UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


WASHINGTON,
D.C. 20549




Form 10-K


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





For
      the fiscal year ended December 31,
2008




oTRANSITION 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
      registeredUnits
      Representing Limited Liability Company Interests
            
            The
      NASDAQ Stock Market LLC





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


None





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities
Act.        YesxNoo




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.        YesoNox




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.       YesxNoo




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).


Yeso         Nox




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




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





Documents
Incorporated By Reference:





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








TABLE OF CONTENTS





PageGlossary of Terms
            
            iiPart IItem 1.
            Business
            
            1Item 1A.
            Risk Factors
            
            16Item 1B.
            Unresolved Staff Comments
            
            25Item 2.
            Properties
            
            25Item 3.
            Legal Proceedings
            
            25Item 4.
            Submission of Matters to a Vote of Security
      Holders
            
            25Part IIItem 5.
            Market for Registrant’s Common Equity, Related Stockholder
      Matters and Issuer Purchases of Equity Securities
            
            26Item 6.
            Selected Financial Data
            
            29Item 7.
            Management’s Discussion and Analysis of Financial Condition and
      Results of Operations
            
            31Item 7A.
            Quantitative and Qualitative Disclosures About Market
      Risk
            
            55Item 8.
            Financial Statements and Supplementary Data
            
            56Item 9.
            Changes in and Disagreements With Accountants on Accounting and
      Financial Disclosure
            
            102Item 9A.
            Controls and Procedures
            
            102Item 9B.
            Other Information
            
            102Part IIIItem 10.
            Directors, Executive Officers and Corporate
      Governance
            
            103Item 11.
            Executive Compensation
            
            103Item 12.
            Security Ownership of Certain Beneficial Owners and Management
      and Related Stockholder Matters
            
            103Item 13.
            Certain Relationships and Related Transactions, and Director
      Independence
            
            103Item 14.
            Principal Accounting Fees and Services
            
            103Part IVItem 15.
            Exhibits and Financial Statement Schedules
            
            104Signatures
            
            105






i
 Table of Contents
 GLOSSARY OF TERMS


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




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




Bcf.  One billion
cubic feet.




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




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




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




Dry hole orwell.  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 orgross wells.  The
total acres or wells, as the case may be, in which a working interest is
owned.




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




MBbls/d.MBbls per
day.




Mcf.  One thousand
cubic feet.




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




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




MMBtu.  One million
British thermal units.




MMcf.  One million
cubic feet.




MMcf/d.MMcf per
day.




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




MMcfe/d.MMcfe per
day.




MMMBtu.  One
billion British thermal units.




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




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




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


ii
 Table of Contents


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




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




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




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




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




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




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




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




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




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




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




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




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


iii
 Table of Contents
 Part I
  Item
1.        Business


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




References




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




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




Overview




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




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




Strategy




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




·
            efficiently
      operate and develop acquired
properties;


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


·
            grow
      through acquisition of long life, high quality
  properties.




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




Efficiently
Operate and Develop Acquired Properties




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


1
 Table of Contents


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




Reduce
Cash Flow Volatility Through Commodity Price and Interest Rate
Hedging




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




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




Grow
Through Acquisition of Long Life, High Quality Properties




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




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




Recent
      Developments




Asset
Sales




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




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


2
 Table of Contents


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




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




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




Interest
Rate Swap Restructuring




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




Year
                2009
            
            Year
                2010
            
            Year
                2011
            
            Year
                2012
            
            Year
                2013
            
            Year
                2014(1)(dollars
      in thousands)Notional
      Amount
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000Fixed
      Rate
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %




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




Distributions




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




Unit
Repurchase Plan




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




Credit
and Capital Market Disruptions




Multiple
events during 2008 involving numerous financial institutions have effectively
restricted current liquidity within the capital markets throughout the United
States and around the world.  Despite efforts by treasury and banking
regulators in the United States, Europe and other nations to provide liquidity
to the financial sector, capital


3
 Table of Contents


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




Operating
Regions




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




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


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


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




Mid-Continent
Deep




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




Mid-Continent
Shallow




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




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




Western




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




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


4
 Table of Contents


Drilling
and Acreage




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




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




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




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




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




Total(1)Proved
      undeveloped
            
            
            1,259Other
      locations
            
            
            2,810Total
      drilling locations
            
            
            4,069Leasehold
      interests – net acres (in thousands)
            
            
            737




(1)      Does
not include optimization projects.




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


5
 Table of Contents


Productive
Wells




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




Gas
      Wells
            
            Oil
      Wells
            
            Total
      WellsGross
            
            Net
            
            Gross
            
            Net
            
            Gross
            
            NetOperated
      (1)
            
            
            1,969
            
            
            
            1,647
            
            
            
            2,484
            
            
            
            2,271
            
            
            
            4,453
            
            
            
            3,918Non-operated
      (2)
            
            
            1,313
            
            
            
            205
            
            
            
            950
            
            
            
            54
            
            
            
            2,263
            
            
            
            259Total
            
            
            3,282
            
            
            
            1,852
            
            
            
            3,434
            
            
            
            2,325
            
            
            
            6,716
            
            
            
            4,177




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




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




Developed
and Undeveloped Acreage




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




Developed
                Acreage
            
            
            Undeveloped
                Acreage
            
            
            Total
                AcreageGross
            
            
            Net
            
            
            Gross
            
            
            Net
            
            
            Gross
            
            
            Net(in
      thousands)Leasehold
      acreage
            
            
            1,555
            
            
            
            664
            
            
            
            116
            
            
            
            73
            
            
            
            1,671
            
            
            
            737




Production,
Price and Cost History




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




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




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




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


6
 Table of Contents


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




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




Year
      Ended December 31,2008
            
            2007
            
            2006Average daily production– continuing
      operations:Gas
      (MMcf/d)
            
            
            124
            
            
            
            51
            
            
            
            2Oil
      (MBbls/d)
            
            
            9
            
            
            
            3
            
            
            
            1NGL
      (MBbls/d)
            
            
            6
            
            
            
            3
            
            
            
            ―Total
      (MMcfe/d)
            
            
            212
            
            
            
            87
            
            
            
            8Average daily production– discontinued
      operations:Total
      (MMcfe/d)
            
            
            12
            
            
            
            24
            
            
            
            22Weighted average prices
      (hedged):(1)Gas
      (Mcf)
            
            $
            8.42
            
            
            $
            8.36
            
            
            $
            ―Oil
      (Bbl)
            
            $
            80.92
            
            
            $
            67.07
            
            
            $
            ―NGL
      (Bbl)
            
            $
            57.86
            
            
            $
            55.51
            
            
            $
            ―Weighted average prices
      (unhedged):(2)Gas
      (Mcf)
            
            $
            7.39
            
            
            $
            6.39
            
            
            $
            5.99Oil
      (Bbl)
            
            $
            92.78
            
            
            $
            66.44
            
            
            $
            49.55NGL
      (Bbl)
            
            $
            57.86
            
            
            $
            55.51
            
            
            $
            ―Representative
      NYMEX oil and gas prices:Gas
      (MMBtu)
            
            $
            9.04
            
            
            $
            6.86
            
            
            $
            7.23Oil
      (Bbl)
            
            $
            99.65
            
            
            $
            72.34
            
            
            $
            66.21Costs
      per Mcfe of production:Lease
      operating expenses
            
            $
            1.49
            
            
            $
            1.31
            
            
            $
            2.36Transportation
      expenses
            
            $
            0.23
            
            
            $
            0.17
            
            
            $
            0.01General
      and administrative expenses (3)
            
            $
            1.00
            
            
            $
            1.61
            
            
            $
            13.61Depreciation,
      depletion and amortization
            
            $
            2.50
            
            
            $
            2.16
            
            
            $
            1.56Taxes,
      other than income taxes
            
            $
            0.79
            
            
            $
            0.70
            
            
            $
            0.09




(1)
            Includes
      the effect of realized gains of $9.4 million (excluding $81.4 million
      realized losses on canceled derivative contracts) and $37.3 million on
      derivatives for the years ended December 31, 2008 and 2007,
      respectively.  During the year ended December 31, 2008, the
      Company canceled (before the contract settlement date) derivative
      contracts on estimated future gas production primarily associated with
      properties in the Appalachian Basin and Verden areas resulting in realized
      losses of $81.4 million.  This information is not presented for
      the year ended December 31, 2006 because it is not meaningful due to
      the classification of Appalachian Basin results of operations in
      discontinued operations (see
Note 2).




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




(3)
            General
      and administrative expenses for the years ended December 31, 2008,
      2007 and 2006 includes approximately $14.6 million, $13.5 million and
      $21.6 million, respectively, of non-cash unit-based compensation and unit
      warrant expenses.  General and administrative expenses for the
      year ended December 31, 2006 also includes $2.0 million of IPO
      bonuses paid to certain executive officers.  Excluding these
      amounts, general and administrative expenses for the years ended
      December 31, 2008, 2007 and 2006 were $0.81 per Mcfe, $1.19 per Mcfe
      and $5.14 per Mcfe, respectively.  This is a non-GAAP measure
      used by management to analyze the Company’s
  performance.


7
 Table of Contents


Reserve
      Data




Proved
Reserves




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




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




December 31,2008
            
            2007
            
            2006Reserve
      data – continuing operations:Estimated
      net proved reserves:Gas
      (Bcf)
            
            
            851
            
            
            
            833
            
            
            
            77Oil
      (MMBbls)
            
            
            84
            
            
            
            55
            
            
            
            30NGL
      (MMBbls)
            
            
            51
            
            
            
            43
            
            
            
            —Total
      (Bcfe)
            
            
            1,660
            
            
            
            1,419
            
            
            
            255Proved
      developed (Bcfe)
            
            
            1,134
            
            
            
            1,024
            
            
            
            195Proved
      undeveloped (Bcfe)
            
            
            526
            
            
            
            395
            
            
            
            60Proved
      developed reserves as a % of total proved reserves
            
            
            68
            %
            
            
            72
            %
            
            
            76
            %Standardized
      measure of discounted future net cash flows (in millions)
            
            $
            1,424
            
            
            $
            3,175
            
            
            $
            299Reserve
      data – discontinued operations:Estimated
      net proved reserves:Gas
      (Bcf)
            
            
            —
            
            
            
            195
            
            
            
            197Oil
      (MMBbls)
            
            
            —
            
            
            
            1
            
            
            
            1Total
      (Bcfe)
            
            
            —
            
            
            
            197
            
            
            
            199Proved
      developed (Bcfe)
            
            
            —
            
            
            
            148
            
            
            
            119Proved
      undeveloped (Bcfe)
            
            
            —
            
            
            
            49
            
            
            
            80Proved
      developed reserves as a % of total proved reserves
            
            
            —
            
            
            
            75
            %
            
            
            60
            %Standardized
      measure of discounted future net cash flows (in millions)
            
            $
            —
            
            
            $
            283
            
            
            $
            254Representative
      NYMEX oil and gas prices at period end:Gas
      (MMBtu)
            
            $
            5.71
            
            
            $
            6.80
            
            
            $
            5.64Oil
      (Bbl)
            
            $
            39.22
            
            
            $
            95.92
            
            
            $
            61.05




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




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


8
 Table of Contents


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




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




Operational
Overview




General




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




Principal
Customers




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




Competition




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




Operating
Hazards and Insurance




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


9
 Table of Contents


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




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




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




Title
to Properties




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




Seasonal
Nature of Business




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




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




Environmental
Matters and Regulation




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




·
            require
      the acquisition of various permits before drilling
    commences;


·
            require
      the installation of expensive pollution control
  equipment;


10
 Table of Contents


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


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


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


·
            impose
      substantial liabilities for pollution resulting from operations;
      and


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




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




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




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


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


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


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


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


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


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


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




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




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


11
 Table of Contents


Executive
Officers of the Company




Name
            
            Age
            
            Position
      with the CompanyMichael
      C. Linn
            
            57
            
            Chairman
      and Chief Executive OfficerMark
      E. Ellis
            
            53
            
            President
      and Chief Operating OfficerKolja
      Rockov
            
            38
            
            Executive
      Vice President and Chief Financial OfficerDavid
      B. Rottino
            
            43
            
            Senior
      Vice President and Chief Accounting OfficerCharlene
      A. Ripley
            
            45
            
            Senior
      Vice President, General Counsel and Corporate SecretaryArden
      L. Walker, Jr.
            
            49
            
            Senior
      Vice President - Operations and Chief
Engineer




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




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




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


12
 Table of Contents


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




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




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




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


13
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Employees




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




Principal
Executive Offices




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




Company
Website




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




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




Forward-Looking
Statements




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




·
            business
      strategy;


·
            acquisition
      strategy;


·
            financial
      strategy;


·
            drilling
      locations;


·
            oil,
      gas and NGL reserves;


·
            realized
      oil, gas and NGL prices;


·
            production
      volumes;


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


·
            future
      operating results; and


·
            plans,
      objectives, expectations and
intentions.




All of
these types of statements, other than statements of historical fact included in
this Annual Report on Form 10-K, are forward-looking
statements.  These forward-looking statements may be found in
Part I. Item 1. “Business;” Part I. Item 1A. “Risk Factors;”
Part II. Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” and other items within this Annual Report
on Form 10-K.  In some cases, forward-looking statements can be
identified by terminology such as “may,” “will,” “could,” “should,” “expect,”
“plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,”
“potential,” “pursue,” “target,” “continue,” the negative of such terms or other
comparable terminology.




The
forward-looking statements contained in this Annual Report on Form 10-K are
largely based on Company expectations, which reflect estimates and assumptions
made by Company management.  These estimates and assumptions reflect
management’s best judgment based on currently known market conditions and other
factors.  Although the Company believes such estimates and assumptions
to be reasonable, they are inherently uncertain and involve a number of risks
and uncertainties beyond its control.  In addition, management’s
assumptions may prove to be inaccurate.  The Company cautions that the
forward-looking statements contained in this Annual Report on  14
 Table of Contents


Form 10-K
are not guarantees of future performance, and it cannot assure any reader that
such statements will be realized or the forward-looking statements or events
will occur.  Actual results may differ materially from those
anticipated or implied in forward-looking statements due to factors listed in
the “Risk Factors” section and elsewhere in this Annual Report on
Form 10-K.  The forward-looking statements speak only as of the
date made, and other than as required by law, the Company undertakes no
obligation to publicly update or revise any forward-looking statement, whether
as a result of new information, future events or otherwise.




Securities
Act Disclaimer




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




15
 Table of Contents
 Item 1A.     Risk Factors


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




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




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




·
            produced
      volumes of oil, gas and NGL;


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


·
            level
      of our operating costs;


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


·
            level
      of our capital expenditures.




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




·
            availability
      of borrowings under our credit facility to pay
    distributions;


·
            the
      costs of acquisitions, if any;


·
            fluctuations
      in our working capital needs;


·
            timing
      and collectibility of receivables;


·
            restrictions
      on distributions contained in our credit
  facility;


·
            prevailing
      economic conditions; and


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




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




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




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




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


·
            the
      risk of title defects discovered after
closing;


·
            inaccurate
      assumptions about revenues and costs, including
  synergies;


·
            significant
      increases in our indebtedness and working capital
      requirements;


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


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


·
            the
      potential environmental problems and
costs;


·
            the
      assumption of unknown liabilities;


·
            limitations
      on rights to indemnity from the
seller;


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


·
            increased
      demands on existing personnel and on our corporate
    structure;




16
 Table of Contents


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


·
            the
      failure to realize expected growth or
  profitability.




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




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




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




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


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


·
            outbid
      by competitors.




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




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




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




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




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




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


17
 Table of Contents


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




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




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




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




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




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




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




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




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




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




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




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




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


·
            the
      price and level of foreign imports;


·
            the
      level of consumer product demand;


·
            weather
      conditions;


18
 Table of Contents


·
            overall
      domestic and global economic
conditions;


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


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


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


·
            technological
      advances affecting energy
consumption;


·
            domestic
      and foreign governmental regulations and
  taxation;


·
            the
      impact of energy conservation
efforts;


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


·
            the
      price and availability of alternative
fuels.




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




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




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




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




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




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




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


19
 Table of Contents


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




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




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


·
            the
      amount and timing of actual
production;


·
            the
      timing and success of development
activities;


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


·
            changes
      in governmental regulations or
taxation.




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




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




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




·
            our
      proved reserves;


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


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


·
            our
      ability to acquire, locate and produce new
  reserves.




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




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




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




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


20
 Table of Contents


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




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




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




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




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




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




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




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




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


21
 Table of Contents


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




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




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




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


·
            unexpected
      operational events;


·
            adverse
      weather conditions;


·
            facility
      or equipment malfunctions;


·
            title
      problems;


·
            pipeline
      ruptures or spills;


·
            compliance
      with environmental and other governmental
  requirements;


·
            unusual
      or unexpected geological
formations;


·
            loss
      of drilling fluid circulation;


·
            formations
      with abnormal pressures;


·
            fires;


·
            blowouts,
      craterings and explosions; and


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




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




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




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




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


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


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


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


22
 Table of Contents


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




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




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




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




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




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




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




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


·
            our
      management team, subject to oversight from our Board of Directors,
      determines the timing and extent of our drilling program and related
      capital expenditures, asset purchases and sales, borrowings, issuances
      of 23
 Table of Contents


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


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




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




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




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




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




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




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




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




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


24
 Table of Contents


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




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




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




Item 1B.     Unresolved Staff
Comments




None.




Item
2.        Properties




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




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




Offices




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




Item 3.        Legal
Proceedings




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




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




None.




25
 Table of Contents
 Part II
  Item 5.
                  Market
      for Registrant’s Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities


Market
Information




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




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


Unit
      Price Range
              
              Cash
                Distribution
                DeclaredQuarter
              
              High
              
              Low
              
              Per
      Unit2008:October
      1 – December 31
              
              $
              17.03
              
              
              $
              11.20
              
              
              $
              0.63July
      1 – September 30
              
              $
              24.88
              
              
              $
              14.93
              
              
              $
              0.63April
      1 – June 30
              
              $
              25.57
              
              
              $
              19.44
              
              
              $
              0.63January
      1 – March 31
              
              $
              24.41
              
              
              $
              18.88
              
              
              $
              0.632007:October
      1 – December 31
              
              $
              30.79
              
              
              $
              22.88
              
              
              $
              0.57July
      1 – September 30
              
              $
              37.80
              
              
              $
              31.64
              
              
              $
              0.57April
      1 – June 30
              
              $
              39.61
              
              
              $
              32.47
              
              
              $
              0.52January
      1 – March 31
              
              $
              35.05
              
              
              $
              30.16
              
              
              $
              0.52


Distributions




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




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




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


·
            comply
      with applicable laws, debt instruments or other
  agreements;




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




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




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


26
 Table of Contents


Unitholder
Return Performance Presentation




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










January
      13, 2006
            
            
            December 31,
      2006
            
            
            December 31,
      2007
            
            
            December 31,
      2008Linn
      Energy, LLC
            
            $
            100
            
            
            $
            153
            
            
            $
            128
            
            
            $
            87Alerian
      MLP Index
            
            $
            100
            
            
            $
            120
            
            
            $
            136
            
            
            $
            86S&P
      500 Index
            
            $
            100
            
            
            $
            112
            
            
            $
            118
            
            
            $
            75




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




Securities
Authorized for Issuance Under Equity Compensation Plans




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




Sales
of Unregistered Securities




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


27
 Table of Contents


Issuer
Purchases of Equity Securities




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




Period
            
            Total
      Number
                of
      Units
                Purchased
            
            Average
      Price
                Paid
      Per Unit
            
            Total
      Number of Units
                Purchased
      as Part of
                Publicly
      Announced
                Plans
      or Programs
            
            Approximate
      Dollar
                Value of Units
      that
                May Yet be Purchased
                Under the Plans
      or
                Programs(1)(in
      millions)December
      1 – December 31
            
            
            1,076,900
            
            
            $
            12.09
            
            
            
            1,076,900
            
            
            $
            87.0




(1)
            In
      October 2008, the Board of Directors of the Company authorized the
      repurchase of up to $100.0 million of the Company’s outstanding
      units.  The Company may purchase units from time to time on the
      open market or in negotiated purchases.  The repurchase plan
      does not obligate the Company to acquire any specific number of units and
      may be discontinued at any time.  28
 Table of Contents
 Item 6.      Selected
Financial Data


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




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




Year
      Ended December 31,2008
            
            2007
            
            2006
            
            2005
            
            2004(in
      thousands, except per unit amounts)Statement
      of operations data:Oil,
      gas and natural gas liquid sales
            
            $
            755,644
            
            
            $
            255,927
            
            
            $
            21,372
            
            
            $
            ―
            
            
            $
            ―Gain
      (loss) on oil and gas derivatives
            
            
            662,782
            
            
            
            (345,537
            )
            
            
            103,308
            
            
            
            (76,193
            )
            
            
            (11,004
            )Depreciation,
      depletion and amortization
            
            
            194,093
            
            
            
            69,081
            
            
            
            4,352
            
            
            
            ―
            
            
            
            ―Interest
      expense
            
            
            94,517
            
            
            
            38,974
            
            
            
            5,909
            
            
            
            481
            
            
            
            124Income
      (loss) from continuing operations
            
            
            825,657
            
            
            
            (356,194
            )
            
            
            69,811
            
            
            
            (79,311
            )
            
            
            (12,665
            )Income
      (loss) from discontinued operations, net of taxes (1)
            
            
            173,959
            
            
            
            (8,155
            )
            
            
            9,374
            
            
            
            22,960
            
            
            
            7,849Net
      income (loss)
            
            
            999,616
            
            
            
            (364,349
            )
            
            
            79,185
            
            
            
            (56,351
            )
            
            
            (4,816
            )Income
      (loss) from continuing operations per unit:Basic
            
            
            7.23
            
            
            
            (5.17
            )
            
            
            2.33
            
            
            
            (3.87
            )
            
            
            (0.62
            )Diluted
            
            
            7.23
            
            
            
            (5.17
            )
            
            
            2.30
            
            
            
            (3.87
            )
            
            
            (0.62
            )Income
      (loss) from discontinued operations per unit:Basic
            
            
            1.53
            
            
            
            (0.12
            )
            
            
            0.31
            
            
            
            1.12
            
            
            
            0.39Diluted
            
            
            1.52
            
            
            
            (0.12
            )
            
            
            0.31
            
            
            
            1.12
            
            
            
            0.39Net
      income (loss) per unit:Basic
            
            
            8.76
            
            
            
            (5.29
            )
            
            
            2.64
            
            
            
            (2.75
            )
            
            
            (0.23
            )Diluted
            
            
            8.75
            
            
            
            (5.29
            )
            
            
            2.61
            
            
            
            (2.75
            )
            
            
            (0.23
            )Distributions
      declared per unit
            
            
            2.52
            
            
            
            2.18
            
            
            
            1.15
            
            
            
            ―
            
            
            
            ―Weighted
      average units outstanding
            
            
            114,140
            
            
            
            68,916
            
            
            
            28,281
            
            
            
            20,518
            
            
            
            20,518Cash
      flow data:Net
      cash provided by (used in):Operating
      activities (2)
            
            $
            179,515
            
            
            $
            (44,814
            )
            
            $
            (6,805
            )
            
            $
            (29,518
            )
            
            $
            10,351Investing
      activities
            
            
            (35,550
            )
            
            
            (2,892,420
            )
            
            
            (551,631
            )
            
            
            (150,898
            )
            
            
            (61,373
            )Financing
      activities
            
            
            (116,738
            )
            
            
            2,932,080
            
            
            
            553,990
            
            
            
            189,269
            
            
            
            31,167Balance
      sheet data:Total
      assets
            
            $
            4,722,020
            
            
            $
            3,807,703
            
            
            $
            905,912
            
            
            $
            280,924
            
            
            $
            105,425Long-term
      debt
            
            
            1,653,568
            
            
            
            1,443,830
            
            
            
            428,237
            
            
            
            207,695
            
            
            
            72,750Unitholders’
      capital (deficit)
            
            
            2,760,686
            
            
            
            2,026,641
            
            
            
            450,954
            
            
            
            (46,831
            )
            
            
            9,520




(1)


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






29
 Table of Contents


Year
      Ended December 31,2008
            
            2007
            
            2006
            
            2005
            
            2004Production
      data:Average
      daily production – continuing operations:Gas
      (MMcf/d)
            
            
            124
            
            
            
            51
            
            
            
            2
            
            
            
            ―
            
            
            
            ―Oil
      (MBbls/d)
            
            
            9
            
            
            
            3
            
            
            
            1
            
            
            
            ―
            
            
            
            ―NGL
      (MBbls/d)
            
            
            6
            
            
            
            3
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―Total
      (MMcfe/d)
            
            
            212
            
            
            
            87
            
            
            
            8
            
            
            
            ―
            
            
            
            ―Average
      daily production – discontinued operations:Total
      (MMcfe/d)
            
            
            12
            
            
            
            24
            
            
            
            22
            
            
            
            13
            
            
            
            9Estimated
      net proved reserves – continuing operations:Gas
      (Bcf)
            
            
            851
            
            
            
            833
            
            
            
            77
            
            
            
            ―
            
            
            
            ―Oil
      (MMBbls)
            
            
            84
            
            
            
            55
            
            
            
            30
            
            
            
            ―
            
            
            
            ―NGL
      (MMBbls)
            
            
            51
            
            
            
            43
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―Total
      (Bcfe)
            
            
            1,660
            
            
            
            1,419
            
            
            
            255
            
            
            
            ―
            
            
            
            ―Estimated
      net proved reserves – discontinued operations:Total
      (Bcfe)
            
            
            ―
            
            
            
            197
            
            
            
            199
            
            
            
            193
            
            
            
            120




30
 Table of Contents
 Item 7.       Management’s
Discussion and Analysis of Financial Condition and Results of Operations


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




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




Executive
Overview




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




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




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




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




The
results of the Company’s Appalachian Basin and Mid Atlantic operations are
classified as discontinued operations for all periods
presented.  Unless otherwise indicated, results of operations
information presented herein relates only to Linn Energy’s continuing
operations.  31
 Table of Contents


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




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


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


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


·
            306
      wells drilled; and


·
            average
      of 11 operated drilling rigs.




Asset
Sales




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




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




·
            On
      December 4, 2008, the Company completed the sale of its deep rights
      in certain central Oklahoma acreage, which includes the Woodford Shale
      interval, to Devon for a contract price of $202.3 million, subject to
      closing adjustments.  The sale included approximately 34,000 net
      acres and no producing reserves.  Linn Energy retains the rights
      to the shallow portion of this acreage.  Net proceeds were
      $153.2 million and the carrying value of net assets sold was $54.2
      million, resulting in a gain on the sale of $99.0 million, which is
      recorded in “(gain) loss on sale of assets, net” on the consolidated
      statement of operations.  In January 2009, certain post closing
      matters were resolved and the Company received additional proceeds of
      $11.5 million, which will be reported as a gain in the first quarter of
      2009.  Pending resolution of title issues, the Company estimates
      it may receive additional proceeds ranging from $12.0 million to $18.0
      million during the first quarter of 2009.  These assets were
      acquired by the Company with its acquisition of oil and gas properties
      from Dominion in August 2007.  The Company used the net proceeds
      from the sale to reduce indebtedness (see
  Note 8).




Unit
Repurchase Plan




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


32
 Table of Contents


Interest
Rate Swap Restructuring




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




Year
                2009
            
            Year
                2010
            
            Year
                2011
            
            Year
                2012
            
            Year
                2013
            
            Year
                2014(1)(dollars
      in thousands)Notional
      Amount
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000Fixed
      Rate
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %




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




Canceled
Commodity Contracts




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




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




Credit
and Capital Market Disruption




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


33
 Table of Contents


Operating
Regions




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




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


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


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




Mid-Continent
Deep




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




Mid-Continent
Shallow




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




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




Western




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




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


34
 Table of Contents


Results
of Operations – Continuing Operations




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




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




Notes
to table:




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




35
 Table of Contents





Year
      Ended December 31,2008
            
            2007
            
            VarianceAverage daily production– continuing
      operations:Gas
      (MMcf/d)
            
            
            124
            
            
            
            51
            
            
            
            143
            %Oil
      (MBbls/d)
            
            
            9
            
            
            
            3
            
            
            
            200
            %NGL
      (MBbls/d)
            
            
            6
            
            
            
            3
            
            
            
            100
            %Total
      (MMcfe/d)
            
            
            212
            
            
            
            87
            
            
            
            144
            %Average daily production– discontinued
      operations:Total
      (MMcfe/d)
            
            
            12
            
            
            
            24
            
            
            
            (50
            )%Weighted average prices
      (hedged):(1)Gas
      (Mcf)
            
            $
            8.42
            
            
            $
            8.36
            
            
            
            1
            %Oil
      (Bbl)
            
            $
            80.92
            
            
            $
            67.07
            
            
            
            21
            %NGL
      (Bbl)
            
            $
            57.86
            
            
            $
            55.51
            
            
            
            4
            %Weighted average prices
      (unhedged):(2)Gas
      (Mcf)
            
            $
            7.39
            
            
            $
            6.39
            
            
            
            16
            %Oil
      (Bbl)
            
            $
            92.78
            
            
            $
            66.44
            
            
            
            40
            %NGL
      (Bbl)
            
            $
            57.86
            
            
            $
            55.51
            
            
            
            4
            %Representative
      NYMEX oil and gas prices:Gas
      (MMBtu)
            
            $
            9.04
            
            
            $
            6.86
            
            
            
            32
            %Oil
      (Bbl)
            
            $
            99.65
            
            
            $
            72.34
            
            
            
            38
            %Costs
      per Mcfe of production:Lease
      operating expenses
            
            $
            1.49
            
            
            $
            1.31
            
            
            
            14
            %Transportation
      expenses
            
            $
            0.23
            
            
            $
            0.17
            
            
            
            35
            %General
      and administrative expenses (3)
            
            $
            1.00
            
            
            $
            1.61
            
            
            
            (38
            )%Depreciation,
      depletion and amortization
            
            $
            2.50
            
            
            $
            2.16
            
            
            
            16
            %Taxes,
      other than income taxes
            
            $
            0.79
            
            
            $
            0.70
            
            
            
            13
            %




Notes
to table:




(1)
            Includes
      the effect of realized gains of $9.4 million (excluding $81.4 million
      losses on canceled derivative contracts) and $37.3 million on derivatives
      for the years ended December 31, 2008 and 2007,
      respectively.  During the year ended December 31, 2008, the
      Company canceled (before the contract settlement date) derivative
      contracts on estimated future gas production primarily associated with
      properties in the Appalachian Basin and Verden areas resulting in realized
      losses of $81.4 million.




(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
      2007 includes approximately $14.6 million and $13.5 million, respectively,
      of non-cash unit-based compensation and unit warrant
      expenses.  Excluding these amounts, general and administrative
      expenses for the years ended December 31, 2008 and 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.  36
 Table of Contents


Revenues
and Other




Oil,
Gas and NGL Sales


Oil, 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.




The
increase in oil, gas and NGL revenues was primarily attributable to increased
production as a result of acquisitions and, to a lesser extent,
drilling.  Total production increased to 212 MMcfe/d during the year
ended December 31, 2008, from 87 MMcfe/d during the year ended
December 31, 2007.  The increase in production was due primarily
to the acquisition of oil and gas properties in the Mid-Continent Deep and
Mid-Continent Shallow regions (see Note 3).  In addition, the
Company drilled 306 wells during the year ended December 31, 2008, compared
to 138 wells during the year ended December 31, 2007.  Volume
increases during the year ended December 31, 2008 increased total oil, gas
and NGL revenues by $366.3 million compared to the year ended December 31,
2007.




Gas
production increased to 124 MMcf/d during the year ended December 31, 2008,
from 51 MMcf/d during the year ended December 31, 2007, primarily due to
the 2007 and 2008 acquisitions in the Mid-Continent Deep and Mid-Continent
Shallow regions (see Note 3) and to drilling.  The increase in
the weighted average price of gas for 2008, to $7.39 per Mcf, from $6.39 per
Mcf, contributed approximately $45.5 million to the increase in gas
revenues.




Oil
production increased to 9 MBbls/d during the year ended December 31, 2008,
from 3 MBbls/d during the year ended December 31, 2007, due to acquisitions
and the drilling of new wells.  Acquisitions and drilling also
increased NGL production to 6 MBbls/d during the year ended December 31,
2008, from 3 MBbls/d during the year ended December 31,
2007.  The increase in the weighted average price of oil for 2008, to
$92.78 per Bbl, from $66.44 per Bbl, contributed approximately $82.6 million to
the increase in oil revenues.  The increase in the weighted average
price of NGL for 2008, to $57.86 per Bbl, from $55.51 per Bbl, contributed
approximately $5.3 million to the increase in NGL revenues.




Gain
(Loss) on Oil and Gas Derivatives


The
Company determines the fair value of its oil and gas derivatives using pricing
models that use a variety of techniques, including quotes and pricing
analysis.  See Note 9 and Note 10 for additional information
and details regarding derivatives in place through December 31,
2014.  During the year ended December 31, 2008, the Company had
commodity derivative contracts for approximately 112% of its gas production and
82% of its oil and NGL production, which resulted in realized losses of $72.0
million.  During the year ended December 31, 2008, the Company
canceled (before the contract settlement date) derivative contracts on estimated
future gas production primarily associated with properties in the Appalachian
Basin and Verden areas (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 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 gas prices increased,
which resulted in unrealized losses on derivatives of approximately $382.8
million for the year ended December 31, 2007.  Market value
adjustments, if realized in the future, would be offset by higher actual prices
for production.  For information about the Company’s credit risk
related to derivative contracts see “Fair Value of Financial Instruments”
below.




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 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.


37
 Table of Contents


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.  As noted below, total
general and administrative expenses increased; however, 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.




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 over 2007 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 2007 (see Note 3).  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 with XTO (see Note 2).




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 unproved leasehold costs associated with
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 a petition for reorganization under Chapter 11.




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 2008 and 2007, 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 ended December 31, 2007, primarily due to higher depletion rates on oil
and gas properties acquired in the Mid-Continent Deep region in August 2007, as
compared to the Company’s other oil and gas 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 is
associated with impairment of goodwill and approximately $30.2 million is
associated with impairment of oil and gas properties.  See Note 1 and
also “Critical Accounting Policies and Estimates” below for additional
information.




Taxes,
Other Than Income Taxes


Taxes,
other than income taxes, which consists 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 and ad valorem taxes were
approximately 8% of total sales for each of the years ended December 31,
2008 and 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


38
 Table of Contents


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, Net


The
increase in (gain) loss on sale of assets, net for the year ended
December 31, 2008 is primarily due to a gain of $99.0 million from the sale
of Woodford Shale assets in December 2008 (see Note 3).




Other
Income and (Expenses)




Other
income and (expenses) increased by approximately $98.0 million, to expense of
$168.9 million for the year ended December 31, 2008, compared to expense of
$70.9 million for the year ended December 31, 2007, 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 Company’s interest rate swaps were not designated as cash
flow hedges under SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended, (“SFAS 133”), even
though they reduce exposure to changes in interest rates (see
Note 9).  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 2007,
respectively.  These amounts are non-cash
items.  Additionally, the Company wrote-off deferred financing fees of
approximately $6.7 million during the year ended December 31, 2008,
compared to approximately $2.8 million during the year ended December 31, 2007,
which contributed to the increase in other income and (expenses).




Income
Tax Benefit (Expense)




Income
tax expense was approximately $2.7 million and $4.8 million for the years ended
December 31, 2008 and 2007, respectively.  Tax expense for the
year ended December 31, 2008 primarily represents Texas margin tax
expense.  Limited liability companies are subject to state income
taxes in Texas.  The Company is treated as a partnership for federal
and state income tax purposes; however, certain of the Company’s subsidiaries
are Subchapter C-corporations subject to federal and state income
taxes.  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 intercompany charge for services to
Linn Energy, which resulted in income tax expense for Linn Energy for the year
ended December 31, 2007.


39
 Table of Contents


Results
of Operations – Continuing Operations




Year
Ended December 31, 2007 Compared to Year Ended December 31,
2006




Year
      Ended December 31,2007
            
            2006
            
            Variance(in
      thousands)Revenues
      and other:Gas
      sales
            
            $
            118,343
            
            
            $
            4,475
            
            
            $
            113,868Oil
      sales
            
            
            82,523
            
            
            
            16,897
            
            
            
            65,626NGL
      sales
            
            
            55,061
            
            
            
            ―
            
            
            
            55,061Total
      oil, gas and NGL sales
            
            
            255,927
            
            
            
            21,372
            
            
            
            234,555Gain
      (loss) on oil and gas derivatives
            
            
            (345,537
            )
            
            
            103,308
            
            
            
            (448,845
            )Gas
      marketing revenues
            
            
            11,589
            
            
            
            ―
            
            
            
            11,589Other
      revenues
            
            
            2,738
            
            
            
            846
            
            
            
            1,892$
            (75,283
            )
            
            $
            125,526
            
            
            $
            (200,809
            )Expenses:Lease
      operating expenses
            
            $
            41,946
            
            
            $
            6,603
            
            
            $
            35,343Transportation
      expenses
            
            
            5,575
            
            
            
            40
            
            
            
            5,535Gas
      marketing expenses
            
            
            9,100
            
            
            
            ―
            
            
            
            9,100General
      and administrative expenses (1)
            
            
            51,374
            
            
            
            37,997
            
            
            
            13,377Exploration
      costs
            
            
            4,053
            
            
            
            286
            
            
            
            3,767Bad
      debt expenses
            
            
            ―
            
            
            
            12
            
            
            
            (12
            )Depreciation,
      depletion and amortization
            
            
            69,081
            
            
            
            4,352
            
            
            
            64,729Taxes,
      other than income taxes
            
            
            22,350
            
            
            
            243
            
            
            
            22,107(Gain)
      loss on sale of assets, net
            
            
            1,767
            
            
            
            28
            
            
            
            1,739$
            205,246
            
            
            $
            49,561
            
            
            $
            155,685Other
      income and (expenses)
            
            $
            (70,877
            )
            
            $
            (8,127
            )
            
            $
            (62,750
            )Income
      (loss) from continuing operations before income taxes
            
            $
            (351,406
            )
            
            $
            67,838
            
            
            $
            (419,244
            )




Notes
to table:




(1)
            General
      and administrative expenses for the years ended December 31, 2007 and
      2006 includes approximately $13.5 million and $21.6 million, respectively,
      of non-cash unit-based compensation and unit warrant
      expenses.  General and administrative expenses for the year
      ended December 31, 2006 also includes $2.0 million of IPO bonuses
      paid to certain executive officers.




40
 Table of Contents




Year
      Ended December 31,2007
            
            2006
            
            VarianceAverage daily production– continuing
      operations:Gas
      (MMcf/d)
            
            
            51
            
            
            
            2
            
            
            
            2,450
            %Oil
      (MBbls/d)
            
            
            3
            
            
            
            1
            
            
            
            200
            %NGL
      (MBbls/d)
            
            
            3
            
            
            
            ―
            
            
            
            ―Total
      (MMcfe/d)
            
            
            87
            
            
            
            8
            
            
            
            988
            %Average daily production– discontinued
      operations:Total
      (MMcfe/d)
            
            
            24
            
            
            
            22
            
            
            
            9
            %Weighted average prices
      (hedged):(1)Gas
      (Mcf)
            
            $
            8.36
            
            
            $
            ―
            
            
            
            ―Oil
      (Bbl)
            
            $
            67.07
            
            
            $
            ―
            
            
            
            ―NGL
      (Bbl)
            
            $
            55.51
            
            
            $
            ―
            
            
            
            ―Weighted average prices
      (unhedged):(2)Gas
      (Mcf)
            
            $
            6.39
            
            
            $
            5.99
            
            
            
            7
            %Oil
      (Bbl)
            
            $
            66.44
            
            
            $
            49.55
            
            
            
            34
            %NGL
      (Bbl)
            
            $
            55.51
            
            
            $
            ―
            
            
            
            ―Representative
      NYMEX oil and gas prices:Gas
      (MMBtu)
            
            $
            6.86
            
            
            $
            7.23
            
            
            
            (5
            )%Oil
      (Bbl)
            
            $
            72.34
            
            
            $
            66.21
            
            
            
            9
            %Costs
      per Mcfe of production:Lease
      operating expenses
            
            $
            1.31
            
            
            $
            2.36
            
            
            
            (44
            )%Transportation
      expenses
            
            $
            0.17
            
            
            $
            0.01
            
            
            
            1,600
            %General
      and administrative expenses (3)
            
            $
            1.61
            
            
            $
            13.61
            
            
            
            (88
            )%Depreciation,
      depletion and amortization
            
            $
            2.16
            
            
            $
            1.56
            
            
            
            38
            %Taxes,
      other than income taxes
            
            $
            0.70
            
            
            $
            0.09
            
            
            
            678
            %




Notes
to table:




(1)
            Includes
      the effect of realized gains of $37.3 million on derivatives for the year
      ended December 31, 2007.  The data for the year ended
      December 31, 2006 is not presented because it is not meaningful due
      to the classification of Appalachian Basin results of operations in
      discontinued operations (see
Note 2).




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




(3)
            General
      and administrative expenses for the years ended December 31, 2007 and
      2006 includes approximately $13.5 million and $21.6 million, respectively,
      of non-cash unit-based compensation and unit warrant
      expenses.  General and administrative expenses for the year
      ended December 31, 2006 also includes $2.0 million of IPO bonuses
      paid to certain executive officers.  Excluding these amounts,
      general and administrative expenses for the years ended December 31,
      2007 and 2006 were $1.19 per Mcfe and $5.14 per Mcfe,
      respectively.  This is a non-GAAP measure used by management to
      analyze the Company’s performance.




41
 Table of Contents


Revenues
and Other




Oil,
Gas and NGL Sales


Oil, gas
and NGL sales increased by approximately $234.5 million, or 1,096%, to
approximately $255.9 million for the year ended December 31, 2007, from
$21.4 million for the year ended December 31, 2006.




The
increase in oil, gas and NGL revenues was primarily attributable to increased
production as a result of acquisitions and, to a lesser extent,
drilling.  Total production increased to 87 MMcfe/d during the year
ended December 31, 2007, from 8 MMcfe/d during the year ended
December 31, 2006.  The increase in production was due primarily
to production from oil and gas properties acquired in 2007 in the Mid-Continent
Deep and Mid-Continent Shallow regions (see Note 3).  In
addition, the Company drilled 138 wells during the year ended December 31,
2007, compared to 4 wells during the year ended December 31,
2006.  Volume increases during the year ended December 31, 2007
increased total oil, gas and NGL revenues by $206.2 million compared to the year
ended December 31, 2006.




Gas
production increased to 51 MMcf/d during the year ended December 31, 2007,
from 2 MMcf/d during the year ended December 31, 2006, primarily due to
acquisitions and drilling.  The increase in the weighted average price
of gas for 2007, to $6.39 per Mcf, from $5.99 per Mcf, contributed approximately
$7.3 million to the increase in gas revenues.




Oil
production increased to 3 MBbls/d during the year ended December 31, 2007,
from 1 MBbls/d during the year ended December 31, 2006, due to acquisitions
and drilling.  Acquisitions and drilling also increased NGL production
to 3 MBbls/d during the year ended December 31, 2007, from zero during the
year ended December 31, 2006.  The increase in the weighted
average price of oil for 2007, to $66.44 per Bbl, from $49.55 per Bbl,
contributed approximately $21.0 million to the increase in oil
revenues.




Gain
(Loss) on Oil and Gas Derivatives


During
the years ended December 31, 2007 and 2006, the Company had commodity
pricing derivative contracts for its oil, gas and NGL production, which resulted
in realized gains of $37.3 million and $20.2 million,
respectively.  Unrealized losses on derivatives in the amount of
$382.8 million for the year ended December 31, 2007, and unrealized gains
of $83.1 million for the year ended December 31, 2006, were also
recorded.  Unrealized gains and losses result from changes in market
valuations of derivatives as future commodity price expectations change compared
to the contract price on the derivative.  During 2007, expected future
oil and gas prices increased, which reduced the market value of the
derivatives.  Market value adjustments, if realized in the future,
would be offset by higher actual prices for production.  See
Note 9 for details regarding derivatives in place through December 31,
2014.




Expenses




Lease
Operating Expenses


Lease
operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies and workover
expenses.  As noted below, total lease operating expenses increased;
however, lease operating expenses per equivalent unit of production decreased to
$1.31 per Mcfe for the year ended December 31, 2007, compared to $2.36 per
Mcfe for the year ended December 31, 2006, due to acquired properties
providing cost efficiencies and economies of scale.




Lease
operating expenses increased by approximately $35.3 million, or 535%, to $41.9
million for the year ended December 31, 2007, from $6.6 million for the
year ended December 31, 2006.  Lease operating expenses increased
primarily due to higher production and costs associated with the 2007
acquisitions in the Mid-Continent Deep and Mid-Continent Shallow
regions.




Transportation
Expenses


Transportation
expenses increased to $5.6 million for the year ended December 31, 2007,
from approximately $40,000 for the year ended December 31, 2006, primarily
due to increased production from the 2007 acquisitions in the Mid-Continent Deep
and Mid-Continent Shallow regions.


42
 Table of Contents


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.  As noted below, total
general and administrative expenses increased; however, expenses per equivalent
unit of production decreased to $1.61 per Mcfe for the year ended
December 31, 2007, compared to $13.61 per Mcfe for the year ended
December 31, 2006, due to increases in production, cost efficiencies and
economies of scale provided by acquired properties.




General
and administrative expenses include the costs of employees and executive
officers, related benefits, office leases, professional fees and other costs not
directly associated with field operations.  General and administrative
expenses increased to approximately $51.4 million for the year ended
December 31, 2007, from $38.0 million for the year ended December 31,
2006.  The increase in general and administrative expenses was
primarily due to costs incurred to support the Company’s rapid growth through
acquisitions and position the Company for future growth.  In
conjunction with expansion and development of the organization during 2007, the
Company hired approximately 150 employees (including approximately 100
corporate, administrative and support employees with the August 2007 acquisition
in the Mid-Continent Deep region) and as a result, salaries and benefits expense
increased approximately $13.5 million over 2006.  Costs to perform the
necessary functions associated with being a growing company were $13.8 million
during 2007, compared to $5.6 million during 2006.  These costs
include expenses for recruitment of key management team members, acquisition
related data conversion and integration, public partnership tax reporting, audit
fees, legal fees, proxy and printing costs and other professional fees,
including costs related to compliance with Section 404 of the
Sarbanes-Oxley Act of 2002.  In addition, acquisition costs that are
not eligible for capitalization, including internal and indirect costs for
completed acquisitions, as well as direct costs associated with acquisition
efforts that have not reached fruition, contributed to the
increase.  The increase in general and administrative expenses was
partially offset by lower employee unit-based compensation expense during the
year ended December 31, 2007.  Unit-based compensation expense
incurred during the year ended December 31, 2006 was higher compared to
that incurred in 2007, primarily due to expense associated with unit awards
granted in conjunction with the Company’s IPO in January 2006.




Exploration
Costs


The
Company incurred exploration costs of approximately $4.1 million and $0.3
million during the years ended December 31, 2007 and 2006,
respectively.  The increase in expense during 2007 primarily
represents payments for access to 3-D seismic and other data libraries in the
Mid-Continent Deep region.  Increased unproved leasehold and delay
rental costs also contributed to the increase.




Depreciation,
Depletion and Amortization


Depreciation,
depletion and amortization increased by approximately $64.7 million, to $69.1
million for the year ended December 31, 2007, from $4.4 million for the
year ended December 31, 2006.  Depreciation, depletion and
amortization per Mcfe also increased, to $2.16 per Mcfe for the year ended
December 31, 2007, from $1.56 per Mcfe for the year ended December 31,
2006.  Higher total production levels, primarily due to the Company’s
acquisitions in the Mid-Continent Deep and Mid-Continent Shallow regions in
2007, were the main reason for the increase.  Approximately $37.9
million of the increase was as a result of depletion related to the August 2007
acquisition in the Mid-Continent Deep region.  The properties acquired
earlier in 2007 in the Mid-Continent Shallow region contributed approximately
$12.4 million to the increase.




Taxes,
Other Than Income Taxes


Taxes,
other than income taxes, which consists primarily of production and ad valorem
taxes, increased by approximately $22.2 million to $22.4 million for the year
ended December 31, 2007, from $0.2 million for the year ended
December 31, 2006.  Production taxes, which are a function of
revenues generated from production, increased by approximately $14.8 million
compared to the year ended December 31, 2006.  Ad valorem taxes,
which are based on the value of reserves and production equipment and vary by
location, increased by approximately $5.3 million compared to the year ended
December 31, 2006.


43
 Table of Contents


Other
Income and (Expenses)




Other
income and (expenses) increased by approximately $62.8 million, to expense of
$70.9 million for the year ended December 31, 2007, compared to expense of
$8.1 million for the year ended December 31, 2006, primarily due to an
increase in interest expense of approximately $33.1 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 $28.4 million over the year ended December 31,
2006.  The Company’s interest rate swaps were not designated as cash
flow hedges under SFAS 133, even though they reduce exposure to changes in
interest rates (see Note 9).  The changes in fair values of these
instruments were recorded as an unrealized loss of approximately $29.5 million
and an unrealized gain of approximately $0.1 million for the years ended
December 31, 2007 and 2006, respectively.  These amounts are
non-cash items.




Income
Tax Benefit (Expense)




Income
tax was an expense of approximately $4.8 million for the year ended
December 31, 2007 and a benefit of approximately $2.0 million for the year
ended December 31, 2006.  The Company is treated as a partnership
for federal and state income tax purposes; however, certain of the Company’s
subsidiaries are Subchapter C-corporations subject to corporate income
taxes.  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 intercompany charge for services to
Linn Energy, which resulted in income tax expense for Linn Energy for the year
ended December 31, 2007.




Results
of Operations – Discontinued Operations




The
following table presents comparative data for the Company’s discontinued
operations related to its Appalachian Basin assets.  See Note 2
for additional details about discontinued operations.




Year
      Ended December 31,2008
            
            
            2007
            
            
            2006Average
      daily production:Total
      (MMcfe/d)
            
            
            12
            
            
            
            24
            
            
            
            22




The sale
of properties in the Appalachian Basin (see Note 2) will produce taxable
gains or losses to unitholders.  The amount of gain or loss will be
determined at unitholder level, based on each affected unitholder’s tax basis in
the disposed properties and allocated sale proceeds and in accordance with the
terms of the Company’s Second Amended and Restated Limited Liability Company
Agreement, as amended, and the applicable tax laws, and will be reflected in
unitholder K-1s to be provided in the spring of 2009.




Liquidity
and Capital Resources




The
Company has utilized public and private equity, proceeds from bank borrowings
and issuance of senior notes, and cash flow from operations for capital
resources and liquidity.  To date, the primary use of capital has been
for the acquisition and development of oil and gas properties.  The
Company manages its working capital and cash requirements to borrow only as
needed.  The Company had $415.4 million in available borrowing
capacity at January 30, 2009.




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


44
 Table of Contents


Cash
Flows




The
following presents a comparative cash flow summary:




Year
      Ended
                December 31,2008
            
            2007
            
            Variance(in
      thousands)Net
      cash:Provided
      by (used in) operating activities (1)
      (2)
            
            $
            179,515
            
            
            $
            (44,814
            )
            
            $
            224,329Used
      in investing activities
            
            
            (35,550
            )
            
            
            (2,892,420
            )
            
            
            2,856,870Provided
      by (used in) financing activities
            
            
            (116,738
            )
            
            
            2,932,080
            
            
            
            (3,048,818
            )Increase
      (decrease) in cash and cash equivalents
            
            $
            27,227
            
            
            $
            (5,154
            )
            
            $
            32,381




(1)
            The
      years ended December 31, 2008 and 2007 include premiums paid for
      derivatives of approximately $129.5 million and $279.3 million,
      respectively.  Premiums paid during the year ended
      December 31, 2008 include $67.6 million for contracts that replaced
      those with Lehman Commodity Services (see
  Note 13).




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




Operating
Activities


At
December 31, 2008, the Company had $28.7 million cash and cash equivalents
compared to $1.4 million at December 31, 2007.  Cash provided by
operating activities for the year ended December 31, 2008 was approximately
$179.5 million, compared to cash used by operating activities of $44.8 million
for the year ended December 31, 2007.  The increase in cash
provided by operating activities was primarily due to increased production
during the year ended December 31, 2008.  During the year ended
December 31, 2008, the Company canceled (before the contract settlement
date) derivative contracts on estimated future gas production primarily
associated with properties in the Appalachian Basin and Verden areas (see
Note 2) resulting in realized losses of approximately $81.4
million.  In addition, premiums paid for derivatives were
approximately $129.5 million during the year ended December 31, 2008,
compared to $279.3 million during the year ended December 31,
2007.  Premiums paid during the year ended December 31, 2008
include $67.6 million for contracts that replaced those with Lehman Commodity
Services (see Note 13).  The premiums paid were for derivative
contracts that hedge future production for up to five years.  These
derivative contracts are expected to provide or stabilize the Company’s future
cash flow and were funded through the Company’s credit facility.  See
Note 9 for additional details about commodity derivatives.  The
amount of derivative contracts the Company enters into in the future will be
directly related to expected future production.




Investing
Activities


Cash used
in investing activities was approximately $35.6 million for the year ended
December 31, 2008, compared to $2.89 billion for the year ended
December 31, 2007.  The decrease in cash used in investing
activities was due to a decrease in acquisition and development activity and an
increase in proceeds from asset sales during the year ended December 31,
2008, compared to the year ended December 31, 2007.




The total
cash used in investing activities for the year ended December 31, 2008
includes $510.6 million for the January 2008 acquisition of properties in the
Mid-Continent Shallow region (see Note 3).  Other acquisitions,
including acquisitions of additional working interests in current wells, were
approximately $82.8 million and other property and equipment purchases were $9.1
million.  The total for the year ended December 31, 2008 also
includes approximately $330.6 million for the drilling and development of oil
and gas properties.  During the year ended December 31, 2008, the
Company also received proceeds from the sales of oil and gas properties to XTO,
Laredo and Devon, and other plant and equipment totaling approximately $897.6
million (see Note 2).




For 2009,
the Company estimates its total drilling and development capital expenditures
will be approximately $150.0 million compared to approximately $321.3 million
from continuing operations in 2008.  This estimate is under continuous
review and is subject to on-going adjustment.  The Company expects to
fund these capital expenditures with cash flow from operations.


45
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Financing
Activities


Cash used
by financing activities was approximately $116.7 million for the year ended
December 31, 2008, compared to cash provided by financing activities of
$2.93 billion for the year ended December 31, 2007.  During the
year ended December 31, 2008, total proceeds from the issuance of debt were
$1.46 billion and total repayments of debt were $1.25 billion.  See
additional discussion about the Company’s credit facility, term loan and senior
notes below.  In addition, see detail of distributions paid during the
year ended December 31, 2008 below.




Distributions




Under the
limited liability company agreement, Company unitholders are entitled to receive
a quarterly distribution of available cash to the extent there is sufficient
cash from operations after establishment of cash reserves and payment of fees
and expenses.  The following provides a summary of distributions paid
by the Company during the year ended December 31, 2008:




Date
      Paid
            
            Period
      Coveredby
      Distribution
            
            Distribution
                Per
      Unit
            
            Total
              Distribution(in
      millions)November
      2008
            
            July
      1 – September 30, 2008
            
            $
            0.63
            
            
            $
            72.6August
      2008
            
            April
      1 – June 30, 2008
            
            $
            0.63
            
            
            
            72.6May
      2008
            
            January
      1 – March 31, 2008
            
            $
            0.63
            
            
            
            72.6February
      2008
            
            October
      1 – December 31, 2007
            
            $
            0.63
            
            
            
            72.2$
            290.0




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




Credit
Facility




The
Company currently has a $1.85 billion borrowing base under its Third Amended and
Restated Credit Agreement (“Credit Facility”) with a maturity of August
2010.  The borrowing base under the Credit Facility will be
redetermined semi-annually by the lenders in their sole discretion, based on,
among other things, reserve reports as prepared by reserve engineers taking into
account the oil and gas prices at such time.  Significant declines in
oil, gas or NGL prices may result in a decrease in the borrowing
base.  During 2009, the Company plans to renegotiate its Credit
Facility, which is anticipated to result in increased interest
expense.  There can be no assurance that the borrowing base under a
new Credit Facility will remain at the current level.




At the
Company’s election, interest on borrowings under the Credit Facility is
determined by reference to either the London Interbank Offered Rate (“LIBOR”)
plus an applicable margin between 1.00% and 1.75% per annum or the alternate
base rate (“ABR”) plus an applicable margin between 0% and 0.25% per
annum.  The Company is required to pay a fee ranging from 0.3% to
0.375% per year on the unused portion of the Credit Facility.




As noted
above, 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 flows for investing activities and borrows as cash is
needed.  Absent such borrowing, 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 “Credit and Capital Market
Disruptions” in the “Executive Overview” above and also Part I. Item 1A.
“Risk Factors.”




Certain
subsidiaries of Lehman Holdings, including Lehman Commodity Services, were
lenders in the Company’s Credit Facility.  In September 2008 and
October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed
voluntary petitions for reorganization under Chapter 11 (see
“Contingencies” below).  In October


46
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2008, the
Company replaced Lehman Holdings’ subsidiaries with another lender and Lehman
Holdings’ subsidiaries no longer participate in the Company’s Credit
Facility.  At January 30, 2009, available borrowing under the
Credit Facility was $415.4 million, which includes a $6.2 million reduction in
availability for outstanding letters of credit.




Term
Loan




On
January 31, 2008, in order to fund a portion of the January 2008
acquisition of oil and gas properties in the Mid-Continent Shallow region (see
Note 3), the Company entered into a $400.0 million Second Lien Term Loan
Agreement (“Term Loan”) maturing on July 31, 2009.  Interest was
determined by reference to LIBOR plus an applicable margin of 5.0% for the first
twelve months and 7.5% for the remaining period until maturity, or a domestic
bank rate plus an applicable margin of 3.5% for the first twelve months and 6.0%
for the remaining period until maturity.  On June 30, 2008, the
Company repaid $243.6 million in indebtedness under the Term Loan with net
proceeds from the Senior Notes (see below).  On July 1, 2008, the
Company repaid the balance of the Term Loan of $156.4
million.  Deferred financing fees associated with the Term Loan of
approximately $4.6 million were written off during the year ended
December 31, 2008.




Senior
Notes




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 (“Senior Notes”).  The Senior Notes were offered
and sold to the Initial Purchasers and then resold to qualified institutional
buyers each in transactions exempt from the registration requirements under the
Securities Act of 1933, as amended (“Securities Act”).  The Company
used the net proceeds (after deducting the Initial Purchasers’ discounts and
offering expense) of approximately $243.6 million to repay loans outstanding
under the Company’s Term Loan (see above).  In connection with the
Senior Notes, the Company incurred financing fees of approximately $7.8 million,
which will be amortized over the life of the Senior Notes; the expense is
recorded in “interest expense, net of amounts capitalized” on the consolidated
statement of operations.  The $5.9 million discount on the Senior
Notes will be amortized over the life of the Senior Notes; the expense is
recorded in “interest expense, net of amounts capitalized” on the consolidated
statement of operations.  As of January 30, 2009, the net
carrying value of the Senior Notes was approximately $250.2 million and the fair
value was approximately $201.5 million.  The fair value of the Senior
Notes was estimated based on prices quoted from third-party financial
institutions.




The
Senior Notes were issued under an Indenture dated June 27, 2008, mature on
July 1, 2018 and bear interest at 9.875%.  Interest is payable
semi-annually beginning January 1, 2009.  The Senior Notes are
general unsecured senior obligations of the Company and are effectively junior
in right of payment to any secured indebtedness of the Company to the extent of
the collateral securing such indebtedness.  Each of the Company’s
material subsidiaries guaranteed the Senior 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 Senior 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 Senior 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 Senior 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
Senior Notes at a redemption price equal to 101%, plus accrued and unpaid
interest.




The
Senior 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.




In
connection with the issuance and sale of the Senior Notes, the Company entered
into a Registration Rights Agreement with the Initial
Purchasers.  Under the Registration Rights Agreement, the Company
agreed to use its


47
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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 Senior Notes in exchange for outstanding Senior
Notes.  In certain circumstances, the Company may be required to file
a shelf registration statement to cover resales of the Senior
Notes.  The Company will not be obligated to file the registration
statements described above if the restrictive legend on the Senior Notes has
been removed and the Senior Notes are freely tradable (in each case, other than
with respect to persons that are affiliates of the Company) pursuant to
Rule 144 under the Securities Act, as of the 366th day after the Senior
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 Senior Notes under certain
circumstances.




Fair
Value of Financial Instruments




The
Company accounts for its oil and gas commodity derivatives and interest rate
swaps at fair value on a recurring basis (see
Note 10).  Effective January 1, 2008, the Company adopted
SFAS No. 157, “Fair Value
Measurements” (“SFAS 157”) for these financial
instruments.  SFAS 157 defines fair value, establishes a
framework for measuring fair value, establishes a fair value hierarchy based on
the quality of inputs used to measure fair value, and enhances disclosure
requirements for fair value measurements.  The impact of the adoption
of SFAS 157 to the Company’s results of operations was a decrease in net
income of approximately $4.0 million, or $0.04 per unit, for the year ended
December 31, 2008, resulting from assumed credit risk
adjustments.  The credit risk adjustments are based on published
credit ratings, public bond yield spreads and credit default swap
spreads.  The impact of the Company’s assumed credit risk adjustment
was a gain of approximately $8.9 million.  The impact of the
counterparties’ assumed credit risk adjustment was a loss of approximately $12.9
million.




The
Company’s counterparties are participants in its Credit Facility (see
Note 8) which is secured by the Company’s oil and gas reserves; therefore,
the Company is not required to post any collateral.  The Company does
not require collateral from the 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 are also lenders in the Company’s Credit Facility, each
of which currently meet 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 swap derivatives are subject to counterparty
netting under agreements governing such derivatives and therefore the risk of
loss due to counterparty nonperformance is somewhat mitigated at
December 31, 2008.




Off-Balance
Sheet Arrangements




At
December 31, 2008, the Company did not have any off-balance sheet
arrangements.




Contingencies




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




During
the years ended December 31, 2008, 2007 and 2006, 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.


48
 Table of Contents


Commitments
and Contractual Obligations




The
following summarizes, as of December 31, 2008, certain long-term
contractual obligations that are reflected in the consolidated balance sheet
and/or disclosed in the accompanying notes thereto:




Payments
      DueContractual
      Obligations
            
            Total
            
            2009
            
            2010
      – 2011
            
            2012
      – 2013
            
            2014
      and Beyond(in
      thousands)Long-term
      debt obligations:Credit
      facility
            
            $
            1,403,393
            
            
            $
            ―
            
            
            $
            1,403,393
            
            
            $
            ―
            
            
            $
            ―Senior
      notes
            
            
            255,927
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            255,927Interest
      (1)
            
            
            294,977
            
            
            
            59,937
            
            
            
            70,766
            
            
            
            50,546
            
            
            
            113,728Operating
      lease obligations:Office,
      property and equipment leases
            
            
            20,608
            
            
            
            3,538
            
            
            
            7,059
            
            
            
            6,011
            
            
            
            4,000Other
      noncurrent liabilities:Asset
      retirement obligations
            
            
            28,922
            
            
            
            ―
            
            
            
            112
            
            
            
            208
            
            
            
            28,602Other:Interest
      rate swaps
            
            
            82,422
            
            
            
            43,969
            
            
            
            38,453
            
            
            
            ―
            
            
            
            ―Commodity
      derivatives
            
            
            3,933
            
            
            
            ―
            
            
            
            615
            
            
            
            3,318
            
            
            
            ―Services
      agreement
            
            
            547
            
            
            
            212
            
            
            
            335
            
            
            
            ―
            
            
            
            ―Executive
      severance
            
            
            692
            
            
            
            507
            
            
            
            185
            
            
            
            ―
            
            
            
            ―$
            2,091,421
            
            
            $
            108,163
            
            
            $
            1,520,918
            
            
            $
            60,083
            
            
            $
            402,257




(1)
            Represents
      interest on the Company’s Credit Facility computed at the weighted average
      LIBOR rate of 2.47% through maturity in August 2010 and interest on Senior
      Notes computed at a fixed rate of 9.875% through maturity in July
      2018.




Capital
Structure




The
Company’s capitalization is presented below:




December 31,2008
            
            2007(in
      thousands)Cash
      and cash equivalents
            
            $
            28,668
            
            
            $
            1,441Credit
      facility
            
            $
            1,403,393
            
            
            $
            1,443,000Senior
      notes, net
            
            
            250,175
            
            
            
            ―Other
      noncurrent debt
            
            
            ―
            
            
            
            8301,653,568
            
            
            
            1,443,830Total
      unitholders’ capital
            
            
            2,760,686
            
            
            
            2,026,641Total
      capitalization
            
            $
            4,414,254
            
            
            $
            3,470,471


49
 Table of Contents


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 U.S. 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, gas and
NGL, future cash flows from oil and gas properties, depreciation, depletion and
amortization, asset retirement obligations, the fair value of derivatives and
unit-based compensation expense.  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 a discussion of additional accounting
policies and estimates made by Company management.




Oil
and Gas Reserves




The
Company’s estimates of proved reserves are based on the quantities of oil, gas
and NGL that engineering and geological analyses demonstrate, with reasonable
certainty, to be recoverable from established reservoirs in the future under
current operating and economic parameters.  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, 2008.




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 Company prepares its reserve estimates, and the
projected cash flows derived from these reserve estimates, in accordance with
SEC guidelines.  The independent engineering firm described above
adheres to the same guidelines when preparing their reserve
reports.  The accuracy of the 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.




The
Company’s proved 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, gas
and NGL eventually recovered.




Oil
and Gas Properties/Property and Equipment




Proved
Oil and Gas Properties


The
Company accounts for oil and gas properties under the successful efforts
method.  Under 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 gas properties on a
field-by-field basis whenever events or changes in circumstances indicate an
asset’s carrying amount may not be recoverable.  The carrying amount
of proved oil and gas properties are reduced to fair value when the expected
undiscounted future cash flows are less than the asset’s net book
value.  Cash flows are determined based upon reserves using prices,
costs and discount factors consistent with those used for internal decision
making.  The underlying commodity prices


50
 Table of Contents


embedded
in the Company’s estimated cash flows are the product of a process that begins
with the Henry Hub forward curve pricing, adjusted for estimated location and
quality differentials, as well as other factors that management believes will
impact realizable prices.  Although prices used are likely to
approximate market, they do not necessarily represent current market
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 for oil and gas properties 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 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 $0.9 million, $0.5 million and
$0.1 million for the years ended December 31, 2008, 2007 and 2006,
respectively.




Unproved
Oil and Gas Properties


Unproved
properties consist of costs incurred to acquire unproved leasehold as well as
costs incurred to acquire unproved resources.  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 has expired.  Unamortized leasehold costs related to
successful exploratory drilling are reclassified to proved properties and
depleted on a unit-of-production basis.  The carrying value of the
Company’s unproved resources, which were acquired in connection with business
acquisitions, was determined using the market-based weighted average cost of
capital rate, subjected to additional project-specific risking
factors.  Because these reserves do not meet the definition of proved
reserves, the related costs are not classified as proved
properties.  As the unproved resources are developed and proven, the
associated costs are reclassified to proved properties and depleted on a
unit-of-production basis.  The Company assesses unproved resources for
impairment annually on the basis of the experience of the Company in similar
situations and other information about such factors as the primary lease terms
of those 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.




Impairment


Based on
the analysis described above, the Company recorded non-cash impairment of oil
and gas 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 statement of
operations.  The Company recorded no impairment of oil and gas
properties in continuing operations for the years ended December 31, 2007
or 2006.




Exploration
Costs


Geological
and geophysical costs, delay rentals, amortization of unproved leasehold costs
and costs to drill exploratory wells that do not find proved reserves are
expensed as oil and gas 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.
 Other
Property and Equipment


Other
property and equipment includes 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 3 to 39 years for the individual asset or group of
assets.


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 Table of Contents


Goodwill




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 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.  See
Note 4 for additional details.




Goodwill
is not amortized to earnings but is tested annually during the fourth quarter or
whenever events or changes in circumstances indicate that the carrying value may
not be recoverable.  Goodwill is subject to annual reviews for
impairment based on a two-step accounting test.  The first step is to
compare the estimated fair value of reporting units that have recorded goodwill
with the recorded net book value (including the goodwill) of the reporting
unit.  If the estimated fair value of the reporting unit is higher
than the recorded net book value, no impairment is deemed to exist and no
further testing is required.  If, however, the estimated fair value of
the reporting unit is below the recorded net book value, then a second step must
be performed to determine the goodwill impairment required, if
any.  The second step utilizes the estimated fair value from the first
step as the purchase price in a hypothetical acquisition of the reporting
unit.




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 which had adverse
impacts on stock markets and oil and gas 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, the Company’s market
capitalization value was below the recorded net book value of its balance sheet,
including goodwill.  Because quoted market prices for the Company’s
reporting units are not available, management used judgment in determining the
estimated 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.




Based on
its analysis, the Company concluded that impairment of the entire amount of
recorded goodwill for the Mid-Continent Deep reporting unit was required as of
December 31, 2008.  A $20.3 million before and after tax non-cash
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 statement of operations.  This impairment is not expected
to result in current or future cash expenditures.




Revenue
Recognition




Sales of
oil, gas and NGL are recognized when oil, gas or NGL 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.  Virtually all of the Company’s contract
pricing provisions are tied to a market index, with certain adjustments based
on, among other factors, whether a well delivers to a gathering or transmission
line, quality of oil, gas and NGL, and prevailing supply and demand conditions,
so that prices fluctuate to remain competitive with other available
suppliers.


52
 Table of Contents


The
Company has elected the entitlements method to account for gas production
imbalances.  Gas imbalances occur when the Company sells more or less
than its entitled ownership percentage of total gas production.  Under
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, 2008 and 2007, the Company had gas production imbalance
receivables of approximately $17.1 million and $17.7 million, respectively,
which are included in “accounts receivable – trade, net” on the
consolidated balance sheet and gas production imbalance payables of
approximately $9.9 million and $11.5 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 gas
and subsequently markets such gas to independent purchasers under separate
arrangements.  As such, the Company separately reports third-party
marketing sales and gas marketing expenses.  Marketing margins related
to the Company’s production are included in oil, gas and NGL sales.




The
Company generates electricity with excess 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 statement of
operations.




Asset
Retirement Obligations




The
Company has the obligation to plug and abandon oil and 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 statement of operations.  Asset
retirement costs are estimated by the Company’s engineers using existing
regulatory requirements and anticipated future inflation
rates.  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 12).




Derivative
Instruments




The
Company uses derivative financial instruments to achieve a more predictable cash
flow from its oil, gas and NGL production by reducing its exposure to price
fluctuations.  These transactions are in the form of swap contracts,
collars and put options.  A put option requires the Company to pay the
counterparty a premium equal to the fair value of the option at the purchase
date and receive from the counterparty the excess, if any, of the fixed floor
over the floating market price.  Additionally, the Company uses
derivative financial instruments in the form of interest rate swaps to mitigate
its interest rate exposure.




The
Company accounts for these activities pursuant to SFAS 133.  This
statement establishes accounting and reporting standards requiring that
derivative instruments (including certain derivative instruments embedded in
other contracts) be recorded at fair value and included in the balance sheet as
assets or liabilities.  The Company accounts for its derivatives at
fair value as an asset or liability and the change in the fair value of the
derivatives is included in earnings since none of the Company’s commodity or
interest rate derivatives are designated as hedges under
SFAS 133.  The Company determines the fair value of its
derivative financial instruments in accordance with SFAS 157, which defines
fair value and establishes a framework for measuring fair value.  The
Company utilizes pricing models for significantly similar instruments to
determine fair value.  The models use a variety of techniques to
arrive at fair value, including quotes and pricing analysis.  Inputs
to the pricing models include publicly available prices and forward curves
generated from a compilation of data gathered from third parties.  See
Note 9 and Note 10 for additional details about the Company’s derivative
financial instruments.  See Item 7A. “Quantitative and
Qualitative Disclosures About Market Risk” for discussion regarding the
Company’s sensitivity analysis for the Company’s financial
instruments.




Purchase
Accounting




The
establishment of the asset base through the date of this report has included
numerous acquisitions of working interests in oil and gas
properties.  These acquisitions have been accounted for using the
purchase method of


53
 Table of Contents


accounting
as prescribed in SFAS No. 141, “Business
Combinations.”  See Note 3 for additional details about
acquisitions.




In
connection with a business combination, the acquiring company must allocate the
cost of the acquisition to assets acquired and liabilities assumed based on fair
values as of the acquisition date.  The purchase price allocations are
based on independent appraisals, discounted cash flows, quoted market prices and
estimates by management.  In addition, when appropriate, the Company
reviews comparable purchases and sales of oil and 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 purchase price over amounts assigned to
assets and liabilities is recorded as goodwill.  The amount of
goodwill recorded in any particular business combination can vary significantly
depending upon the value attributed to assets acquired and liabilities
assumed.




The
Company made various assumptions in estimating the fair values of assets
acquired and liabilities assumed.  The most significant assumptions
related to the estimated fair values assigned to proved and unproved oil and gas
properties.  To estimate the fair values of these properties, the
Company prepared estimates of oil and gas reserves.  The Company
estimated future prices to apply to the estimated reserve quantities acquired,
and estimated future operating and development costs, to arrive at estimates of
future net revenues.  For estimated proved reserves, the future net
revenues were discounted using a market-based weighted average cost of capital
rate determined appropriate at the time of the acquisition.  The
market-based weighted average cost of capital rate was 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 were reduced by additional
risk-weighting factors.




Deferred
taxes must be 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
estimates of fair value for the assets acquired and liabilities assumed have no
effect on cash flows, they can have an effect on the future results of
operations.  Generally, higher fair values assigned to oil and 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 gas properties, based on higher future
estimates of oil and gas 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 an
impairment has no effect on cash flows but results in a decrease in net income
for the period in which the impairment is recorded.




Unit-Based
Compensation




The
Company accounts for unit-based compensation pursuant to SFAS No. 123
(revised 2004), “Share-Based
Payment”(“SFAS 123R”).  SFAS 123R requires an entity
to recognize the grant-date fair-value of stock options and other equity-based
compensation issued to employees in the income statement and eliminates the
alternative to use the intrinsic value method of accounting that was provided
under the original provisions of SFAS 123, which resulted in no
compensation expense recorded in the financial statements related to the
issuance of equity awards to employees.  It establishes fair value as
the measurement objective in accounting for share-based payment arrangements and
requires companies to apply a fair-value-based measurement method in accounting
for share-based payment transactions with employees.  The Company also
follows the guidance in Staff Accounting Bulletin (“SAB”) No. 107,“Share-Based Payment,” which
contains the express views of the SEC staff regarding the interaction between
SFAS 123R and certain SEC rules and regulations and provides the staff’s
views regarding the valuation of share-based payment arrangements for public
companies.  See Note 7 for additional details about the Company’s
accounting for unit-based compensation.




New
Accounting Pronouncements




See
Note 19 for details regarding SFAS 157 implementation effective
January 1, 2008 and January 1, 2009, and also for details regarding
SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities – an Amendment of FASB
Statement 133” (“SFAS 161”) implementation effective
January 1, 2008.  54
 Table of Contents


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 oil, gas and NGL 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
speculative trading.




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 9 for additional details.  At December 31, 2008, the
fair value of contracts that settle during the next twelve months was an asset
of approximately $346.1 million and a liability of zero for a net asset of
approximately $346.1 million.  A 10% increase in the index oil and gas
prices above the December 31, 2008 prices for the next twelve months would
result in a net asset of approximately $273.7 million which represents a
decrease in the fair value of approximately $72.4 million; conversely, a 10%
decrease in the index oil and gas prices would result in a net asset of
approximately $419.2 million which represents an increase in the fair value of
approximately $73.1 million.




Interest
Rate Risk




At
December 31, 2008, the Company had long-term debt outstanding under its
Credit Facility of approximately $1.40 billion, which incurred interest at
floating rates.  See Note 8 for additional details.  At
December 31, 2008, the interest rate based on LIBOR was approximately
2.47%.  A 1% increase in LIBOR would result in an estimated $14.0
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 9 for additional
details.




Credit
Risk




The
Company accounts for its oil and gas commodity derivatives and interest rate
swaps at fair value on a recurring basis in accordance with the provisions of
SFAS 157 (see Note 10).  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, 2008, the average public bond yield spread utilized to
estimate the impact of the Company’s credit risk on derivative liabilities was
approximately 9.9%.  A 1% increase in the average public bond yield
spread would result in an estimated $1.9 million increase in net income for the
year ended December 31, 2008.  At December 31, 2008, the
credit default swap spreads utilized to estimate the impact of counterparties’
credit risk on derivative assets ranged between 0% and 2.6%.  A 1%
increase in each of the counterparties’ credit default swap spreads would result
in an estimated $13.1 million decrease in net income for the year ended
December 31, 2008.




55
 Table of Contents
 Item 8.        Financial
Statements and Supplementary Data


INDEX
TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA




PageManagement’s Report on Internal Control Over Financial
      Reporting
            57Report of Independent Registered Public Accounting Firm
      (Financial Statements)
            58Report of Independent Registered Public Accounting Firm
      (Internal Control Over Financial Reporting)
            59Consolidated Balance Sheets, as of December 31, 2008 and
      2007
            60Consolidated Statements of Operations, for the years ended
      December 31, 2008, 2007 and 2006
            61Consolidated
      Statements of Unitholders’ Capital (Deficit), for the years ended
      December 31, 2008, 2007and
      2006
            62Consolidated Statements of Cash Flows, for the years ended
      December 31, 2008, 2007 and 2006
            63Notes to Consolidated Financial
    Statements
            64Supplemental Oil and Gas Data
    (Unaudited)
            95Supplemental Quarterly Data (Unaudited)
            100


56
 Table of Contents


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, 2008, 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, 2008, 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, 2008, which is included
herein.






/s/ Linn
Energy, LLC


57
 Table of Contents


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, 2008 and 2007, and the related consolidated
statements of operations, unitholders’ capital (deficit), and cash flows for
each of the years in the three-year period ended December 31,
2008.  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, 2008 and 2007, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2008, 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, 2008, 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, 2009,
expressed an unqualified opinion on the effectiveness of the Company’s internal
control over financial reporting.






/s/ KPMG
LLP




Houston,
Texas


February 25,
2009


58
 Table of Contents


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, 2008, 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, 2008, 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, 2008 and 2007, and the related
consolidated statements of operations, unitholders’ capital (deficit) and cash
flows for each of the years in the three-year period ended December 31,
2008, and our report dated February 25, 2009, expressed an unqualified
opinion on those consolidated financial statements.






/s/ KPMG
LLP




Houston,
Texas


February 25,
2009


59
 Table of Contents


LINN ENERGY, LLC


CONSOLIDATED
BALANCE SHEETS




December 31,2008
            
            2007(in
      thousands,
              except
      unit amounts)AssetsCurrent
      assets:Cash
      and cash equivalents
            
            $
            28,668
            
            
            $
            1,441Accounts
      receivable – trade, net
            
            
            144,882
            
            
            
            149,850Derivative
      instruments
            
            
            368,951
            
            
            
            26,100Other
      current assets, net
            
            
            21,430
            
            
            
            5,768Total
      current assets
            
            
            563,931
            
            
            
            183,159Noncurrent
      assets:Oil
      and gas properties (successful efforts method)
            
            
            3,831,183
            
            
            
            3,506,559Less
      accumulated depletion and amortization
            
            
            (278,805
            )
            
            
            (120,498
            )3,552,378
            
            
            
            3,386,061Other
      property and equipment
            
            
            111,459
            
            
            
            149,589Less
      accumulated depreciation
            
            
            (13,171
            )
            
            
            (12,150
            )98,288
            
            
            
            137,439Derivative
      instruments
            
            
            493,705
            
            
            
            ―Goodwill
            
            
            ―
            
            
            
            64,419Other
      noncurrent assets, net
            
            
            13,718
            
            
            
            36,625507,423
            
            
            
            101,044Total
      assets
            
            $
            4,722,020
            
            
            $
            3,807,703Liabilities
      and Unitholders’ CapitalCurrent
      liabilities:Accounts
      payable and accrued expenses
            
            $
            163,662
            
            
            $
            222,149Derivative
      instruments
            
            
            47,005
            
            
            
            6,148Other
      accrued liabilities
            
            
            27,163
            
            
            
            14,430Total
      current liabilities
            
            
            237,830
            
            
            
            242,727Noncurrent
      liabilities:Credit
      facility
            
            
            1,403,393
            
            
            
            1,443,000Senior
      notes, net
            
            
            250,175
            
            
            
            ―Derivative
      instruments
            
            
            39,350
            
            
            
            63,813Other
      noncurrent liabilities
            
            
            30,586
            
            
            
            31,522Total
      noncurrent liabilities
            
            
            1,723,504
            
            
            
            1,538,335Unitholders’
      capital:114,079,533
      and 113,815,914 units issued and outstanding at December 31, 2008 and
      2007, respectively
            
            
            2,109,089
            
            
            
            2,374,660Accumulated
      income (deficit)
            
            
            651,597
            
            
            
            (348,019
            )2,760,686
            
            
            
            2,026,641Total
      liabilities and unitholders’ capital
            
            $
            4,722,020
            
            
            $
            3,807,703




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


60
 Table of Contents


LINN ENERGY, LLC


CONSOLIDATED
STATEMENTS OF OPERATIONS




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands, except per unit amounts)Revenues
      and other:Oil,
      gas and natural gas liquid sales
            
            $
            755,644
            
            
            $
            255,927
            
            
            $
            21,372Gain
      (loss) on oil and gas derivatives
            
            
            662,782
            
            
            
            (345,537
            )
            
            
            103,308Gas
      marketing revenues
            
            
            12,846
            
            
            
            11,589
            
            
            
            ―Other
      revenues
            
            
            3,759
            
            
            
            2,738
            
            
            
            8461,435,031
            
            
            
            (75,283
            )
            
            
            125,526Expenses:Lease
      operating expenses
            
            
            115,402
            
            
            
            41,946
            
            
            
            6,603Transportation
      expenses
            
            
            17,597
            
            
            
            5,575
            
            
            
            40Gas
      marketing expenses
            
            
            11,070
            
            
            
            9,100
            
            
            
            ―General
      and administrative expenses
            
            
            77,391
            
            
            
            51,374
            
            
            
            37,997Exploration
      costs
            
            
            7,603
            
            
            
            4,053
            
            
            
            286Bad
      debt expenses
            
            
            1,436
            
            
            
            ―
            
            
            
            12Depreciation,
      depletion and amortization
            
            
            194,093
            
            
            
            69,081
            
            
            
            4,352Impairment
      of goodwill and long-lived assets
            
            
            50,505
            
            
            
            ―
            
            
            
            ―Taxes,
      other than income taxes
            
            
            61,435
            
            
            
            22,350
            
            
            
            243(Gain)
      loss on sale of assets, net
            
            
            (98,763
            )
            
            
            1,767
            
            
            
            28437,769
            
            
            
            205,246
            
            
            
            49,561Other
      income and (expenses):Interest
      expense, net of amounts capitalized
            
            
            (94,517
            )
            
            
            (38,974
            )
            
            
            (5,909
            )Gain
      (loss) on interest rate swaps
            
            
            (66,674
            )
            
            
            (28,081
            )
            
            
            363Other,
      net
            
            
            (7,702
            )
            
            
            (3,822
            )
            
            
            (2,581
            )(168,893
            )
            
            
            (70,877
            )
            
            
            (8,127
            )Income
      (loss) from continuing operations before income taxes
            
            
            828,369
            
            
            
            (351,406
            )
            
            
            67,838Income
      tax benefit (expense)
            
            
            (2,712
            )
            
            
            (4,788
            )
            
            
            1,973Income
      (loss) from continuing operations
            
            
            825,657
            
            
            
            (356,194
            )
            
            
            69,811Discontinued
      operations:Gain
      (loss) on sale of assets, net of taxes
            
            
            159,045
            
            
            
            936
            
            
            
            (45
            )Income
      (loss) from discontinued operations, net of taxes
            
            
            14,914
            
            
            
            (9,091
            )
            
            
            9,419173,959
            
            
            
            (8,155
            )
            
            
            9,374Net
      income (loss)
            
            $
            999,616
            
            
            $
            (364,349
            )
            
            $
            79,185Income
      (loss) per unit – continuing operations:Units
      – basic
            
            $
            7.23
            
            
            $
            (5.17
            )
            
            $
            2.33Units
      – diluted
            
            $
            7.23
            
            
            $
            (5.17
            )
            
            $
            2.30Income
      (loss) per unit – discontinued operations:Units
      – basic
            
            $
            1.53
            
            
            $
            (0.12
            )
            
            $
            0.31Units
      – diluted
            
            $
            1.52
            
            
            $
            (0.12
            )
            
            $
            0.31Net
      income (loss) per unit:Units
      – basic
            
            $
            8.76
            
            
            $
            (5.29
            )
            
            $
            2.64Units
      – diluted
            
            $
            8.75
            
            
            $
            (5.29
            )
            
            $
            2.61Weighted
      average units outstanding:Units
      – basic
            
            
            114,140
            
            
            
            68,916
            
            
            
            28,281Units
      – diluted
            
            
            114,256
            
            
            
            68,916
            
            
            
            30,385Class
      B – basic
            
            
            ―
            
            
            
            ―
            
            
            
            1,737Class
      B – diluted
            
            
            ―
            
            
            
            ―
            
            
            
            1,737Distributions
      declared per unit
            
            $
            2.52
            
            
            $
            2.18
            
            
            $
            1.15




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


61
 Table of Contents


LINN ENERGY, LLC


CONSOLIDATED
STATEMENTS OF UNITHOLDERS’ CAPITAL (DEFICIT)




Units
            
            Unitholders’
                Capital
            
            Accumulated
                Income
      (Deficit)
            
            Treasury
                Units
                (at
      Cost)
            
            Total
      Unitholders’
                Capital
      (Deficit)(in
      thousands)December
      31, 2005
            
            
            20,518
            
            
            $
            16,024
            
            
            $
            (62,855
            )
            
            $
            ―
            
            
            $
            (46,831
            )Sale
      of initial public offering units, net of underwriting discounts of $18,302
      and expense of $4,339
            
            
            12,450
            
            
            
            225,139
            
            
            
            ―
            
            
            
            13,671
            
            
            
            238,810Sale
      of private placement units, net of expense of $348
            
            
            14,721
            
            
            
            304,652
            
            
            
            ―
            
            
            
            ―
            
            
            
            304,652Issuance
      of units
            
            
            613
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―Cancellation
      of units
            
            
            (5,499
            )
            
            
            (100,778
            )
            
            
            ―
            
            
            
            100,778
            
            
            
            ―Purchase
      of units
            
            
            
            
            
            
            ―
            
            
            
            ―
            
            
            
            (114,449
            )
            
            
            (114,449
            )Distributions
      to unitholders
            
            
            
            
            
            
            (32,056
            )
            
            
            ―
            
            
            
            ―
            
            
            
            (32,056
            )Unit-based
      compensation expenses
            
            
            
            
            
            
            21,643
            
            
            
            ―
            
            
            
            ―
            
            
            
            21,643Net
      income
            
            
            
            
            
            
            ―
            
            
            
            79,185
            
            
            
            ―
            
            
            
            79,185December
      31, 2006
            
            
            42,803
            
            
            
            434,624
            
            
            
            16,330
            
            
            
            ―
            
            
            
            450,954Sale
      of private placement units, net of expense of $34,334
            
            
            69,874
            
            
            
            2,085,666
            
            
            
            ―
            
            
            
            ―
            
            
            
            2,085,666Issuance
      of units
            
            
            1,366
            
            
            
            2,811
            
            
            
            ―
            
            
            
            ―
            
            
            
            2,811Cancellation
      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
            
            
            
            ―
            
            
            
            ―
            
            
            
            13,921Net
      loss
            
            
            
            
            
            
            ―
            
            
            
            (364,349
            )
            
            
            ―
            
            
            
            (364,349
            )December
      31, 2007
            
            
            113,816
            
            
            
            2,374,660
            
            
            
            (348,019
            )
            
            
            ―
            
            
            
            2,026,641Issuance
      of units
            
            
            1,435
            
            
            
            23,483
            
            
            
            ―
            
            
            
            ―
            
            
            
            23,483Cancellation
      of units
            
            
            (1,171
            )
            
            
            (14,998
            )
            
            
            ―
            
            
            
            14,998
            
            
            
            ―Purchase
      of units
            
            
            
            
            
            
            ―
            
            
            
            ―
            
            
            
            (14,998
            )
            
            
            (14,998
            )Distributions
      to unitholders
            
            
            
            
            
            
            (289,915
            )
            
            
            ―
            
            
            
            ―
            
            
            
            (289,915
            )Reclassification
      of distributions paid on forfeited restricted units
            
            
            
            
            
            
            182
            
            
            
            ―
            
            
            
            ―
            
            
            
            182Unit-based
      compensation expenses
            
            
            
            
            
            
            15,677
            
            
            
            ―
            
            
            
            ―
            
            
            
            15,677Net
      income
            
            
            
            
            
            
            ―
            
            
            
            999,616
            
            
            
            ―
            
            
            
            999,616December 31,
      2008
            
            
            114,080
            
            
            $
            2,109,089
            
            
            $
            651,597
            
            
            $
            ―
            
            
            $
            2,760,686




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


62
 Table of Contents


LINN ENERGY, LLC


CONSOLIDATED
STATEMENTS OF CASH FLOWS




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands)Cash
      flow from operating activities:Net
      income (loss)
            
            $
            999,616
            
            
            $
            (364,349
            )
            
            $
            79,185Adjustments
      to reconcile net income (loss) to net cash provided by (used in) operating
      activities:Depreciation,
      depletion and amortization
            
            
            200,306
            
            
            
            94,200
            
            
            
            22,304Impairment
      of goodwill and long-lived assets
            
            
            50,505
            
            
            
            3,343
            
            
            
            1,000Unit-based
      compensation and unit warrant expenses
            
            
            15,677
            
            
            
            13,921
            
            
            
            21,643Bad
      debt expenses
            
            
            1,436
            
            
            
            ―
            
            
            
            12Amortization
      and write-off of deferred financing fees and other
            
            
            17,024
            
            
            
            5,746
            
            
            
            5,658(Gain)
      loss on sale of assets, net
            
            
            (257,808
            )
            
            
            831
            
            
            
            73Deferred
      income tax
            
            
            ―
            
            
            
            3,360
            
            
            
            (3,434
            )Mark-to-market
      on derivatives:Total
      (gains) losses
            
            
            (596,108
            )
            
            
            373,618
            
            
            
            (103,671
            )Cash
      settlements
            
            
            (20,901
            )
            
            
            40,784
            
            
            
            20,442Cash
      settlements on canceled derivatives
            
            
            (81,358
            )
            
            
            ―
            
            
            
            ―Premiums
      paid for derivatives
            
            
            (129,520
            )
            
            
            (279,313
            )
            
            
            (49,807
            )Changes
      in assets and liabilities:(Increase)
      decrease in accounts receivable – trade, net
            
            
            3,673
            
            
            
            (117,361
            )
            
            
            (383
            )(Increase)
      decrease in other assets
            
            
            (2,556
            )
            
            
            3,286
            
            
            
            2,833Increase
      (decrease) in accounts payable and accrued expenses
            
            
            (36,451
            )
            
            
            161,844
            
            
            
            (6,782
            )Increase
      in other liabilities
            
            
            15,980
            
            
            
            15,276
            
            
            
            4,122Net
      cash provided by (used in) operating activities
            
            
            179,515
            
            
            
            (44,814
            )
            
            
            (6,805
            )Cash
      flow from investing activities:Acquisition
      of oil and gas properties
            
            
            (593,412
            )
            
            
            (2,649,965
            )
            
            
            (467,137
            )Development
      of oil and gas properties
            
            
            (330,615
            )
            
            
            (185,534
            )
            
            
            (46,963
            )Deposit
      for oil and gas properties
            
            
            ―
            
            
            
            (27,610
            )
            
            
            (20,086
            )Purchases
      of other property and equipment
            
            
            (9,109
            )
            
            
            (33,849
            )
            
            
            (17,551
            )Proceeds
      from sales of oil and gas properties and other property and
      equipment
            
            
            897,586
            
            
            
            4,538
            
            
            
            106Net
      cash used in investing activities
            
            
            (35,550
            )
            
            
            (2,892,420
            )
            
            
            (551,631
            )Cash
      flow from financing activities:Proceeds
      from sale and issuance of units
            
            
            ―
            
            
            
            2,120,000
            
            
            
            548,149Purchase
      of units
            
            
            (14,998
            )
            
            
            (7,399
            )
            
            
            (114,449
            )Proceeds
      from issuance of debt
            
            
            1,459,000
            
            
            
            1,298,000
            
            
            
            584,000Principal
      payments on debt
            
            
            (1,250,172
            )
            
            
            (283,108
            )
            
            
            (425,743
            )Distributions
      to unitholders
            
            
            (289,915
            )
            
            
            (154,963
            )
            
            
            (32,056
            )Offering
      costs
            
            
            ―
            
            
            
            (34,334
            )
            
            
            (1,210
            )Financing
      fees and other, net
            
            
            (20,653
            )
            
            
            (6,116
            )
            
            
            (4,701
            )Net
      cash provided by (used in) financing activities
            
            
            (116,738
            )
            
            
            2,932,080
            
            
            
            553,990Net
      increase (decrease) in cash and cash equivalents
            
            
            27,227
            
            
            
            (5,154
            )
            
            
            (4,446
            )Cash
      and cash equivalents:Beginning
            
            
            1,441
            
            
            
            6,595
            
            
            
            11,041Ending
            
            $
            28,668
            
            
            $
            1,441
            
            
            $
            6,595




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


63
 Table of Contents
 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 gas
company focused on the development and acquisition of long life properties which
complement its asset profile in producing basins within the United
States.  Linn Energy began operations in March 2003 and 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.”




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 (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 U.S. generally
accepted accounting principles (“GAAP”).  The consolidated financial
statements include the accounts of the Company and its wholly owned
subsidiaries.  All significant intercompany transactions and balances
have been eliminated upon consolidation.




(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
statement of operations for all periods presented.  Unless otherwise
indicated, information about the statement of operations that is presented in
the notes to consolidated financial statements relates only to Linn Energy’s
continuing operations.




(d)          Presentation
Change


Certain
amounts in the consolidated financial statements and notes thereto have been
reclassified to conform to the 2008 financial statement
presentation.  In particular, the consolidated statement of operations
includes categories of expense titled “lease operating expenses,”
“transportation expenses,” “exploration costs,” “bad debt expenses,” “impairment
of goodwill and long-lived assets,” “taxes, other than income taxes” and “(gain)
loss on sale of assets, net” which were not reported in prior period
presentations.  The new categories present expenses in greater detail
than was previously reported and all comparative periods presented have been
reclassified to conform to the 2008 financial statement
presentation.  There was no impact to net income (loss) for prior
periods.




(e)          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, gas and
natural gas liquids (“NGL”), future cash flows from oil and gas properties,
depreciation, depletion and amortization, asset retirement obligations, the fair
value of derivatives and unit-based compensation expense.  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,


64
 Table of Contents


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.




(f)           Cash
Equivalents


For
purposes of the statement of cash flows, the Company considers all highly liquid
short-term investments with original maturities of three months or less to be
cash equivalents.  The Company manages its working capital and cash
requirements to borrow only as needed from its credit facility.  At
December 31, 2007, the Company had approximately $5.2 million of
outstanding checks, the balance of which is included in “accounts payable and
accrued expenses” on the consolidated balance sheet.




(g)          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 $1.5
million and $100,000 at December 31, 2008 and 2007,
respectively.




(h)          Inventories


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




(i)           Oil
and Gas Properties/Property and Equipment


Proved
Oil and Gas Properties


The
Company accounts for oil and gas properties under the successful efforts
method.  Under 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 gas properties on a
field-by-field basis whenever events or changes in circumstances indicate an
asset’s carrying amount may not be recoverable.  The carrying amount
of proved oil and gas properties are reduced to fair value when the expected
undiscounted future cash flows are less than the asset’s net book
value.  Cash flows are determined based upon reserves using prices,
costs and discount factors consistent with those used for internal decision
making.  The underlying commodity prices embedded in the Company’s
estimated cash flows are the product of a process that begins with the Henry Hub
forward curve pricing, adjusted for estimated location and quality
differentials, as well as other factors that 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 for oil and gas properties are capitalized 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
 65
 Table of Contents


and 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 $0.9 million, $0.5 million and
$0.1 million for the years ended December 31, 2008, 2007 and 2006,
respectively.


Unproved
Oil and Gas Properties


Unproved
properties consist of costs incurred to acquire unproved leasehold as well as
costs incurred to acquire unproved resources.  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 has expired.  Unamortized leasehold costs related to
successful exploratory drilling are reclassified to proved properties and
depleted on a unit-of-production basis.  The carrying value of the
Company’s unproved resources, which were acquired in connection with business
acquisitions, was determined using the market-based weighted average cost of
capital rate, subjected to additional project-specific risking
factors.  Because these reserves do not meet the definition of proved
reserves, the related costs are not classified as proved
properties.  As the unproved resources are developed and proven, the
associated costs are reclassified to proved properties and depleted on a
unit-of-production basis.  The Company assesses unproved resources for
impairment annually on the basis of the experience of the Company in similar
situations and other information about such factors as the primary lease terms
of those 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.


Impairment


Based on
the analysis described above, the Company recorded non-cash impairment of oil
and gas 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 statement of
operations.  The Company recorded no impairment of oil and gas
properties in continuing operations for the years ended December 31, 2007
or 2006.




Exploration
Costs


Geological
and geophysical costs, delay rentals, amortization of unproved leasehold costs
and costs to drill exploratory wells that do not find proved reserves are
expensed as oil and gas 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.


Other
Property and Equipment


Other
property and equipment includes gas gathering systems, pipelines, buildings,
software, data processing and telecommunication 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 3 to 39 years for the individual asset or group of
assets.


(j)           Goodwill


Goodwill
represents the excess of the cost of an acquired business over the net amounts
assigned to assets acquired and liabilities assumed.  The Company
accounts for goodwill in accordance with Statement of Financial Accounting
Standards (“SFAS”) No. 142, “Goodwill and Other Intangible
Assets.”  The Company recorded goodwill in conjunction with its
August 2007 acquisition in the Mid-Continent Deep region, all of which was
allocated to the 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.  See Note 4 for
additional details.


66
 Table of Contents


Goodwill
is not amortized to earnings but is tested annually during the fourth quarter or
whenever events or changes in circumstances indicate that the carrying value may
not be recoverable.  Goodwill is subject to annual reviews for
impairment based on a two-step accounting test.  The first step is to
compare the estimated fair value of reporting units that have recorded goodwill
with the recorded net book value (including the goodwill) of the reporting
unit.  If the estimated fair value of the reporting unit is higher
than the recorded net book value, no impairment is deemed to exist and no
further testing is required.  If, however, the estimated fair value of
the reporting unit is below the recorded net book value, then a second step must
be performed to determine the goodwill impairment required, if
any.  The second step utilizes the estimated fair value from the first
step as the purchase price in a hypothetical acquisition of the reporting
unit.




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 which had adverse
impacts on stock markets and oil and gas 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, the Company’s market
capitalization value was below the recorded net book value of its balance sheet,
including goodwill.  Because quoted market prices for the Company’s
reporting units are not available, management used judgment in determining the
estimated 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.




Based on
its analysis, the Company concluded that impairment of the entire amount of
recorded goodwill for the Mid-Continent Deep reporting unit was required as of
December 31, 2008.  A $20.3 million before and after tax non-cash
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 statement of operations.




(k)          Revenue
Recognition


Sales of
oil and gas and NGL are recognized when oil, gas or NGL 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.  Virtually all of the Company’s contract
pricing provisions are tied to a market index, with certain adjustments based
on, among other factors, whether a well delivers to a gathering or transmission
line, quality of oil, gas and NGL, and prevailing supply and demand conditions,
so that prices fluctuate to remain competitive with other available
suppliers.




Revenues
are presented on a gross basis on the consolidated statement of
operations.  Production taxes are included in “taxes, other than
income taxes” on the consolidated statements of operations and were
approximately $47.2 million, $14.8 million and zero for the years ended
December 31, 2008, 2007 and 2006, respectively.


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The
Company has elected the entitlements method to account for gas production
imbalances.  Gas imbalances occur when the Company sells more or less
than its entitled ownership percentage of total gas production.  Under
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, 2008 and 2007, the Company had gas production imbalance
receivables of approximately $17.1 million and $17.7 million, respectively,
which are included in “accounts receivable – trade, net” on the
consolidated balance sheet and gas production imbalance payables of
approximately $9.9 million and $11.5 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 gas
and subsequently markets such gas to independent purchasers under separate
arrangements.  As such, the Company separately reports third-party
marketing sales and gas marketing expenses.




(l)           Restricted
Cash


Restricted
cash of $1.3 million and $0.5 million is included in “other noncurrent assets,
net” on the consolidated balance sheets at December 31, 2008 and 2007,
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 achieve a more predictable cash
flow from its oil, gas and NGL production by reducing its exposure to price
fluctuations.  These transactions are in the form of swap contracts,
collars and put options.  Additionally, the Company uses derivative
financial instruments in the form of interest rate swaps to mitigate its
interest rate exposure.




The
Company accounts for these activities pursuant to SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended,
(“SFAS 133”).  This statement establishes accounting and
reporting standards requiring that derivative instruments (including certain
derivative instruments embedded in other contracts) be recorded at fair value
and included in the balance sheet as assets or liabilities.  The
Company accounts for its derivatives at fair value as an asset or liability and
the change in the fair value of the derivatives is included in earnings since
none of the Company’s commodity or interest rate derivatives are designated as
hedges under the provisions of SFAS 133.  The Company determines
the fair value of its derivative financial instruments in accordance with SFAS
No. 157, “Fair Value
Measurements” (“SFAS 157”), which defines fair value and establishes
a framework for measuring fair value.  The Company utilizes pricing
models for significantly similar instruments to determine fair
value.  The models use a variety of techniques to arrive at fair
value, including quotes and pricing analysis.  See Note 9 and
Note 10 for additional details about the Company’s derivative financial
instruments.




(n)          Unit-Based
Compensation


SFAS
No. 123 (revised 2004),“Share-Based Payment” (“SFAS 123R”) requires the recognition of
compensation expense, over the requisite service period, in an amount equal to
the fair value of unit-based payments granted to employees and non-employee
directors.  The fair value of the unit-based payments, excluding
liability awards, is computed at the date of grant and will not be
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.  SFAS 123R also requires the benefits of tax deductions
in excess of recognized compensation costs to be reported as financing cash
flow, rather than as an operating cash flow as required under prior
guidance.  This requirement will reduce net operating cash flows and
increase net financing cash flows in periods in which such tax deduction
exists.  The Company had no excess tax deductions for any periods
presented.


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The
Company has made a policy decision, in accordance with the provisions of
SFAS 123R, to recognize compensation cost for service-based awards on a
straight-line basis over the requisite service period.  The Company
did not issue any unit-based compensation awards prior to January
2006.  See Note 7 for a discussion of the Company’s accounting
for unit-based compensation expense.




(o)          Deferred
Financing Fees


The
Company incurred legal and bank fees related to the issuance of debt (see
Note 8).  At December 31, 2008 and 2007, net deferred
financing fees of approximately $11.9 million and $8.3 million, respectively,
are included in “other noncurrent assets, net” on the consolidated balance
sheets.  These debt issuance costs are amortized over the life of the
debt agreement.  For the years ended December 31, 2008, 2007 and
2006, amortization expense of $5.2 million, $1.5 million and $1.1 million,
respectively, is included in “interest expense, net of amounts capitalized” on
the consolidated statements of operations.  Deferred financing fees of
approximately $6.7 million, $2.8 million and $3.3 million were written-off in
connection with refinancings and debt extinguishments during the years ended
December 31, 2008, 2007 and 2006, respectively, and are included in “other,
net” on the consolidated statements of operations.




(p)          Fair
Value of Financial Instruments


The
carrying values of the Company’s receivables, payables and credit facility are
estimated to be substantially the same as their fair values at December 31,
2008 and 2007.  See Note 10 for fair value disclosures related to
the Company’s senior notes.  As noted above, the Company determines
the fair value of its derivative financial instruments in accordance
SFAS 157.  See Note 10 for details about the fair value of the
Company’s derivative financial instruments.




(q)          Income
Taxes


The
Company is a limited liability company and 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 being passed through to
the unitholders.  As such, 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 corporate income taxes, which are accounted for under the provisions
of SFAS No. 109 “Accounting for Income Taxes”
(“SFAS 109”), which uses 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 16 for detail of amounts recorded in
consolidated financial statements.




(2)
            Discontinued
      Operations and Dispositions




On
July 1, 2008, the Company completed the sale of its interests in oil and
gas properties located in the Appalachian Basin to XTO Energy, Inc. (“XTO”) for
a contract price of $600.0 million.  Net proceeds were $566.5 million
and the carrying value of net assets sold was $405.8 million, resulting in a
gain on the sale of $160.7 million, which is recorded in “discontinued
operations: gain (loss) on sale of assets, net of taxes” on the consolidated
statement of operations.  The Company used the net proceeds from the
sale to repay loans outstanding under its term loan agreement and reduce
indebtedness under its credit facility (see Note 8).




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.  At December 31, 2008, substantially all of
the


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property
and equipment previously held by Mid Atlantic totaling $9.2 million had been
sold.  During the year ended December 31, 2008, the Company
recorded a loss on the sale of the Mid Atlantic assets of $1.6 million, which is
recorded in “discontinued operations: gain (loss) on sale of assets, net of
taxes” on the consolidated statement of operations.




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 31,2008
            
            2007
            
            2006(in
      thousands)Total
      revenues and other
            
            $
            50,601
            
            
            $
            67,110
            
            
            $
            65,532Total
      operating expenses
            
            
            (23,677
            )
            
            
            (54,260
            )
            
            
            (37,594
            )Interest
      expense
            
            
            (13,401
            )
            
            
            (23,156
            )
            
            
            (19,948
            )Income
      (loss) from discontinued operations
            
            
            13,523
            
            
            
            (10,306
            )
            
            
            7,990Income
      tax benefit
            
            
            1,391
            
            
            
            1,215
            
            
            
            1,429Income
      (loss) from discontinued operations, net of taxes
            
            $
            14,914
            
            
            $
            (9,091
            )
            
            $
            9,419




The
Company computed interest expense related to discontinued operations in
accordance with Emerging Issues Task Force Issue No. 87-24, “Allocation of Interest to
Discontinued Operations” based on debt required to be repaid as a result
of the disposal transaction.




On
August 15, 2008, the Company completed the sale of certain properties in
the Verden area in Oklahoma to Laredo Petroleum, Inc. (“Laredo”) for a contract
price of $185.0 million, subject to closing adjustments.  Net proceeds
and the carrying value of net assets sold were $169.4 million.  The
Verden assets were acquired by the Company with its acquisition of oil and gas
properties from Dominion Resources, Inc. (“Dominion”) in August
2007.  The Company used the net proceeds from the sale to reduce
indebtedness (see Note 8).




In
addition, on December 4, 2008, the Company completed the sale of its deep
rights in certain central Oklahoma acreage, which includes the Woodford Shale
interval, to Devon Energy Production Company, LP (“Devon”) for a contract price
of $202.3 million, subject to closing adjustments.  The sale
included no producing reserves.  Linn Energy retains the rights to the
shallow portion of this acreage.  Net proceeds were $153.2 million and
the carrying value of net assets sold was $54.2 million, resulting in a gain on
the sale of $99.0 million, which is recorded in “(gain) loss on sale of assets,
net” on the consolidated statement of operations.  In January 2009,
certain post closing matters were resolved and the Company received additional
proceeds of $11.5 million, which will be reported as a gain in the first quarter
of 2009.  Pending resolution of title issues, the Company estimates it
may receive additional proceeds ranging from $12.0 million to $18.0 million
during the first quarter of 2009.  These assets were acquired by the
Company with its acquisition of oil and gas properties from Dominion in August
2007.  The Company used the net proceeds from the sale to reduce
indebtedness (see Note 8).




(3)
            Acquisitions




The
Company accounts for its acquisitions using the purchase method of accounting as
prescribed in SFAS No. 141, “Business
Combinations.”  On January 31, 2008, the Company completed
the acquisition of certain oil and gas properties located primarily in the
Mid-Continent Shallow region from Lamamco Drilling Company (“Lamamco”) for a
contract price of $552.2 million, subject to closing adjustments.  The
acquisition was financed with a combination of borrowings under the Company’s
credit facility and proceeds from a term loan entered into at closing (see
Note 8).


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The
following presents the purchase accounting for the acquisition, based on
estimates of fair value (in thousands):




Cash
            
            $
            537,253Estimated
      transaction costs
            
            
            966538,219Fair
      value of liabilities assumed
            
            
            4,029Total
      purchase price
            
            $
            542,248




The
following presents the allocation of the purchase price for the acquisition,
based on estimates of fair value (in thousands):




Current
      assets
            
            $
            1,811Oil
      and gas properties
            
            
            538,328Other
      property and equipment
            
            
            2,109$
            542,248




The
purchase price and purchase price allocation above are based on reserve reports,
published market prices and estimates by management.  The most
significant assumptions are related to the estimated fair values assigned to
proved oil and gas properties.  To estimate the fair values of these
properties, the Company utilized estimates of oil and gas
reserves.  The Company estimated future prices to apply to the
estimated reserve quantities acquired, and estimated future operating and
development costs to arrive at estimates of future net revenues.  The
Company also reviewed comparable purchases and sales of oil and gas properties
within the same regions.




The
following unaudited pro forma financial information presents a summary of Linn
Energy’s consolidated results of continuing operations for the years ended
December 31, 2008 and 2007, assuming the acquisition of assets from Lamamco
had been completed as of January 1, 2007, including adjustments to reflect
the allocation of the purchase price to the acquired net assets.  The
pro forma financial information also assumes that the following 2007
acquisitions were completed as of January 1, 2007:




·
            February 1,
      2007, acquisition of certain oil and gas properties and related assets in
      the Mid-Continent Shallow region, in the Texas Panhandle, from Stallion
      Energy LLC, acting as general partner for Cavallo Energy, LP, for a
      contract price of $415.0 million




·
            June 12,
      2007, acquisition of certain oil and gas properties in the Mid-Continent
      Shallow region, in the Texas Panhandle, for a contract price of $90.5
      million




·
            August 31,
      2007, acquisition of certain oil and gas properties in the Mid-Continent
      Deep region, in Oklahoma, Kansas and the Texas Panhandle from Dominion for
      a contract price of
$2.05 billion




The
revenues and expenses of the above assets are included in the consolidated
results of the Company as of February 1, 2007, June 12, 2007 and
September 1, 2007.  The revenues and expenses of the assets
acquired from Lamamco are included in the consolidated results of the Company
effective February 1,


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2008.  The
pro forma financial information is not necessarily indicative of the results of
operations if the acquisitions had been effective as of January 1,
2007.  All amounts reflect continuing operations.




Year
      Ended
                December 31,2008
              
              2007(in
      thousands, except per unit amounts)Total
      revenues and other
              
              $
              1,444,304
              
              
              $
              236,641Total
      operating expenses
              
              $
              442,406
              
              
              $
              376,941Income
      (loss) from continuing operations
              
              $
              826,663
              
              
              $
              (290,641
              )Income
      (loss) from continuing operations per unit:Units
      – basic
              
              $
              7.24
              
              
              $
              (4.21
              )Units
      – diluted
              
              $
              7.24
              
              
              $
              (4.21
              )




(4)
            Goodwill




Goodwill
was recorded in conjunction with the Company’s acquisition of assets from
Dominion in August 2007 (see Note 3).




The
following reflects the changes in the carrying amount of goodwill during the
years ended December 31, 2008 and 2007 (in thousands):




Balance,
      December 31, 2006
            
            $
            —Acquisition
      of assets from Dominion
            
            
            64,419Balance,
      December 31, 2007
            
            
            64,419Purchase
      accounting adjustments:Post
      closing statement and other
            
            
            25,424Verden
      assets (1)
            
            
            (18,231
            )Woodford
      Shale assets (1)
            
            
            (51,319
            )Impairment
      (2)
            
            
            (20,293
            )Balance,
      December 31, 2008
            
            $
            —




(1)
            Represents
      update to preliminary purchase accounting in which amounts were allocated
      to unproved oil and gas properties and subsequently sold (see
      Note 2).




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




(5)
            Unitholders’
      Capital




Unit
Repurchase Plan




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


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Issuance
and Cancellation of Units




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 year
ended December 31, 2008, the Company issued 600,000 units in connection
with the acquisition of certain 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 withholding
taxes due on units issued under its equity compensation plan (see
Note 7).  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 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 withholding
taxes due on units issued under its equity compensation plan (see
Note 7).  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 August 2007 acquisition of certain oil and gas properties in the
Mid-Continent Deep region (see Note 3).  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 repay 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 finance the acquisition of certain oil and
gas properties.  The Class C units were converted into units on a
one-for-one basis in April 2007.




In
October 2006, the Company closed its private placement of $305.0 million of
units to a group of institutional investors, consisting of 9,185,965 Class B
units at a price of $20.55 per unit, and 5,534,687 units at a price of $21.00
per unit.  Proceeds, net of expenses were $304.7 million and were used
to repay indebtedness.  The Class B units were converted into
units on a one-for-one basis in January 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 statement of operations for the
year ended December 31, 2007.




Initial
Public Offering




During
the year ended December 31, 2006, the Company completed its IPO of
12,450,000 units representing limited liability interest in the Company at
$21.00 per unit, for net proceeds, after underwriting discounts of $18.3 million
and offering expenses of $4.3 million, of $238.8 million, of which $122.0
million was used to reduce indebtedness and $114.4 million was used to redeem a
portion of membership interests in the Company and units held by certain holders
and approximately $2.0 million was used to pay bonuses to certain executive
officers of the Company.


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Distributions




Under the
limited liability company agreement, Company unitholders are entitled to receive
a quarterly distribution of available cash to the extent there is sufficient
cash from operations after establishment of cash reserves and payment of fees
and expenses.  Distributions paid by the Company are presented on the
consolidated statements of unitholders’ capital (deficit).  In January
2009, the Company’s Board of Directors declared a cash distribution of $0.63 per
unit with respect to the fourth quarter of 2008.  The distribution
totaled approximately $72.5 million and was paid on February 13, 2009 to
unitholders of record as of the close of business on February 6,
2009.




(6)
            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 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 gas purchasers and the Company generally does not require collateral, since
it has not experienced 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, 2008, the Company’s three largest customers
represented 21%, 18% and 10% of the Company’s sales.  For the year
ended December 31, 2007, the Company’s two largest customers represented
27% and 22% of the Company’s sales.  The Company’s largest customer
represented approximately 81% of the Company’s sales for the year ended
December 31, 2006.




At
December 31, 2008, two customers’ trade accounts receivable from oil, gas
and NGL sales accounted for more than 10% of the Company’s total trade accounts
receivable.  At December 31, 2008, trade accounts receivable from
the Company’s two largest customers represented approximately 20% and 16% of the
Company’s receivables.  At December 31, 2007, three customers’
trade accounts receivable from oil, gas and NGL sales accounted for more than
10% of the Company’s total trade accounts receivable.  At
December 31, 2007, trade accounts receivable from the Company’s three
largest customers represented approximately 22%, 13% and 12% of the Company’s
receivables.




(7)
            Unit-Based
      Compensation and Other Benefit
Plans




Incentive
Plan Summary




The
Amended and Restated Linn Energy, LLC Long-Term Incentive Plan (the “Plan”)
originally became effective in December 2005.  The Plan, which is
administered by the Compensation Committee of the Board of Directors, permits
the granting of unit grants, unit options, restricted units, phantom units and
unit appreciation rights to employees, consultants and non-employee 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 ten 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
of the Board of Directors 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


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 Table of Contents


be
granted, subject to unitholder approval as required by the exchange upon which
the units are listed at that time.  However, no change in any
outstanding grant may be made that would materially reduce the benefits to the
participant without the consent of the participant.




Upon
exercise or vesting of an award of, or 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 of, or settled in, units, 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 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,
consulting relationship or membership on the Board of Directors 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 will contain terms as determined by
the Compensation Committee, including the period or terms over which phantom
units will 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, 2008, 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, 2008, approximately 1,590,438 units were issuable under the
Plan pursuant to outstanding award or other agreements and an additional
8,278,115 units were reserved for future issuance under the Plan.




Accounting
for Unit-Based Compensation




Activities
and balances presented in this Note 7 include amounts associated with
discontinued operations (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 non-employee
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 statement of
operations.


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For the
years ended December 31, 2008, 2007 and 2006, the Company recorded
unit-based compensation expense of approximately $15.7 million, $12.5 million
and $21.6 million, respectively, as a charge against income before income taxes
and it is included in “lease operating expenses,” “general and administrative
expenses” or “income (loss) from discontinued operations, net of taxes” on the
consolidated statements of operations.  Approximately $14.7 million,
$12.1 million and $21.6 million of expense is included in results of continuing
operations for the years ended December 31, 2008, 2007 and 2006,
respectively.  No related income tax benefit was recognized due to
non-deductibility and recognition of a valuation allowance (see
Note 16).




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 non-vested units as of
December 31, 2008, is presented below:




Number
      of
                Non-vested
                Units
            
            Weighted
                Average
                Grant
      Date
                Fair
      ValueNon-vested
      units at December 31, 2007
            
            
            833,820
            
            
            $
            29.43Granted
            
            
            589,770
            
            
            $
            23.82Vested
            
            
            (502,523
            )
            
            $
            27.94Forfeited
            
            
            (86,063
            )
            
            $
            23.18Non-vested
      units at December 31, 2008
            
            
            835,004
            
            
            $
            27.01




The
weighted-average grant-date fair value of unrestricted unit grants and
restricted units granted during the years ended December 31, 2007 and 2006 was
$31.16 and $22.98, respectively.




As of
December 31, 2008, there was approximately $13.0 million of unrecognized
compensation cost related to non-vested restricted units.  The cost is
expected to be recognized over a weighted average period of approximately 1.21
years.  The total fair value of units that vested was approximately
$14.0 million, $19.4 million and $2.4 million for the years ended
December 31, 2008, 2007 and 2006, respectively.




Changes
in Unit Options and Unit Options Outstanding




The
following provides information related to unit option activity for the year
ended December 31, 2008:




Number
      of
                Units
      Underlying
                Options
            
            Weighted
                Average
                Exercise
      Price
                Per
      Unit
            
            
            Weighted
                Average
                Grant
      Date
                Fair
      Value
            
            
            Weighted
                Average
                Remaining
                Contractual
                Life
      in YearsOutstanding
      at December 31, 2007
            
            
            997,021
            
            
            $
            24.68
            
            
            $
            4.67Granted
            
            
            691,000
            
            
            $
            23.26
            
            
            $
            2.58Exercised
            
            
            (1,333
            )
            
            $
            21.00
            
            
            $
            4.24Forfeited
            
            
            (96,250
            )
            
            $
            25.17
            
            
            $
            4.70Outstanding
      at December 31, 2008
            
            
            1,590,438
            
            
            $
            24.04
            
            
            $
            3.76
            
            
            
            8.23Exercisable
      at December 31, 2008
            
            
            724,490
            
            
            $
            24.32
            
            
            $
            4.49
            
            
            
            7.71




The
weighted-average grant-date fair value of options granted during the years ended
December 31, 2007 and 2006 was $4.59 and $3.59,
respectively.  The total intrinsic value of options exercised during
the years ended December 31, 2008 and 2007 was approximately $4,000 and
$95,000, respectively.  No options were exercised during the year
ended December 31, 2006.





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As of
December 31, 2008, there was approximately $1.6 million of total
unrecognized compensation cost related to non-vested unit
options.  The cost is expected to be recognized over a weighted
average period of approximately 1.22 years.  At December 31,
2008, exercisable unit options and all outstanding unit options had no aggregate
intrinsic value.  The total fair value of all options that vested
during the years ended December 31, 2008, 2007 and 2006 was approximately
$2.1 million, $1.5 million and $76,000, respectively.  No options
expired during the years ended December 31, 2008, 2007 or
2006.




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




2008
            
            2007
            
            2006Expected
      volatility
            
            30.59
            %
            
            –
            
            34.57
            %
            
            30.40
            %
            
            –
            
            35.58
            %
            
            29.70
            %
            
            –
            
            31.30
            %Expected
      distributions
            
            10.13
            %
            
            –
            
            12.32
            %
            
            6.51
            %
            
            –
            
            10.67
            %
            
            7.20
            %
            
            –
            
            8.50
            %Risk
      free rate
            
            2.66
            %
            
            –
            
            3.41
            %
            
            3.53
            %
            
            –
            
            5.18
            %
            
            4.31
            %
            
            –
            
            5.04
            %Expected
      term
            
            5.0
      years
            
            5.0
      years
            
            5.0
      years




Although
the fair value of unit option grants is determined in accordance with
SFAS 123R using a Black-Scholes option-pricing model, that value may not be
indicative of the fair value observed in a willing buyer/willing seller market
transaction.




Non-Employee
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,
2008, and expire ten years from issuance.  In accordance with
SFAS 123R, the Company computed the fair value of the unit warrants using
the Black-Scholes model.  The expense of approximately $1.4 million is
included in “general and administrative expenses” on the consolidated statement
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 consist of a
discretionary matching contribution equal to 100% of the first 4% of eligible
compensation contributed by the employee on a before-tax basis.  The
Company contributed approximately $1.6 million, $0.8 million and $0.2 million
during the years ended December 31, 2008, 2007 and 2006, 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.


77
 Table of Contents


(8)
            Debt




At
December 31, 2008 and 2007, the Company had the following debt
outstanding:




December 31,2008
            
            2007(in
      thousands)Credit
      facility (1)
            
            $
            1,403,393
            
            
            $
            1,443,000Senior
      notes, net (2)
            
            
            250,175
            
            
            
            ―Less
      current maturities
            
            
            ―
            
            
            
            ―$
            1,653,568
            
            
            $
            1,443,000




(1)
            Variable
      interest rate of 2.47% and 7.02% at December 31, 2008 and 2007,
      respectively.




(2)
            Fixed
      interest rate of 9.875% and effective interest rate of 10.25%; net of
      unamortized discount of approximately $5.8 million at December 31,
      2008.




Credit
Facility




At
December 31, 2008, the Company had a $1.85 billion borrowing base under its
Third Amended and Restated Credit Agreement (“Credit Facility”) with a maturity
of August 2010.  The borrowing base under the Credit Facility will be
redetermined semi-annually by the lenders in their sole discretion, based on,
among other things, reserve reports as prepared by reserve engineers taking into
account the oil and gas prices at such time.  Significant declines in
oil, gas or NGL prices may result in a decrease in the borrowing
base.  During 2009, the Company plans to renegotiate its Credit
Facility, which is anticipated to result in increased interest
expense.  There can be no assurance that the borrowing base under a
new Credit Facility will remain at the current level.




The
Company’s obligations under the Credit Facility are secured by mortgages on its
oil and 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 oil and gas
properties.  Additionally, the obligations under the Credit Facility
are guaranteed by all of the Company’s 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 1.00% and 1.75% per annum or the alternate
base rate (“ABR”) plus an applicable margin between 0% and 0.25% 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 ranging from 0.3% to 0.375% per year on the unused portion of the
Credit Facility.




The
Credit Facility contains various covenants that limit the Company’s ability to
incur indebtedness, enter into interest rate swaps, grant certain liens, make
certain loans, acquisitions, capital expenditures and investments, make
distributions other than from available cash, 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 that 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 its Credit Facility.




Certain
subsidiaries of Lehman Brothers Holdings Inc. (“Lehman Holdings”), including
Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”), were
lenders in the Company’s Credit Facility.  In September 2008 and
October 2008, Lehman Holdings and Lehman Commodity Services, respectively, filed
voluntary petitions for reorganization under Chapter 11 of the United
States Bankruptcy Code (see Note 13).  In October 2008, the
Company replaced Lehman Holdings’ subsidiaries with another lender and Lehman
Holdings’ subsidiaries no longer participate in the Company’s Credit
Facility.  At December 31, 2008, available borrowing under the
Credit Facility was $440.2 million, which includes a $6.4 million


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reduction
in availability for outstanding letters of credit.  Available
borrowing under the Credit Facility was $415.4 million at January 30, 2009
which includes a $6.2 million reduction in availability for outstanding letters
of credit.




Term
Loan




On
January 31, 2008, in order to fund a portion of the January 2008
acquisition of oil and gas properties in the Mid-Continent Shallow region (see
Note 3), the Company entered into a $400.0 million Second Lien Term Loan
Agreement (“Term Loan”) maturing on July 31, 2009.  Interest was
determined by reference to LIBOR plus an applicable margin of 5.0% for the first
twelve months and 7.5% for the remaining period until maturity, or by reference
to a domestic bank rate plus an applicable margin of 3.5% for the first twelve
months and 6.0% for the remaining period until maturity.  On
June 30, 2008, the Company repaid $243.6 million in indebtedness under the
Term Loan with net proceeds from the Senior Notes (see below).  On
July 1, 2008, the Company repaid the balance of the Term Loan of $156.4
million.  Deferred financing fees associated with the Term Loan of
approximately $4.6 million were written off during the year ended
December 31, 2008.




Senior
Notes




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 (“Senior Notes”).  The Senior Notes were offered
and sold to the Initial Purchasers and then resold to qualified institutional
buyers each in transactions exempt from the registration requirements under the
Securities Act of 1933, as amended (“Securities Act”).  The Company
used the net proceeds (after deducting the Initial Purchasers’ discounts and
offering expense) of approximately $243.6 million to repay loans outstanding
under the Company’s Term Loan (see above).  In connection with the
Senior Notes, the Company incurred financing fees of approximately $7.8 million,
which will be amortized over the life of the Senior Notes; the expense is
recorded in “interest expense, net of amounts capitalized” on the consolidated
statement of operations.  The $5.9 million discount on the Senior
Notes will be amortized over the life of the Senior Notes; the expense is
recorded in “interest expense, net of amounts capitalized” on the consolidated
statement of operations.  See Note 10 for fair value disclosures
related to the Senior Notes.




The
Senior Notes were issued under an Indenture dated June 27, 2008
(“Indenture”), mature on July 1, 2018 and bear interest at
9.875%.  Interest is payable semi-annually beginning January 1,
2009.  The Senior Notes are general unsecured senior obligations of
the Company and are effectively junior in right of payment to any secured
indebtedness of the Company to the extent of the collateral securing such
indebtedness.  Each of the Company’s material subsidiaries guaranteed
the Senior 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 Senior 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 Senior 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 Senior 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 Senior Notes at a
redemption price equal to 101%, plus accrued and unpaid interest.




The
Senior 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.


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 Table of Contents


In
connection with the issuance and sale of the Senior 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 Senior Notes in exchange for
outstanding Senior Notes.  In certain circumstances, the Company may
be required to file a shelf registration statement to cover resales of the
Senior Notes.  The Company will not be obligated to file the
registration statements described above if the restrictive legend on the Senior
Notes has been removed and the Senior Notes are freely tradable (in each case,
other than with respect to persons that are affiliates of the Company) pursuant
to Rule 144 under the Securities Act, as of the 366th day after the Senior
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 Senior Notes under certain
circumstances.




(9)
            Derivatives




Commodity
Derivatives




The
Company sells oil, gas and NGL in the normal course of its business and utilizes
derivative instruments to minimize the variability in cash flows due to price
movements in oil, gas and NGL.  The Company enters into derivative
instruments such as swap contracts, collars and put options to economically
hedge a portion of its forecasted oil, 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 under SFAS 133; therefore,
the changes in fair value of these instruments are recorded in current
earnings.  See Note 10 for additional disclosures about oil and
gas commodity derivatives as required by SFAS 157.


80
 Table of Contents


The
following table summarizes open positions as of December 31, 2008 and
represents, as of such date, derivatives in place through December 31,
2014, on annual production volumes:




Year
                2009
            
            Year
                2010
            
            Year
                2011
            
            Year
                2012
            
            Year
                2013
            
            Year
                2014Gas
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MMMBtu)
            
            
            39,586
            
            
            
            39,566
            
            
            
            31,901
            
            
            
            29,662
            
            
            
            ―
            
            
            
            ―Average
      Price ($/MMBtu)
            
            $
            8.53
            
            
            $
            8.20
            
            
            $
            8.27
            
            
            $
            8.46
            
            
            $
            ―
            
            
            $
            ―Puts:Hedged
      Volume (MMMBtu)
            
            
            6,960
            
            
            
            6,960
            
            
            
            6,960
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―Average
      Price ($/MMBtu)
            
            $
            7.50
            
            
            $
            7.50
            
            
            $
            7.50
            
            
            $
            ―
            
            
            $
            ―
            
            
            $
            ―PEPL
      Puts: (1)Hedged
      Volume (MMMBtu)
            
            
            5,334
            
            
            
            10,634
            
            
            
            13,259
            
            
            
            5,934
            
            
            
            ―
            
            
            
            ―Average
      Price ($/MMBtu)
            
            $
            7.85
            
            
            $
            7.85
            
            
            $
            7.85
            
            
            $
            7.85
            
            
            $
            ―
            
            
            $
            ―Total:Hedged
      Volume (MMMBtu)
            
            
            51,880
            
            
            
            57,160
            
            
            
            52,120
            
            
            
            35,596
            
            
            
            ―
            
            
            
            ―Average
      Price ($/MMBtu)
            
            $
            8.32
            
            
            $
            8.05
            
            
            $
            8.06
            
            
            $
            8.36
            
            
            $
            ―
            
            
            $
            ―Oil
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MBbls)
            
            
            2,437
            
            
            
            2,150
            
            
            
            2,073
            
            
            
            2,025
            
            
            
            2,275
            
            
            
            2,200Average
      Price ($/Bbl)
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            84.22
            
            
            $
            84.22
            
            
            $
            84.22
            
            
            $
            84.22Puts:
      (2)Hedged
      Volume (MBbls)
            
            
            1,843
            
            
            
            2,250
            
            
            
            2,352
            
            
            
            500
            
            
            
            ―
            
            
            
            ―Average
      Price ($/Bbl)
            
            $
            120.00
            
            
            $
            110.00
            
            
            $
            69.11
            
            
            $
            77.73
            
            
            $
            ―
            
            
            $
            ―Collars:Hedged
      Volume (MBbls)
            
            
            250
            
            
            
            250
            
            
            
            276
            
            
            
            348
            
            
            
            ―
            
            
            
            ―Average
      Floor Price ($/Bbl)
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            ―
            
            
            $
            ―Average
      Ceiling Price ($/Bbl)
            
            $
            114.25
            
            
            $
            112.00
            
            
            $
            112.25
            
            
            $
            112.35
            
            
            $
            ―
            
            
            $
            ―Total:Hedged
      Volume (MBbls)
            
            
            4,530
            
            
            
            4,650
            
            
            
            4,701
            
            
            
            2,873
            
            
            
            2,275
            
            
            
            2,200Average
      Price ($/Bbl)
            
            $
            102.21
            
            
            $
            99.68
            
            
            $
            77.00
            
            
            $
            83.79
            
            
            $
            84.22
            
            
            $
            84.22Gas
      Basis Differential Positions:PEPL
      Basis Swaps:Hedged
      Volume (MMMBtu)
            
            
            46,916
            
            
            
            43,166
            
            
            
            35,541
            
            
            
            34,066
            
            
            
            31,700
            
            
            
            ―Hedged
      Differential ($/MMBtu)
            
            $
            (0.97
            )
            
            $
            (0.97
            )
            
            $
            (0.96
            )
            
            $
            (0.95
            )
            
            $
            (1.01
            )
            
            $
            ―




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




(2)
            The
      Company utilizes oil puts to hedge revenues associated with its NGL
      production.




Settled
derivatives on gas production for the year ended December 31, 2008 included
a volume of 50,730 MMMBtu at an average contract price of
$8.49.  Settled derivatives on oil and NGL production for the year
ended December 31, 2008 included a volume of 4,421 MBbls at an average
contract price of $77.67.  The gas derivatives are settled based on
the closing NYMEX future price of gas or on the published PEPL spot price of gas
on the settlement date, which occurs on the third day preceding the production
month.  The oil derivatives are settled based on the average month’s
daily NYMEX price of light oil and settlement occurs on the final day of the
production month.




Interest
Rate Swaps




The
Company has entered into interest rate swap agreements based on LIBOR to
minimize the effect of fluctuations in interest rates.  If LIBOR is
lower than the fixed rate in the contract, the Company is required


81
 Table of Contents


to pay
the counterparties the difference, and conversely, the counterparties are
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 under SFAS No. 133; therefore, the changes
in fair value of these instruments are recorded in current
earnings.  See Note 10 for additional disclosures about interest
rate swaps as required by SFAS 157.




The
following presents the settlement terms of the interest rate swaps:




Year
                2009
            
            Year
                2010
            
            Year
                2011(1)(dollars
      in thousands)Notional
      Amount
            
            $
            1,212,000
            
            
            $
            1,212,000
            
            
            $
            1,212,000Fixed
      Rate
            
            
            5.06
            %
            
            
            5.06
            %
            
            
            5.06
            %




(1)
            Represents
      interest rate swaps that settle in January
2011.




In
January 2009, the Company amended and extended its interest rate swap
portfolio.  The Company canceled, in a cashless transaction, its
existing interest rate swap agreements and entered into new agreements that
settle at a fixed rate of 3.80% through 2014.  The following presents
the settlement terms of the new interest rate swaps:




Year
                2009
            
            Year
                2010
            
            Year
                2011
            
            Year
                2012
            
            Year
                2013
            
            Year
                2014(1)(dollars
      in thousands)NotionalAmount
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000
            
            
            $
            1,250,000Fixed
      Rate
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %
            
            
            3.80
            %




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




Outstanding
Notional Amounts




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




December 31,2008
            
            2007Outstanding
      notional amounts of gas contracts (MMMBtu)
            
            
            196,756
            
            
            
            275,769Maximum
      number of months gas contracts outstanding
            
            
            48
            
            
            
            59Outstanding
      notional amounts of oil contracts (MBbls)
            
            
            21,229
            
            
            
            16,214Maximum
      number of months oil contracts outstanding
            
            
            72
            
            
            
            72Outstanding
      notional amount of interest rate swaps (in thousands)
            
            $
            1,212,000
            
            
            $
            1,212,000Maximum
      number of months interest rate swaps outstanding
            
            
            24
            
            
            
            36


82
 Table of Contents


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 31,2008
            
            2007(in
      thousands)Assets:Commodity
      derivatives
            
            $
            977,847
            
            
            $
            246,124Interest
      rate swaps
            
            
            ―
            
            
            
            2,548$
            977,847
            
            
            $
            248,672Liabilities:Commodity
      derivatives
            
            $
            119,124
            
            
            $
            260,058Interest
      rate swaps
            
            
            82,422
            
            
            
            32,475$
            201,546
            
            
            $
            292,533




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 in
its Credit Facility (see Note 8) which is secured by the Company’s oil and
gas reserves; therefore, the Company is not required to post any
collateral.  The Company does not require collateral from the
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 $977.8 million at December 31,
2008.  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 are
also lenders in the Company’s Credit Facility, each of which currently meet 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 swap derivatives are subject to counterparty netting
under agreements governing such derivatives and therefore the risk of such loss
is somewhat mitigated at December 31, 2008.  See Note 13 for
details about canceled commodity contracts with Lehman Commodity
Services.




Gain
(Loss) on Derivatives




Gains and
losses on derivatives are reported on the consolidated statement of operations
in “gain (loss) on oil and gas derivatives” and “gain (loss) on interest rate
swaps” and include realized and unrealized gains (losses).  Realized
gains (losses), excluding canceled commodity 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 non-cash items.


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




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands)Realized
      gains (losses):Commodity
      derivatives
            
            $
            9,408
            
            
            $
            37,250
            
            
            $
            20,160Canceled
      commodity derivatives
            
            
            (81,358
            )
            
            
            ―
            
            
            
            ―Interest
      rate swaps
            
            
            (16,036
            )
            
            
            1,467
            
            
            
            281$
            (87,986
            )
            
            $
            38,717
            
            
            $
            20,441Unrealized
      gains (losses):Commodity
      derivatives
            
            $
            734,732
            
            
            $
            (382,787
            )
            
            $
            83,148Interest
      rate swaps
            
            
            (50,638
            )
            
            
            (29,548
            )
            
            
            82$
            684,094
            
            
            $
            (412,335
            )
            
            $
            83,230Total
      gains (losses):Commodity
      derivatives
            
            $
            662,782
            
            
            $
            (345,537
            )
            
            $
            103,308Interest
      rate swaps
            
            
            (66,674
            )
            
            
            (28,081
            )
            
            
            363$
            596,108
            
            
            $
            (373,618
            )
            
            $
            103,671




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




In
addition, in September 2008, the Company canceled (before the contract
settlement date) all of its commodity derivative contracts with Lehman Commodity
Services as counterparty.  The Company entered into contracts for
substantially the same volumes at identical strike prices with another
participant in its Credit Facility for a cost of approximately $67.6
million.  As a result, effective September 17, 2008, Lehman
Commodity Services was no longer a counterparty to any of the Company’s
commodity derivative contracts and the Company’s overall derivative positions
are unchanged.  See Note 13 for details about the Company’s
receivable for the canceled derivative contracts from Lehman Commodity
Services.




(10)
            Fair
      Value of Financial Instruments




The
Company accounts for its oil and gas commodity derivatives and interest rate
swaps at fair value (see Note 9) on a recurring basis.  Effective
January 1, 2008, the Company adopted SFAS 157 for these financial
instruments.  SFAS 157 defines fair value, establishes a
framework for measuring fair value, establishes a fair value hierarchy based on
the quality of inputs used to measure fair value, and enhances disclosure
requirements for fair value measurements.  The impact of the adoption
of SFAS 157 to the Company’s results of operations was a decrease in net
income of approximately $4.0 million, or $0.04 per unit, for the year ended
December 31, 2008, resulting from assumed credit risk
adjustments.  The credit risk adjustments are based on published
credit ratings, public bond yield spreads and credit default swap
spreads.  The impact of the Company’s assumed credit risk adjustment
was a gain of approximately $8.9 million.  The impact of the
counterparties’ assumed credit risk adjustment was a loss of approximately $12.9
million.




The fair
value of derivative instruments is determined utilizing pricing models for
significantly similar instruments.  The models use a variety of
techniques to arrive at fair value, including quotes and pricing
analysis.  Inputs to the pricing models include publicly available
prices and forward curves generated from a compilation of data gathered from
third parties.


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Fair
Value Hierarchy




In
accordance with SFAS 157, the Company has categorized its financial
instruments, based on the priority of inputs to the valuation technique, into a
three-level fair value hierarchy.  The fair value hierarchy gives the
highest priority to quoted prices in active markets for identical assets or
liabilities (Level 1) and the lowest priority to unobservable inputs
(Level 3).




Financial
assets and liabilities recorded on the consolidated balance sheet 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.




As
required by SFAS 157, 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 Company’s fair value hierarchy for assets and liabilities
measured at fair value on a recurring basis at December 31,
2008.  These items are included in “derivative instruments” on the
consolidated balance sheet.




Fair
      Value Measurements on a Recurring Basis
                December 31,
      2008Level
      2
            
            Netting(1)
            
            Total(in
      thousands)Assets:Commodity
      derivatives
            
            $
            977,847
            
            
            $
            (115,191
            )
            
            $
            862,656Interest
      rate swaps
            
            $
            ―
            
            
            $
            ―
            
            
            $
            ―Liabilities:Commodity
      derivatives
            
            $
            119,124
            
            
            $
            (115,191
            )
            
            $
            3,933Interest
      rate swaps
            
            $
            82,422
            
            
            $
            ―
            
            
            $
            82,422




(1)
            Represents
      counterparty netting under derivative netting
  agreements.




At
December 31, 2008, the Company also had Senior Notes with a net carrying
value of $250.2 million (see Note 8) and a fair value of $147.3
million.  The fair value of the Senior Notes was estimated based on
prices quoted from third-party financial institutions.


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(11)
            Other
      Property and Equipment




Other
property and equipment consists of the following:




December 31,2008
            
            2007(in
      thousands)Gas
      compression plant and pipeline
            
            $
            87,133
            
            
            $
            112,182Land
            
            
            848
            
            
            
            1,052Buildings
      and leasehold improvements
            
            
            7,382
            
            
            
            8,510Vehicles
            
            
            4,121
            
            
            
            7,405Drilling
      and other equipment
            
            
            4,708
            
            
            
            12,313Furniture
      and office equipment
            
            
            7,267
            
            
            
            8,127111,459
            
            
            
            149,589Less
      accumulated depreciation
            
            
            (13,171
            )
            
            
            (12,150
            )$
            98,288
            
            
            $
            137,439




(12)
            Asset
      Retirement Obligations




Asset
retirement obligations (“ARO”) 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.  This liability is offset by a
corresponding increase in the carrying amount of the underlying
asset.  The cost of the tangible asset, including the initially
recognized ARO, is depleted such that the cost of the ARO is recognized over the
useful life of the asset.  The ARO is recorded at fair value, and
accretion expense is recognized over time as the discounted liability is
accreted to its expected settlement value.  The fair value of ARO is
measured using expected future cash outflows discounted at the Company’s average
credit-adjusted risk-free interest rate (7.8%, 7.0% and 7.0% for the years ended
December 31, 2008, 2007 and 2006, respectively).




Inherent
in the fair value calculation of ARO are numerous assumptions and judgments
including the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, 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 ARO
liability, a corresponding adjustment is made to the asset balance.




The
following presents a reconciliation of the ARO liability:




December 31,2008
            
            2007(in
      thousands)ARO
      at beginning of year
            
            $
            29,073
            
            
            $
            8,594Liabilities
      added related to acquisitions and drilling
            
            
            5,939
            
            
            
            15,922Liabilities
      associated with assets sold
            
            
            (8,020
            )
            
            
            ―Current
      year accretion expense
            
            
            1,967
            
            
            
            1,014Settlements
            
            
            (37
            )
            
            
            ―Revision
      of estimates
            
            
            ―
            
            
            
            3,543ARO
      at end of year
            
            $
            28,922
            
            
            $
            29,073


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(13)
            Commitments
      and Contingencies




On
September 15, 2008, 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 Commodity
Services also filed a voluntary petition for reorganization under Chapter 11
with the Court.  As of December 31, 2008, the Company had a
receivable of approximately $67.6 million from Lehman Commodity Services for
canceled derivative contracts (see Note 9).  The Company is
pursuing various legal remedies to protect its interests.  Based on
market expectations, at December 31, 2008, the Company estimated
approximately $6.7 million of the receivable balance to be
collectible.  The net receivable of approximately $6.7 million is
included in “other current assets, net” on the consolidated balance sheet at
December 31, 2008.  The related expense is included in "gain
(loss) on oil and gas derivatives" on the consolidated statement of operations
for the year ended December 31, 2008.  The Company believes that the
ultimate disposition of this matter will not have a material adverse effect on
its business, financial position, results of operations or
liquidity.




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.




(14)
            Earnings
      Per Unit




Basic
earnings per unit is computed in accordance with SFAS No. 128, “Earnings Per Share”
(“SFAS 128”) 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.  At December 31, 2006, the Company had two
classes of units outstanding: (i) units representing limited liability
company interests (“units”) listed on The NASDAQ Global Market under the symbol
“LINE” and (ii) Class B units.




In
accordance with SFAS 128, dual presentation of basic and diluted earnings
per unit has been presented in the consolidated statement of operations for the
year ended December 31, 2006 for each class of units issued and outstanding
at that date, units and Class B units.  Net income per unit was
allocated to the units and the Class B units on an equal
basis.  Certain existing holders of Linn Energy units totaling over
50% committed in advance to vote at a unitholder meeting in favor of the
conversion of Class B units to units and the Class B units were
converted to units on a one-for-one basis in January 2007; therefore, the
Class B units share equally with the units in the net income of the
Company.  Since the Class B units were converted to units in
January 2007, they share equally in the February 2007 distributions and all
future distributions.  The Company made no distributions to
Class B unitholders during the period the Class B units were
outstanding.


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The
following table summarizes the calculation of basic and diluted net income
(loss) per unit:




Year
      Ended December 31,2008
              
              2007
              
              2006(in
      thousands, except per unit amounts)Income
      (loss) from continuing operations
              
              $
              825,657
              
              
              $
              (356,194
              )
              
              $
              69,811Income
      (loss) from discontinued operations
              
              
              173,959
              
              
              
              (8,155
              )
              
              
              9,374Net
      income (loss)
              
              $
              999,616
              
              
              $
              (364,349
              )
              
              $
              79,185Weighted
      average units outstanding:Basic
      units outstanding
              
              
              114,140
              
              
              
              68,916
              
              
              
              28,281Dilutive
      effect of unit equivalents
              
              
              116
              
              
              
              ―
              
              
              
              2,104Diluted
      units outstanding
              
              
              114,256
              
              
              
              68,916
              
              
              
              30,385Weighted
      average Class B units outstanding:Basic
      Class B units outstanding
              
              
              ―
              
              
              
              ―
              
              
              
              1,737Dilutive
      effect of unit equivalents
              
              
              ―
              
              
              
              ―
              
              
              
              ―Diluted
      Class B units outstanding
              
              
              ―
              
              
              
              ―
              
              
              
              1,737Income
      (loss) per unit – continuing operations:Units
      – basic
              
              $
              7.23
              
              
              $
              (5.17
              )
              
              $
              2.33Units
      – diluted
              
              $
              7.23
              
              
              $
              (5.17
              )
              
              $
              2.30Class
      B units – basic
              
              $
              ―
              
              
              $
              ―
              
              
              $
              2.33Class
      B units – diluted
              
              $
              ―
              
              
              $
              ―
              
              
              $
              2.30Income
      (loss) per unit – discontinued operations:Units
      – basic
              
              $
              1.53
              
              
              $
              (0.12
              )
              
              $
              0.31Units
      – diluted
              
              $
              1.52
              
              
              $
              (0.12
              )
              
              $
              0.31Class B
      units – basic
              
              $
              ―
              
              
              $
              ―
              
              
              $
              0.31Class B
      units – diluted
              
              $
              ―
              
              
              $
              ―
              
              
              $
              0.31Net
      income (loss) per unit:Units
      – basic
              
              $
              8.76
              
              
              $
              (5.29
              )
              
              $
              2.64Units
      – diluted
              
              $
              8.75
              
              
              $
              (5.29
              )
              
              $
              2.61Class B
      units – basic
              
              $
              ―
              
              
              $
              ―
              
              
              $
              2.64Class B
      units – diluted
              
              $
              ―
              
              
              $
              ―
              
              
              $
              2.61




Basic
units outstanding excludes the effect of average anti-dilutive common stock
equivalents related to unit options and warrants and unvested restricted units
of 2.2 million, 2.0 million and 0.2 million for the years ended
December 31, 2008, 2007 and 2006, respectively.  In addition,
basic units outstanding excludes the effect of average anti-dilutive
Class B units for the year ended December 31, 2006.  All
equivalent units were anti-dilutive for the year ended December 31, 2007,
as the Company reported a loss from continuing operations.




(15)
            Operating
      Leases




The
Company leases office space and other property and equipment under lease
agreements expiring on various dates through 2015.  The Company
recognized expense under operating leases of approximately $3.2 million, $1.2
million and $0.5 million for the years ended December 31, 2008, 2007 and
2006, respectively.


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As of
December 31, 2008, future minimum lease payments were as follows (in
thousands):




2009
            
            $
            3,5382010
            
            
            3,6822011
            
            
            3,3772012
            
            
            3,2372013
            
            
            2,774Thereafter
            
            
            4,000$
            20,608




(16)
            Income
      Taxes




The
Company is 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 being passed through to the unitholders.  As
such, 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.  Its
taxable income or loss, which may vary substantially from the net income or net
loss reported in the consolidated statement 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 corporate
income taxes.  In addition, limited liability companies are subject to
state income taxes in Texas.  The income tax benefit (expense) from
continuing operations consisted of the following:




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands)Current
      taxes:Federal
            
            $
            (1,184
            )
            
            $
            (1,355
            )
            
            $
            —State
            
            
            (1,528
            )
            
            
            (283
            )
            
            
            (2
            )Deferred
      taxes:Federal
            
            
            —
            
            
            
            (3,066
            )
            
            
            1,594State
            
            
            —
            
            
            
            (84
            )
            
            
            381$
            (2,712
            )
            
            $
            (4,788
            )
            
            $
            1,973




As of
December 31, 2008, the Company’s taxable entities had approximately $7.0
million of net operating loss carryforwards for federal income tax purposes,
which will begin expiring in 2025.


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Income
tax 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 31,2008
            
            2007
            
            2006Federal
      statutory rate
            
            
            35.0
            %
            
            
            35.0
            %
            
            
            35.0
            %State,
      net of federal tax benefit
            
            
            0.1
            
            
            
            (0.1
            )
            
            
            (0.6
            )Income
      (loss) from non-taxable entities
            
            
            (34.9
            )
            
            
            (35.3
            )
            
            
            (50.2
            )Non-deductible
      compensation
            
            
            —
            
            
            
            (0.3
            )
            
            
            10.1Other
      items
            
            
            0.1
            
            
            
            (0.7
            )
            
            
            2.8Effective
      rate
            
            
            0.3
            %
            
            
            (1.4
            )%
            
            
            (2.9
            )%




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




December 31,2008
            
            2007(in
      thousands)Deferred
      tax assets:Net
      operating loss carryforwards
            
            $
            2,767
            
            
            $
            2,449Unit-based
      compensation
            
            
            5,617
            
            
            
            3,762Other
            
            
            897
            
            
            
            285Valuation
      allowance
            
            
            (7,132
            )
            
            
            (4,249
            )Total
      deferred tax assets
            
            
            2,149
            
            
            
            2,247Deferred
      tax liabilities:Property
      and equipment principally due to differences in
    depreciation
            
            
            (2,149
            )
            
            
            (2,247
            )Total
      deferred tax liabilities
            
            
            (2,149
            )
            
            
            (2,247
            )Net
      deferred tax assets (liabilities)
            
            $
            —
            
            
            $
            —




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




December 31,2008
            
            2007(in
      thousands)Deferred
      tax asset
            
            $
            2,149
            
            
            $
            2,247Deferred
      tax liability
            
            
            (2,149
            )
            
            
            (2,247
            )Net
      deferred tax assets (liabilities)
            
            $
            —
            
            
            $
            —




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 not more likely than not that
the Company will realize the benefits of these deductible differences at
December 31, 2008; therefore, the Company has recorded a valuation
allowance against the deferred tax asset.


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The
Company adopted Financial Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes – an interpretation of FASB Statement No. 109” (“FIN
48”) on January 1, 2007.  FIN 48 requires that the Company
recognize 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.  It also requires expanded financial statement disclosure
of such positions.




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.  The Company had no material uncertain tax positions at
December 31, 2008 or 2007.




(17)
            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 under the provisions of SFAS No. 57 “Related Party Disclosures”
during that time frame.  Lehman Holdings’ subsidiaries provided
certain services to the Company, including participation in the Company’s Credit
Facility, Term Loan, offering of Senior Notes (see Note 8), sale of
Appalachian Basin assets (see Note 2) and sale of commodity derivative
instruments (see Note 9), 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 13 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 years 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 year ended
December 31, 2008 (through July 3), the Company purchased
approximately $1.3 million of deal contingent oil swap contracts from
Lehman.  In addition, during the year ended December 31, 2007,
the Company paid Lehman approximately $226.3 million for oil and gas swap
contracts.




The
following sets forth the amounts due to or from Lehman as of December 31,
2007 (in thousands):




Assets:Current
      oil and gas derivative assets
            
            $
            14,226Liabilities:Other
      accrued liabilities
            
            $
            1,440Long-term
      debt
            
            $
            40,404Noncurrent
      oil and gas derivative liabilities
            
            $
            7,028


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Other




Eric P.
Linn, brother of the Company’s Chairman and Chief Executive Officer, 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.  Under the terms of that agreement, Mr. Linn will
receive $0.2 million in cash, six months of outplacement services, accelerated
vesting of certain unvested restricted units and unvested options, and payment
of COBRA coverage until December 31, 2008 or until obtainment of other
comparable health care benefits.




During
the years ended December 31, 2008 and 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
gas and are primarily included in “gas marketing expenses” on the consolidated
statements of operations.  The expenses were consummated on terms
equivalent to those that prevail in arm’s-length transactions.




During
the year ended December 31, 2006, the Company made payments of
approximately $0.4 million to a company owned by one of its senior
executives.  The payments reflect reimbursement for maintenance and
hourly usage fees for business use of an aircraft that was partially owned by
the senior executive.  These costs are included in “general and
administrative expenses” on the consolidated statement of
operations.  The fees and expenses associated with the reimbursements
were consummated on terms equivalent to those that prevail in arm’s-length
transactions.  During the year ended December 31, 2006, the
Company made other arrangements for corporate travel and these reimbursements
were discontinued.




(18)
            Supplemental
      Disclosures to the Consolidated Balance Sheet and Consolidated Statement
      of Cash Flows




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




December 31,2008
            
            2007(in
      thousands)Accrued
      compensation
            
            $
            11,366
            
            
            $
            6,498Accrued
      interest
            
            
            14,232
            
            
            
            5,802Other
            
            
            1,565
            
            
            
            2,130$
            27,163
            
            
            $
            14,430


92
 Table of Contents


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




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands)Cash
      payments for interest
            
            $
            94,958
            
            
            $
            57,348
            
            
            $
            24,147Cash
      payments for income taxes
            
            $
            452
            
            
            $
            ―
            
            
            $
            ―Non-cash
      investing activities:In
      connection with the purchase of oil and gas properties, liabilities were
      assumed as follows:Fair
      value of assets acquired
            
            $
            602,858
            
            
            $
            2,710,417
            
            
            $
            470,362Cash
      paid
            
            
            (593,412
            )
            
            
            (2,649,965
            )
            
            
            (467,137
            )Liabilities
      assumed, net
            
            $
            9,446
            
            
            $
            60,452
            
            
            $
            3,225Non-cash
      financing activities:Units
      issued in connection with the purchase of oil and gas
      properties
            
            $
            23,455
            
            
            $
            ―
            
            
            $
            ―




(19)
            Recently
      Issued Accounting Standards




In
October 2008, the Financial Accounting Standards Board (“FASB”) issued FASB
Staff Position (“FSP”) FAS 157-3, “Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active”(“FSP 157-3”), which
clarifies the application of SFAS 157 in a market that is not
active.  FSP 157-3 is effective upon issuance and its adoption
had no material impact on the Company’s results of operations or financial
position.




In June
2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating
Securities,” which addresses whether instruments granted in share-based
payment transactions are participating securities prior to vesting and,
therefore, need to be included in the earnings allocation in computing earnings
per share under the two-class method.  This FSP is effective for
financial statements issued for fiscal years beginning after December 15,
2008.  The Company is currently evaluating the impact the provisions
of this FSP will have on its results of operations and financial position, but
does not expect it will be material.




In April
2008, the FASB issued FSP FAS 142-3, “Determination of the Useful Life of
Intangible Assets,”which amends the factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of
a recognized intangible asset.  The intent of this FSP is to improve
the consistency between the useful life of a recognized intangible asset and the
period of expected cash flows used to measure the fair value of the
asset.  This FSP is effective for financial statements issued for
fiscal years beginning after December 15, 2008.  The Company is
currently evaluating the impact the provisions of this FSP will have on its
results of operations and financial position, but does not expect it will be
material.




In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities - an Amendment of FASB Statement 133”(“SFAS 161”).SFAS 161 requires
expanded disclosure regarding derivatives and hedging activities including
disclosure of the fair values of derivative instruments and their gains and
losses in tabular form.  SFAS 161 is effective for fiscal years
and interim periods beginning after November 15, 2008, with early adoption
encouraged.  The Company adopted SFAS 161 effective
January 1, 2008 (see Note 9).  The adoption of the
requirements of SFAS 161, which solely expanded disclosures, had no effect
on the Company’s results of operations or financial position.


93
 Table of Contents


In
February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement
No. 157,” which defers the effective date of SFAS 157 for one
year for certain nonfinancial assets and nonfinancial liabilities, except those
that are recognized or disclosed at fair value in the financial statements on a
recurring basis.  On January 1, 2008, the Company adopted the
provisions of SFAS 157 related to financial assets and liabilities and to
nonfinancial assets and liabilities measured at fair value on a recurring basis
(see Note 10).  On January 1, 2009, the Company will adopt
the provisions for nonfinancial assets and nonfinancial liabilities that are not
required or permitted to be measured at fair value on a recurring basis, which
include those measured at fair value in goodwill impairment testing,
indefinite-lived intangible assets measured at fair value for impairment
assessment, nonfinancial long-lived assets measured at fair value for impairment
assessment, asset retirement obligations initially measured at fair value, and
those initially measured at fair value in a business combination.  The
Company is currently evaluating the impact the provisions of SFAS 157
related to these items will have on its results of operations and financial
position.




In
December 2007, the FASB issued SFAS No. 141 (Revised 2007), “BusinessCombinations”(“SFAS 141R”).  Under Statement 141R, an acquiring
entity will be required to recognize all the assets acquired and liabilities
assumed at the acquisition date fair value with limited
exceptions.  Statement 141R will change the accounting treatment
for certain specific items, including acquisition costs, which will be expensed
as incurred, and acquired contingent liabilities, which will be recorded at fair
value at the acquisition date.  SFAS 141R also includes new
disclosure requirements.  SFAS 141R 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, with earlier adoption prohibited.  The Company will implement
SFAS 141R as related to acquisitions that occur after January 1,
2009.




In
September 2006, the FASB issued SFAS 157, which provides guidance for using
fair value to measure assets and liabilities.  SFAS 157 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.  SFAS 157 also requires
expanded disclosure of the effect on earnings for items measured using
unobservable data.  The Company adopted the provisions of
SFAS 157 for financial assets effective January 1, 2008 (see
Note 10).  The provisions of SFAS 157 are applicable to
non-financial assets effective for fiscal years beginning after
November 15, 2008.  The Company is currently evaluating the
impact the adoption of SFAS 157 for non-financial assets will have on its
results of operations and financial position.




94
 Table of Contents
 LINN ENERGY, LLC
 SUPPLEMENTAL
OIL AND GAS DATA (Unaudited)


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




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




Costs
incurred in oil and gas property acquisition and development, whether
capitalized or expensed, are presented below (balances include amounts
associated with oil and gas properties for which results are reported in
discontinued operations):




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands)Property
      acquisition costs:Proved
            
            $
            595,795
            
            
            $
            2,422,983
            
            
            $
            450,232Unproved
            
            
            4,111
            
            
            
            148,284
            
            
            
            4,062Development
      costs
            
            
            332,557
            
            
            
            189,466
            
            
            
            47,112Total
      costs incurred
            
            $
            932,463
            
            
            $
            2,760,733
            
            
            $
            501,406




Costs incurred
during the year ended December 31, 2008 include approximately $900.3 million
($314.9 million excluding acquisition and asset retirement obligation costs) of
costs from continuing operations and $32.2 million ($15.7 million excluding
acquisition and asset retirement obligation costs) of costs from discontinued
operations.  Costs incurred during the year ended
December 31, 2007 include approximately $2.67 billion ($144.8 million
excluding acquisition and asset retirement obligation costs) of costs from
continuing operations and $86.3 million ($40.7 million excluding acquisition and
asset retirement obligation costs) of costs from discontinued
operations.  Costs incurred during the year ended
December 31, 2006 include approximately $417.7 million ($4.2 million
excluding acquisition and asset retirement obligation costs) of costs from
continuing operations and $83.7 million ($42.8 million excluding acquisition and
asset retirement obligation costs) of costs from discontinued
operations.




(B)
            Oil
      and Gas Capitalized Costs




Aggregate
capitalized costs related to oil and gas production activities with applicable
accumulated depletion and amortization are presented below (balances include
amounts associated with oil and gas properties for which results are reported in
discontinued operations):




December 31,2008
            
            2007(in
      thousands)Proved
      properties:Leasehold
      acquisition
            
            $
            3,278,155
            
            
            $
            3,095,400Development
            
            
            460,730
            
            
            
            254,251Unproved
      properties
            
            
            92,298
            
            
            
            156,9083,831,183
            
            
            
            3,506,559Less
      accumulated depletion and amortization
            
            
            (278,805
            )
            
            
            (120,498
            )Net
      capitalized costs
            
            $
            3,552,378
            
            
            $
            3,386,061


95
 Table of Contents


(C)
            Results
      of Oil and Gas Producing Activities




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




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands)Revenues
      and other:Oil,
      gas and natural gas liquid sales
            
            $
            755,644
            
            
            $
            255,927
            
            
            $
            21,372Gain
      (loss) on oil and gas derivatives
            
            
            662,782
            
            
            
            (345,537
            )
            
            
            103,3081,418,426
            
            
            
            (89,610
            )
            
            
            124,680Production
      costs:Lease
      operating expenses
            
            
            115,402
            
            
            
            41,946
            
            
            
            6,603Transportation
      expenses
            
            
            17,597
            
            
            
            5,575
            
            
            
            40Production
      and ad valorem taxes
            
            
            59,598
            
            
            
            20,295
            
            
            
            229192,597
            
            
            
            67,816
            
            
            
            6,872Other
      costs:Exploration
      costs
            
            
            7,603
            
            
            
            4,053
            
            
            
            286Depletion
      and amortization
            
            
            185,857
            
            
            
            64,857
            
            
            
            4,018Impairment
      of goodwill and long-lived assets
            
            
            50,505
            
            
            
            ―
            
            
            
            ―Texas
      margin tax expense
            
            
            920
            
            
            
            ―
            
            
            
            ―(Gain)
      loss on sale of assets, net
            
            
            (99,050
            )
            
            
            ―
            
            
            
            ―145,835
            
            
            
            68,910
            
            
            
            4,304Results
      of continuing operations
            
            $
            1,079,994
            
            
            $
            (226,336
            )
            
            $
            113,504Results
      of discontinued operations
            
            $
            190,915
            
            
            $
            19,111
            
            
            $
            30,475




There is
no federal tax provision included in the results of oil and gas producing
activities because the Company’s subsidiaries subject to federal tax do not own
any of the Company’s oil and gas interests.  Limited liability
companies are subject to state income taxes in Texas (see
Note 16).


96
 Table of Contents


(D)
            Net
      Proved Oil and Gas Reserves




The
proved reserves of oil and gas of the Company have been prepared by the
independent engineering firm DeGolyer and MacNaughton at December 31, 2008,
2007 and 2006.  These reserve estimates have been prepared in
compliance with the SEC rules based on year-end prices.  An analysis
of the change in estimated quantities of oil and gas reserves, all of which are
located within the United States, is shown below:




Year
      Ended December 31, 2008Gas
      (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
            
            
            
            1,616,107Revisions
      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
            
            
            
            373,476Sales
      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
            
            
            
            229,840Production
            
            
            (45,206
            )
            
            
            (3,138
            )
            
            
            (2,252
            )
            
            
            (77,548
            )
            
            
            (4,546
            )
            
            
            (82,094
            )End
      of year
            
            
            851,232
            
            
            
            84,144
            
            
            
            50,722
            
            
            
            1,660,428
            
            
            
            —
            
            
            
            1,660,428Proved
      developed reserves:Beginning
      of year
            
            
            616,109
            
            
            
            42,509
            
            
            
            25,546
            
            
            
            1,024,440
            
            
            
            147,702
            
            
            
            1,172,142End
      of year
            
            
            585,071
            
            
            
            61,884
            
            
            
            29,600
            
            
            
            1,133,976
            
            
            
            —
            
            
            
            1,133,976





Year
      Ended December 31, 2007Gas
      (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
            
            
            
            454,066Revisions
      of previous estimates
            
            
            (7,375
            )
            
            
            6,555
            
            
            
            162
            
            
            
            32,923
            
            
            
            (18,392
            )
            
            
            14,531Purchase
      of minerals in place
            
            
            714,026
            
            
            
            17,823
            
            
            
            41,741
            
            
            
            1,071,409
            
            
            
            23,558
            
            
            
            1,094,967Sales
      of minerals in place
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            (1,511
            )
            
            
            (1,511
            )Extensions,
      discoveries and other additions
            
            
            67,994
            
            
            
            1,694
            
            
            
            2,213
            
            
            
            91,437
            
            
            
            3,196
            
            
            
            94,633Production
            
            
            (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
            
            
            
            1,616,107Proved
      developed reserves:Beginning
      of year
            
            
            49,383
            
            
            
            24,304
            
            
            
            —
            
            
            
            195,206
            
            
            
            118,851
            
            
            
            314,057End
      of year
            
            
            616,109
            
            
            
            42,509
            
            
            
            25,546
            
            
            
            1,024,440
            
            
            
            147,702
            
            
            
            1,172,142





Year
      Ended December 31, 2006Gas
      (MMcf)
            
            Oil
      (MBbls)
            
            Total
                Continuing
                Operations
                (MMcfe)
            
            Total
                Discontinued
                Operations
                (MMcfe)
            
            Total
                (MMcfe)Proved
      developed and undeveloped reserves:Beginning
      of year
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            193,210
            
            
            
            193,210Revisions
      of previous estimates
            
            
            (6,929
            )
            
            
            196
            
            
            
            (5,754
            )
            
            
            (29,264
            )
            
            
            (35,018
            )Purchase
      of minerals in place
            
            
            84,951
            
            
            
            29,784
            
            
            
            263,655
            
            
            
            ―
            
            
            
            263,655Extensions,
      discoveries and other additions
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            43,037
            
            
            
            43,037Production
            
            
            (747
            )
            
            
            (341
            )
            
            
            (2,792
            )
            
            
            (8,026
            )
            
            
            (10,818
            )End
      of year
            
            
            77,275
            
            
            
            29,639
            
            
            
            255,109
            
            
            
            198,957
            
            
            
            454,066Proved
      developed reserves:Beginning
      of year
            
            
            ―
            
            
            
            ―
            
            
            
            —
            
            
            
            125,220
            
            
            
            125,220End
      of year
            
            
            49,383
            
            
            
            24,304
            
            
            
            195,206
            
            
            
            118,851
            
            
            
            314,057


97
 Table of Contents


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 oil and gas 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.




Substantially
all of the 228,036 MMcfe negative revision of previous estimates during the year
ended December 31, 2008 was due to decreases in oil and gas
prices.  The 14,531 MMcfe positive revision of previous estimates
during the year ended December 31, 2007 was due to a combination of reasons
including higher oil and gas prices, partially offset by higher operating costs,
asset performance and changes to future scheduled capital
projects.  The 35,018 MMcfe negative revision of previous estimate
during the year ended December 31, 2006 was due primarily to a decrease in
gas prices.




The
Company made four, eight and five acquisitions of working and royalty interests
during the years ended December 31, 2008, 2007 and 2006, respectively, with
total proved reserves of 373,476 MMcfe, 1,094,967 MMcfe and 263,655 MMcfe,
respectively.  See Note 3 for additional details.




Extensions
and discoveries of 229,840 MMcfe, 94,633 MMcfe and 43,037 MMcfe during the years
ended December 31, 2008, 2007 and 2006, respectively, were primarily due to
the drilling of 351 wells during 2008, 253 wells during 2007 and 159 wells
during 2006, which increased the Company’s proved reserves.




(E)
            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 year-end 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 16).




December 31,2008
            
            2007
            
            2006(in
      thousands)Future
      estimated revenues
            
            $
            8,261,234
            
            
            $
            12,565,382
            
            
            $
            1,814,226Future
      estimated production costs
            
            
            (3,410,684
            )
            
            
            (3,052,847
            )
            
            
            (538,968
            )Future
      estimated development costs
            
            
            (896,625
            )
            
            
            (582,890
            )
            
            
            (92,904
            )Future
      net cash flows
            
            
            3,953,925
            
            
            
            8,929,645
            
            
            
            1,182,35410%
      annual discount for estimated timing of cash flows
            
            
            (2,529,558
            )
            
            
            (5,754,798
            )
            
            
            (883,594
            )Standardized
      measure of discounted future net cash flows – continuing
      operations
            
            $
            1,424,367
            
            
            $
            3,174,847
            
            
            $
            298,760Standardized
      measure of discounted future net cash flows – discontinued
      operations
            
            $
            —
            
            
            $
            283,392
            
            
            $
            253,500Representative
      NYMEX oil and gas prices atperiod
      end:Gas
      (MMBtu)
            
            $
            5.71
            
            
            $
            6.80
            
            
            $
            5.64Oil
      (Bbl)
            
            $
            39.22
            
            
            $
            95.92
            
            
            $
            61.05


98
 Table of Contents


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




Year
      Ended December 31,2008
            
            2007
            
            2006(in
      thousands)Sales
      of oil and gas production, net of production costs
            
            $
            (563,047
            )
            
            $
            (188,111
            )
            
            $
            (14,500
            )Changes
      in estimated future development costs
            
            
            32,006
            
            
            
            6,271
            
            
            
            (521
            )Net
      changes in prices and production costs
            
            
            (2,837,262
            )
            
            
            81,654
            
            
            
            ―Purchase
      of minerals in place
            
            
            1,066,615
            
            
            
            2,438,178
            
            
            
            508,107Sale
      of minerals in place
            
            
            (102,437
            )
            
            
            ―
            
            
            
            ―Extensions,
      discoveries, and improved recovery, less related costs
            
            
            383,017
            
            
            
            172,989
            
            
            
            ―Development
      costs incurred during the period
            
            
            76,150
            
            
            
            69,221
            
            
            
            47,112Revisions
      of previous quantity estimates
            
            
            (69,044
            )
            
            
            56,154
            
            
            
            ―Change
      in discount
            
            
            317,485
            
            
            
            29,876
            
            
            
            ―Changes
      in production rates and other
            
            
            (53,963
            )
            
            
            209,855
            
            
            
            (241,438
            )Change
      – continuing operations
            
            $
            (1,750,480
            )
            
            $
            2,876,087
            
            
            $
            298,760Change
      – discontinued operations
            
            $
            (283,392
            )
            
            $
            29,892
            
            
            $
            (298,575
            )




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.




(F)
            Recent
      SEC Rule-Making Activity




In
December 2008, the SEC announced that it had approved revisions designed to
modernize the oil and gas company reserve reporting requirements.  The
most significant amendments to the requirements include the
following:




·
            commodity
      prices – economic producibility of reserves and discounted cash flows will
      be based on a 12-month average commodity price unless contractual
      arrangements designate the price to be
used;


·
            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


·
            non-traditional
      resources– the
      definition of oil and gas producing activities will expand and focus on
      the marketable product rather than the method of
    extraction.




The rules
are effective for fiscal years ending on or after December 31, 2009, and early
adoption is not permitted.  The Company is currently evaluating the
new rules and assessing the impact they will have its reported oil and gas
reserves.  The SEC is coordinating with the FASB to obtain the
revisions necessary to SFAS No. 19, “Financial Accounting and Reporting
by Oil and Gas Producing Companies,” and SFAS No. 69, “Disclosures about Oil and Gas
Producing Activities” to provide consistency with the new rules. In the
event that consistency is not achieved in time for companies to comply with the
new rules, the SEC will consider delaying the compliance date.


99
 Table of Contents
 LINN ENERGY, LLC
 SUPPLEMENTAL
QUARTERLY DATA (Unaudited)


The
following discussion and analysis should be read in conjunction with the
“Selected Historical Consolidated Financial and Operating Data” and the
financial statements and related notes included elsewhere in this Annual Report
on Form 10-K.




(A)
            Quarterly
      Financial Data




Quarters
      EndedMarch
      31
            
            June
      30
            
            September
      30
            
            December 31(in
      thousands, except per unit amounts)2008Oil,
      gas and natural gas liquid sales (1)
            
            $
            175,872
            
            
            $
            255,586
            
            
            $
            240,634
            
            
            $
            83,552Gain
      (loss) on oil and gas derivatives
            
            $
            (268,794
            )
            
            $
            (870,804
            )
            
            $
            845,818
            
            
            $
            956,562Total
      revenues and other
            
            $
            (89,627
            )
            
            $
            (610,983
            )
            
            $
            1,091,660
            
            
            $
            1,043,981Total
      expenses (2)
            
            $
            104,274
            
            
            $
            118,521
            
            
            $
            132,889
            
            
            $
            180,848(Gain)
      loss on sale of assets, net
            
            $
            ―
            
            
            $
            ―
            
            
            $
            ―
            
            
            $
            (98,763
            )Income
      (loss) from continuing operations
            
            $
            (258,959
            )
            
            $
            (725,381
            )
            
            $
            921,943
            
            
            $
            888,054Income
      (loss) from discontinued operations, net of taxes (3)
            
            $
            (400
            )
            
            $
            13,239
            
            
            $
            160,668
            
            
            $
            452Net
      income (loss)
            
            $
            (259,359
            )
            
            $
            (712,142
            )
            
            $
            1,082,611
            
            
            $
            888,506Income
      (loss) per unit – continuing operations:Basic
            
            $
            (2.28
            )
            
            $
            (6.35
            )
            
            $
            8.06
            
            
            $
            7.77Diluted
            
            $
            (2.28
            )
            
            $
            (6.35
            )
            
            $
            8.05
            
            
            $
            7.76Income
      per unit – discontinued operations:Basic
            
            $
            ―
            
            
            $
            0.12
            
            
            $
            1.41
            
            
            $
            0.01Diluted
            
            $
            ―
            
            
            $
            0.12
            
            
            $
            1.41
            
            
            $
            ―Net
      income (loss) per unit:Basic
            
            $
            (2.28
            )
            
            $
            (6.23
            )
            
            $
            9.47
            
            
            $
            7.78Diluted
            
            $
            (2.28
            )
            
            $
            (6.23
            )
            
            $
            9.46
            
            
            $
            7.76




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




(2)
            Includes
      the following expenses: lease operating, transportation, 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.  100
 Table of Contents





Quarters
      EndedMarch
      31
            
            June
      30
            
            September
      30
            
            December 31(in
      thousands, except per unit amounts)2007Oil,
      gas and natural gas liquid sales
            
            $
            23,567
            
            
            $
            32,495
            
            
            $
            61,318
            
            
            $
            138,547Loss
      on oil and gas derivatives
            
            $
            (60,441
            )
            
            $
            (17,707
            )
            
            $
            (65,440
            )
            
            $
            (201,949
            )Total
      revenues and other
            
            $
            (34,308
            )
            
            $
            18,015
            
            
            $
            (203
            )
            
            $
            (58,787
            )Total
      expenses (1)
            
            $
            25,558
            
            
            $
            30,689
            
            
            $
            54,172
            
            
            $
            93,060(Gain)
      loss on sale of assets, net
            
            $
            ―
            
            
            $
            ―
            
            
            $
            67
            
            
            $
            1,700Loss
      from continuing operations
            
            $
            (68,421
            )
            
            $
            (17,064
            )
            
            $
            (71,831
            )
            
            $
            (198,878
            )Income
      (loss) from discontinued operations, net of taxes (2)
            
            $
            574
            
            
            $
            (62
            )
            
            $
            (4,391
            )
            
            $
            (4,276
            )Net
      loss
            
            $
            (67,847
            )
            
            $
            (17,126
            )
            
            $
            (76,222
            )
            
            $
            (203,154
            )Loss
      per unit – continuing operations:Basic
            
            $
            (1.36
            )
            
            $
            (0.29
            )
            
            $
            (0.89
            )
            
            $
            (1.97
            )Diluted
            
            $
            (1.36
            )
            
            $
            (0.29
            )
            
            $
            (0.89
            )
            
            $
            (1.97
            )Income
      (loss) per unit – discontinued operations:Basic
            
            $
            0.01
            
            
            $
            ―
            
            
            $
            (0.05
            )
            
            $
            (0.04
            )Diluted
            
            $
            0.01
            
            
            $
            ―
            
            
            $
            (0.05
            )
            
            $
            (0.04
            )Net
      loss per unit:Basic
            
            $
            (1.35
            )
            
            $
            (0.29
            )
            
            $
            (0.94
            )
            
            $
            (2.01
            )Diluted
            
            $
            (1.35
            )
            
            $
            (0.29
            )
            
            $
            (0.94
            )
            
            $
            (2.01
            )




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




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




101
 Table of Contents
 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, 2008.




Management’s
Annual Report on Internal Control Over Financial Reporting




See
Management’s Report on Internal Control Over Financial Reporting under
Item 8 of this Form 10-K.




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 2008 that materially affected, or were reasonably
likely to materially affect, the Company’s internal control over financial
reporting.




Item 9B.     Other
Information




None.


102
 Table of Contents
 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.
Item 1. “Business” in this Form 10-K.  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 May 5,
2009 (the “2009 Proxy Statement”).  That information is incorporated
herein by reference.




The
information in the 2009 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
2009 Proxy Statement under the caption “Corporate Governance.”




Item 11.      Executive
Compensation




Information
required by this item is incorporated herein by reference to the 2009 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 2009 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, 2008:




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
      Plans
                (Excluding
      Securities
                Reflected
      in Column (a))(a)
            
            (b)
            
            (c)Equity
      compensation plans approved by security holders
            
            
            1,590,438
            
            
            
            
            $
            24.04
            
            
            
            
            8,278,115Equity
      compensation plans not approved by security holders
            
            
            ―
            
            
            
            
            
            ―
            
            
            
            
            ―Total
            
            
            1,590,438
            
            
            
            
            $
            24.04
            
            
            
            
            8,278,115




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




Information
required by this item is incorporated herein by reference to the 2009 Proxy
Statement.




Item 14.      Principal Accounting
Fees and Services




Information
required by this item is incorporated herein by reference to the 2009 Proxy
Statement.


103
 Table of Contents
 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 under Part II. Item 8. “Financial
Statements and Supplementary Data.”




(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.


104
 Table of Contents


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, LLCDate:  February 26,
      2009
            By:
            /s/
      Michael C. LinnMichael
      C. LinnChairman
      and Chief Executive OfficerDate:  February 26,
      2009
            By:
            /s/
      David B. RottinoDavid
      B. RottinoSenior
      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
            
            Chairman
      and Chief Executive Officer
              (Principal
      Executive Officer)
            
            February
       26, 2009Michael
      C. Linn/s/
      Kolja Rockov
            
            Executive
      Vice President and
              Chief
      Financial Officer
              (Principal
      Financial Officer)
            
            February 26,
      2009Kolja
      Rockov/s/
      David B. Rottino
            
            Senior
      Vice President and
              Chief
      Accounting Officer
              (Principal
      Accounting Officer)
            
            February 26,
      2009David
      B. Rottino/s/
      George A. Alcorn
            
            Independent
      Director
            
            February 26,
      2009George
      A. Alcorn/s/
      Terrence S. Jacobs
            
            Independent
      Director
            
            February 26,
      2009Terrence
      S. Jacobs/s/
      Joseph P. McCoy
            
            Independent
      Director
            
            February 26,
      2009Joseph
      P. McCoy/s/ Jeffrey
      C. Swoveland
            
            Independent
      Director
            
            February 26,
      2009Jeffrey
      C. Swoveland


105
 Table of Contents
 INDEX
TO EXHIBITS


Exhibit
      Number
            
            
            
            Description2
            .1*
            
            —
            
            Limited
      Partnership Asset Purchase and Sale Agreement, dated as of April 13,
      2008, between Linn Energy Holdings, LLC, Marathon 85-II Limited
      Partnership and Marathon 85-III Limited Partnership, as sellers, and
      XTO Energy, Inc., as buyer (incorporated herein by reference to
      Exhibit 2.2 to Quarterly Report on Form 10-Q filed on
      May 8, 2008)2
            .2*
            
            —
            
            First
      Amendment, dated as of July 1, 2008, to Limited Partnership Asset
      Purchase and Sale Agreement between Linn Energy Holdings, LLC, Marathon
      85-II Limited Partnership, Marathon 85-III Limited Partnership, as sellers
      and XTO Energy Inc., as buyer (incorporated herein by reference to
      Exhibit 2.3 to Quarterly Report on Form 10-Q filed on
      August 7, 2008)2
            .3*
            
            —
            
            Asset
      Purchase and Sale Agreement, dated October 9, 2008, between Linn
      Energy Holdings, LLC, Mid-Continent I, LLC, Mid-Continent II, LLC, Linn
      Operating, Inc. and Devon Energy Production Company, LP (incorporated
      herein by reference to Exhibit 2.1 to Quarterly Report on
      Form 10-Q filed on November 6, 2008)2
            .4*†
            
            —
            
            First
      Amendment, dated as of December 4, 2008, to Asset Purchase and Sale
      Agreement, dated October 9, 2008, between Linn Energy Holdings, LLC,
      Mid-Continent I, LLC, Mid-Continent II, LLC, Linn Operating, Inc. and
      Devon Energy Production Company, LP3
            .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 the 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
            
            —
            
            Registration
      Rights Agreement, dated June 27, 2008, 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 June 30, 2008)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)  106
 Table of Contents


Exhibit
      Number
            
            
            
            Description10
            .2**†
            
            —
            
            Amendment
      No. 1 to Linn Energy, LLC Amended and Restated Long-Term Incentive
      Plan, dated February 4, 200910
            .3**†
            
            —
            
            Form
      of Executive Unit Option Agreement pursuant to the Linn Energy, LLC
      Amended and Restated Long-Term Incentive Plan, as
  amended10
            .4**†
            
            —
            
            Form
      of Executive Restricted Unit Agreement pursuant to the Linn Energy, LLC
      Amended and Restated Long-Term Incentive Plan, as
  amended10
            .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
    amended10
            .7**†
            
            —
            
            Third
      Amended and Restated Employment Agreement, dated effective as of
      December 17, 2008 between Linn Operating, Inc. and Michael C.
      Linn10
            .8**†
            
            —
            
            Third
      Amended and Restated Employment Agreement, dated effective as of
      December 17, 2008 between Linn Operating, Inc. and Kolja
      Rockov10
            .9**†
            
            —
            
            Amended
      and Restated Employment Agreement, dated effective as of December 17,
      2008 between Linn Operating, Inc. and Mark E. Ellis10
            .10**†
            
            —
            
            Amended
      and Restated Employment Agreement, dated effective December 17, 2008
      between Linn Operating, Inc. and Charlene A. Ripley10
            .11**†
            
            —
            
            Amended
      and Restated Employment Agreement, dated effective December 17, 2008
      between Linn Operating, Inc. and Arden L. Walker, Jr.10
            .12**†
            
            —
            
            Second
      Amended and Restated Employment Agreement, dated December 17, 2008
      between Linn Operating, Inc. and David B. Rottino10
            .13**
            
            —
            
            Separation
      Agreement, dated effective June 11, 2008 between Linn Operating, Inc.
      and Lisa D. Anderson (incorporated herein by reference to
      Exhibit 10.3 to Quarterly Report on Form 10-Q filed on
      August 7, 2008)10
            .14**
            
            —
            
            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
            .15**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      George A. Alcorn10
            .16**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Joseph P. McCoy10
            .17**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Terrence S. Jacobs10
            .18**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Jeffrey C. Swoveland10
            .19**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Michael C. Linn10
            .20**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Mark E. Ellis10
            .21**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Kolja Rockov10
            .22**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Charlene A. Ripley10
            .23**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      David B. Rottino10
            .24**†
            
            —
            
            Indemnity
      Agreement, dated as of February 4, 2009 between Linn Energy, LLC and
      Arden L. Walker, Jr.10
            .25
            
            —
            
            Third
      Amended and Restated Credit Agreement dated as of August 31, 2007
      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 Current Report on Form 8-K filed on
      September 5, 2007)


107
 Table of Contents


Exhibit
      Number
            
            
            
            Description10
            .26
            
            —
            
            First
      Amendment, dated November 2, 2007, to Third 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 10.15 to Annual Report
      on Form 10-K for the year ended December 31, 2007, filed on
      February 29, 2008)10
            .27
            
            —
            
            Second
      Amendment, dated January 31, 2008, to Third 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 10.16 to Annual Report
      on Form 10-K for the year ended December 31, 2007, filed on
      February 29, 2008)10
            .28
            
            —
            
            Third
      Amendment, dated as of June 16, 2008, to Third 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 7, 2008)10
            .29
            
            —
            
            Fourth
      Amendment, dated effective August 20, 2008, to Third 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 Current Report
      on Form 8-K filed on August 26, 2008)10
            .30
            
            —
            
            Third
      Amended and Restated Guaranty and Pledge Agreement, dated as of
      August 31, 2007, 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 Current Report on
      Form 8-K filed on September 5, 2007)21
            .1†
            
            —
            
            Significant
      Subsidiaries of Linn Energy, LLC23
            .1†
            
            —
            
            Consent
      of KPMG LLP for Linn Energy, LLC23
            .2†
            
            —
            
            Consent
      of DeGolyer and MacNaughton Data and Consulting
Services31
            .1†
            
            —
            
            Section 302
      Certification of Michael C. Linn, Chairman, President and Chief Executive
      Officer of Linn Energy, LLC31
            .2†
            
            —
            
            Section 302
      Certification of Kolja Rockov, Executive Vice President and Chief
      Financial Officer of Linn Energy, LLC32
            .1†
            
            —
            
            Section 906
      Certification of Michael C. Linn, Chairman, President and Chief Executive
      Officer of Linn Energy, LLC32
            .2†
            
            —
            
            Section 906
      Certification of Kolja Rockov, Executive Vice President and Chief
      Financial Officer of Linn Energy,
LLC




†
            Filed
      herewith.




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




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