half Percent (2.5%) of the Purchase Price (the “Environmental Defect Deductible”), after which point Purchaser shall be entitled to adjustments to the Purchase Price or other remedies only to the extent the aggregate Environmental Defect Amounts with respect to all uncured Material Environmental Defects are in excess of such Environmental Defect Deductible.  To the extent the Independent Expert fails to determine any disputed Environmental Defect Amounts prior to Closing, then, within ten (10) days after the Independent Expert delivers written notice to Purchaser and Seller of his award with respect to an Environmental Defect Amount, Seller shall pay to Purchaser the amount, if any, so awarded by the Independent Examiner, plus interest payable on such amount at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date on which such amount is paid to Purchaser.

Section 4.4                      Inspection Indemnity.

Purchaser hereby agrees to defend, indemnify and hold harmless each of the Third Party operators and owners of the Assets and Seller Indemnified Parties from and against any and all Liabilities arising out of, resulting from or relating to any field visit, environmental property assessment, or other due diligence activity conducted by Purchaser or any Purchaser’s Representative with respect to the Assets, even if such Liabilities arise out of or result from, solely or in part, the sole, active, passive, concurrent or comparative negligence, strict liability or other fault or violation of Law of or by any such Third Party operator or owner or Seller

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Indemnified Party, excepting only Liabilities actually resulting on the account of the gross negligence or willful misconduct of such person.

Section 4.5                      Exclusive Remedy.

Subject to the limitations contained therein, Section 5.12 and Section 4.3 shall be the exclusive right and remedy of Purchaser with respect to any Environmental Defect.  Purchaser hereby waives any claims of cost recovery or contribution from Seller or its Affiliates related to the Assets under any Environmental Law or other cause of action.  Notwithstanding anything herein provided to the contrary, if an Environmental Defect under this Article 4 results from any matter which could also result in the breach of any representation or warranty of Seller set forth in Article 5, then Purchaser shall only be entitled to assert such matter (i) before Closing, as an Environmental Defect to the extent permitted by this Article 4, and shall be precluded from also asserting such matter as the basis of the breach of any such representation or warranty, and (ii) after Closing, in accordance with and subject to the limitations of Article 11 (provided that nothing herein shall be construed as permitting Purchaser to assert an Environmental Defect after the Environmental Claim Date unless such matter is being raised solely as a breach of the Representation in Section 5.12 and only to the extent such matter constitutes a breach thereunder.

ARTICLE 5

REPRESENTATIONS AND WARRANTIES OF SELLER

Section 5.1                      Generally.

(a)           Any representation or warranty qualified “to the knowledge of Seller” or “to Seller’s knowledge” or with any similar knowledge qualification is limited to matters within the actual knowledge of the officers of Seller or its Affiliates or those employees of Seller or any of its Affiliates who have responsibility for the Assets and who have the following titles:  General Manager – South Division.  “Actual knowledge” for purposes of this Agreement means information actually personally known by such Persons.

(b)           Inclusion of a matter on a Schedule in relation to a representation or warranty which addresses matters having a Material Adverse Effect shall not be deemed an indication that such matter does, or may, have a Material Adverse Effect. Likewise, the inclusion of a matter on a Schedule in relation to a representation or warranty shall not be deemed an indication that such matter necessarily would, or may, breach such representation or warranty absent its inclusion on such Schedule. Matters may be disclosed on a Schedule to this Agreement for purposes of information only.

(c)           Subject to the foregoing provisions of this Section 5.1, the disclaimers and waivers contained in Sections 11.8, 11.9 and 11.10 and the other terms and conditions of this Agreement, Seller represents and warrants to Purchaser the matters set out in the remainder of this Article 5.

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Section 5.2                      Existence and Qualification.

Each entity comprising Seller is either a limited partnership or a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as a foreign corporation  where the Assets are located, except where the failure to so qualify would not have a Material Adverse Effect.

Section 5.3                      Power.

Seller has the power and authority to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 5.4                      Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary limited partnership or limited liability company action (as applicable) on the part of Seller. This Agreement has been duly executed and delivered by Seller (and all documents required hereunder to be executed and delivered by Seller at Closing will be duly executed and delivered by Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Seller, enforceable against Seller in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar laws affecting the rights and remedies of creditors generally as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

Section 5.5                      No Conflicts.

           Subject to the giving of all notices to Third Parties and the receipt of all consents, approvals and waivers from Third Parties in connection with the transactions contemplated hereby, the execution, delivery and performance by Seller of this Agreement and the consummation of the transactions contemplated herein will not (i) conflict with or result in a breach of any provisions of the organizational documents of Seller, (ii) result in a default or the creation of any encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any Lease, Contract, note, bond, mortgage, indenture, license or other material agreement to which any Seller is a party or by which any Seller or the Assets may be bound or (iii) violate any material Laws applicable to any Seller or any of the Assets.

Section 5.6                      Liability for Brokers’ Fees.

Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Seller or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

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Section 5.7                      Litigation.

With respect to the Assets and Seller’s or any of its Affiliates’ ownership, operation, development, maintenance, or use of any of the Assets, except as set forth in: (i) Schedule 5.7, no proceeding, arbitration, action, suit, pending settlement, or other legal proceeding of any kind or nature before or by any Governmental Body (each, a “Proceeding,” and collectively “Proceedings”) (including any take-or-pay claims) to which Seller or any of its Affiliates is a party and which relates to the Assets is pending or, to Seller’s knowledge, threatened against Seller or any of its Affiliates; (ii) Schedule 5.7, to Seller’s knowledge, no Proceeding or investigation to which Seller is not a party which relates to the Assets is pending or threatened; and (iii) Schedule 5.7, no notice in writing from any third party (including any Governmental Body) has been received by Seller or any of its Affiliates threatening any Proceeding relating to the Assets which could have a Material Adverse Effect (excluding any notices relating to any Environmental Liabilities or Environmental Law).

Section 5.8                      Taxes and Assessments.

(a)           Seller has paid or has caused to be paid, or will pay or will cause to be paid (including by Purchaser), all material Taxes imposed on the Assets or in connection with the business in which the Assets are used that have become due and payable before the Effective Time are being properly paid, other than taxes which are being contested in good faith as disclosed on Schedule 5.8

(b)           To Seller’s knowledge, all of the Assets that are subject to Property Tax have been properly listed and described on the property tax rolls of the appropriate taxing jurisdiction for all periods prior to the Closing Date and no portion of the Assets constitutes omitted property for Property Tax purposes.

Section 5.9                      Compliance with Laws.

Except as disclosed on Schedule 5.9, the Assets are, and the ownership, operation, development, maintenance, and use of any of the Assets are, in compliance with the provisions and requirements of all Laws of all Governmental Bodies having jurisdiction with respect to the Assets, or the ownership, operation, development, maintenance, or use of any of the Assets, except where the failure to so comply would not have a Material Adverse Effect.  Notwithstanding the foregoing, Seller makes no representation or warranty, express or implied, under this Section 5.9 relating to any Environmental Liabilities or Environmental Law.

Section 5.10                    Contracts.

Except as disclosed on Schedule 5.10, to the knowledge of Seller, Seller has paid its share of all costs (including all Property Costs) payable by it under the Contracts.  Seller is in compliance and, to Seller’s knowledge, all counterparties are in compliance under all Contracts, except as disclosed on Schedule 5.10 and except for such non-compliance as would not, individually or the aggregate, have a Material Adverse Effect. To Seller’s knowledge, Schedule 5.10 sets forth all agreement(s) or contract for the sale, exchange, or other disposition of

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Hydrocarbons produced from or attributable to Seller’s interest in the Assets that is not cancelable without penalty or other material payment without first providing more than 60 days prior written notice.

Section 5.11                    Payments for Hydrocarbon Production.

Except as set forth on Schedule 5.11, (a) all rentals, royalties, excess royalty, overriding royalty interests, Hydrocarbon production payments, and other payments due and payable by Seller to overriding royalty holders and other interest owners under or with respect to the Assets and the Hydrocarbons produced therefrom or attributable thereto, have been paid, and (b) Seller is not obligated under any contract or agreement for the sale of gas from the Assets containing a take-or-pay, advance payment, prepayment, or similar provision, or under any gathering, transmission, or any other contract or agreement with respect to any of the Assets to gather, deliver, process, or transport any gas  without then or thereafter receiving full payment therefor.

Section 5.12                    Governmental Authorizations.

Except as disclosed on Schedule 5.9 or Schedule 5.12, (i) Seller has obtained and is maintaining all material federal, state and local governmental licenses, permits, franchises, orders, exemptions, variances, waivers, authorizations, certificates, consents, rights, privileges and applications therefor (the “Governmental Authorizations”) that are presently necessary or required for the ownership and operation of the Seller Operated Assets as currently owned and operated, and (ii) no written notices of material violation have been received by Seller, and no Proceedings are pending or, to Seller’s knowledge, threatened in writing that might result in any material modification, revocation, termination or suspension of any such Governmental Authorizations or which would require any material corrective or remediation action by Seller

Section 5.13                    Outstanding Capital Commitments.

As of the date hereof, there are no outstanding AFEs or other commitments to make capital expenditures which are binding on the Assets and which Seller reasonably anticipates will individually require expenditures by the owner of the Assets after the Effective Time in excess of $100,000(net to Seller’s interest)other than those shown on Schedule 5.13.

Section 5.14                    Imbalances.

To Seller’s knowledge, Schedule 5.14 accurately sets forth in all material respects all of Seller’s Imbalances as of the respective dates set forth therein, arising with respect to the Assets and, except as disclosed in Schedule 5.14, (i) no Person is entitled to receive any material portion of Seller’s Hydrocarbons produced from the Assets or to receive material cash or other payments to “balance” any disproportionate allocation of Hydrocarbons produced from the Assets under any operating agreement, gas balancing or storage agreement, gas processing or dehydration agreement, gas transportation agreement, gas purchase agreement, or other agreements, whether similar or dissimilar, and (ii) Seller is not obligated to deliver any material quantities of gas or to pay any material penalties or other material amounts, in connection with the violation of any of the terms of any gas contract or other agreement with shippers with respect to the Assets.

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Section 5.15                    Condemnation.

To Seller’s knowledge, there is no actual or threatened taking (whether permanent, temporary, whole or partial) of any part of the Properties by reason of condemnation or the threat of condemnation.

Section 5.16                    Bankruptcy.

There are no bankruptcy, reorganization, or receivership proceedings pending against, or, to Seller’s knowledge, being contemplated by or threatened against Seller.

Section 5.17                    Affiliated Contracts.

After Closing, the Assets will not be bound or burdened by any contractual obligation to Seller or an Affiliate of Seller except pursuant to this Agreement.

Section 5.18                    Foreign Person.

No withholding under Section 1445 of the Code is required with respect to any Seller or its partners.

Section 5.19                    Seller Affiliate Obligations.

Other than as shown on Schedule 5.19, after Closing, the Assets shall not be bound by any obligation to Seller or an Affiliate of Seller except as expressly contemplated by this Agreement.

Section 5.20                    Abandoned Wells.

Seller has not abandoned, or agreed to abandon, any wells included in the Assets since the Effective Date and, except as otherwise provided on Exhibit A-1 and except to the extent such wells would not require material plugging and abandonment costs, to Seller’s knowledge there are no dry holes, or otherwise inactive wells, located on the Lands, other than wells that have been properly plugged or abandoned.  For purposes of this Section 5.20, “material plugging and abandonment costs” means, for any individual well, costs of $25,000 or more.

Section 5.21                    Accuracy of Information.

To Seller’s knowledge, the data and information described on Schedule 5.21 is accurate, complete and correct, except for such inaccuracies as would not have a Material Adverse Effect.  The representations contained in this Section 5.21 shall not be construed to be a representation with respect to the accuracy of any estimates, forecasts or conclusions contained in any document.

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Section 5.22                    Payout Balances.

To Seller’s knowledge, Schedule 5.22 sets forth a complete and accurate list of the status of any “payout” balance, as of the Effective Date, for the Wells, subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

Section 5.23                    Operations.

To Seller’s knowledge, except as disclosed in any Schedule hereto (including, without limitation, Schedule 5.7, Schedule 5.9, Schedule 5.12), Seller has operated the Seller Operated Assets in all material respects in accordance with the conditions and provisions of any Governmental Authorizations.

ARTICLE 6

REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to Seller the following:

Section 6.1                      Existence and Qualification.

Purchaser is duly organized, validly existing and in good standing under the laws of the state of its formation; and Purchaser is duly qualified to do business as a foreign limited liability companyin every jurisdiction in which it is required to qualify in order to conduct its business, except where the failure to so qualify would not have a material adverse effect on Purchaser; and Purchaser is or will be as of Closing duly qualified to do business as a foreign limited liability company in the respective jurisdictions where the Assets are located.

Section 6.2                      Power.

Purchaser has the power and authority to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 6.3                      Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transaction contemplated hereby, have been duly and validly authorized by all necessary limited liability company action on the part of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and all documents required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable against Purchaser in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar laws affecting the rights

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and remedies of creditors generally as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 6.4                      No Conflicts.

The execution, delivery and performance by Purchaser of this Agreement and the consummation of the transactions contemplated herein will not conflict with or result in a breach of any provisions of the organizational or other governing documents of Purchaser nor will it violate any Laws applicable to Purchaser or any of its property.

Section 6.5                      Liability for Brokers’ Fees.

Seller shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Purchaser or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 6.6                      Litigation.

There are no Proceedings pending, or to the actual knowledge of Purchaser, threatened in writing before any Governmental Body against Purchaser or any Affiliate of Purchaser which are reasonably likely to impair materially Purchaser’s ability to perform its obligations under this Agreement.

Section 6.7                      Financing.

Prior to the Closing Date, Purchaser will have sufficient cash (in United States dollars) to enable it to pay the Closing Payment to Seller at the Closing and to otherwise satisfy its obligations under this Agreement.

Section 6.8                      Limitation.

Except for the representations and warranties expressly made by Seller in Article 5 of this Agreement, in the Conveyances or confirmed in any certificate furnished or to be furnished to Purchaser pursuant to this Agreement, Purchaser represents and acknowledges that (i) there are no representations or warranties, express, statutory or implied, as to the Assets or prospects thereof, and (ii) Purchaser has not relied upon any oral or written information provided by Seller.  Without limiting the generality of the foregoing, subject to Section 5.7, Purchaser represents and acknowledges that Seller has made and will make no representation or warranty regarding any matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment or any other environmental condition of the Assets.

Section 6.9                      SEC Disclosure.

Purchaser is acquiring the Assets for its own account for use in its trade or business, and not with a view toward or for sale associated with any distribution thereof, nor with any present

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intention of making a distribution thereof within the meaning of the Securities Act of 1933, as amended, and applicable state securities laws.

Section 6.10                    Bankruptcy.

There are no bankruptcy, reorganization or receivership proceedings pending against, being contemplated by, or, to Purchaser’s knowledge, threatened against Purchaser.

Section 6.11                    Qualification.

Purchaser is now, and hereafter shall continue to be, qualified to own and assume operatorship of federal and state oil, gas and mineral leases in all jurisdictions where the Assets to be transferred to it are located, and the consummation of the transactions contemplated in this Agreement will not cause Purchaser to be disqualified as such an owner or operator.  To the extent required by the applicable Law, as of the Closing, Purchaser currently has, and will continue to maintain, lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, such state or federal regulations governing the ownership and operation of such leases.

Section 6.12                    Knowledge of Title Defects and Environmental Defects.

Seller does not have any actual knowledge of any Title Defects or Environmental Defects associated with the Assets as of the date of this Agreement.

Section 6.13                    Independent Evaluation.

Purchaser is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities.  In making its decision to enter into this Agreement and to consummate the transactions contemplated herein, Purchaser (a) has relied or shall rely solely on its own independent investigation and evaluation of the Assets and the advice of its own legal, tax, economic, insurance, environmental, engineering, geological and geophysical advisors and the express provisions of this Agreement and not on any comments, statements, projections or other materials made or given by any representatives or consultants or advisors engaged by Seller, and (b) has satisfied or shall satisfy itself through its own due diligence as to the environmental and physical condition and state of repair of and contractual arrangements and other matters affecting the Assets.  Purchaser has no knowledge of any fact that results in the breach of any representation, warranty or covenant of Seller given hereunder.

ARTICLE 7

COVENANTS OF THE PARTIES

Section 7.1                      HSR Act.

If applicable, within five business days following the execution by Purchaser and Seller of this Agreement, Purchaser and Seller will each prepare and simultaneously file with the DOJ and the FTC, as applicable, the notification and report form required for the transactions contemplated by this Agreement by the HSR Act, and request early termination of the waiting period thereunder.  Purchaser and Seller agree to respond promptly to any inquiries from the

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DOJ or the FTC concerning such filings and to comply in all material respects with the filing requirements of the HSR Act.  Purchaser and Seller shall cooperate with each other and, subject to the terms of the Confidentiality Agreement, shall promptly furnish all information to the other party that is necessary in connection with Purchaser’s and Seller’s compliance with the HSR Act.  Purchaser and Seller shall keep each other fully advised with respect to any requests from or communications with the DOJ or FTC concerning such filings and shall consult with each other with respect to all responses thereto.  Each of Seller and Purchaser shall use its reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act filing to consummate the transactions contemplated hereby.

Section 7.2                      Government Reviews.

(a)           Seller and Purchaser shall in a timely manner (a) make all required filings, if any, with and prepare applications to and conduct negotiations with, each Governmental Body as to which such filings, applications or negotiations are necessary or appropriate in the consummation of the transactions contemplated hereby and (b) provide such information as each may reasonably request to make such filings, prepare such applications and conduct such negotiations.  Each party shall cooperate with and use all commercially reasonable efforts to assist the other with respect to such filings, applications and negotiations.

Section 7.3                      Notification of Breaches.

Until the Closing,

(a)           Purchaser shall notify Seller promptly after Purchaser obtains actual knowledge that any representation or warranty of Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by Seller prior to or on the Closing Date has not been so performed or observed in any material respect.

(b)           Seller shall notify Purchaser promptly after Seller obtains actual knowledge that any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by Purchaser prior to or on the Closing Date has not been so performed or observed in any material respect.

(c)           If any of Purchaser’s or Seller’s representations or warranties is untrue or shall become untrue in any material respect between the date of execution of this Agreement and the Closing Date, or if any of Purchaser’s or Seller’s covenants or agreements to be performed or observed prior to or on the Closing Date shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing, then such breach shall be considered not to have occurred for all purposes of this Agreement.  No such notification shall affect the representations or warranties of the parties or the conditions to their respective obligations hereunder.

(d)           There shall be no breach of the covenants in this Section as a result of a party’s failure to report a breach of any representation or warranty or a failure to perform or observe any

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covenant or agreement of which it had knowledge if the party subject to the breach or failure also had knowledge thereof prior to Closing.

Section 7.4                      Letters-in-Lieu; Assignments; Operatorship.

(a)           Seller will execute on the Closing Date letters in lieu of division and transfer orders relating to the Assets, on forms prepared by Seller and reasonably satisfactory to Purchaser, to reflect the transaction contemplated hereby.

(b)           Seller will prepare and execute, and Purchaser will execute, on the Closing Date, all assignments necessary to convey to Purchaser all federal and state Leases in the form as prescribed by the applicable Governmental Body and otherwise acceptable to Purchaser and Seller.

(c)           Seller makes no representations or warranties to Purchaser as to transferability or assignability of operatorship of any Seller Operated Assets.  Rights and obligations associated with operatorship of such Properties are governed by operating and similar agreements covering the Properties and will be determined in accordance with the terms of such agreements. However, Seller will assist Purchaser in Purchaser’s efforts to succeed Seller, through Purchaser’s agent, Linn Operating, Inc., as operator of any Wells and Units included in the Assets.  Purchaser shall, promptly following Closing, file all appropriate forms and declarations or bonds with federal and state agencies relative to its assumption of operatorship.  For all Seller Operated Assets, Seller shall execute and deliver to Purchaser, and Purchaser shall promptly file the appropriate forms with the applicable regulatory agency transferring operatorship of such Assets to Purchaser.

Section 7.5                      Public Announcements.

Until the Closing, neither Seller nor Purchaser shall make any press release or other public announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of the others; provided, however, the foregoing shall not restrict disclosures by Purchaser or Seller which are required by applicable securities or other laws or regulations or the applicable rules of any stock exchange having jurisdiction over the disclosing party or its Affiliates.  At or after Closing, the content of any press release or public announcement first announcing the consummation of this transaction shall be subject to the prior review and reasonable approval of Seller and Purchaser; provided, however, the foregoing shall not restrict disclosures by Purchaser or Seller which are required by applicable securities or other laws or regulations or the applicable rules of any stock exchange having jurisdiction over the disclosing party or its Affiliates.

Section 7.6                      Operation of Business.

Except as set forth on Schedule 7.6, until the Closing, Seller (i) will operate the Assets and the business thereof in the ordinary course, (ii) will not, without the prior written consent of Purchaser, which consent shall not be unreasonably withheld, commit to any operation, or series of related operations thereon, reasonably anticipated to require future capital expenditures by Purchaser as owner of the Assets in excess of $100,000 (net to Seller’s interest), or make any capital expenditures in respect of the Assets in excess of $100,000 (net to Seller’s interest), or

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terminate, materially amend, execute or extend any material Contracts affecting the Assets, (iii) will use commercially reasonable efforts to maintain insurance coverage on the Assets presently furnished by nonaffiliated third parties in the amounts and of the types presently in force, (iv) will use commercially reasonable efforts to maintain in full force and effect all Leases, (v) will maintain all material governmental permits and approvals affecting the Assets, (vi) will not transfer, farmout, sell, encumber or otherwise dispose of any Assets, except for (A) sales and dispositions of Hydrocarbon production in the ordinary course of business consistent with past practices or (B) transfers, farmouts, encumbrances or other dispositions of Assets, in one or more transactions, not exceeding $100,000 (net to Seller’s interest) of consideration (in any form), in the aggregate, and (vii) will not commit to do any of the foregoing. Purchaser’s approval of any action restricted by this Section 7.6 shall be considered granted within ten (10) days (unless a shorter time is reasonably required by the circumstances and such shorter time is specified in Seller’s written notice) of Seller’s written notice to Purchaser requesting such consent unless Purchaser notifies Seller to the contrary in writing during that period. In the event of an emergency, Seller may take such action as a prudent operator would take and shall notify Purchaser of such action promptly thereafter.  Until and through the Closing Date, Seller agrees to use commercially reasonable efforts to timely notify Purchaser of any forced pooling applications received by Seller with respect to the Assets in order to allow Purchaser to timely respond thereto; provided, however, that any failure by Seller to comply with this sentence shall not constitute a breach of this Agreement or otherwise subject Seller to any liability to Purchaser.

Purchaser acknowledges that Seller may own an undivided interest in certain of the Assets, and Purchaser agrees that the acts or omissions of the other working interest owners who are not affiliated with Seller shall not constitute a violation of the provisions of this Section 7.6 nor shall any action required by a vote of working interest owners constitute such a violation so long as Seller has voted its interest in a manner consistent with the provisions of this Section 7.6.

Section 7.7                      Preference Rights and Transfer Requirements.

(a)           The transactions contemplated by this Agreement are expressly subject to all validly existing and applicable Preference Rights and Transfer Requirements.  Prior to the Closing Date, Seller shall initiate all procedures which are reasonably required to comply with or obtain the waiver of all Preference Rights and Transfer Requirements set forth in Schedule 7.7 with respect to the transactions contemplated by this Agreement.  Seller shall use its commercially reasonable efforts to obtain all applicable consents and to obtain waivers of applicable Preference Rights; provided, however, Seller shall not be obligated to pay any consideration to (or incur any cost or expense for the benefit of) the holder of any Preference Right or Transfer Requirement in order to obtain the waiver thereof or compliance therewith.

(b)           If the holder of a Preference Right elects prior to Closing to purchase the Asset subject to a Preference Right (a “Preference Property”) in accordance with the terms of such Preference Right, and Seller receives written notice of such election prior to the Closing, such Preference Property will be eliminated from the Assets and the Purchase Price shall be reduced by the Allocated Value of the Preference Property.

(c)           If

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(i) a third party brings any suit, action or other proceeding prior to the Closing seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby in connection with a claim to enforce a Preference Right;

(ii) an Asset is subject to a Transfer Requirement that provides that transfer of such Asset without compliance with such Transfer Requirement will result in termination or other material impairment of any rights in relation to such Asset, and such Transfer Requirement is not waived, complied with or otherwise satisfied prior to the Closing Date; or

(iii) the holder of a Preference Right does not elect to purchase such Preference Property or waive such Preference Right with respect to the transactions contemplated by this Agreement prior to the Closing Date and the time in which the Preference Right may be exercised has not expired,

then, unless otherwise agreed by Seller and Purchaser, the Asset or portion thereof affected by such Preference Right or Transfer Requirement (a “Retained Asset”) shall be held back from the Assets to be transferred and conveyed to Purchaser at Closing and the Purchase Price to be paid at Closing shall be reduced by the Allocated Value of such Retained Asset pursuant to Section 7.7(b). Any Retained Asset so held back at the initial Closing will be conveyed to Purchaser at a delayed Closing (which shall become the new Closing Date with respect to such Retained Asset) within ten (10) days following the date on which the suit, action or other proceeding, if any, referenced in clause (i) above is settled or a judgment is rendered (and no longer subject to appeal) permitting transfer of the Retained Asset to Purchaser pursuant to this Agreement and Seller obtains, complies with, obtains a waiver of or notice of election not to exercise or otherwise satisfies all remaining Preference Rights and Transfer Requirements with respect to such Retained Asset as contemplated by this Section (or if multiple Assets are Retained Assets, on a date mutually agreed to by the parties in order to consolidate, to the extent reasonably possible, the number of Closings).  At the delayed Closing, Purchaser shall pay Seller a purchase price equal to the amount by which the Purchase Price was reduced on account of the holding back of such Retained Asset (as adjusted pursuant to Section 2.2 through the new Closing Date therefor); provided, however, if all such Preference Rights and Transfer Requirements with respect to any Retained Asset so held back at the initial Closing are not obtained, complied with, waived or otherwise satisfied as contemplated by this Section within one hundred eighty (180) days after the initial Closing has occurred with respect to any Asset, then at the sole election of Seller such Retained Asset shall be eliminated from the Assets and shall become an Excluded Asset and this Agreement, unless Seller decides to proceed with a closing on such Retained Asset, in which case Purchaser shall be deemed to have waived any objection (and shall be obligated to indemnify the Seller Indemnified Persons for all Losses) with respect to non-compliance with such Preference Rights and Transfer Requirements with respect to such Retained Asset(s).

(d)           Purchaser acknowledges that Seller desires to sell all of the Assets to Purchaser and would not have entered into this Agreement but for Purchaser’s agreement to purchase all of the Assets as herein provided.  Accordingly, it is expressly understood and agreed that Seller does not desire to sell any Property affected by a Preference Right to Purchaser unless the sale of

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all of the Assets is consummated by the Closing Date in accordance with the terms of this Agreement.  In furtherance of the foregoing, Seller’s obligation hereunder to sell the Preference Properties to Purchaser is expressly conditioned upon the consummation by the Closing Date of the sale of all of the Assets (other than Retained Assets or other Assets excluded pursuant to the express provisions of this Agreement) in accordance with the terms of this Agreement, either by conveyance to Purchaser or conveyance pursuant to an applicable Preference Right; provided that, nothing herein is intended or shall operate to extend or apply any Preference Right to any portion of the Assets which is not otherwise burdened thereby.  Time is of the essence with respect to the parties’ agreement to consummate the sale of the Assets by the Closing Date (or by the delayed Closing Date pursuant to Section 7.7(c)).

Section 7.8                      Tax Matters.

(a)          Each party shall provide the other party with reasonable information which may be required by the other party for the purpose of preparing Tax Returns and responding to any audit by any Taxing Authority.  Each party shall cooperate with all reasonable requests of the other party made in connection with contesting the imposition of Taxes.  Notwithstanding anything to the contrary in this Agreement neither party shall be required at any time to disclose to the other party any Tax Returns or other confidential Tax information

(b)           Seller shall prepare or cause to be prepared all Tax Returns with respect to the Assets required to be filed prior to or on the Closing Date.  The Seller will cause such Tax Returns to be timely filed and will provide a copy to the Purchaser.

(c)           Purchaser shall prepare or cause to be prepared all Tax Returns with respect to the Assets required to be filed after the Closing Date for all Pre-Closing Periods and all Straddle Periods.  The Purchaser will cause such Tax Return to be timely filed and will provide a copy to the Seller.  Subject to Section 11.12(c), not later than five (5) days prior to the due date for payment of Taxes with respect to any Tax Return for a Pre-Closing Period or Straddle Period, the Seller shall pay to the Purchaser the amount of any Taxes with respect to such Tax Return for which Seller is responsible pursuant to Section 1.4(c).

(d)           Notwithstanding anything to the contrary in this Section 7.8,Purchaser shall be responsible for the Taxes set forth in Section 12.3.

Section 7.9                      Further Assurances.

After Closing, Seller and Purchaser each agrees to take such further actions and to execute, acknowledge and deliver all such further documents as are reasonably requested by the other party for carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement.

Section 7.10                    Insurance.

At all times material to this Agreement, Purchaser will maintain the types and amount of insurance that is reasonable and customary in the industry.  The parties agree that the types and amount provided by Purchaser to Seller via email on the date of this Agreement is reasonable and customary as of the date of this Agreement.

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Section 7.11                    No Solicitation of Transactions.

So long as Purchaser is not in default of this Agreement, Seller shall not, directly or indirectly, through any officer, director, stockholder, employee, agent, financial advisor, banker or other representative or Affiliate, or otherwise, solicit, initiate, or encourage the submission of any proposal or offer from any Person relating to any acquisition or purchase of all or any material portion of the Assets or participate in any negotiations regarding, or furnish to any other Person any information with respect to, or otherwise cooperate in any way with, or assist or participate in, facilitate, or encourage, any effort or attempt by any other Person to do or seek any of the foregoing.  Seller shall communicate as soon as reasonably practicable to Purchaser the material terms of any such proposal (and the identity of the party making such proposal) which it may receive and, if such proposal is in writing, Seller shall promptly deliver a copy of such proposal to Purchaser.  Seller agrees not to release any third party from, or waive any provision of, any confidentiality agreement relating to the Assets to which Seller or any of its Affiliates is a party.  Seller immediately shall cease and cause to be terminated all existing discussions or negotiations with any parties conducted heretofore with respect to any of the foregoing.

Section 7.13                    Record Retention.

Purchaser, for a period of seven years following Closing, will (i) retain the Records, (ii) provide Seller, its Affiliates and its and their officers, employees and representatives with access to the Records (to the extent that Seller has not retained the original or a copy) during normal business hours for review and copying at Seller’s expense and upon reasonable notice, and (iii) provide Seller, its Affiliates and its and their officers, employees and representatives with access, during normal business hours, to materials received or produced after Closing relating to any indemnity claims made under Sections 11.3 and 11.4 of this Agreement for review and copying at Seller’s expense.  If Purchaser shall desire to dispose of or transfer any such Records or other materials upon or after the expiration of such seven-year period, Purchaser shall, prior to any disposition, give Seller notice and a reasonable opportunity at Seller’s expense to segregate and remove or copy such Records or other materials as Seller may select.

Section 7.14                    Bonds, Letters of Credit and Guarantees.

Purchaser acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by Seller or its Affiliates with Governmental Authorities or Third Parties and relating to the Assets are transferable to Purchaser.  Except to the extent that Purchaser will, as of Closing, be covered by the bonds of the operators of the applicable Assets, then on or before the Closing Date, Purchaser shall obtain, or cause to be obtained in the name of Purchaser, replacements for such bonds, letters of credit and guarantees, to the extent such replacements are necessary to permit the cancellation as of Closing of the bonds, letters of credit and guarantees posted by Seller and/or its Affiliates.  A schedule of the bonds Seller has been required to maintain with respect to the Assets is attached hereto as Schedule 7.14.

Section 7.15                    Cure of Misrepresentations.

If any of the representations and warranties contained in Article 5 or 6 hereof are determined (whether by notice from a party or otherwise) to have been untrue or incorrect as of

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the date of this Agreement, then any cure by the other party of same shall be at such other party’s own expense.

          Section 7.16                   Cooperation with Respect to Seller Retained Litigation, Etc.

Purchaser agrees to use reasonable efforts to cooperate with Seller in connection with Seller’s defense and other actions relating to or arising out of the litigation and claims set forth on Schedule 5.7 and with respect to future audits.  Purchaser agrees to make available Purchaser’s employees engaged in, or having information about, the ownership and operation of the Assets, for the purposes of providing testimony, depositions, information and other related activities relating to such litigation, claims and audits.

Section 7.17                    Plugging, Abandonment, Decommissioning and Other Costs..

In addition to its other obligations under this Agreement, Purchaser shall comply with all Laws, Leases, Contracts (including all joint and unit operating agreements) and prevailing industry standards relating to (i) the plugging, abandonment and/or replugging of all Wells, including inactive Wells or temporarily abandoned Wells, included in the Assets, (ii) the dismantling or decommissioning and removal of any Equipment and other property of whatever kind related to or associated with operations and activities conducted by whomever on the Properties or otherwise, pursuant to the Leases or Applicable Contracts and (iii) the clean up, restoration and/or remediation of the property covered by the Leases or related to the Assets (collectively, the “P&A Obligations”).

Section 7.18                    Employee Matters.

(a)                   Effective as of the Closing Date, Purchaser may make an offer of employment to Business Employees. Nothing in this Agreement shall require or be construed or interpreted as requiring the Purchaser to offer employment to any Business Employee or to continue the employment of any employee of Seller (including any Transferred Employees) following their respective Hire Date, or to prevent Purchaser from changing the terms and conditions of employment (including compensation and benefits) of any of its employees (including any Transferred Employees) following their respective Hire Dates.  Seller and the Purchaser hereby acknowledge and agree that any employment offered by Purchaser to a Transferred Employee will be "at will" and may be terminated by the Purchaser or such Transferred Employee at any time for any reason (subject to applicable Laws and to any specific written commitments made to the contrary by Purchaser or by such Transferred Employee).  Further, any such offer of employment shall be on such terms and conditions as Purchaser determines and may be conditioned upon the Transferred Employee’s passage of Purchaser’s pre-employment screening requirements.

(b)                   For purposes of this Agreement, a “Transferred Employee” is a Business Employee who accepts an offer of employment made pursuant to Section 7.18(a).  No Seller Employee will become a Transferred Employee unless he or she (i) accepts Purchaser’s offer of employment under the terms provided in Purchaser’s offer, (ii) passes any required pre-employment screening required by Purchaser, (iii) on the date hired by Purchaser, is actively at work, on sickness or disability leave, or an approved leave of absence; and (iv) completes one

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hour of actual service with Purchaser.  On or before each Transferred Employee’s date of hire by Purchaser, if any, Seller shall take any necessary action to waive any covenants not to compete, confidentiality provisions or similar restrictions under agreements between Seller and the Transferred Employee that may be applicable to any Transferred Employee, but only to the extent any of the foregoing would preclude a Transferred Employee from accepting employment with Purchaser, and may not restrain such Transferred Employee in any way in performing his services for the Purchaser

(c)           Purchaser shall take such actions as are necessary to provide each Transferred Employee with credit for up to five (5) years of service for Seller and its ERISA Affiliates (including, without limitation, Merit Energy Company LLC) for all purposes, including eligibility, vesting, entitlement to benefits, and benefit accruals, under all employee benefit plans (as defined in section 3(3) of ERISA) and all vacation, sick leave, service award, severance, pension, medical and dental (including retiree medical and dental), and compensation plans, policies, agreements and arrangements maintained by the Purchaser or any of its Affiliates in which such Transferred Employee participates on or after the Closing Date in the same manner as if such service had been service for Purchaser completed after the Closing.

(d)           Purchaser shall take such actions as are necessary to offer Transferred Employees medical and dental coverage for Transferred Employees and their spouses and dependents under Purchaser’s Group Health Plan.  Purchaser shall use best efforts to cause each such Group Health Plan, and applicable insurance carriers, third party administrators and any other third parties, to (i) waive any waiting period(s) under the Group Health Plan otherwise applicable to such Transferred Employees, (ii) waive all limitations as to pre-existing medical conditions under the Group Health Plan applicable to Transferred Employees to the extent that such medical conditions would be covered under the Group Health Plan if they were not pre-existing conditions, and (iii) provide Transferred Employees with credit, for the year in which the Closing Date occurs, for any co-payments, deductibles and out-of-pocket expenses paid prior to the Closing Date in satisfying any applicable co-payment, deductible and out-of-pocket expense requirements under the Group Health Plan.  Purchaser shall take such actions as are necessary to provide continuation health care coverage to Transferred Employees and their qualified beneficiaries who incur qualifying events on or after the Closing Date in accordance with the continuation health care coverage requirements of COBRA.

(e)           Purchaser shall take such actions as are necessary to cause Transferred Employees to participate in any incentive bonus programs in which similarly situated employees of Purchaser or its Affiliates participate.

(f)           With respect to events following the Closing, Seller shall be responsible for sending timely and appropriate notices to all Transferred Employees required under the Worker Adjustment and Retraining Notification Act (“WARN”) and all other applicable Laws relating to plant or facility closings or otherwise regulating the termination of employees.  To the extent that any liability is incurred under any such Laws based on Purchaser’s actions after the Closing, Purchaser shall be solely and exclusively responsible for all obligations and liabilities incurred under WARN and other such Laws relating to this transaction.

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(g)           Seller shall make available to Purchaser records which provide information regarding Transferred Employees’ names and dates of hire by Seller or its ERISA Affiliates.  Seller shall not provide Purchaser records pertaining to performance ratings and evaluations, disciplinary records and medical records.

(h)           Following the Closing Purchaser shall cause to be accepted by the trustee of a Purchaser Retirement Plan in which a Transferred Employee is eligible to participate in a rollover of any eligible rollover distribution (within the meaning of section 402(c) of the Code) of such Transferred Employee’s benefit under a Seller Retirement Plan provided that Purchaser obtains such information as is satisfactory to Purchaser to assure itself that such Seller Retirement Plan satisfies the qualification requirements of section 401(a) of the Code.

ARTICLE 8

CONDITIONS TO CLOSING

Section 8.1                      Conditions of Seller to Closing.

The obligations of Seller to consummate the transactions contemplated by this Agreement are subject, at the option of Seller, to the satisfaction or waiver by Seller on or prior to Closing of each of the following conditions:

(a)           Each of the representations and warranties of Purchaser contained in this Agreement shall be true and correct in all material respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of such specified date;

(b)           Purchaser shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)           No Proceeding by a third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction or decree shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction, and no statute, rule, regulation or other requirement shall have been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby; provided, however, the Closing shall proceed notwithstanding any Proceedings seeking to restrain, enjoin or otherwise prohibit consummation of the transactions contemplated hereby brought by holders of Preference Rights seeking to enforce such rights with respect to the Assets with aggregate Allocated Values of less than twenty percent (20%) of the total unadjusted Purchase Price, and the Assets subject to such Proceedings shall be treated in accordance with Section 7.7;

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(d)           Purchaser shall have delivered (or be ready, willing and able to immediately deliver) to Seller duly executed counterparts of the Conveyances and all other documents and certificates to be delivered by Purchaser under Section 9.3 and shall have performed (or be ready, willing and able to immediately perform) the other obligations required to be performed by it under Section 9.3 (including, without limitation, delivery of the Closing Payment); and

(e)           The sum of all uncured Title Defect Amounts for Material Title Defects determined under Section 3.4(g) prior to Closing, less the sum of all Title Benefit Amounts for Material Title Benefits determined under Section 3.4(h) prior to the Closing, plus Environmental Defects Amounts attributable to Material Environmental Defects, determined or asserted in accordance with this Agreement, shall be less than twenty percent (20%) of the total unadjusted Purchase Price.

(f)           The sum of all Losses from casualties to and takings of the Assets, determined or asserted in accordance with this Agreement, shall be less than twenty percent (20%) of the unadjusted Purchase Price;

(g)           If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions contemplated hereby shall have expired, notice of early termination shall have been received or a consent order issued by or from applicable Governmental Authorities.

(h)           Purchaser shall have obtained, or caused to be obtained, in the name of Purchaser, (i) the Bond, and (ii) replacements for Seller’s and/or its Affiliates’ bonds, letters of credit and guaranties, if any, to the extent required by Section 7.15.

(i)           Purchaser shall have furnished Seller with certificates of insurance on forms reasonably acceptable to Seller which list Purchaser’s insurance policies relating to the Assets, including (i) insurance which complies with all applicable workers’ compensation and occupational disease laws covering all of Purchaser’s employees performing any work or activities as to oil and gas leasehold interests subject to this Agreement, (ii) commercial general liability insurance (including contractual liability coverage) and pollution liability insurance, (iii) excess liability insurance (including contractual liability coverage) of at least $50,000,000, (iv) well control insurance of at least $10,000,000, and (v) such other insurance and proof of financial responsibility as is required under the applicable Laws.

Section 8.2                      Conditions of Purchaser to Closing.

The obligations of Purchaser to consummate the transactions contemplated by this Agreement are subject, at the option of Purchaser, to the satisfaction or waiver by Purchaser on or prior to Closing of each of the following conditions:

(a)           Each of the representations and warranties of Seller contained in this Agreement shall be true and correct in all material respects (other than those representations and warranties of Seller that are qualified by materiality or Material Adverse Effect, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material

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respects (other than those representations and warranties of Seller that are qualified by materiality or Material Adverse Effect, which shall be true and correct in all respects) as of such specified date;

(b)           Seller shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)           No Proceeding by a third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction or decree shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction, and no statute, rule, regulation or other requirement shall have been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby; provided, however, the Closing shall proceed notwithstanding any Proceedings seeking to restrain, enjoin or otherwise prohibit consummation of the transactions contemplated hereby brought by holders of Preference Rights seeking to enforce such rights with respect to the Assets with aggregate Allocated Values of less than twenty percent (20%) of the total unadjusted Purchase Price, and the Assets subject to such Proceedings shall be treated in accordance with Section 7.7;

(d)           Seller shall have delivered (or be ready, willing and able to immediately deliver) to Purchaser duly executed counterparts of the Conveyances and all other documents and certificates to be delivered by Seller under Section 9.2 and shall have performed (or be ready, willing and able to immediately perform) the other obligations required to be performed by it under Section 9.2;

(e)           The sum of all uncured Title Defect Amounts for Material Title Defects determined under Section 3.4(g) prior to the Closing, less the sum of all Title Benefit Amounts for Material Title Benefits determined under Section 3.4(h) prior to the Closing, plus Environmental Defects Amounts attributable to Material Environmental Defects, shall be less than twenty percent (20%) of the unadjusted Purchase Price;

(f)           The sum of all Losses from casualties to and takings of the Assets, determined or asserted in accordance with this Agreement, shall be less than twenty percent (20%) of the unadjusted Purchase Price; and

(g)           If applicable, the waiting period under the HSR Act applicable to the consummation of the transactions contemplated hereby shall have expired, notice of early termination shall have been received or a consent order issued by or from applicable Governmental Authorities.

ARTICLE 9

CLOSING

Section 9.1                      Time and Place of Closing.

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(a)           Unless this Agreement shall have been terminated and the transactions herein contemplated shall have been abandoned pursuant to Article 10, and subject to the satisfaction or waiver of the conditions set forth in Article 8 (other than conditions the fulfillment of which by their nature is to occur at the completion of the transactions contemplated by this Agreement (the “Closing”)), the Closing shall take place at 10:00 a.m., local time, on January 29, 2009, at Seller’s offices  in Dallas, Texas, unless another date, time or place is mutually agreed to in writing by Purchaser and Seller.  If any of the conditions (other than conditions the fulfillment of which by their nature is to occur at the Closing) set forth in Article 8 are not satisfied or waived at the time the Closing is to occur pursuant to the foregoing sentence of this Section 9.1(a), then subject to Article 10 the Closing shall occur on a date thereafter that is the third Business Day after the satisfaction or waiver of all such conditions.

(b)           The date on which the Closing occurs is herein referred to as the “Closing Date.”

Section 9.2                      Obligations of Seller at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Seller shall deliver or cause to be delivered to Purchaser, or perform or cause to be performed, the following:

(a)           the Conveyances in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, duly executed by Seller;

(b)           letters-in-lieu of transfer orders covering the Assets, duly executed by Seller;

(c)           a certificate duly executed by an authorized corporate officer of Seller, dated as of Closing, certifying on behalf of Seller that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

(d)           the Preliminary Closing Statement;

(e)           an executed statement described in Treasury Regulation 1.1445-2(b)(2) certifying that neither Seller nor any partner of Seller is a foreign person within the meaning of the Code.

(f)           any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at Closing.

Section 9.3                      Obligations of Purchaser at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Purchaser shall deliver or cause to be delivered to Seller, or perform or caused to be performed, the following:

(a)           a wire transfer of the Closing Payment, in same-day funds;

(b)           the Conveyances, duly executed by Purchaser;

(c)           letters-in-lieu of transfer orders covering the Assets, duly executed by Purchaser;

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(d)           a certificate by an authorized corporate officer of Purchaser, dated as of Closing, certifying on behalf of Purchaser that the conditions set forth in Sections 8.1(a) and 8.1(b) have been fulfilled;

(e)            the Preliminary Closing Statement; and

(f)           Any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at Closing.

Section 9.4                      Closing Adjustments and Closing Payment.

(a)           Not later than five (5) Business Days prior to the Closing Date, Seller shall prepare and deliver to Purchaser, based upon the best information available to Seller, a preliminary settlement statement estimating the Adjusted Purchase Price after giving effect to all adjustments listed in Section 2.2 and 2.3 (the “Preliminary Closing Statement”).  The estimate delivered in accordance with this Section 9.4(a) shall constitute the dollar amount to be paid by Purchaser to Seller at the Closing (the “Closing Payment”). Until one (1) Business Day before the Closing Date, Purchaser shall have the opportunity to review and discuss the Preliminary Closing Statement with Seller; provided, however, Seller shall not be required to make any change thereto to which Seller does not reasonably agree.

(b)           As soon as reasonably practicable after the Closing but not later than ninety (90) days following the Closing Date, Seller shall prepare and deliver to Purchaser a statement (the “Final Closing Statement”) setting forth the final calculation of the Agreed Purchase Price and showing the calculation of each adjustment, based, to the extent possible, on actual credits, charges, receipts and other items before and after the Effective Time and taking into account all adjustments provided for in this Agreement (the “Final Purchase Price”). Seller shall, at Purchaser’s request, supply reasonable documentation available to support any credit, charge, receipt or other item.  Seller shall afford Purchaser and its representatives the opportunity to review such statement and the supporting schedules, analyses, work papers, and other underlying records or documentation as are reasonably necessary and appropriate in Purchaser’s review of such statement.  Each party shall cooperate fully and promptly with the other and their respective representatives in such examination with respect to all reasonable requests related thereto.  As soon as reasonably practicable but not later than the one hundred twentieth (120th) day following the Closing Date, Purchaser shall deliver to Seller a written report containing any changes that Purchaser proposes be made to such statement. Seller and Purchaser shall undertake to agree on the final statement of the Final Purchase Price no later than one hundred fifty (150) days after the Closing Date (the “Final Settlement Date”).  Unless the parties are unable to reach agreement on the Final Closing Statement on or before the Final Settlement Date, then on the Final Settlement Date, (x) Purchaser shall pay to Seller the amount by which the Final Purchase Price exceeds the Closing Payment or (y) Seller shall pay to Purchaser the amount by which the Closing Payment exceeds the Final Purchase Price, as applicable (in either case, the “Final Adjustment”).

In the event that Seller and Purchaser cannot reach agreement by the Final Settlement Date, either party may refer the remaining matters in dispute to a nationally-recognized independent accounting firm as may be mutually accepted by Purchaser and Seller, for review and final determination (the “Agreed Accounting Firm”).  If issues are submitted to the Agreed

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Accounting Firm for resolution, Seller and Purchaser shall each enter into a customary engagement letter with the Agreed Accounting Firm at the time the issues remaining in dispute are submitted to the Agreed Accounting Firm.  The Agreed Accounting Firm will be directed to (i) review the statement setting forth Seller’s calculation of the Final Purchase Price and the records relating thereto only with respect to items identified by Purchaser in its written report containing changes to such statement that remain disputed immediately following the Final Settlement Date and (ii) determine the final adjustments.  Each party shall furnish the Agreed Accounting Firm such work papers and other records and information relating to the objections in dispute as the Agreed Accounting Firm may reasonably request and that are available to such party or its Affiliates (and such parties’ independent public accountants).  The parties will, and will cause their representatives to, cooperate and assist in the conduct of any review by the Agreed Accounting Firm, including, but not limited to, making available books, records and, as available, personnel as reasonably required.  The Agreed Accounting Firm shall conduct the arbitration proceedings in Houston, Texas in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section 9.4.  The Agreed Accounting Firm’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding on both parties, without right of appeal and such decision shall constitute an arbitral award upon which a judgment may be entered by a court having jurisdiction thereof.  In determining the proper amount of any adjustment to the Final Purchase Price, the Agreed Accounting Firm shall not increase the Final Purchase Price more than the increase proposed by Seller nor decrease the Final Asset Value more than the decrease proposed by Purchaser, as applicable, and may not award damages or penalties to either party with respect to any matter. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case. Each party shall bear one-half of the costs and expenses of the accounting firm.  Within ten (10) Business Days after the date on which the parties or the Agreed Accounting Firm, as applicable, finally determines the disputed matters and have executed the final settlement statement, (x) Purchaser shall pay to Seller the amount by which the Final Purchase Price exceeds the Closing Payment or (y) Seller shall pay to Purchaser the amount by which the Closing Payment exceeds the Final Purchase Price, as applicable. Any post-Closing payment pursuant to this Section 9.4(b) shall bear interest at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date both Purchaser and Seller have executed the final settlement statement.  The Parties acknowledge that it is not the intent of this Agreement that either Party be deprived of material amounts of revenue or be burdened by material amounts of expense until the final adjustment pursuant to Section 9.4(b).  If at any time after Closing either Party believes it is owed material revenues or material expense reimbursement, which revenues and expense reimbursement owed shall be netted against revenues and expenses due the other Party, it may request payment from the other Party, not more frequently than monthly, and such Party shall make payment of any undisputed amounts within a commercially reasonable period of time.  For purposes of the immediately proceeding sentence, material shall mean an amount in excess of $1,000,000.

(c)           All payments made or to be made hereunder to Seller shall be by electronic transfer of immediately available funds to the account of Seller as may be specified by Seller in writing. All payments made or to be made hereunder to Purchaser shall be by electronic transfer of immediately available funds to a bank and account specified by Purchaser in writing to Seller.  Upon execution of the Final Closing Statement by the parties and the payment of the Final

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Adjustment by one party to the other, neither party shall have any further obligation to for any additional adjustments to the Purchase Price under Section 2.2.

ARTICLE 10

TERMINATION

Section 10.1                    Termination.

This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Closing:

(a)           by mutual written consent of Seller and Purchaser;

(b)           by either Seller or Purchaser, if:

(i) the Closing shall not have occurred on or before March 1, 2010 (the “Termination Date”); provided, however, that the right to terminate this Agreement under this Section 10.1(b)(i) shall not be available (A) to Seller, if any breach of this Agreement by Seller has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date or (B) to Purchaser, if any breach of this Agreement by Purchaser has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date; or

(ii) there shall be any Law that makes consummation of the transactions contemplated hereby illegal or otherwise prohibited or a Governmental Body shall have issued an order, decree, or ruling or taken any other action permanently restraining, enjoining, or otherwise prohibiting the consummation of the transactions contemplated hereby, and such order, decree, ruling, or other action shall have become final and non appealable;

(c)           by Seller, if (i) any of the representations and warranties of Purchaser contained in this Agreement shall not be true and correct in all material respects (provided that any such representation or warranty that is already qualified by a materiality standard or a material adverse effect qualification shall not be further qualified); or (ii) Purchaser shall have failed to fulfill in any material respect any of its obligations under this Agreement; and, in the case of each of clauses (i) and (ii), such misrepresentation, or breach of warranty, if curable, has not been cured within ten (10) days after written notice thereof from Seller to Purchaser; provided that any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date; or

(d)           by Purchaser, if (i) any of the representations and warranties of Seller contained in this Agreement shall not be true and correct in all material respects (provided that any such representation or warranty that is already qualified by a materiality or Material Adverse Effect qualification shall not be further qualified); or (ii) Seller shall have failed to fulfill in any material respect any of its obligations under this Agreement, and, in the case of each of clauses (i) and (ii), such misrepresentation, breach of warranty or failure, if curable, has not been cured

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within ten (10) days after written notice thereof from Purchaser to Seller; provided that any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date.

Section 10.2                    Effect of Termination.

If this Agreement is terminated pursuant to Section 10.1, this Agreement shall become void and of no further force or effect (except for the provisions of Section 4.4, Section 5.6, Section 6.5, Section 7.5,  Section 11.8, Section 11.9 and Section 11.10 of this Agreement and this Article 10, the Section entitled “Definitions,” and Article 12  all of which shall continue in full force and effect).  Notwithstanding the foregoing, nothing contained in this Section 10.2 shall relieve any party from liability for Losses resulting from its breach of this Agreement.

Section 10.3                    Distribution of Deposit Upon Termination.

(a)           If Seller terminates this Agreement (i) because Purchaser has failed to comply with any provision of Sections 8.1(a), 8.1(b), 8.1(d), 8.1(g), or 8.1(h);or (ii) as the result of any default or breach by Purchaser of Purchaser’s obligations hereunder, and if Seller is not then in default in any material respect under this Agreement, then Seller may retain the Deposit with any earned interest, as its sole and exclusive remedy as liquidated damages, free of any claims by Purchaser or any other Person with respect thereto.  It is expressly stipulated by the parties that the actual amount of damages resulting from such a termination would be difficult if not impossible to determine accurately because of the unique nature of this Agreement, the unique nature of the Assets, the uncertainties of applicable commodity markets and differences of opinion with respect to such matters, and that the liquidated damages provided for herein are a reasonable estimate by the parties of such damages.

(b)           If this Agreement is terminated for any reason other than the reasons set forth in Section 10.3(a),then Seller shall deliver the Deposit to Purchaser without interest thereon, free of any claims by Seller or any other Person with respect thereto after Purchaser has satisfied any remaining obligations hereunder.

(c)           Notwithstanding anything to the contrary in this Agreement, Purchaser shall not be entitled to receive interest on the Deposit, whether the Deposit is applied against the Purchase Price or returned to Purchaser pursuant to this Section 10.3.

ARTICLE 11

POST-CLOSING OBLIGATIONS; INDEMNIFICATION;

LIMITATIONS; DISCLAIMERS AND WAIVERS

Section 11.1                    Assumed Seller Obligations.

Subject to the indemnification by Seller under Section 11.3 and Section 11.12, on the Closing Date, Purchaser shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of Seller, known or unknown, with respect to the Assets, regardless of whether such obligations or liabilities arose prior to, on or after the Effective Time, including but not limited to obligations to (a) furnish makeup gas according to the terms of applicable gas sales, gathering or transportation contracts, and to satisfy all other gas balancing obligations, if any, (b) pay working interests,

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royalties, overriding royalties and other interests held in suspense, (c) properly plug and abandon any and all wells (including, without limitation, the Wells), including inactive wells or temporarily abandoned wells, drilled on the Properties, as required by Law, (d) replug any well, wellbore, or previously plugged well on the Properties to the extent required by Governmental Body, (e) dismantle, salvage and remove any equipment, structures, materials, platforms, flow lines, and property of whatever kind related to or associated with operations and activities conducted on the Properties, (f) clean up, restore and/or remediate the premises covered by or related to the Assets in accordance with applicable agreements and Laws, (g) pay all Property Costs, (h) perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases or with respect to the Mineral Interests and related contracts, or as required by applicable Laws (all of said obligations and liabilities, subject to the exclusions below, herein being referred to as the “Assumed Seller Obligations”); provided, however, that the Assumed Seller Obligations shall not include, and Purchaser shall have no obligation to assume, any obligations or liabilities of Seller to the extent that they are (such excluded obligations and liabilities, the “Excluded Seller Obligations”):

(i) attributable to or arise out of the Excluded Assets;

(ii) attributable to or arising out of the actions, suits or proceedings, if any, set forth on Schedule 5.7(a), except in so far as they are attributable to or relate to the Assets for periods after the Effective Time;

(iii) Retained Employee Liabilities; and

(iv) Any improper disposal by Seller of materials regulated by Environmental Laws that were removed from the Assets and disposed of at a location other than the Assets.

Section 11.2                    Survival.

(a)           All representations and warranties of Seller and Purchaser contained herein shall expire on the date that is one hundred twenty (120) days after the Closing Date (the “Indemnity End Date”); provided, however, that the representations and warranties contained in Section 5.3, Section 5.4, Section 5.6, Section 5.8, Section 6.2, Section 6.3, and Section 6.5 (collectively, the “Fundamental Representations”)shall survive until the end of six months following the expiration of the applicable statute of limitations period.  Upon the termination of a representation or warranty in accordance with the foregoing, such representation or warranty shall have no further force or effect for any purpose under this Agreement.  The covenants and other agreements of Seller and Purchaser set forth in this Agreement shall survive the Closing Date until fully performed.

(b)           No party hereto shall have any indemnification obligation pursuant to this Article 11 or otherwise hereunder unless it shall have received from the party seeking indemnification a written notice (a “Claim Notice”) of the existence of the claim for or in respect of which indemnification is being sought hereunder on or before the expiration of the applicable survival period set forth in Section 11.2(a).  If an Indemnified Party delivers a Claim Notice with respect to a representation or warranty to an Indemnifying Party before the expiration of the applicable

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survival period set forth in Section 11.2(a), then the applicable representation or warranty shall survive until, but only for purposes of, the resolution of the matter covered by such Claim Notice.  A Claim Notice shall set forth with reasonable specificity (1) the basis for such claim under this Agreement, and the facts that otherwise form the basis of such claim and (2) to the extent reasonably estimable, an estimate of the amount of such claim (which estimate shall not be conclusive of the final amount of such claim) and an explanation of the calculation of such estimate.

Section 11.3                    Indemnification by Seller.

From and after the Closing, subject to the terms and conditions of this Article 11 (including, without limitation, the survival and the timing requirement in Section 11.2) and subject to Purchaser’s indemnification obligations with respect to its representations and warranties herein, Seller shall jointly and severally indemnify, defend and hold harmless Purchaser and its directors, officers, employees, stockholders, members, agents, consultants, advisors and other representatives (including legal counsel, accountants and financial advisors) and Affiliates and the successors and permitted assigns of this Agreement of Purchaser (collectively, the “Purchaser Indemnified Persons”) from and against any and all Losses asserted against, resulting from, imposed upon, or incurred or suffered by any Purchaser Indemnified Person to the extent resulting from, arising out of or relating to:

(a)           any breach of any representation of Seller contained in this Agreement or confirmed in any certificate furnished by or on behalf of Seller in connection with this Agreement REGARDLESS OF FAULT;

(b)           any breach or nonfulfillment of or failure to perform any covenant or agreement of Seller contained in this Agreement REGARDLESS OF FAULT or confirmed in any certificate furnished by or on behalf of Seller in connection with this Agreement; and

(c)           any Excluded Seller Obligations.

Section 11.4                    Indemnification by Purchaser.

From and after the Closing, subject to the adjustments to the Purchase Price for purposes of the Closing Statements contained in Section 2.2 and the terms and conditions of this Article 11 (including, without limitation, the survival and timing requirements of Section 11.2), and subject to Seller’s indemnification obligations with respect to its representations and warranty obligations herein, Purchaser shall indemnify, defend and hold harmless Seller, Seller’s Affiliates, and each of their respective managers, general partners, directors, officers, employees, agents, consultants, equity owners, stockholders, advisors and other representatives (including legal counsel, accountants and financial advisors), and Seller’s predecessors-in-interest (all such persons referred to collectively as the “Seller Indemnified Persons”) from and against any and all Losses, asserted against, resulting from, imposed upon, or incurred or suffered by any Seller Indemnified Person, directly or indirectly, to the extent resulting from, arising out of, or relating to:

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(a)           any breach of any representation of Purchaser contained in this Agreement or confirmed in any certificate furnished by or on behalf of Purchaser to Seller in connection with this Agreement REGARDLESS OF FAULT;

(b)           any breach or nonfulfillment of or failure to perform any covenant or agreement of Purchaser contained in this Agreement REGARDLESS OF FAULT or confirmed in any certificate furnished by or on behalf of Purchaser to Seller in connection with this Agreement;

(c)           the ownership, use or operation of the Assets including without limitation any and all Property Costs (other than any Excluded Seller Obligations) whether before or after the Effective Time;

(d)           the Assumed Seller Obligations REGARDLESS OF FAULT;

(e)           Environmental Laws, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment, or any other environmental condition of the Assets, REGARDLESS OF FAULT; and

(f)           Any other indemnity obligations of Purchaser contained herein, including without limitation, Section 4.4.

Section 11.5                    Indemnification Proceedings.

(a)           In the event that any claim or demand for which Seller or Purchaser (such Person, an “Indemnifying Party”) may be liable to a Purchaser Indemnified Person under Section 11.3 or to an Seller Indemnified Person under Section 11.4 (an “Indemnified Party”) is asserted against or sought to be collected from an Indemnified Party by a third party, other than to the extent a claim is sought under Section 11.12 (a “Third Party Claim,”) the Indemnified Party shall with reasonable promptness notify the Indemnifying Party of such Third Party Claim by delivery of a Claim Notice, provided that the failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11, except (and solely) to the extent that the Indemnifying Party demonstrates that its defense of such Third Party Claim is actually and materially prejudiced thereby.  The Indemnifying Party shall have thirty (30) days from receipt of the Claim Notice from the Indemnified Party (in this Section 11.5, the “Notice Period”) to notify the Indemnified Party whether or not the Indemnifying Party desires, at the Indemnifying Party’s sole cost and expense, to defend the Indemnified Party against such claim or demand; provided, that the Indemnified Party is hereby authorized prior to and during the Notice Period, and at the cost and expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall reasonably deem necessary to protect its interests or those of the Indemnifying Party.  The Indemnifying Party shall have the right to assume the defense of such Third Party Claim only if and for so long as the Indemnifying Party (i) notifies the Indemnified Party during the Notice Period that the Indemnifying Party is assuming the defense of such Third Party Claim, (ii) uses counsel of its own choosing that is reasonably satisfactory to the Indemnified Party, and (iii) conducts the defense of such Third Party Claim in an active and diligent manner.  If the Indemnifying Party is entitled to, and does, assume the defense of any such Third Party Claim, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof; provided, however, that

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notwithstanding the foregoing, the Indemnifying Party shall pay the reasonable attorneys’ fees of the Indemnified Party if the Indemnified Party’s counsel shall have advised the Indemnified Party that there is a conflict of interest that could make it inappropriate under applicable standards of professional conduct to have common counsel for the Indemnifying Party and the Indemnified Party (provided that the Indemnifying Party shall not be responsible for paying for more than one separate firm of attorneys and one local counsel to represent all of the Indemnified Parties subject to such Third Party Claim).  If the Indemnifying Party elects (and is entitled) to assume the defense of such Third Party Claim, (i) no compromise or settlement thereof or consent to any admission or the entry of any judgment with respect to such Third Party Claim may be effected by the Indemnifying Party without the Indemnified Party’s written consent (which shall not be unreasonably withheld, conditioned or delayed) unless the sole relief provided is monetary damages that are paid in full by the Indemnifying Party (and no injunctive or other equitable relief is imposed upon the Indemnified Party) and there is an unconditional provision whereby each plaintiff or claimant in such Third Party Claim releases the Indemnified Party from all liability with respect thereto and (ii) the Indemnified Party shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which shall not be unreasonably withheld).  If the Indemnifying Party elects not to assume the defense of such Third Party Claim (or fails to give notice to the Indemnified Party during the Notice Period or otherwise is not entitled to assume such defense), the Indemnified Party shall be entitled to assume the defense of such Third Party Claim with counsel of its own choice, at the expense and for the account of the Indemnifying Party; provided, however, that the Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of any Indemnifying Party without the prior written consent of such Indemnifying Party, which consent shall not be unreasonably withheld, conditioned or delayed.

(b)           Notwithstanding the foregoing, the Indemnifying Party shall not be entitled to control (but shall be entitled to participate at its own expense in the defense of), and the Indemnified Party, shall be entitled to have sole control over, the defense or settlement, compromise, admission, or acknowledgment of any Third Party Claim (i) at the reasonable expense of the Indemnifying Party, as to which the Indemnifying Party fails to assume the defense during the Notice Period after the Indemnified Party gives notice thereof to the Indemnifying Party or (ii) at the reasonable expense of the Indemnifying Party, to the extent the Third Party Claim seeks an order, injunction, or other equitable relief against the Indemnified Party which, if successful, could materially adversely affect the business, condition (financial or other), capitalization, assets, liabilities, results of operations or prospects of the Indemnified Party.  The Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of the Indemnifying Party without the prior written consent of the Indemnifying Party (which consent shall not be unreasonably withheld, conditioned or delayed).

(c)           In any case in which an Indemnified Party seeks indemnification hereunder and no Third Party Claim is involved, the Indemnified Party shall deliver a Claim Notice to the Indemnifying Party within a reasonably prompt period of time after an officer of such Indemnified Party or its Affiliates has obtained knowledge of the Loss giving rise to indemnification hereunder.  The failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11 except to the extent such

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failure results in insufficient time being available to permit the Indemnifying Party to effectively mitigate the resulting Losses or otherwise prejudices the Indemnifying Party.

(d)           Neither Seller nor Purchaser shall have any liability for any indemnification under Section 11.3(a) or Section 11.4(a) resulting from a breach of representation or warranties until and unless the amount of the liability for any individual claim or series of claims arising out of the same or similar set of facts for which a Claim Notice is delivered by Purchaser or Seller, as applicable, exceeds $50,000.

Section 11.6                    Limitations on Indemnities.

Solely for purposes of calculating the amount of Losses incurred arising out of or relating to any breach or inaccuracy of a representation or warranty (and not for determining whether a breach has occurred), the references to “Material Adverse Effect” or other materiality qualifications (or correlative terms) shall be disregarded.

Section 11.7                    Release.

EXCEPT WITH RESPECT TO POST-CLOSING REMEDIATION AGREED TO PURSUANT TO SECTION 4.3 (IF ANY), AND CLAIMS OR DEMANDS FOR WHICH A CLAIM NOTICE HAS BEEN SENT TO SELLER PRIOR TO THE INDEMNITY END DATE, AT THE CLOSING PURCHASER HEREBY RELEASES, REMISES AND FOREVER DISCHARGES THE SELLER INDEMNIFIED PERSONS FROM ANY AND ALL CLAIMS, KNOWN OR UNKNOWN, WHETHER NOW EXISTING OR ARISING IN THE FUTURE, CONTINGENT OR OTHERWISE, WHICH PURCHASER MIGHT NOW OR SUBSEQUENTLY MAY HAVE AGAINST THE SELLER INDEMNIFIED PERSONS, RELATING DIRECTLY OR INDIRECTLY TO THE CLAIMS ARISING OUT OF OR INCIDENT TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, INCLUDING, WITHOUT LIMITATION, RIGHTS TO CONTRIBUTION UNDER CERCLA, REGARDLESS OF FAULT.

Section 11.8                    Disclaimers.

(a)           EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, OR CONFIRMED IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(c), IN THE CONVEYANCE, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO PURCHASER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING, WITHOUT LIMITATION, ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY OFFICER, DIRECTOR, EMPLOYEE,

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AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY OF ITS AFFILIATES.

(b)           EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 5 OF THIS AGREEMENT, OR CONFIRMED IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(c), IN THE CONVEYANCE, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR  RECOVERABILITY OF PETROLEUM SUBSTANCES IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY THIRD PARTIES, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO PURCHASER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM REDHIBITORY VICES OR DEFECTS (INCLUDING THOSE CONTEMPLATED IN LOUISIANA CIVIL CODE ARTICLES 2475, AND 2520 THROUGH 2548), FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT PURCHASER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS AND THAT PURCHASER HAS MADE OR CAUSED TO BE  MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE, OR (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(c)           EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 5, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND PURCHASER SHALL BE DEEMED TO

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BE TAKING THE ASSETS “AS IS” AND “WHERE IS” FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION.

Section 11.9                    Recording.

As soon as practicable after Closing, Purchaser shall record the Conveyances in the appropriate counties and/or parishes and provide Seller with copies of all recorded or approved instruments.  The Conveyances are intended to convey all of the Properties being conveyed pursuant to this Agreement.  Certain Properties or specific portions of the Properties that are leased from, or require the approval to transfer by, a Governmental Body are conveyed under the Conveyances and also are described and covered by other separate assignments made by Seller to Purchaser on officially approved forms, or forms acceptable to such entity, in sufficient multiple originals to satisfy applicable statutory and regulatory requirements.  The interests conveyed by such separate assignments are the same, and not in addition to, the interests conveyed in the Conveyances attached as Exhibit B.  Further, such assignments shall be deemed to contain the special warranty of title of Seller and all of the exceptions, reservations, rights, titles, power and privileges set forth herein and in the Conveyances as fully and only to the extent as though they were set forth in each such separate assignment.

Section 11.10Non-Compensatory Damages.

None of the Purchaser Indemnified Parties nor Seller Indemnified Parties shall be entitled to recover from Seller or Purchaser, or their respective Affiliates, any indirect, consequential, punitive or exemplary damages or damages for lost profits of any kind arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such party suffers such damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending of such damages) to a Third Party, which damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder.  Subject to the preceding sentence, Purchaser, on behalf of each of the Purchaser Indemnified Parties, and Seller, on behalf of each of Seller Indemnified Parties, waive any right to recover punitive, special, exemplary and consequential damages, including damages for lost profits, arising in connection with or with respect to this Agreement or the transactions contemplated hereby.

Section 11.11Disclaimer of Application of Anti-Indemnity Statutes.

The parties acknowledge and agree that the provisions of any anti-indemnity statute relating to oilfield services and associated activities shall not be applicable to this Agreement and/or the transactions contemplated hereby.

        Section 11.12                  Tax Indemnification.

(a)           Seller shall be liable for, and covenants and agrees to indemnify and hold harmless the Purchaser and its Affiliates from and against, any and all liabilities incurred by Purchaser or its Affiliates for Taxes for which Seller bears responsibility pursuant to Section 1.4(c) hereof.

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(b)           Purchaser shall be liable for, and covenants and agrees to indemnify and hold harmless Seller and its Affiliates from and against, any and all liabilities incurred by any of Seller or its Affiliates for Taxes for which Purchaser bears responsibility pursuant to Section 1.4(c) and Section 12.3 of this Agreement.

(c)           If a party (the “Tax Indemnified Party”) determines that it or any of its Affiliates is or may be entitled to indemnification by another Party (the “Tax Indemnifying Party”) under Section 11.12(a) or 11.12(b) hereof, the Tax Indemnified Party will promptly deliver to the Tax Indemnifying Party a written notice and demand therefor (the “Tax Notice”) specifying the basis for indemnification and, if known, the amount for which the Tax Indemnified Party reasonably believes it or any of its Affiliates is entitled to be indemnified (a “Tax Claim”), together with any supporting documentation (including, if applicable, any relevant notice from any Taxing Authority).  The Tax Notice must be received by the Tax Indemnifying Party no later than thirty (30) days before the expiration of the applicable Tax statute of limitations; provided, however, that if the Tax Indemnified Party does not receive notice from the applicable Taxing Authority (“Taxing Authority Notice”) that an item exists that could give rise to a Tax Claim more than thirty (30) days before the expiration of the applicable Tax statute of limitations, then the Tax Notice must be received by the Tax Indemnifying Party as promptly as practicable after the Tax Indemnified Party receives the Taxing Authority Notice (but in no event more than five (5) Business Days after the Tax Indemnified Party receives the Taxing Authority Notice).  If the Tax Indemnifying Party objects to the Tax Claim in the manner set forth in Section 11.12(d) hereof, then the Tax Indemnifying Party shall not be liable to make an indemnification payment to the Tax Indemnified Party until there is a determination by the Agreed Accounting Firm or a Final Determination regarding the Tax Claim, as the case may be, and any such indemnification payment will be paid by the Tax Indemnifying Party to the Tax Indemnified Party in the amount determined by the Agreed Accounting Firm or in the Final Determination regarding the Tax Claim within thirty (30) days after the date of such determination or Final Determination, as the case may be.  In all other cases, the Tax Indemnifying Party will pay the Tax Indemnified Party the amount set forth in the Taxing Authority Notice, in cash or other immediately available funds, within thirty (30) days after receipt of the Taxing Authority Notice; provided, however, that if the amount for which the Tax Indemnified Party reasonably believes it is entitled to be indemnified is not known at the time of the Taxing Authority Notice, the Tax Indemnifying Party shall pay the amount known to be due and the Tax Indemnified Party will deliver to the Tax Indemnifying Party a further Taxing Authority Notice specifying the unknown amount as soon as reasonably practicable after such amount is known and payment will then be made as set forth above.

(d)           The Tax Indemnifying Party may object to the Tax Claim (or the amount thereof) set forth in any Taxing Authority Notice by giving the Tax Indemnified Party, within thirty (30) days following receipt of such Taxing Authority Notice, written notice setting forth the Tax Indemnifying Party’s grounds for so objecting (the “Tax Objection Notice”).  If the Tax Indemnifying Party does not give the Tax Indemnified Party the Tax Objection Notice within such thirty (30) day period, the Tax Indemnified Party may exercise any and all of its rights under applicable Law and this Agreement to collect such amount.

(e)           The amount of a Tax Claim shall be the amount of Taxes payable by the Tax Indemnified Party net of the present value of any anticipated benefit to the Tax Indemnified

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Party or any of its Affiliates attributable to any Tax item resulting from the facts underlying such Tax Claim.

(f)            If the Tax Indemnified Party and the Tax Indemnifying Party are unable to settle any dispute regarding a Tax Claim within thirty (30) days after receipt of the Tax Objection Notice, the Tax Indemnified Party and the Tax Indemnifying Party will jointly request the Agreed Accounting Firm to resolve the dispute as promptly as possible.

(g)           Failure by the Tax Indemnified Party to promptly deliver to the Tax Indemnifying Party a Taxing Authority Notice in accordance with Section 11.12(c) hereof will not relieve the Tax Indemnifying Party of any of its obligations under this Agreement except to the extent the Tax Indemnifying Party is prejudiced by such failure.

(h)           This Section 11.12 shall survive until the end of the six month period following the applicable statute of limitations period.

ARTICLE 12

MISCELLANEOUS

Section 12.1                    Counterparts.

This Agreement may be executed and delivered (including by facsimile transmission) in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.

Section 12.2                    Notices.

All notices which are required or may be given pursuant to this Agreement shall be sufficient in all respects if given in writing and delivered personally, by telecopy or by registered or certified mail, postage prepaid, as follows:

If to Seller:	Merit Energy Company
	13727 Noel Road, Ste 500
	Dallas, Texas 75240
	Attention:   General Counsel
	Telephone:  972-701-8377
	Telecopy:    972-960-1252
With a copy to (which:	Merit Energy Company
shall not constitute	13727 Noel Road, Ste. 500
notice to Seller):	Dallas, Texas 75240
	Attention:  Director – Acquisitions and Divestitures
	Telephone:  972-701-8377
	Telecopy:    972-960-1252
If to Purchaser:	Linn Energy Holdings, LLC
	600 Travis Street, Ste. 1500

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Houston, Texas 77002

Attn: Charlene A. Ripley, Sr. Vice President, General

Counsel and Corporate Secretary

Either party may change its address for notice by notice to the other in the manner set forth above.  All notices shall be deemed to have been duly given at the time of receipt by the party to which such notice is addressed.

Section 12.3                    Sales or Use Tax Recording Fees and Similar Taxes and Fees.

Purchaser shall bear any sales, use, excise, real property transfer, gross receipts, goods and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees (collectively “Transfer Taxes”) incurred and imposed upon, or with respect to, the transactions contemplated by this Agreement.  Seller will determine, and Purchaser will cooperate with Seller in determining the amount of any Transfer Taxes, if any, that is due in connection with the transactions contemplated by this Agreement and Purchaser agrees to pay any such Transfer Tax to Seller or to the appropriate Governmental Body.  If any of the transactions contemplated by this Agreement are exempt from any such Transfer Taxes upon the filing of an appropriate certificate or other evidence of exemption, Purchaser will timely furnish to Seller such certificate or evidence.

Section 12.4                    Expenses.

Except as otherwise expressly provided in Section 12.3, or elsewhere in this Agreement, (a) all expenses incurred by Seller in connection with or related to the authorization, preparation or execution of this Agreement, the Conveyance delivered hereunder and the Exhibits and Schedules hereto and thereto, and all other matters related to the Closing, including without limitation, all fees and expenses of counsel, accountants and financial advisers employed by Seller, shall be borne solely and entirely by Seller, and (b) all such expenses incurred by Purchaser shall be borne solely and entirely by Purchaser.

Section 12.5                    Change of Name.

As promptly as practicable, but in any case within ninety (90) days after the Closing Date, Purchaser shall eliminate the names “Merit Energy Company”, “Merit” and any variants thereof and any names of Seller’s Affiliates and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

Section 12.6                    Governing Law and Venue.

THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF

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THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS OTHERWISE APPLICABLE TO SUCH DETERMINATIONS.

Section 12.7                    Captions.

The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

Section 12.8                    Waivers.

Any failure by any party or parties to comply with any of its or their obligations, agreements or conditions herein contained may be waived in writing, but not in any other manner, by the party or parties to whom such compliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.  The rights of Seller and Purchaser under this Agreement shall be cumulative and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

Section 12.9                    Assignment.

No party shall assign all or any part of this Agreement, nor shall any party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other party.    Notwithstanding the foregoing, Purchaser may, upon written notice to Seller, assign all or part of its interest in this Agreement to one or more Affiliates of Purchaser, provided that Purchaser shall remain responsible for any obligations hereunder including, without limitation, the indemnification provisions of Article 11.  This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.

Section 12.10                  Entire Agreement.

The Confidentiality Agreement, this Agreement and the Exhibits and Schedules attached hereto, and the documents to be executed hereunder constitute the entire agreement between the parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties pertaining to the subject matter hereof.

Section 12.11                  Amendment.

(a)           This Agreement may be amended or modified only by an agreement in writing executed by the  parties hereto.

(b)           No waiver of any right under this Agreement shall be binding unless executed in writing by the party to be bound thereby.

Section 12.12                  No Third-Party Beneficiaries.

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Nothing in this Agreement shall entitle any Person other than Purchaser or Seller to any claims, remedy or right of any kind, except as to those rights expressly provided to the Seller Indemnified Persons and Purchaser Indemnified Persons (provided, however, any claim for indemnity hereunder on behalf of an Seller Indemnified Person or an Purchaser Indemnified Person must be made and administered by a party to this Agreement).

Section 12.13                  References.

In this Agreement:

(a)           References to any gender includes a reference to all other genders;

(b)           References to the singular includes the plural, and vice versa;

(c)           Reference to any Article or Section means an Article or Section of this Agreement;

(d)           Reference to any Exhibit or Schedule means an Exhibit or Schedule to this Agreement, all of which are incorporated into and made a part of this Agreement;

(e)           Unless expressly provided to the contrary, “hereunder”, “hereof’, “herein” and words of similar import are references to this Agreement as a whole and not any particular Section or other provision of this Agreement;

(f)           “Include” and “including” shall mean include or including without limiting the generality of the description preceding such term; and

(g)           Capitalized terms used herein shall have the meanings ascribed to them in this Agreement as such terms are identified and/or defined in the Definitions section hereof.

Section 12.14                  Construction.

Purchaser is a party capable of making such investigation, inspection, review and evaluation of the Assets as a prudent party would deem appropriate under the circumstances including with respect to all matters relating to the Assets, their value, operation and suitability. Each of Seller and Purchaser has had substantial input into the drafting and preparation of this Agreement and has had the opportunity to exercise business discretion in relation to the negotiation of the details of the transactions contemplated hereby. This Agreement is the result of arm’s-length negotiations from equal bargaining positions.  In the event of a dispute over the meaning or application of this Agreement, it shall be construed fairly and reasonably and neither more strongly for nor against either party.

Section 12.15                  Conspicuousness.

The parties agree that provisions in this Agreement in “bold” type satisfy any requirements of the “express negligence rule” and any other requirements at law or in equity that provisions be conspicuously marked or highlighted.

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Section 12.16                  Severability.

If any term or other provisions of this Agreement is held invalid, illegal or incapable of being enforced under any rule of law, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in a materially adverse manner with respect to either party; provided, however, that if any such term or provision may be made enforceable by limitation thereof, then such term or provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by applicable Law.

Section 12.17                  Time of Essence.

Time is of the essence in this Agreement.  If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

Section 12.18                  Limitation on Damages.

Notwithstanding any other provision contained elsewhere in this Agreement to the contrary, the parties acknowledge that this Agreement does not authorize one party to sue for or collect from the other party its own punitive damages, or its own consequential or indirect damages in connection with this Agreement and the transactions contemplated hereby and each party expressly waives for itself and on behalf of its Affiliates, any and all Claims it may have against the other party for its own such damages in connection with this Agreement and the transactions contemplated hereby.

Section 12.19                  Access for Financial Reporting Purposes.

At the Closing, Seller acknowledges that Purchaser and/or its Affiliates may be required to include statements of revenues and direct operating expenses and other financial information relating to the Assets (“Financial Statements”) in documents filed with the SEC by Purchaser and/or its Affiliates pursuant to the Securities Act of 1933, as amended, and that such Financial Statements may be required to be audited.  In that regard, Seller shall provide Purchaser reasonable access to such records (to the extent such information is available) and personnel of Seller as Purchaser may reasonably request to enable Purchaser, and its representatives and accountants, at Purchaser’s sole cost and expense, to create and audit any Financial Statements that Purchaser deems necessary.  Notwithstanding the foregoing, (i) Seller shall in no event be required to create new records relating to the Assets and (ii) the access to be provided to Purchaser pursuant to this Section 8.6 shall not interfere with Seller’s ability to prepare its own financial statements or its regular conduct of business and shall be made available during Seller’s normal business hours.  If reasonably required to accomplish the foregoing, and at the sole cost and expense of Purchaser, Seller will provide suitable electronic detail in the form of lease operating statements by property adequately supporting all statements provided.

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[SIGNATURES BEGIN ON THE FOLLOWING PAGE]

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IN WITNESS WHEREOF, this Agreement has been signed by each of the parties hereto on the date first above written.

SELLER:

MERIT MANAGEMENT PARTNERS I, L.P.

MERIT MANAGEMENT PARTNERS II, L.P.

MERIT MANAGEMENT PARTNERS III, L.P.

MERIT ENERGY PARTNERS III, L.P.

By:          Merit Management Partners GP, LLC,

its general partner

By: /s/ Christopher S. Hagge           

Name: Christopher S. Hagge           

Title: Assistant Secretary                 

MERIT ENERGY PARTNERS D-III, L.P.

By:          Merit Management Partners I, L.P.,

its general partner

By:          Merit Management Partners GP, LLC,

its general partner

By: /s/ Christopher S. Hagge                

Name: Christopher S. Hagge                

Title: Assistant Secretary                      

MERIT ENERGY PARTNERS E-III, L.P.

By:          Merit Management Partners II, L.P.,

its general partner

By:           Merit Management Partners GP, LLC,

its general partner

By: /s/ Christopher S. Hagge                

Name: Christopher S. Hagge                

Title: Assistant Secretary                      

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MERIT ENERGY PARTNERS F-III, L.P.

By:           Merit Management Partners III, L.P.,

its general partner

By:          Merit Management Partners GP, LLC,

its general partner

By: /s/ Christopher S. Hagge                

Name: Christopher S. Hagge                

Title: Assistant Secretary                      

PURCHASER:

LINN ENERGY HOLDINGS, LLC

By: /s/ Mark E. Ellis                                          

Name: Mark E. Ellis                                          

Title: President & COO                                    

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EXHIBIT A

TO

PURCHASE AND SALE AGREEMENT

DATED NOVEMBER ___, 2009 BY AND BETWEEN

MERIT MANAGEMENT PARTNERS I, L.P., ET AL, AS SELLER

AND

LINN ENERGY HOLDINGS, LLC, AS PURCHASER

[LEASES]

62

EXHIBIT A-1

TO

PURCHASE AND SALE AGREEMENT

DATED NOVEMBER ___, 2009 BY AND BETWEEN

MERIT MANAGEMENT PARTNERS I, L.P., ET AL, AS SELLER

AND

LINN ENERGY HOLDINGS, LLC, AS PURCHASER

[WELLS AND UNITS]

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EXHIBIT B

TO

PURCHASE AND SALE AGREEMENT

DATED NOVEMBER ___, 2009 BY AND BETWEEN

MERIT MANAGEMENT PARTNERS I, L.P., ET AL, AS SELLER

AND

LINN ENERGY HOLDINGS, LLC, AS PURCHASER

FORM OF ASSIGNMENT, CONVEYANCE AND BILL OF SALE

THIS ASSIGNMENT, CONVEYANCE AND BILL OF SALE (this “Assignment”), is made and entered this [___] day of [______], 2009, but is effective as of November 1, 2009, at 7:00 a.m. Central Daylight Time (the “Effective Time”), from [MERIT MANAGEMENT PARTNERS I, L.P., ___________] [ALSO TO ADD NPI PARTNERSHIPS], all Delaware limited partnerships (collectively, “Assignor”), whose addresses are 13727 Noel Road, Suite 500, Dallas, Texas 75240, and Linn Energy Holdings, LLC, a Delaware limited liability company (“Assignee”), whose address is 600 Travis Street, Ste. 5100, Houston, Texas 77002.

WITNESSETH:

This Assignment is made pursuant to the terms of that certain Purchase and Sale Agreement dated October __, 2009 by and among Merit Management Partners I, L.P., et al., and Assignee (the “Purchase and Sale Agreement”).  All capitalized terms used but not otherwise defined herein shall have the respective meanings ascribed to them in the Purchase and Sale Agreement.

That Assignor, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, does hereby sell, transfer, assign, and convey to Assignees, all of Assignor’s right, title, interest and estate, real or personal, recorded or unrecorded, movable or immovable, tangible or intangible, in and to the following (less and except the Excluded Assets, as such term is defined below) (collectively, the “Assets”):

(a)           All of (i) the oil and gas leases; subleases and other leaseholds; net profits interests; carried interests; farmout rights; options; and other properties and interests described on Exhibit A (collectively, the “Leases”), together with each and every kind and character of right, title, claim, and interest that Seller has in and to the lands covered by the Leases or the lands currently pooled, unitized, communitized or consolidated therewith (the “Lands”);

(b)           All oil, gas, water, disposal or injection wells located on or associated with the Lands, whether producing, shut-in, or abandoned, including the wells shown on Exhibit A-1, whether producing, shut-in, or temporarily abandoned (even to the extent not located on the Lands) (collectively, the “Wells”);

(c)           All interest of Seller derived from the Leases in or to any currently existing pools or units which include any Lands or all or a part of any Leases or include any Wells, including those pools or units shown on Exhibit A-1 (the “Units”; the Units, together with the Leases,

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Lands and Wells, being hereinafter referred to as the “Properties”), and including all interest of Seller derived from the Leases in production of Hydrocarbons from any such Unit, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease, and all tenements, hereditaments and appurtenances belonging to the Leases and Units;

(d)           All contracts, agreements and instruments by which the Properties are bound, or that relate to or are otherwise applicable to the Properties, only to the extent applicable to the Properties rather than Seller’s other properties, including but not limited to, operating agreements, unitization, pooling and communitization agreements, declarations and orders, joint venture agreements, farmin and farmout agreements, exploration agreements, participation agreements, exchange agreements, transportation or gathering agreements, agreements for the sale and purchase of oil, gas, casinghead gas or processing agreements to the extent applicable to the Properties or the production of Hydrocarbons produced in association therewith from the Properties, including those identified on Schedule 1.2(d) (hereinafter collectively referred to as “Contracts”), but excluding any master service agreements and any contracts, agreements and instruments to the extent transfer is restricted by third-party agreement or applicable Law and the necessary consents to transfer are not obtained pursuant to Section 7.7 and provided that “Contracts” shall not include the instruments constituting the Leases;

(e)           All easements, permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (“Easements”) appurtenant to, and used or held for use in connection with the Properties (including those identified on Schedule 1.2(e)), but excluding any permits and other rights to the extent transfer is restricted by third-party agreement or applicable Law and the necessary consents to transfer are not obtained pursuant to Section 7.7;

(f)All equipment, machinery, fixtures and other tangible personal property and improvements located on the Properties owned by Seller and used or held for use primarily in connection with the operation of the Properties (other than vehicles or vessels which are addressed specifically by Section 1.2(k)) (collectively, “Equipment”);

(g)           All flow lines, pipelines, gathering systems and appurtenances thereto located on the Properties or used, or held for use, in connection with the operation of the Properties, including those identified on Schedule 1.2(g) (“Pipelines” and, together with the Equipment and Wells, “Personal Property”);

(h)           All Hydrocarbons produced from or attributable to the Leases, Lands, and Wells from and after the Effective Time;

(i)All Imbalances;

(j)All lease files; land files; well files; gas and oil sales contract files; gas processing files; division order files; abstracts; title opinions; land surveys; logs; maps; engineering data and reports; interpretive data, technical evaluations and technical outputs; and other books, records, data, files, and accounting records, in each case to the extent related to the Assets, or used or held for use in connection with the maintenance or operation thereof, but excluding (i) any books, records, data, files, logs, maps, evaluations, outputs, and accounting records to the extent disclosure or transfer would result in a violation of applicable Law or is restricted by any

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Transfer Requirement that is not satisfied pursuant to Section 7.7, (ii) computer or communications software or intellectual property (including tapes, codes, data and program documentation and all tangible manifestations and technical information relating thereto), (iii) attorney-client privileged communications and work product of Seller’s or any of its Affiliates’ legal counsel (other than title opinions), (iv) reserve studies and evaluations, and (v) records relating to the negotiation and consummation of the sale of the Assets (subject to such exclusions, the “Records”); provided, however, that Seller may retain the originals of such Records as Seller has reasonably determined may be required for existing litigation, tax, accounting, and auditing purposes;

(k)           Those vehicles and vessels specifically listed on Schedule 1.2(k); and

(l)All Geological Data specifically listed on Schedule 1.2(l).

provided, however, that notwithstanding the foregoing, the Assets shall not include, and Assignor hereby reserves and retains, all of the Excluded Assets.

TO HAVE AND TO HOLD to Assignee, its successors and assigns, forever, subject to the Permitted Encumbrances, as such term is defined in the Purchase and Sale Agreement, and the other terms and provisions hereof and of the Purchase and Sale Agreement referred to below.

This Assignment is made by Assignor and accepted by Assignees subject to the following terms and conditions:

1.           Effective Time.  This Assignment shall be effective as of the Effective Time.

2,           Purchase and Sale Agreement.  This Assignment is expressly made subject to the Purchase and Sale Agreement.  In the event of a conflict between this Assignment and the Purchase and Sale Agreement, the Purchase and Sale Agreement shall control.  Capitalized terms used and not otherwise defined herein are used with the meanings given thereto in the Purchase and Sale Agreement.

3.           Disclaimers.

EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN SECTION 4 HEREOF OR IN ARTICLE 3 OF THE PURCHASE AND SALE AGREEMENT, (i) ASSIGNOR MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (ii) ASSIGNOR EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO ASSIGNEE OR ANY OF ASSIGNEE’S AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING, WITHOUT LIMITATION, ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO ASSIGNEE BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF ASSIGNOR OR ANY OF ITS AFFILIATES).  IN PARTICULAR, EXCEPT AS EXPRESSLY SET FORTH IN ARTICLE 3 OF THE PURCHASE AND SALE AGREEMENT, AND WITHOUT LIMITING THE GENERALITY OF THE

66

FOREGOING, ASSIGNOR EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (i) TITLE TO ANY OF THE ASSETS, (ii) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (iii) THE QUANTITY, QUALITY OR  RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (iv) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (v) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (vi) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (vii) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY ASSIGNOR OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (viii) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO ASSIGNEE OR ITS AFFILIATES, OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THE PURCHASE AND SALE AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (ix) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.  EXCEPT AS EXPRESSLY SET FORTH IN ARTICLE 4 HEREOF ASSIGNOR FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY ASSETS, RIGHTS OF A ASSIGNEE UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT ASSIGNEE SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT ASSIGNEE HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS ASSIGNEE DEEMS APPROPRIATE.

Assignor and Assignee agree that, to the extent required by applicable Law to be effective, the disclaimers of certain representations and warranties contained in this Section 3 are “conspicuous” disclaimers for the purpose of any applicable Law.

4.           Special Warranty of Title.  This Assignment is made, executed, and delivered without warranty of title, either express or implied, even as to a return of the purchase price, except that Assignor specially warrants and agrees to defend Defensible Title, as such term is defined in the Purchase and Sale Agreement, to the Assets against the claims and demand of all Persons claiming by, through, or under Assignor or its Affiliates, but not otherwise, up to the Allocated Value thereof and subject to the applicable limitations and provisions of Article 11 of the Purchase and Sale Agreement, but with full right of substitution and subrogation of Assignee in and to all claims Assignor has or may have against all preceding owners.

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5.           Assumption by Assignee.  In addition to their other obligations under this Agreement, Assignee shall comply with all Laws, Leases, Applicable Contracts (including all joint and unit operating agreements) and prevailing industry standards relating to (i) the plugging, abandonment and/or replugging of all Wells, including inactive Wells or temporarily abandoned Wells, included in the Assets or otherwise drilled on the Lands, (ii) the dismantling or decommissioning and removal of any Personal Property and other property of whatever kind related to or associated with operations and activities conducted by whomever on the Properties, or otherwise, pursuant to the Leases or Applicable Contracts and (iii) the clean up, restoration and/or remediation of the Lands covered by the Leases or related to the Assets (collectively, the “P&A Obligations”).  Subject to the indemnification by certain members of Assignor under Section 11.3 of the Purchase and Sale Agreement, on the Closing Date, Assignee shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of Assignor, known or unknown, with respect to the Assets, regardless of whether such obligations or liabilities arose prior to, on or after the Effective Time, including but not limited to obligations to (a) furnish makeup gas according to the terms of applicable gas sales, gathering or transportation contracts, and to satisfy all other gas balancing obligations, if any, (b) pay working interests, royalties, overriding royalties and other interests held in suspense, (c) properly plug and abandon any and all wells (including, without limitation, the Wells), including inactive wells or temporarily abandoned wells, drilled on the Properties, as required by Law, (d) replug any well, wellbore, or previously plugged well on the Properties to the extent required by Governmental Body, (e) dismantle, salvage and remove any equipment, structures, materials, platforms, flowlines, and property of whatever kind related to or associated with operations and activities conducted on the Properties, (f) clean up, restore and/or remediate the premises covered by or related to the Assets in accordance with applicable agreements and Laws, (g) perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases or with respect to the Mineral Interests and related contracts, or as required by applicable Laws (all of said obligations and liabilities, subject to the exclusions below, herein being referred to as the “Assumed Assignor Obligations”); provided, however, that the Assumed Assignor Obligations shall not include, and Assignee shall have no obligation to assume, any obligations or liabilities of Assignor to the extent that they are (such excluded obligations and liabilities, the “Excluded Assignor Obligations”):

(i)attributable to or arise out of the Excluded Assets;

(ii)           attributable to or arising out of the actions, suits or proceedings, if any, set forth on Schedule 5.7(a) of the Purchase and Sale Agreement, except in so far as they are attributable to or relate to the Assets for periods after the Effective Time; and

(iii)          Retained Employee Liabilities.

6.           Further Assignments.  Assignees acknowledge that this Assignment is a global assignment intended for filing with the applicable counties and parishes in Texas and Louisiana, and that Assignees and Assignor have separately entered into multiple assignments for the purpose of recording the assignment of the Assets with the Minerals Management Service.

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7.           Covenants Running with the Land.  The terms and provisions hereof shall be deemed to be covenants running with the Lands, Leases, and other interests covered hereby and shall extend to, bind and inure to the benefit of the parties hereto, their heirs, successors and assigns.

[Signature Page Follows]

69

IN WITNESS WHEREOF, this Assignment is executed by the duly authorized officers or representatives of the parties as of the date first hereinabove written.

	ASSIGNOR:
WITNESSES:	MERIT MANAGEMENT PARTNERS I, L.P.
		Name:
		Title:
		Name:
		Title:
		Name:
		Title:
		Name:
		Title:

	ASSIGNEE:
WITNESSES:	[_______________________]
	By:
		Name:
		Title:

STATE OF TEXAS	§
	§
COUNTY OF DALLAS	§

BEFORE ME, the undersigned Notary Public, on this day personally appeared [________], known to me to be the person whose name is subscribed to the foregoing instrument and acknowledged to me that he, being fully authorized to do so, executed and delivered the same as [_______] of the above-listed affiliates of Merit Management Partners GP, LLC, on the day and year therein mentioned and as the act and deed of said corporation, for the purpose and consideration therein expressed.

GIVEN UNDER MY HAND AND SEAL OF OFFICE, this [__] day of [______], 2009.

____________________________________

Notary Public

My Commission Expires:_______________

EXHIBIT C

TO

PURCHASE AND SALE AGREEMENT

DATED NOVEMBER ___, 2009 BY AND BETWEEN

MERIT MANAGEMENT PARTNERS I, L.P., ET AL, AS SELLER

AND

LINN ENERGY HOLDINGS, LLC, AS PURCHASER

FORM OF INDEMNITY AGREEMENT

This Indemnity Agreement is executed on _____________, 2009 (the “Effective Date”), by and among [Insert appropriate Merit partnerships], each a Delaware limited partnership (together, "Indemnifying Parties", individually, “Indemnifying Party”), and Linn Energy Holdings, LLC, a Delaware limited liability company ("Indemnified Party").

WHEREAS, Indemnifying Parties, as seller, and Indemnified Party, as purchaser, entered into that certain Purchase and Sale Agreement, dated November __, 2009, (the “PSA”); and

WHEREAS, pursuant to Section 3.4(d)(ii) of the PSA, Indemnifying Parties desire to indemnify and hold Indemnified Party harmless with respect to certain losses associated with certain Title Defects (as defined in the PSA), as more fully set forth in this Agreement.

NOW, THEREFORE, in consideration of the premises, covenants and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.           Indemnification by Indemnifying Parties.  Indemnifying Parties hereby indemnify and hold harmless the Indemnified Party from and against loss of property value, as well as reasonable outside counsel attorney fees and other actual and reasonable third-party costs and expenses of investigation and litigation (“Losses”) arising out of or attributable to Third Party Claims (as defined below) relating to the Title Defects identified on Exhibit A attached hereto and incorporated herein by reference (individually, a “Subject Title Defect”, collectively, the “Subject Title Defects”), up to the amount attributed to each Subject Title Defect, which amount is also identified on Exhibit A (with respect to each Subject Title Defect, the “Individual Defect Amount”, with respect to the aggregate amount for all Subject Title Defects identified on Exhibit A, the “Aggregate Defect Amount”).

2.Limits on Indemnification, Dispute regarding Losses

(a)         Notwithstanding anything in the PSA or this Agreement to the contrary, the Indemnified Party and the Indemnifying Parties hereby agree and acknowledge that the Indemnified Party’s sole and exclusive remedy with relation to Losses suffered by the Indemnified Party relating to all Subject Title Defects shall be limited to the Aggregate Defect Amount and with relation to Losses suffered by the Indemnified Party regarding any individual Subject Title Defect shall be limited to the corresponding Individual Defect Amount.

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Additionally, notwithstanding anything in the PSA or this Agreement to the contrary, the Indemnified Party’s sole and exclusive remedy with respect to any and all claims, liabilities, suits, controversies, losses, costs and expenses relating to the Subject Title Defects shall be limited to a claim for reimbursement of Losses pursuant to this Agreement. Each of the parties to this Agreement expressly waives and agrees not to seek, and to cause its affiliates not to seek, indirect, consequential, punitive or exemplary damages or damages for lost profits of any kind with respect to any dispute arising under, related to, or in connection with this Agreement or the Subject Title Defects.

(b)         For purposes of calculating the amount of any Losses payable by the Indemnifying Parties, the amount of such Losses shall be determined as agreed upon by the Indemnifying Parties and the Indemnified Party with reference to the applicable Individual Defect Amount in accordance with the terms of, and subject to the limitations contained in, this Agreement and with regard to the portion of the Individual Defect Amount that is affected by a Third Party Claim.  In the event the parties to this Agreement are unable to agree upon the amount of any Losses, the dispute shall be exclusively and finally resolved pursuant to this Section2(b). There shall be a single arbitrator, who shall be a title attorney with at least ten (10) years experience in oil and gas titles involving properties in the regional area in which the properties constituting the Subject Title Defect are located, as selected by mutual agreement of the parties hereto (the "Title Expert"). The Title Expert's determination shall be made within twenty (20) days after submission of the matters in dispute and shall be final and binding upon all parties to this Agreement, without right of appeal. In making his determination, the Title Expert shall be bound by the rules and limitations set forth in this Agreement and may consider such other matters as in the opinion of the Title Expert are necessary or helpful to make a proper determination. The Title Expert may allow the parties to make written submissions of their positions in the manner and to the extent the Title Expert deems appropriate, and the Title Expert may call on the parties to submit such other materials as the Title Expert deems helpful and appropriate to resolution of the dispute.  Additionally, the Title Expert may consult with and engage disinterested third parties to advise the Title Expert, including without limitation petroleum engineers. The parties hereto shall each bear its own legal fees and other costs of presenting its case. Each party shall bear one-half of the costs and expenses of the Title Expert, including any costs incurred by the Title Expert that are attributable to such third party consultation. Within ten (10) days after the Title Expert delivers written notice to the parties to this Agreement of his award with respect to the disputed Losses, the Indemnifying Parties shall pay to the Indemnified Party the amount, if any, so awarded by the Title Expert to the Indemnified Party.

                (c)         Claims by the Indemnified Party for reimbursement for Losses pursuant to this Agreement shall be limited to claims made within the Claim Period (as defined below).  To the extent the Indemnified Party fails to notify the Indemnifying Parties of any claims for reimbursement for Losses within the Claim Period, the Indemnified Party shall be deemed to have waived any right to reimbursement for any Losses or any other damages the Indemnified Party may have suffered or incurred with respect to any such Subject Title Defect.

                3.           Indemnification Proceedings.

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 (a)        At any time prior to the date which is four (4) years following the Effective Date (the “Claim Period”), the Indemnified Party will have the right to notify the Indemnifying Parties in writing that the Indemnified Party is making an indemnification claim for reimbursement for any Losses incurred or reasonably anticipated to be incurred with respect to any third party claim regarding title to or ownership of an interest in a property which is identified as a Subject Title Defect.  In the event that any third party makes a claim regarding title to or ownership of an interest in a property which is identified as a Subject Title Defect for which the Indemnifying Parties may be liable to the Indemnified Party pursuant to Section 1 above (a "Third Party Claim"), the Indemnified Party shall with reasonable promptness notify the Indemnifying Parties of such Third Party Claim by delivery of a written notice to the Indemnifying Parties (a “Claim Notice”), provided that the failure or delay to so notify the Indemnifying Parties shall not relieve the Indemnifying Parties of their obligations under this Agreement, except to the extent that the Indemnifying Parties demonstrate that their defense of such Third Party Claim is materially prejudiced thereby. The Indemnifying Parties shall have thirty (30) days from receipt of the Claim Notice from the Indemnified Party (the "Notice Period") to notify the Indemnified Party whether or not the Indemnifying Parties desire, at the Indemnifying Parties' sole cost and expense, to defend the Indemnified Party against such claim or demand; provided, that the Indemnified Party is hereby authorized prior to and during the Notice Period, and at the cost and expense of the Indemnifying Parties, to file any motion, answer or other pleading that it shall reasonably deem necessary to protect its interests or those of the Indemnifying Parties. The Indemnifying Parties shall have the right to assume the defense of such Third Party Claim only if and for so long as the Indemnifying Parties (i) notify the Indemnified Party during the Notice Period that the Indemnifying Parties are assuming the defense of such Third Party Claim, (ii) use counsel of its own choosing that is reasonably satisfactory to the Indemnified Party, and (iii) conduct the defense of such Third Party Claim in an active and diligent manner. If the Indemnifying Parties are entitled to, and do, assume the defense of any such Third Party Claim, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof. If the Indemnifying Parties elect (and are entitled) to assume the defense of such Third Party Claim, (i) no compromise or settlement thereof or consent to any admission or the entry of any judgment with respect to such Third Party Claim may be effected by the Indemnifying Parties without the Indemnified Party's written consent (which shall not be unreasonably withheld, conditioned or delayed) unless the sole relief provided is monetary damages that are paid in full by the Indemnifying Parties (and no injunctive or other equitable relief is imposed upon the Indemnified Party) and there is an unconditional provision whereby each plaintiff or claimant in such Third Party Claim releases the Indemnified Party from all liability with respect thereto and (ii) the Indemnified Party shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which shall not be unreasonably withheld). If the Indemnifying Parties elect not to assume the defense of such Third Party Claim (or fails to give notice to the Indemnified Party during the Notice Period), the Indemnified Party shall be entitled to assume the defense of such Third Party Claim with counsel of its own choice, at the expense and for the account of the Indemnifying Parties; provided, however, that the Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of any of the Indemnifying Parties without the prior written consent of such Indemnifying Parties, which consent shall not be unreasonably withheld, conditioned or delayed.

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     (b)         Notwithstanding the foregoing, the Indemnifying Parties shall not be entitled to control (but shall be entitled to participate at its own expense in the defense of), and the Indemnified Party shall be entitled to have sole control over, the defense or settlement, compromise, admission, or acknowledgment of any Third Party Claim (i) at the reasonable expense of the Indemnifying Parties, as to which the Indemnifying Parties fail to assume the defense during the Notice Period after the Indemnified Party gives notice thereof to the Indemnifying Parties or (ii) at the reasonable expense of the Indemnifying Parties, to the extent the Third Party Claim seeks an order, injunction, or other equitable relief against the Indemnified Party which, if successful, could materially adversely affect the business, condition (financial or other), capitalization, assets, liabilities, results of operations or prospects of the Indemnified Party. The Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of the Indemnifying Parties without the prior written consent of the Indemnifying Parties (which consent shall not be unreasonably withheld, conditioned or delayed).

               4.           Tax Treatment of Indemnification Payments.  All indemnification payments pursuant to this Agreement shall be treated as adjustments to the Purchase Price (as defined in the PSA).

5.           Counterparts.  This Agreement may be executed and delivered (including by facsimile transmission) in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.

     6.           Notice.  All notices which are required or may be given pursuant to this Agreement shall be sufficient in all respects if given in writing and delivered personally, by telecopy or by registered or certified mail, postage prepaid, as follows:

If to Indemnifying Parties:	c/o Merit Energy Company, LLC 13727 Noel Road, Ste. 500 Dallas, Texas 75240 Attention:  Christopher S Hagge Telephone:  972-701-8377 Facsimile:  972-628-1948 and Attention: Jason Lindmark Telephone: 972-701-8377 Facsimile: 972-628-1881
If to Indemnified Party:	________________________ ________________________ ________________________ ________________________

Any party may change its address for notice by notice to the other in the manner set forth above. All notices shall be deemed to have been duly given at the time of receipt by the party to which such notice is addressed.

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      7.           Governing Law and Venue.  THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS OTHERWISE APPLICABLE TO SUCH DETERMINATIONS. JURISDICTION AND VENUE WITH RESPECT TO ANY DISPUTES ARISING HEREUNDER SHALL BE PROPER ONLY IN HARRIS COUNTY, TEXAS.

8.           Captions.  The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

9.           Waivers.  Any failure by any party or parties to comply with any of its or their obligations, agreements or conditions herein contained may be waived in writing, but not in any other manner, by the party or parties to whom such compliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

10.         Assignment.  No party to this Agreement shall assign all or any part of this Agreement, nor shall any party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other parties. Notwithstanding the preceding, however, either of the Indemnifying Parties may, without the Indemnified Party’s consent, assign its rights and duties hereunder to a successor to all or substantially all of such Indemnifying Party’s business or assets.  This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.

11.         Amendment.

                 (a)   This Agreement may be amended or modified only by an agreement in writing executed by the parties hereto.

                 (b)   No waiver of any right under this Agreement shall be binding unless executed in writing by the party to be bound thereby.

      12.        No Third-Party Beneficiaries.  Nothing in this Agreement shall entitle any Person (as defined in the PSA) other than the parties to this Agreement to any benefit, claims, remedy or right of any kind.

13.         Construction.  Each of the parties to this Agreement has had substantial input into the drafting and preparation of this Agreement and has had the opportunity to exercise business discretion in relation to the negotiation of the details of the transactions contemplated hereby. This Agreement is the result of arm's-length negotiations from equal bargaining positions. In the event of a dispute over the meaning or application of this Agreement, it shall be construed fairly and reasonably and neither more strongly for nor against any party.

     14.         Severability.  If any term or other provisions of this Agreement is held invalid, illegal or incapable of being enforced under any rule of law, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or

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legal substance of the transactions contemplated hereby is not affected in a materially adverse manner with respect to any party; provided, however, that if any such term or provision may be made enforceable by limitation thereof, then such term or provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by applicable Law (as defined in the PSA).

[SIGNATURE PAGE FOLLOWS.]

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        IN WITNESS WHEREOF, this Agreement has been signed by each of the parties hereto on the date first above written.

“INDEMNIFYING PARTIES”

[Applicable Merit Partnerships]

By: 

Name: 

Title: 

“INDEMNIFIED PARTY”

[_____________________]

By: _______________________

Name: ____________________

Title: ______________________

[TO ADD: EXHIBIT A - SUBJECT TITLE DEFECTS AND AMOUNTS]

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EXHIBIT D

Attached to That Certain

Purchase and Sale Agreement

By and Between

MERIT MANAGEMENT PARTNERS I, L.P., MERIT ENERGY PARTNERS III, L.P., AND MERIT ENERGY PARTNERS D-III, L.P., as SELLER,

and

LINN ENERGY HOLDINGS, LLC, as PURCHASER

TRANSITION SERVICES AGREEMENT

This Transition Services Agreement ("Agreement") is made and entered into as of this day of October __, 2009, by and between MERIT ENERGY COMPANY, LLC (hereinafter “MEC”) and LINN ENERGY HOLDINGS, LLC (hereinafter "Owner").

WITNESSETH:

WHEREAS, Owner, as purchaser, and certain affiliates of MEC, as seller (“Seller”), have entered into that certain Purchase & Sale Agreement dated November ___ , 2009 (the "Asset Purchase Agreement"), pursuant to which Owner will acquire from certain affiliates of Seller certain Assets (as defined in the Asset Purchase Agreement); and

WHEREAS, in order to provide for an efficient transfer of operations from Seller to Owner following Closing, Owner desires to obtain services from MEC to assist Owner in the operation of the Assets during the term of this Agreement; and

WHEREAS, MEC is agreeable to providing such services pursuant to the terms hereof;

NOW, THEREFORE, in consideration of the premises, mutual covenants and agreements herein contained, Seller, MEC and Owner (sometimes referred to collectively herein as "Parties") agree as follows:

1.           Services

From the Closing Date (as defined in the Asset Purchase Agreement) to the Termination Date as defined in Section 7 below, MEC will provide such services to Owner concerning the Assets as more fully described on Exhibit A, “Scope of Work” attached hereto (the “Services”), as Owner may from time to time request.

2.           Employment Status

All persons providing services on behalf of MEC under this Agreement shall remain employees of MEC or one of its affiliates and each shall continue to be paid by and to enjoy the benefits to which he is entitled as an employee of MEC or one of its affiliates and shall not be an agent or employee of Owner. Each such employee shall not be required by this agreement to work more than his or her regular shift.

3.           Compensation

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     For Services rendered from the Closing Date to the Termination Date, Owner shall pay MEC a fee of $_______________ per month which shall be pro-rated for any portion of a month, and shall reimburse MEC for all third party expenses and for MEC's actual costs of preparing any report or information not routinely generated by MEC or its Affiliates.

4.           Independent Contractor Status

Nothing contained in this Agreement shall make either party hereto the agent of the other party for any purpose. MEC and each employee of Seller or its affiliates performing services hereunder shall be engaged hereunder in a capacity as an independent contractor with full control over the manner and method of performance.

5.           Standard of Care

While performing the services hereunder, MEC and its employees shall perform their duties in a manner they reasonably believe to be in the best interests of Owner, BUT SHALL HAVE NO LIABILITY WHATSOEVER TO PURCHASER FOR ANY DAMAGES, LIABILITIES OR CLAIMS ARISING OUT OF OR RELATED TO THE PERFORMANCE OF SERVICES HEREUNDER, INCLUDING DAMAGES CAUSED BY NEGLIGENCE OR FAULT OF MEC OR ITS AFFILIATES OR THEIR EMPLOYEES OR UNDER CIRCUMSTANCES THAT WOULD CREATE STRICT LIABILITY OF MEC OR SELLER TO PURCHASER, EXCEPT SUCH AS ARE CAUSED BY THEIR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT IN THE PERFORMANCE OF THE SERVICES HEREUNDER.

6.           Indemnity

TO THE MAXIMUM EXTENT PERMITTED BY APPLICABLE LAW, OWNER SHALL INDEMNIFY, DEFEND AND HOLD HARMLESS SELLER, MEC, THEIR AFFILIATES, AND THEIR RESPECTIVE OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, CONTRACTORS AND SUBCONTRACTORS ("MEC INDEMNIFIED PARTIES") FROM AND AGAINST ANY AND ALL CLAIMS COSTS OR LIABILITIES OF ANY KIND OR NATURE WHATSOEVER ("CLAIMS"), ARISING OUT OF ANY ACTS OR OMISSIONS OF THE MEC INDEMNIFIED PARTIES IN THE PERFORMANCE OF THE SERVICES HEREUNDER. THE FOREGOING OBLIGATIONS OF INDEMNITY SHALL APPLY EVEN THOUGH SUCH CLAIMS MAY HAVE BEEN CONTRIBUTED TO OR CAUSED BY THE NEGLIGENCE OR FAULT, OR THE STRICT OR STATUTORY LIABILITY OF THE MEC INDEMNIFIED PARTIES UNDER ANY LAW (INCLUDING STATUTORY, REGULATORY AND CASE LAW), EXCEPT FOR THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE MEC INDEMNIFIED PARTIES.

Nothing contained in this Agreement shall be deemed to relieve either the owners or management of Owner from the performance of their respective duties or limit the exercise of their powers and authority under the law.

7.           Term.

This Agreement, upon execution hereof, shall be effective as of _____________,

2009, and shall continue in effect until 11:59 p.m. central time _______________, 20__ (the

"Termination Date").

[Signature page follows]

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     IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first written above.

“MEC”

MERIT ENERGY COMPANY, LLC

By: 

Name: 

Title: 

“SELLER”

[Applicable Merit Partnerships]

OWNER

[__________________________]

By: 

Name: 

Title: 

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FIRPTA AFFIDAVIT

Section 1445 of the Internal Revenue Code provides that a transferee (buyer) of a U.S. real property interest must withhold tax if the transferor (seller) is a foreign person.

To inform the transferee (buyer) that withholding of tax is not required upon disposition of U.S. real property of even date herewith (the “Property”) by Merit Management Partners I, L.P, Merit Energy Partners III, L.P., and Merit Energy Partners D-III, L.P., each a Delaware limited partnership (each a “Transferor”), the undersigned hereby certifies the following on behalf of Transferor:

1. Transferor is not a foreign corporation, foreign partnership, foreign trust, or foreign estate (as those terms are defined in the Internal Revenue Code and applicable regulations).

2. No Transferor is a disregarded entity as defined in Treasury Regulation Section 1.1145-2(b)(2)(iii), other than each of Merit Management Partners I, L.P., Merit Management Partners II, L.P., and Merit Management Partners III, L.P., each of which is wholly owned, directly and indirectly, by Merit Energy Company, LLC, a Delaware limited liability company  (EIN 75-2280562) which is not a foreign corporation, foreign partnership, foreign trust or foreign estate (as those terms are defined in the Internal Revenue Code and applicable regulations).

3. Transferor’s federal identification number are:

Merit Management Partners I, L.P.	75-2280562
Merit Management Partners II, L.P.	75-2280562
Merit Management Partners III, L.P.	75-2280562
Merit Energy Partners III, L.P.	75-2339519
Merit Energy Partners D-III, L.P.	75-2923653
Merit Energy Partners E-III, L.P.	20-1535870
Merit Energy Partners F-III, L.P.	20-2443414

4. Transferor’s mailing address is 13727 Noel Road, Ste. 500, Dallas, Texas 75240.

The undersigned understands that this certification may be disclosed to the Internal Revenue Service by the transferee and that any false statement contained herein could be punished by fine, imprisonment, or both.

UNDER PENALTIES OF PERJURY the undersigned declares that he has examined this certification and to the best of its knowledge and belief it is true, correct and complete and he does further declare that he has authority to sign this document on behalf of Transferor.

MERIT MANAGEMENT PARTNERS I, L.P.

MERIT MANAGEMENT PARTNERS II, L.P

MERIT MANAGEMENT PARTNERS III, L.P

MERIT ENERGY PARTNERS III, L.P.

By:           Merit Management Partners GP, LLC

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By: 

 Christopher S. Hagge,

 Assistant Secretary

MERIT ENERGY PARTNERS D-III, L.P.

By:          Merit Management Partners I, L.P.,

general partner

By:           Merit Management Partners GP, LLC

By: 

Christopher S. Hagge,

Assistant Secretary

MERIT ENERGY PARTNERS E-III, L.P.

By:           Merit Management Partners II, L.P.,

general partner

By:           Merit Management Partners GP, LLC

By: 

Christopher S. Hagge,

Assistant Secretary

MERIT ENERGY PARTNERS F-III, L.P.

By:           Merit Management Partners III, L.P.,

general partner

By:           Merit Management Partners GP, LLC

By: 

Christopher S. Hagge,

Assistant Secretary

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EX-10.28

Exhibit 10.28

Execution Copy

Amendment No. 1

to

THIRD AMENDED AND RESTATED

EMPLOYMENT AGREEMENT

January 1, 2010

This Amendment No. 1 (this “Amendment”) to the Third Amended and Restated Employment Agreement dated December 17, 2008 (the “Employment Agreement”)between LINN OPERATING, INC., a Delaware corporation (the “Company”), and MICHAEL C. LINN (the “Linn”) is effective as of the date first set forth above (the “Effective Date”) on the terms set forth herein.  LINN ENERGY, LLC, a Delaware limited liability company, and the one hundred percent (100%) parent of the Company (“Linn Energy”), is joining in this Amendment to reflect its agreement to the matters set forth herein as to it and because it is a party to the Employment Agreement for the limited purposes of reflecting its agreement to the matters set forth therein as to it, but its joinder in this Amendment is not intended to make Linn Energy the employer of Linn for any purpose.  Capitalized terms used and not defined herein shall have the meanings ascribed to such terms in the Employment Agreement.

Whereas, the Board of Directors of Linn Energy (the “Board”) deems it to be in the best interests of Linn Energy that Linn continue to provide leadership to Linn Energy and has accordingly authorized a succession plan whereby Linn will step down as Chief Executive Officer of Linn Energy and retain his position as an employee of the Company and remain in his position as Chairman of the Board of Linn Energy but his title will change to Executive Chairman of the Board, as set forth below;

NOW, THEREFORE, in consideration of the premises and mutual covenants contained herein and in the Agreement, the parties, intending to be legally bound, agree as follows:

1.           Effective January 1, 2010, Linn shall resign as Chief Executive Officer of Linn Energy.  It is the intent of the parties hereto that upon Linn’s resignation as Chief Executive Officer, Linn will continue to participate in Linn Energy’s Long Term Incentive Plan (the “LTIP”) and that his change in position shall not be deemed a termination under any award agreement under the LTIP or under any other benefit or other current plan of the Company or Linn Energy.  Linn will be permitted to participate in future Linn Energy and Company plans.

2.           Section 1.1 of the Employment Agreement is hereby amended in its entirety and replaced by the following:

1.1           Employment; Titles; Reporting. The Company agrees to continue to employ Linn and Linn agrees to continue employment

040707, 000014, 103091817.2

with the Company, upon the terms and subject to the conditions provided in the Employment Agreement, as modified by this Amendment.  During the Employment Term, Linn will serve Linn Energy as the Executive Chairman of the Board.  In such capacity, Linn will be an officer and a member of the Board, and Linn will have such duties, responsibilities and authorities as are consistent with the position of a chairman of the board in a publicly traded company comparable to Linn Energy which is engaged in oil and natural gas acquisition, development and production.

3.           Section 1.2 of the Employment Agreement is hereby amended in its entirety and replaced by the following:

1.2           Duties.  During the Employment Term, Linn will promote the Company’s and Linn Energy’s interests and will perform his duties and responsibilities faithfully, diligently and to the best of his ability, consistent with sound business practices.  Linn will comply with the Company’s and Linn Energy’s policies, codes and procedures, as they may be in effect from time to time, applicable to executive officers of the Company and Linn Energy.  Subject to the preceding sentence, Linn may engage in charitable activities without the necessity of seeking Board approval, and may engage in other business activities with prior Board approval, provided that any charitable and/or other business activities do not violate Section 7 of the Employment Agreement.

4.           Linn acknowledges that termination of his title and duties as Chief Executive Officer is being made with his consent and is not intended to and does not create a right to severance benefits under Section 6.4 of the Employment Agreement nor to acceleration of his awards under the LTIP.  Linn further acknowledges that if at any time he voluntarily resigns from his position as Executive Chairman of the Board without Good Reason, whether due to retirement or otherwise, such resignation shall not create a right to severance benefits under Section 6.4 of the Employment Agreement nor to acceleration of his awards under the LTIP.

[Signatures on following  page]

040707, 000014, 103091817.2

2

IN WITNESS WHEREOF, the parties have duly executed this Amendment as of the date first written above.

LINN OPERATING, INC.
By:	/s/ Mark E. Ellis
Name:	Mark E. Ellis
Title:	President and Chief Operating Officer
EMPLOYEE
	/s/ Michael C. Linn
	Michael C. Linn
For the limited purposes set forth herein:
LINN ENERGY, LLC
By:	/s/ Mark E. Ellis
Name:	Mark E. Ellis
Title:	President and Chief Operating Officer

040707, 000014, 103091817.2

3

EX-10.29

Exhibit 10.29

Execution Copy

Amendment No. 1

to

FIRST AMENDED AND RESTATED

EMPLOYMENT AGREEMENT

January 1, 2010

This Amendment No. 1 (this “Amendment”) to the First Amended and Restated Employment Agreement dated December 17, 2008 (the “Employment Agreement”)between LINN OPERATING, INC., a Delaware corporation (the “Company”), and MARK E. ELLIS (the “Employee”) is effective, subject to the terms set forth below, as of the date first set forth above (the “Effective Date”) on the terms set forth herein.  LINN ENERGY, LLC, a Delaware limited liability company, and the one hundred percent (100%) parent of the Company (“Linn Energy”), is joining in this Amendment as it is a party to the Employment Agreement for the limited purposes of reflecting its agreement to the matters set forth therein as to it, but its joinder in this Amendment is not intended to make Linn Energy the employer of the Employee for any purpose.  Capitalized terms used and not defined herein shall have the meanings ascribed to such terms in the Employment Agreement.

Whereas, the board of directors of Linn Energy (the “Board”) has authorized a succession plan whereby the current Chairman of the Board and Chief Executive Officer will terminate his role as Chief Executive Officer and Employee will succeed thereto while retaining his title of President.

Accordingly, the parties, intending to be legally bound, agree as follows:

1.           Section 1.1 of the Employment Agreement is hereby amended in its entirety and replaced by the following:

1.1           Employment; Titles; Reporting. The Company agrees to continue to employ the Employee and the Employee agrees to continue employment with the Company, upon the terms and subject to the conditions provided under the Employment Agreement, as amended by this Amendment.  During the Employment Term, the Employee will serve each of the Company and Linn Energy as the President & Chief Executive Officer. In such capacity, the Employee will report to the Board and otherwise will be subject to the direction and control of the Board, and the Employee will have such duties, responsibilities and authorities as may be assigned to him by the Board from time to time and otherwise consistent with such position in a publicly traded

040707, 000014, 103091870.2

 company comparable to Linn Energy which is engaged in oil and natural gas acquisition, development and production.

2.           Section 3.1 of the Employment Agreement is hereby amended in its entirety and replaced by the following:

3.1           Base Salary. During the Employment Term, the Employee will be entitled to receive a base salary (“Base Salary”) at an annual rate of not less than $600,000 for services rendered to the Company, Linn Energy, and any of its direct or indirect subsidiaries, payable in accordance with the Company’s regular payroll practices.  The Employee’s Base Salary shall be reviewed annually by the Board and may be adjusted upward in the Board’s sole discretion, but not downward.

3. The effectiveness of this Amendment is contingent upon the effectiveness of Amendment No. 1 to the Third Amended and Restated Employment Agreement among the Company, Linn Energy and Michael C. Linn dated as of the date first set forth above.

  IN WITNESS WHEREOF, the parties have duly executed this Agreement as of the date first written above.

LINN OPERATING, INC.
By:	/s/ Michael C. Linn
Name:	Michael C. Linn
Title:	Authorized Signatory
EMPLOYEE
	/s/ Mark E. Ellis
	Mark E. Ellis
For the limited purposes set forth herein:
LINN ENERGY, LLC
By:	/s/ Michael C. Linn
Name:	Michael C. Linn
Title:	Executive Chairman of the Board

2

EX-21.1

Exhibit 21.1

SIGNIFICANT SUBSIDIARIES

As of December 31, 2009, Linn Energy, LLC directly or indirectly owns all of the voting securities of Linn Energy Holdings, LLC, the “significant subsidiary” (as defined in Rule 1−02(w) of Regulation S−X).

The remaining subsidiaries of Linn Energy, LLC considered in the aggregate as a single subsidiary, do not constitute a “significant subsidiary” as of the end of the year covered by this report.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Linn Energy, LLC:

We consent to the incorporation by reference in the registration statements (No. 333-131153 and 333-151610) on Form S-8 and in the registration statements (No. 333-146120, 333-148061, 333-148134, 333-159125 and 333-162357) on Form S-3 of Linn Energy, LLC of our reports dated February 25, 2010, with respect to the consolidated balance sheets of Linn Energy, LLC as of December 31, 2009, and 2008, and the related consolidated statements of operations, unitholders’ capital, and cash flows for each of the years in the three-year period ended December 31, 2009, and the effectiveness of internal control over financial reporting as of December 31, 2009, which reports appear in the December 31, 2009, annual report on Form 10-K of Linn Energy, LLC.

/s/ KPMG LLP                                                                                                                                          

Houston, Texas

February 25, 2010

EX-23.2

Exhibit 23.2

CONSENT OF DEGOLYER AND MACNAUGHTON

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton as independent petroleum engineers, and to the inclusion of information taken from our “Appraisal Report as of December 31, 2009 on Certain Properties owned by Linn Energy, LLC,” “Appraisal Report as of December 31, 2008 on Certain Properties owned by Linn Energy, LLC” and “Appraisal Report as of December 31, 2007 on Certain Properties owned by Linn Energy, LLC” in the sections “Business,” “Risk Factors,” “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Supplemental Oil and Gas Data (Unaudited)” in the Linn Energy, LLC Annual Report on Form 10-K for the year ended December 31, 2009, and in the registration statement on Form S-8 (File No. 333-131153 and 333-151610), and the registration statements (Nos. 333-146120, 333-148061, 333-148134, 333-159125 and 333-162357) on Form S-3.

Very truly yours,

/s/  DeGOLYER and MacNAUGHTON                                      

Texas Registered Engineering Firm F-716

Dallas, Texas

February 25, 2010

EX-31.1

Exhibit 31.1

I, Mark E. Ellis, certify that:

1.      I have reviewed this Annual Report on Form 10-K of Linn Energy, LLC (the “registrant”);

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.      The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-5(f)) for the registrant and have:

 (a)         Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 (b)         Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 (c)         Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 (d)         Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.      The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 (a)         All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 (b)         Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2010

/s/ Mark E. Ellis                                                                

Mark E. Ellis

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

I, Kolja Rockov, certify that:

1.      I have reviewed this Annual Report on Form 10-K of Linn Energy, LLC (the “registrant”);

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.      The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-5(f)) for the registrant and have:

 (a)         Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 (b)         Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 (c)         Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 (d)         Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.      The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 (a)         All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 (b)         Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2010

/s/ Kolja Rockov                                                               

Kolja Rockov

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Linn Energy, LLC (the “Company”) on Form 10-K for the year ended December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mark E. Ellis, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/  Mark E. Ellis                                                               

Mark E. Ellis

President and Chief Executive Officer

Date: February 25, 2010

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Linn Energy, LLC (the “Company”) on Form 10-K for the year ended December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kolja Rockov, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/  Kolja Rockov                                                               

Kolja Rockov

Executive Vice President and Chief Financial Officer

Date: February 25, 2010

EX-99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

APPRAISAL REPORT

as of

DECEMBER 31, 2009

on

CERTAIN PROPERTIES

owned by

LINN ENERGY LLC

SEC CASE

DeGolyer and MacNaughton

TABLE of CONTENTS

	Page
FOREWORD	1
Scope of Investigation	1
Authority	2
Source of Information	2
DEFINITION of RESERVES	4
ESTIMATION of RESERVES	10
VALUATION of RESERVES	12
SUMMARY and CONCLUSIONS	15
CERTIFICATE of QUALIFICATION

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

APPRAISAL REPORT

as of

DECEMBER 31, 2009

on

CERTAIN PROPERTIES

owned by

LINN ENERGY LLC

SEC CASE

FOREWORD

Scope of InvestigationThis  report  presents an  appraisal,  as  of December 31, 2009, of the extent and value of the proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves of certain properties owned by Linn Energy LLC (Linn). The reserves estimated in this report are located in Arkansas, California, Illinois, Kansas, Louisiana, Oklahoma, and Texas and represent 99.7 percent of Linn’s proved reserves. The properties appraised are listed in detail in the related DeGolyer and MacNaughton report entitled “Appraisal Report as of December 31, 2009 on Certain Properties owned by Linn Energy LLC.”

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Linn after deducting royalties and interests owned by others.

This report also presents values that were estimated for proved reserves using initial prices and costs provided by Linn. Prices, as required by the Securities and Exchange Commission (SEC) are the average of the price at the beginning of the previous 12 months. Oil and condensate prices are

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related to the WTI Cushing price of $61.05 per barrel. Natural gas prices are related to the Henry Hub price of $3.87 per million British thermal units (MMBtu). No escalation has been applied to prices and costs. A detailed explanation of the future price and cost assumptions is included in the Valuation of Reserves section of this report.

Values of proved reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported.

Estimates of oil, condensate, natural gas liquids, gas reserves, and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

AuthorityThis report was prepared at the request of Mr. Arden L. Walker, Senior Vice President, Linn.

Source of Information  Data  used  in   the   preparation   of   this report were obtained from Linn, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Linn with respect to its property interests, production from

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DeGolyer and MacNaughton

such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

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DEFINITION of RESERVES

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience,

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DeGolyer and MacNaughton

engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable reserves – Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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DeGolyer and MacNaughton

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible reserves – Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and

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DeGolyer and MacNaughton

engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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DeGolyer and MacNaughton

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped reserves – Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable 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 projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future

9

DeGolyer and MacNaughton

drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. No probable or possible reserves have been evaluated for this report.

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DeGolyer and MacNaughton

ESTIMATION of RESERVES

Estimates of reserves were prepared by the use of geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

The gas reserves included herein are reported as sales gas. Sales gas is defined as that gas to be delivered into a gas

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DeGolyer and MacNaughton

pipeline for sale after separation, processing, fuel use, and flare. All gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state or area in which the reserves are located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. Natural gas liquids reserves are estimated to be those attributable to the leasehold interests appraised based on historical yield information.

In the preparation of this report, as of December 31, 2009, gross production estimated to December 31, 2009, was deducted from gross ultimate recovery to arrive at the estimate of gross reserves. In some fields, this required that the production rates be estimated for up to 4 months, since production data from certain properties were available only through August 2009.

The following table presents estimates of the proved reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

	Gross Reserves				Net Reserves
	Oil and Condensate (Mbbl)		Wet Gas (MMcf)		Oil and Condensate (Mbbl)		NGL (Mbbl)		Sales Gas (MMcf)
Developed Producing		159,780		1,534,748		72,778		32,367		515,674
Developed Nonproducing		9,401		112,900		5,044		1,461		29,397
Undeveloped		34,360		532,755		24,252		20,264		225,261
Total Proved		203,541		2,180,403		102,074		54,092		770,332

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VALUATION of RESERVES

Revenue values in this report were estimated using the initial prices and costs provided by Linn. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB).

In this report, values for proved reserves were based on projections of estimated future production and revenue prepared for these properties.

The following assumptions were used for estimating future prices and costs:

Oil and Condensate Prices

Oil and condensate prices were calculated using specified differentials for each lease to a price of $61.05 per barrel. No escalation was applied to the prices. The WTI Cushing price of $61.05 per barrel is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The weighted average price for the proved reserves over the lives of the properties was $56.93 per barrel.

NGL Prices

NGL prices were calculated using specified differentials for each lease to a price of $61.05 per barrel. No escalation was applied to the prices. The WTI Cushing price of $61.05 per barrel is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The weighted average price for the proved reserves over the lives of the properties was $32.97 per barrel.

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Natural Gas Prices

Natural gas prices were calculated using specified differentials and British thermal unit (Btu) factors for each lease supplied by Linn to a Henry Hub price of $3.87 per million Btu. No escalation was applied to the prices. The Henry Hub gas price of $3.225 per thousand cubic feet is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior December 31, 2009. The weighted average price for the proved reserves over the lives of the properties was $3.225 per thousand cubic feet.

Operating Expenses and Capital Costs

Current operating expenses and capital costs, based on information provided by Linn, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

The future revenue to be derived from the production and sale of the proved reserves, as of December 31, 2009, of the properties appraised is estimated as follows:

	Proved
	Developed Producing (M$)			Developed Nonproducing (M$)			Undeveloped (M$)			Total Proved (M$)
Future Gross Revenue		6,794,997			428,943			2,855,475			10,079,415
Production and Ad Valorem Taxes		531,434			34,334			242,600			808,368
Operating Expenses		2,599,681			86,293			703,715			3,389,689
Net Other Expenses		2,483			0			0			2,483
Capital Costs		8,707			29,849			788,790			827,346
Salvage & Abandonment		(9,022	)		(665	)		(1,081	)		(10,768	)
Future Net Revenue*		3,661,714			279,132			1,121,451			5,062,297
Present Worth at 10 Percent*		1,375,429			96,735			242,467			1,714,631
* Future income taxes have not been taken into account in the preparation of these estimates.

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Timing of capital expenditures and the resulting development of production were based on a development plan provided by Linn.

In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and natural gas, estimated future net revenue from those proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.

To the extent that the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of our report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

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SUMMARY and CONCLUSIONS

Linn owns working and royalty interests in certain properties located in Arkansas, California, Illinois, Kansas, Louisiana, Oklahoma, and Texas. The estimated net proved reserves of the properties appraised, as of December 31, 2009, are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

	Net Reserves
	Oil and Condensate (Mbbl)		NGL (Mbbl)		Sales Gas (MMcf)
Developed Producing		72,778		32,367		515,674
Developed Nonproducing		5,044		1,461		29,397
Undeveloped		24,252		20,264		225,261
Total Proved		102,074		54,092		770,332

The estimated revenue and expenditures attributable to Linn’s interests in the proved reserves, as of December 31, 2009, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows:

	Proved
	Developed Producing (M$)			Developed Nonproducing (M$)			Undeveloped (M$)			Total Proved (M$)
Future Gross Revenue		6,794,997			428,943			2,855,475			10,079,415
Production and Ad Valorem Taxes		531,434			34,334			242,600			808,368
Operating Expenses		2,599,681			86,293			703,715			3,389,689
Net Other Expenses		2,483			0			0			2,483
Capital Costs		8,707			29,849			788,790			827,346
Salvage & Abandonment		(9,022	)		(665	)		(1,081	)		(10,768	)
Future Net Revenue*		3,661,714			279,132			1,121,451			5,062,297
Present Worth at 10 Percent*		1,375,429			96,735			242,467			1,714,631
* Future income taxes have not been taken into account in the preparation of these estimates.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2009,

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estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Linn. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Linn and should not be used for purposes other than those for which it is intended. DeGolyer and MacNaughton has used all procedures, data, and methods that it considers necessary to prepare this report.

All gas quantities in this report are expressed at a temperature base of 60 °F and at the legal pressure base of the state or area in which the reserves are located.

Submitted,

/s/ DeGOLYER and MacNAUGHTON                       

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

SIGNED: February 3, 2010

/s/ Paul J. Szatkowski, P.E.                                           

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas 75244, U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the report entitled “Appraisal Report as of December 31, 2009 on Certain Properties owned by Linn Energy LLC SEC Case” dated February 3, 2010, and that I, as Senior Vice President, was responsible for the preparation of this report.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have in excess of thirty-five (35) years of experience in oil and gas reservoir studies and evaluations.

3. That DeGolyer and MacNaughton or its officers have no direct or indirect interest, nor do they expect to receive any direct or indirect interest in any properties or securities of Linn or affiliate thereof.

SIGNED: February 3, 2010

/s/ Paul J. Szatkowski, P.E.                                           

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton