UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C. 20549


Form 10-Q








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




For
the Quarterly Period Ended September 30, 2009




OR





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




for
the transition period from _______________ to _______________




Commission
File Number: 000-51719












LINN
ENERGY, LLC


(Exact
name of registrant as specified in its charter)








Delaware
            65-1177591(State
      or other jurisdiction of incorporation or organization)
            (IRS
      Employer
              Identification
      No.)600
      Travis, Suite 5100
              Houston,
      Texas
            77002(Address
      of principal executive offices)
            (Zip
      Code)(281) 840-4000
              (Registrant’s
      telephone number, including area code)




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





Indicate
by check mark whether the registrant (1) has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File required
to be submitted and posted pursuant to Rule 405 of Regulation S-T
(§232.405) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files).    Yes   ̈    No   ̈







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





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


(Do not check if a smaller reporting
company)





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





As of
October 30, 2009, there were 129,916,563 units outstanding.








TABLE OF CONTENTS





PageGlossary of Terms
            iiPart I - Financial InformationItem 1.
            Financial StatementsCondensed Consolidated Balance Sheets as of September 30,
      2009, and December 31, 2008
            1Condensed Consolidated Statements of Operations for the
      three months and nine months ended September 30, 2009, and
      September 30, 2008
            2Condensed Consolidated Statement of Unitholders’
      Capital for the nine months ended September 30,
    2009
            3Condensed Consolidated Statements of Cash Flows for the nine
      months ended September 30, 2009, and September 30,
      2008
            4Notes to Condensed Consolidated Financial
      Statements
            5Item 2.
            Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
            25Item 3.
            Quantitative and Qualitative Disclosures About Market
      Risk
            44Item 4.
            Controls and Procedures
            45Part II - Other InformationItem 1.
            Legal Proceedings
            46Item 1A.
            Risk Factors
            46Item 2.
            Unregistered Sales of Equity Securities and Use of
      Proceeds
            46Item 3.
            Defaults Upon Senior Securities
            46Item 4.
            Submission of Matters to a Vote of Security
      Holders
            46Item 5.
            Other Information
            46Item 6.
            Exhibits
            47Signature
            48


i
 Table of Contents
 GLOSSARY OF TERMS


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




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




Bcf.  One billion
cubic feet.




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




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




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




MBbls/d.MBbls per
day.




Mcf.  One thousand
cubic feet.




Mcfe.  One thousand
cubic feet equivalent, determined using the ratio of six Mcf of 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.




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.


ii
 Table of Contents
 PART I – FINANCIAL INFORMATION
  Item 1.Financial
Statements
 LINN ENERGY, LLC
 CONDENSED
CONSOLIDATED BALANCE SHEETS


September 30,
            
            December 31,2009
            
            2008(Unaudited)(in
      thousands,
              except
      unit amounts)AssetsCurrent
      assets:Cash
      and cash equivalents
            
            $
            10,595
            
            
            $
            28,668Accounts
      receivable – trade, net
            
            
            98,150
            
            
            
            138,983Derivative
      instruments
            
            
            290,784
            
            
            
            368,951Other
      current assets
            
            
            22,748
            
            
            
            27,329Total
      current assets
            
            
            422,277
            
            
            
            563,931Noncurrent
      assets:Oil
      and gas properties (successful efforts method)
            
            
            4,060,403
            
            
            
            3,831,183Less
      accumulated depletion and amortization
            
            
            (416,766
            )
            
            
            (278,805
            )3,643,637
            
            
            
            3,552,378Other
      property and equipment
            
            
            116,373
            
            
            
            111,459Less
      accumulated depreciation
            
            
            (20,933
            )
            
            
            (13,171
            )95,440
            
            
            
            98,288Derivative
      instruments
            
            
            213,130
            
            
            
            493,705Other
      noncurrent assets
            
            
            64,679
            
            
            
            13,718277,809
            
            
            
            507,423Total
      noncurrent assets
            
            
            4,016,886
            
            
            
            4,158,089Total
      assets
            
            $
            4,439,163
            
            
            $
            4,722,020Liabilities
      and Unitholders’ CapitalCurrent
      liabilities:Accounts
      payable and accrued expenses
            
            $
            125,731
            
            
            $
            163,662Derivative
      instruments
            
            
            48,042
            
            
            
            47,005Other
      accrued liabilities
            
            
            31,839
            
            
            
            27,163Total
      current liabilities
            
            
            205,612
            
            
            
            237,830Noncurrent
      liabilities:Credit
      facility
            
            
            1,251,000
            
            
            
            1,403,393Senior
      notes, net
            
            
            488,492
            
            
            
            250,175Derivative
      instruments
            
            
            44,945
            
            
            
            39,350Other
      noncurrent liabilities
            
            
            35,613
            
            
            
            30,586Total
      noncurrent liabilities
            
            
            1,820,050
            
            
            
            1,723,504Unitholders’
      capital:121,276,006
      units and 114,079,533 units issued and outstanding atSeptember 30,
      2009, and December 31, 2008, respectively
            
            
            1,994,684
            
            
            
            2,109,089Accumulated
      income
            
            
            418,817
            
            
            
            651,5972,413,501
            
            
            
            2,760,686Total
      liabilities and unitholders’ capital
            
            $
            4,439,163
            
            
            $
            4,722,020




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


1
 Table of Contents
 LINN ENERGY, LLC
 CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
 (Unaudited)


Three
      Months Ended
                September 30,
            
            Nine
      Months Ended
                September 30,2009
            
            2008
            
            2009
            
            2008(in
      thousands, except per unit amounts)Revenues
      and other:Oil,
      gas and natural gas liquid sales
            
            $
            102,989
            
            
            $
            240,634
            
            
            $
            274,759
            
            
            $
            672,092Gain
      (loss) on oil and gas derivatives
            
            
            (14,065
            )
            
            
            845,818
            
            
            
            (85,525
            )
            
            
            (293,780
            )Gas
      marketing revenues
            
            
            1,351
            
            
            
            4,647
            
            
            
            3,050
            
            
            
            11,056Other
      revenues
            
            
            150
            
            
            
            561
            
            
            
            1,757
            
            
            
            1,68290,425
            
            
            
            1,091,660
            
            
            
            194,041
            
            
            
            391,050Expenses:Lease
      operating expenses
            
            
            33,453
            
            
            
            33,503
            
            
            
            100,322
            
            
            
            78,154Transportation
      expenses
            
            
            6,367
            
            
            
            5,683
            
            
            
            11,850
            
            
            
            12,674Gas
      marketing expenses
            
            
            98
            
            
            
            4,061
            
            
            
            1,318
            
            
            
            9,581General
      and administrative expenses
            
            
            19,655
            
            
            
            18,692
            
            
            
            63,247
            
            
            
            55,788Exploration
      costs
            
            
            861
            
            
            
            268
            
            
            
            4,625
            
            
            
            2,949Bad
      debt expenses
            
            
            500
            
            
            
            1,436
            
            
            
            500
            
            
            
            1,436Depreciation,
      depletion and amortization
            
            
            49,440
            
            
            
            52,004
            
            
            
            151,934
            
            
            
            147,259Taxes,
      other than income taxes
            
            
            5,965
            
            
            
            17,242
            
            
            
            21,414
            
            
            
            47,843(Gain)
      loss on sale of assets and other, net
            
            
            1,999
            
            
            
            ―
            
            
            
            (24,717
            )
            
            
            ―118,338
            
            
            
            132,889
            
            
            
            330,493
            
            
            
            355,684Other
      income and (expenses):Interest
      expense, net of amounts capitalized
            
            
            (28,025
            )
            
            
            (22,574
            )
            
            
            (65,696
            )
            
            
            (71,199
            )Loss
      on interest rate swaps
            
            
            (25,709
            )
            
            
            (9,694
            )
            
            
            (25,362
            )
            
            
            (17,483
            )Other,
      net
            
            
            (757
            )
            
            
            (3,558
            )
            
            
            (1,987
            )
            
            
            (8,034
            )(54,491
            )
            
            
            (35,826
            )
            
            
            (93,045
            )
            
            
            (96,716
            )Income
      (loss) from continuing operationsbefore
      income taxes
            
            
            (82,404
            )
            
            
            922,945
            
            
            
            (229,497
            )
            
            
            (61,350
            )Income
      tax expense
            
            
            (58
            )
            
            
            (1,002
            )
            
            
            (379
            )
            
            
            (1,047
            )Income
      (loss) from continuing operations
            
            
            (82,462
            )
            
            
            921,943
            
            
            
            (229,876
            )
            
            
            (62,397
            )Discontinued
      operations:Gain
      (loss) on sale of assets, net of taxes
            
            
            —
            
            
            
            162,442
            
            
            
            (718
            )
            
            
            161,120Income
      (loss) from discontinued operations,net
      of taxes
            
            
            (1,247
            )
            
            
            (1,774
            )
            
            
            (2,186
            )
            
            
            12,387(1,247
            )
            
            
            160,668
            
            
            
            (2,904
            )
            
            
            173,507Net
      income (loss)
            
            $
            (83,709
            )
            
            $
            1,082,611
            
            
            $
            (232,780
            )
            
            $
            111,110Income
      (loss) per unit – continuing operations:Units
      – basic
            
            $
            (0.69
            )
            
            $
            8.01
            
            
            $
            (1.97
            )
            
            $
            (0.55
            )Units
      – diluted
            
            $
            (0.69
            )
            
            $
            8.01
            
            
            $
            (1.97
            )
            
            $
            (0.55
            )Income
      (loss) per unit – discontinued operations:Units
      – basic
            
            $
            (0.01
            )
            
            $
            1.39
            
            
            $
            (0.03
            )
            
            $
            1.52Units
      – diluted
            
            $
            (0.01
            )
            
            $
            1.39
            
            
            $
            (0.03
            )
            
            $
            1.52Net
      income (loss) per unit:Units
      – basic
            
            $
            (0.70
            )
            
            $
            9.40
            
            
            $
            (2.00
            )
            
            $
            0.97Units
      – diluted
            
            $
            (0.70
            )
            
            $
            9.40
            
            
            $
            (2.00
            )
            
            $
            0.97Weighted
      average units outstanding:Units
      – basic
            
            
            119,792
            
            
            
            114,321
            
            
            
            116,610
            
            
            
            114,111Units
      – diluted
            
            
            119,792
            
            
            
            114,345
            
            
            
            116,610
            
            
            
            114,111Distributions
      declared per unit
            
            $
            0.63
            
            
            $
            0.63
            
            
            $
            1.89
            
            
            $
            1.89




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


2
 Table of Contents
 LINN ENERGY, LLC
 CONDENSED
CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL
 (Unaudited)


Units
            
            Unitholders’
                Capital
            
            Accumulated
                Income
            
            Treasury
                Units
                (at
      Cost)
            
            Total
                Unitholders’
                Capital(in
      thousands)December 31,
      2008
            
            
            114,080
            
            
            $
            2,109,089
            
            
            $
            651,597
            
            
            $
            ―
            
            
            $
            2,760,686Sale
      of units, net of underwriting discounts and expenses of
    $4,533
            
            
            6,325
            
            
            
            98,248
            
            
            
            ―
            
            
            
            ―
            
            
            
            98,248Issuance
      of units
            
            
            1,058
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―Cancellation
      of units
            
            
            (187
            )
            
            
            (2,696
            )
            
            
            ―
            
            
            
            2,696
            
            
            
            ―Purchase
      of units
            
            
            
            
            
            
            ―
            
            
            
            ―
            
            
            
            (2,696
            )
            
            
            (2,696
            )Distributions
      to unitholders
            
            
            
            
            
            
            (221,430
            )
            
            
            ―
            
            
            
            ―
            
            
            
            (221,430
            )Unit-based
      compensation expenses
            
            
            
            
            
            
            11,473
            
            
            
            ―
            
            
            
            ―
            
            
            
            11,473Net
      loss
            
            
            
            
            
            
            ―
            
            
            
            (232,780
            )
            
            
            ―
            
            
            
            (232,780
            )September 30,
      2009
            
            
            121,276
            
            
            $
            1,994,684
            
            
            $
            418,817
            
            
            $
            ―
            
            
            $
            2,413,501




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


3
 Table of Contents
 LINN ENERGY, LLC
 CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Unaudited)


Nine
      Months Ended
                September 30,2009
            
            2008(in
      thousands)Cash
      flow from operating activities:Net
      income (loss)
            
            $
            (232,780
            )
            
            $
            111,110Adjustments
      to reconcile net income (loss) to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
            
            
            151,934
            
            
            
            152,017Unit-based
      compensation expenses
            
            
            11,473
            
            
            
            12,376Bad
      debt expenses
            
            
            500
            
            
            
            1,436Amortization
      and write-off of deferred financing fees and other
            
            
            14,231
            
            
            
            12,853(Gain)
      loss on sale of assets, net
            
            
            (22,572
            )
            
            
            (161,120
            )Mark-to-market
      on derivatives:Total
      losses
            
            
            110,887
            
            
            
            311,263Cash
      settlements
            
            
            299,114
            
            
            
            (72,416
            )Cash
      settlements on canceled derivatives
            
            
            48,977
            
            
            
            (81,358
            )Premiums
      paid for derivatives
            
            
            (93,606
            )
            
            
            (129,520
            )Changes
      in assets and liabilities:(Increase)
      decrease in accounts receivable – trade, net
            
            
            39,260
            
            
            
            (99,448
            )(Increase)
      decrease in other assets
            
            
            365
            
            
            
            (3,821
            )Decrease
      in accounts payable and accrued expenses
            
            
            (3,232
            )
            
            
            (15,810
            )Increase
      in other liabilities
            
            
            5,573
            
            
            
            5,226Net
      cash provided by operating activities
            
            
            330,124
            
            
            
            42,788Cash
      flow from investing activities:Acquisition
      of oil and gas properties
            
            
            (116,694
            )
            
            
            (573,096
            )Development
      of oil and gas properties
            
            
            (152,149
            )
            
            
            (249,833
            )Purchases
      of other property and equipment
            
            
            (5,832
            )
            
            
            (5,309
            )Proceeds
      from sale of properties and equipment
            
            
            26,682
            
            
            
            744,133Net
      cash used in investing activities
            
            
            (247,993
            )
            
            
            (84,105
            )Cash
      flow from financing activities:Proceeds
      from sale of units
            
            
            102,781
            
            
            
            ―Purchase
      of units
            
            
            (2,696
            )
            
            
            (1,981
            )Proceeds
      from borrowings
            
            
            599,203
            
            
            
            1,422,000Repayments
      of debt
            
            
            (513,893
            )
            
            
            (1,095,116
            )Distributions
      to unitholders
            
            
            (221,430
            )
            
            
            (217,331
            )Financing
      fees, offering expenses and other, net
            
            
            (64,169
            )
            
            
            (20,427
            )Net
      cash provided by (used in) financing activities
            
            
            (100,204
            )
            
            
            87,145Net
      increase (decrease) in cash and cash equivalents
            
            
            (18,073
            )
            
            
            45,828Cash
      and cash equivalents:Beginning
            
            
            28,668
            
            
            
            1,441Ending
            
            $
            10,595
            
            
            $
            47,269




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


4
 Table of Contents
 LINN ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 (Unaudited)


(1)
            Basis
      of Presentation




Nature
of Business




Linn
Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and gas
company focused on the development and acquisition of long-life properties which
complement its asset profile in producing basins within the United
States.




Principles
of Consolidation and Reporting




The
condensed consolidated financial statements at September 30, 2009, and for
the three months and nine months ended September 30, 2009, and
September 30, 2008, are unaudited, but in the opinion of management include
all adjustments (consisting only of normal recurring adjustments) necessary for
a fair presentation of the results for the interim
periods.  Subsequent events were evaluated through the issuance date
of the financial statements, November 4, 2009.  Certain
information and note disclosures normally included in annual financial
statements prepared in accordance with United States generally accepted
accounting principles (“GAAP”) have been condensed or omitted under Securities
and Exchange Commission (“SEC”) rules and regulations, and as such this report
should be read in conjunction with the financial statements and notes in the
Company’s Annual Report on Form 10-K for the year ended December 31,
2008.  The results reported in these unaudited condensed consolidated
financial statements should not necessarily be taken as indicative of results
that may be expected for the entire year.




The
condensed consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries.  All significant intercompany
transactions and balances have been eliminated upon consolidation.




Presentation
Change




Certain
amounts in the condensed consolidated financial statements and notes thereto
have been reclassified to conform to the 2009 financial statement
presentation.  In particular, the condensed consolidated statements of
operations include categories of expense titled “lease operating expenses,”
“transportation expenses,” “exploration costs,” “taxes, other than income taxes”
and “(gain) loss on sale of assets and other, 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 2009 financial statement
presentation.  There was no impact to net income (loss) for prior
periods.




Discontinued
Operations




The
Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. (“Mid Atlantic”)
operations have been classified as discontinued operations on the condensed
consolidated statements of operations for all periods
presented.  Unless otherwise indicated, information about the
statements of operations that is presented in the notes to condensed
consolidated financial statements relates only to LINN Energy’s continuing
operations.  See Note 2 for additional details.




Use
of Estimates




The
preparation of the accompanying condensed consolidated financial statements in
conformity with GAAP requires management of the Company to make estimates and
assumptions about future events.  These estimates and the underlying
assumptions affect the amount of assets and liabilities reported, disclosures
about contingent assets and liabilities, and reported amounts of revenues and
expenses.  The estimates that are particularly significant to the
financial statements include estimates of the Company’s


5
 Table of Contents
 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


reserves
of oil, gas and natural gas liquids (“NGL”), future cash flows from oil and gas
properties, depreciation, depletion and amortization, asset retirement
obligations, fair values of commodity and interest rate derivatives, and fair
values of assets acquired and liabilities assumed.  These estimates
and assumptions are based on management’s best estimates and
judgment.  Management evaluates its estimates and assumptions on an
ongoing basis using historical experience and other factors, including the
current economic environment, which management believes to be reasonable under
the circumstances.  Such estimates and assumptions are adjusted when
facts and circumstances dictate.  Illiquid credit markets and volatile
equity and energy markets have combined to increase the uncertainty inherent in
such estimates and assumptions.  As future events and their effects
cannot be determined with precision, actual results could differ from these
estimates.  Any changes in estimates resulting from continuing changes
in the economic environment will be reflected in the financial statements in
future periods.




(2)
            Acquisitions,
      Divestitures and Discontinued
Operations




Acquisitions
– 2009




On
August 31, 2009, and September 30, 2009, the Company completed the
acquisitions of certain oil and gas properties located in the Permian Basin in
Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian
Corporation, (collectively referred to as “Forest”) for an aggregate contract
price of $117.6 million.  The Company paid $116.5 million in cash and
recorded a receivable from Forest of approximately $2.7 million, resulting in
total consideration for the acquisitions of approximately $113.8
million.  The transactions were financed with borrowings from the
Company’s Credit Facility (as defined in Note 6).  The
acquisitions represent a strategic entry into the Permian Basin for the
Company.




The
acquisitions were accounted for under the acquisition method of accounting in
accordance with an accounting standard adopted by the Company effective
January 1, 2009, (see Note 16).  Accordingly, the Company
conducted a preliminary assessment of net assets acquired and recognized
provisional amounts for identifiable assets acquired and liabilities assumed at
their estimated acquisition date fair values, while transaction and integration
costs associated with the acquisitions were expensed as incurred.  The
initial accounting for the business combinations is not complete and adjustments
to provisional amounts, or recognition of additional assets acquired or
liabilities assumed, may occur as more detailed analyses are completed and
additional information is obtained about the facts and circumstances that
existed as of the acquisition dates.


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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


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




Assets:Current
      assets
            
            $
            800Oil
      and gas properties
            
            
            115,952Total
      assets acquired
            
            $
            116,752Liabilities:Current
      liabilities
            
            $
            1,567Asset
      retirement obligations
            
            
            1,350Total
      liabilities assumed
            
            $
            2,917Net
      assets acquired
            
            $
            113,835




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




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




Acquisition
– 2008




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 for $542.2 million.




Divestitures
– 2008




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”).  During 2008, the
Company received net proceeds of $153.2 million and the carrying value of net
assets sold was $54.2 million.  In the first quarter of 2009, certain
post-closing matters were resolved and the Company recorded a gain of $25.4
million, which is recorded in “(gain) loss on sale of assets and other, net” on
the condensed consolidated statements of operations for the nine months ended
September 30, 2009.




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




On
July 1, 2008, the Company completed the sale of its interests in oil and
gas properties located in the Appalachian Basin to XTO Energy,
Inc.  During 2008, the Company received net proceeds of $566.5 million
and the carrying value of net assets sold was $405.8 million.  In
addition, in March 2008, the


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 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


Company
exited the drilling and service business in the Appalachian Basin provided by
its wholly owned subsidiary Mid Atlantic.  The Company used the net
proceeds from all divestitures to reduce indebtedness.




Discontinued
Operations




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




Three
      Months Ended
                September 30,
            
            Nine
      Months Ended
                September 30,2009
            
            2008
            
            2009
            
            2008(in
      thousands)Total
      revenues and other
            
            $
            —
            
            
            $
            (421
            )
            
            $
            (1,216
            )
            
            $
            49,564Total
      operating expenses
            
            
            (1,247
            )
            
            
            (1,549
            )
            
            
            (970
            )
            
            
            (23,779
            )Interest
      expense
            
            
            —
            
            
            
            196
            
            
            
            —
            
            
            
            (13,398
            )Income
      (loss) from discontinued operations, net of taxes
            
            $
            (1,247
            )
            
            $
            (1,774
            )
            
            $
            (2,186
            )
            
            $
            12,387




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




(3)
            Unitholders’
      Capital




Public
Offering of Units




In
October 2009, the Company sold 8,625,000 units, representing limited liability
company interests at $21.90 per unit ($21.024 per unit, net of underwriting
discount), for net proceeds (after underwriting discount of $7.6 million and
estimated offering expenses of $0.7 million) of approximately $180.6 million,
which was used to reduce indebtedness under the Company’s Credit
Facility.




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




Unit
Repurchase Plan




In
October 2008, the Board of Directors of the Company authorized the repurchase of
up to $100.0 million of the Company’s outstanding units from time to time on the
open market or in negotiated purchases.  During the nine months ended
September 30, 2009, 123,800 units were repurchased at an average unit price
of $12.99, for a total cost of approximately $1.6 million.  All units
were subsequently canceled.  At September 30, 2009, approximately
$85.4 million was available for unit repurchase under the
program.  The timing and amounts of any such repurchases will be at
the discretion of management, subject to market conditions and other factors,
and in accordance with applicable securities laws and other legal
requirements.  The repurchase plan does not obligate the Company to
acquire any specific number of units and may be discontinued at any
time.  Units are repurchased at fair market value on the date of
repurchase.


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 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


Cancellation
of Units




During
the nine months ended September 30, 2009, the Company purchased 63,031
units for approximately $1.1 million, in conjunction with units received by the
Company for the payment of minimum withholding taxes due on units issued under
its equity compensation plan (see Note 12).  All units were
subsequently canceled.




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 during the nine
months ended September 30, 2009, are presented on the condensed
consolidated statement of unitholders’ capital.  On October 21,
2009, the Company’s Board of Directors declared a cash distribution of $0.63 per
unit with respect to the third quarter of 2009.  The distribution,
totaling approximately $81.9 million, will be paid November 13, 2009, to
unitholders of record as of the close of business November 6,
2009.




(4)
            Oil
      and Gas Capitalized Costs




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




September 30,
                2009
            
            December 31,
                2008(in
      thousands)Proved
      properties:Leasehold
      acquisition
            
            $
            3,396,033
            
            
            $
            3,278,155Development
            
            
            581,976
            
            
            
            460,730Unproved
      properties
            
            
            82,394
            
            
            
            92,2984,060,403
            
            
            
            3,831,183Less
      accumulated depletion and amortization
            
            
            (416,766
            )
            
            
            (278,805
            )$
            3,643,637
            
            
            $
            3,552,378




(5)
            Business
      and Credit Concentrations




For the
three months and nine months ended September 30, 2009, the Company’s three
largest customers represented approximately 26%, 19% and 15%, and 23%, 18% and
15%, respectively, of the Company’s sales.  For the three months and
nine months ended September 30, 2008, the Company’s four largest customers
represented approximately 17%, 12%, 11% and 10%, and 19%, 11%, 11% and 10%,
respectively, of the Company’s sales.




At
September 30, 2009, trade accounts receivable from three customers were
more than 10% of the Company’s total trade accounts receivable.  At
September 30, 2009, trade accounts receivable from the Company’s three
largest customers represented approximately 24%, 18% and 13%, respectively, of
the Company’s receivables.  At December 31, 2008, trade accounts
receivable from two customers were 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%, respectively, of the Company’s receivables.


9
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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


(6)
            Debt




At
September 30, 2009, and December 31, 2008, the Company had the
following debt outstanding:




September 30,
                2009
            
            December 31,
                2008(in
      thousands)Credit
      facility (1)
            
            $
            1,251,000
            
            
            $
            1,403,393Senior
      notes due 2017, net (2)
            
            
            238,038
            
            
            
            ―Senior
      notes due 2018, net (3)
            
            
            250,454
            
            
            
            250,175Less
      current maturities
            
            
            ―
            
            
            
            ―$
            1,739,492
            
            
            $
            1,653,568




(1)
            Variable
      interest rate of 3.0% at September 30, 2009, and 2.47% at
      December 31, 2008.




(2)
            Fixed
      interest rate of 11.75% and effective interest rate of
      12.73%.  Amount is net of unamortized discount of approximately
      $12.0 million at September 30,
2009.




(3)
            Fixed
      interest rate of 9.875% and effective interest rate of
      10.25%.  Amount is net of unamortized discount of approximately
      $5.5 million and $5.8 million at September 30, 2009, and
      December 31, 2008,
respectively.




Credit
Facility




On
April 28, 2009, the Company entered into a Fourth Amended and Restated
Credit Agreement (“Credit Facility”), with an initial borrowing base of $1.75
billion and a maturity of August 2012, which amended and restated the Company’s
existing credit facility, which had a maturity of August 2010.  The
terms of the Credit Facility required that, upon the issuance of the senior
notes due 2017 in May 2009 (see below) and cancelation of certain commodity
derivatives in July 2009 (see Note 7), the borrowing base be decreased by
approximately $62.5 million and $45.0 million, respectively, to $1.64 billion at
September 30, 2009.  At September 30, 2009, available
borrowing capacity was $386.0 million, which reflects borrowings used to finance
the recent acquisitions in the Permian Basin (see Note 2) and a $5.5 million
reduction in availability for outstanding letters of credit.  In
October 2009, the Company used net proceeds from its public offering of units
(see Note 3) to reduce indebtedness under its Credit Facility.  At
October 30, 2009, available borrowing capacity was $535.0 million, which
includes a $5.5 million reduction in availability for outstanding letters of
credit.  In connection with the amended and restated Credit Facility,
during the nine months ended September 30, 2009, the Company paid
approximately $52.7 million in financing fees and expenses, which were deferred
and will be amortized over the life of the Credit Facility.




Redetermination
of the borrowing base under the Credit Facility occurs semi-annually, in April
and October, as well as upon the occurrence of certain events, by the lenders in
their sole discretion, based primarily on reserve reports that reflect oil and
gas prices at such time.  Significant declines in oil, gas or NGL
prices may result in a decrease in the borrowing base.  The Company’s
obligations under the Credit Facility are secured by mortgages on its oil and
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 material operating subsidiaries and may
be guaranteed by any future subsidiaries.




At the
Company’s election, interest on borrowings under the Credit Facility is
determined by reference to either the London Interbank Offered Rate (“LIBOR”)
plus an applicable margin between 2.50% and 3.25% per annum or the alternate
base rate (“ABR”) plus an applicable margin between 1.00% and 1.75%
per


10
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 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


annum.  Interest
is generally payable quarterly for ABR loans and at the applicable maturity date
for LIBOR loans.  The Company is required to pay a fee of 0.5% per
annum on the unused portion of the borrowing base under the Credit
Facility.




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




Senior
Notes Due 2017




On
May 12, 2009, the Company entered into a purchase agreement with a group of
initial purchasers (“Initial Purchasers”), pursuant to which the Company agreed
to issue $250.0 million in aggregate principal amount of the Company’s senior
notes due 2017 (“2017 Notes”).  The 2017 Notes were offered and sold
to the Initial Purchasers and then resold to qualified institutional buyers,
each in transactions exempt from the registration requirements of the Securities
Act.  The Company used the net proceeds (after deducting the Initial
Purchasers’ discounts and offering expenses) of approximately $230.8 million to
reduce indebtedness under its Credit Facility.  In connection with the
2017 Notes, the Company incurred financing fees and expenses of approximately
$6.9 million, which will be amortized over the life of the 2017 Notes; the
expense is recorded in “interest expense, net of amounts capitalized” on the
condensed consolidated statements of operations.  The $12.3
million discount on the 2017 Notes will be amortized over the life of the 2017
Notes; the expense is recorded in “interest expense, net of amounts capitalized”
on the condensed consolidated statements of operations.




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




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


11
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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


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




Senior
Notes Due 2018




On
June 24, 2008, the Company entered into a purchase agreement with a group
of initial purchasers (“Initial Purchasers”), pursuant to which the Company
agreed to issue $255.9 million in aggregate principal amount of the Company’s
senior notes due 2018 (“2018 Notes”).  The 2018 Notes were offered and
sold to the Initial Purchasers and then resold to qualified institutional
buyers, each in transactions exempt from the registration requirements of the
Securities Act.  The Company used the net proceeds (after deducting
the Initial Purchasers’ discounts and offering expenses) of approximately $243.6
million to repay an outstanding term loan.  In connection with the
2018 Notes, the Company incurred financing fees and expenses of approximately
$7.8 million, which will be amortized over the life of the 2018 Notes; the
expense is recorded in “interest expense, net of amounts capitalized” on the
condensed consolidated statements of operations.  The $5.9
million discount on the 2018 Notes will be amortized over the life of the 2018
Notes; the expense is recorded in “interest expense, net of amounts capitalized”
on the condensed consolidated statements of operations.




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




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


12
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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


are
affiliates of the Company).  This terminated the Company’s obligations
under a registration rights agreement entered into in connection with issuance
of the 2018 Notes.




Fair
Value Measurements




At
September 30, 2009, the estimated fair values of the 2017 Notes and the
2018 Notes were approximately $268.8 million and $254.3 million,
respectively.  The fair values were estimated based on prices quoted
from third-party financial institutions.




(7)
            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; therefore, the changes in fair
value of these instruments are recorded in current earnings.  See
Note 8 for fair value disclosures about oil and gas commodity
derivatives.


13
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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


The
following table summarizes open positions as of September 30, 2009, and
represents, as of such date, derivatives in place through December 31,
2013, on annual production volumes:




Year
                2009
            
            Year
                2010
            
            Year
                2011
            
            Year
                2012
            
            Year
                2013Gas
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MMMBtu)
            
            
            9,896
            
            
            
            39,566
            
            
            
            31,901
            
            
            
            —
            
            
            
            —Average
      Price ($/MMBtu)
            
            $
            8.53
            
            
            $
            8.90
            
            
            $
            9.50
            
            
            $
            —
            
            
            $
            —Puts:Hedged
      Volume (MMMBtu)
            
            
            1,740
            
            
            
            6,960
            
            
            
            6,960
            
            
            
            —
            
            
            
            —Average
      Price ($/MMBtu)
            
            $
            7.50
            
            
            $
            8.50
            
            
            $
            9.50
            
            
            $
            —
            
            
            $
            —PEPL
      Puts: (1)Hedged
      Volume (MMMBtu)
            
            
            1,334
            
            
            
            10,634
            
            
            
            13,259
            
            
            
            —
            
            
            
            —Average
      Price ($/MMBtu)
            
            $
            7.85
            
            
            $
            7.85
            
            
            $
            8.50
            
            
            $
            —
            
            
            $
            —Total:Hedged
      Volume (MMMBtu)
            
            
            12,970
            
            
            
            57,160
            
            
            
            52,120
            
            
            
            —
            
            
            
            —Average
      Price ($/MMBtu)
            
            $
            8.32
            
            
            $
            8.66
            
            
            $
            9.25
            
            
            $
            —
            
            
            $
            —Oil
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MBbls)
            
            
            609
            
            
            
            2,150
            
            
            
            2,073
            
            
            
            —
            
            
            
            —Average
      Price ($/Bbl)
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            —
            
            
            $
            —Puts:
      (2)Hedged
      Volume (MBbls)
            
            
            461
            
            
            
            2,250
            
            
            
            2,352
            
            
            
            —
            
            
            
            —Average
      Price ($/Bbl)
            
            $
            120.00
            
            
            $
            110.00
            
            
            $
            75.00
            
            
            $
            —
            
            
            $
            —Collars:Hedged
      Volume (MBbls)
            
            
            62
            
            
            
            250
            
            
            
            276
            
            
            
            —
            
            
            
            —Average
      Floor Price ($/Bbl)
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            90.00
            
            
            $
            —
            
            
            $
            —Average
      Ceiling Price ($/Bbl)
            
            $
            114.25
            
            
            $
            112.00
            
            
            $
            112.25
            
            
            $
            —
            
            
            $
            —Total:Hedged
      Volume (MBbls)
            
            
            1,132
            
            
            
            4,650
            
            
            
            4,701
            
            
            
            —
            
            
            
            —Average
      Price ($/Bbl)
            
            $
            102.21
            
            
            $
            99.68
            
            
            $
            82.50
            
            
            $
            —
            
            
            $
            —Gas
      Basis Differential Positions:PEPL
      Basis Swaps:Hedged
      Volume (MMMBtu)
            
            
            11,729
            
            
            
            43,166
            
            
            
            35,541
            
            
            
            34,066
            
            
            
            31,700Hedged
      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 three months and nine months ended
September 30, 2009, included a volume of 12,970 MMMBtu and 38,910 MMMBtu at
average contract prices of $8.32.  Settled derivatives on oil and NGL
production for the three months and nine months ended September 30, 2009,
included a volume of 1,132 MBbls and 3,397 MBbls at average contract prices of
$102.21.  The gas derivatives are settled based on the closing New
York Mercantile Exchange (“NYMEX”) future price of gas or on the published PEPL
spot price of gas on the settlement date, which occurs on the third
day


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 LINN
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 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


preceding
the production month.  The oil derivatives are settled based on the
month’s average daily NYMEX price of light oil and settlement occurs on the
final day of the production month.




Interest
Rate Swaps




The
Company has entered into interest rate swap agreements based on LIBOR to
minimize the effect of fluctuations in interest rates.  If LIBOR is
lower than the fixed rate in the contract, the Company is required to pay the
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; therefore, the changes in fair value of these
instruments are recorded in current earnings.  See Note 8 for
fair value disclosures about interest rate swaps.




The
following presents the settlement terms of the interest rate swaps at
September 30, 2009:




Year
                2009
            
            Year
                2010
            
            Year
                2011
            
            Year
                2012
            
            Year
                2013(1)(dollars
      in thousands)Notional
      amount
            
            $
            1,212,000
            
            
            $
            1,212,000
            
            
            $
            1,212,000
            
            
            $
            1,212,000
            
            
            $
            1,212,000Fixed
      rate
            
            
            3.85
            %
            
            
            3.85
            %
            
            
            3.85
            %
            
            
            3.85
            %
            
            
            3.85
            %




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




Outstanding
Notional Amounts




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




September 30,
                2009
            
            December 31,
                2008Outstanding
      notional amounts of gas contracts (MMMBtu)
            
            
            122,250
            
            
            
            196,756Maximum
      number of months gas contracts outstanding
            
            
            27
            
            
            
            48Outstanding
      notional amounts of oil contracts (MBbls)
            
            
            10,483
            
            
            
            21,229Maximum
      number of months oil contracts outstanding
            
            
            27
            
            
            
            72Outstanding
      notional amount of interest rate swaps (in thousands)
            
            $
            1,212,000
            
            
            $
            1,212,000Maximum
      number of months interest rate swaps outstanding
            
            
            51
            
            
            
            24


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ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


Balance
Sheet Presentation




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




September 30,
                2009
            
            December 31,
                2008(in
      thousands)Assets:Commodity
      derivatives
            
            $
            636,933
            
            
            $
            977,847Interest
      rate swaps
            
            
            179
            
            
            
            ―$
            637,112
            
            
            $
            977,847Liabilities:Commodity
      derivatives
            
            $
            149,036
            
            
            $
            119,124Interest
      rate swaps
            
            
            77,149
            
            
            
            82,422$
            226,185
            
            
            $
            201,546




By using
derivative instruments to economically hedge exposures to changes in commodity
prices and interest rates, the Company exposes itself to credit risk and market
risk.  Credit risk is the failure of the counterparty to perform under
the terms of the derivative contract.  When the fair value of a
derivative contract is positive, the counterparty owes the Company, which
creates credit risk.  The Company’s counterparties are participants or
affiliates of participants in its Credit Facility (see Note 6), which is
secured by the Company’s oil and gas reserves; therefore, the Company is not
required to post any collateral.  The Company does not require
collateral from its counterparties.  The maximum amount of loss due to
credit risk that the Company would incur if its counterparties failed completely
to perform according to the terms of the contracts, based on the gross fair
value of financial instruments, was approximately $637.1 million at
September 30, 2009.  The Company minimizes the credit risk in
derivative instruments by: (i) limiting its exposure to any single
counterparty; (ii) entering into derivative instruments only with
counterparties that meet the Company’s minimum credit quality standard, or have
a guarantee from an affiliate that meets the Company’s minimum credit quality
standard; and (iii) monitoring the creditworthiness of the Company’s
counterparties on an ongoing basis.  In accordance with the Company’s
standard practice, its commodity and interest rate derivatives are subject to
counterparty netting under agreements governing such derivatives and therefore
the risk of such loss is somewhat mitigated.




Gain
(Loss) on Derivatives




Gains and
losses on derivatives are reported on the condensed consolidated statements 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 noncash items.


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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


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




Three
      Months Ended
                September 30,
            
            Nine
      Months Ended
                September 30,2009
            
            2008
            
            2009
            
            2008(in
      thousands)Realized
      gains (losses):Commodity
      derivatives
            
            $
            97,209
            
            
            $
            (28,270
            )
            
            $
            328,165
            
            
            $
            (62,289
            )Interest
      rate swaps
            
            
            (10,958
            )
            
            
            (5,817
            )
            
            
            (31,629
            )
            
            
            (11,479
            )Canceled
      derivatives
            
            
            44,780
            
            
            
            (13,161
            )
            
            
            48,977
            
            
            
            (81,358
            )$
            131,031
            
            
            $
            (47,248
            )
            
            $
            345,513
            
            
            $
            (155,126
            )Unrealized
      gains (losses):Commodity
      derivatives
            
            $
            (156,054
            )
            
            $
            887,249
            
            
            $
            (462,727
            )
            
            $
            (150,133
            )Interest
      rate swaps
            
            
            (14,751
            )
            
            
            (3,877
            )
            
            
            6,327
            
            
            
            (6,004
            )$
            (170,805
            )
            
            $
            883,372
            
            
            $
            (456,400
            )
            
            $
            (156,137
            )Total
      gains (losses):Commodity
      derivatives
            
            $
            (14,065
            )
            
            $
            845,818
            
            
            $
            (85,525
            )
            
            $
            (293,780
            )Interest
      rate swaps
            
            
            (25,709
            )
            
            
            (9,694
            )
            
            
            (25,362
            )
            
            
            (17,483
            )$
            (39,774
            )
            
            $
            836,124
            
            
            $
            (110,887
            )
            
            $
            (311,263
            )




During
the three months and nine months ended September 30, 2009, the
Company canceled (before the contract settlement date) derivative contracts
on estimated future oil and gas production resulting in realized net gains of
approximately $44.8 million and $49.0 million, respectively.  In July
2009, the Company repositioned its commodity derivative
portfolio.  The Company canceled oil and gas derivative contracts for
years 2012 through 2014 and used the realized net gains of approximately $44.8
million, along with an incremental premium payment of approximately $48.8
million, to raise prices for oil and gas derivative contracts in years 2010 and
2011.




During
the three months and nine months ended September 30, 2008, the Company
canceled (before the contract settlement date) derivative contracts on estimated
future gas production resulting in realized losses of approximately $13.2
million and $81.4 million, respectively.  The future gas production
under the canceled contracts primarily related to properties in the Verden area
and the Appalachian Basin (see Note 2).




(8)
            Fair
      Value Measurements on a Recurring
Basis




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


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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


The
following presents the Company’s fair value hierarchy for assets and liabilities
measured at fair value on a recurring basis at September 30,
2009:




Fair
      Value Measurements on a Recurring Basis
                September 30,
      2009Level
      2
            
            Netting(1)
            
            Total(in
      thousands)Assets:Commodity
      derivatives
            
            $
            636,933
            
            
            $
            (133,019
            )
            
            $
            503,914Interest
      rate swaps
            
            $
            179
            
            
            $
            (179
            )
            
            $
            —Liabilities:Commodity
      derivatives
            
            $
            149,036
            
            
            $
            (133,019
            )
            
            $
            16,017Interest
      rate swaps
            
            $
            77,149
            
            
            $
            (179
            )
            
            $
            76,970




(1)
            Represents
      counterparty netting under derivative netting
  agreements.




(9)
            Asset
      Retirement Obligations




Asset
retirement obligations associated with retiring tangible long-lived assets, are
recognized as a liability in the period in which a legal obligation is incurred
and becomes determinable and are included in “other noncurrent liabilities” on
the condensed consolidated balance sheets.  The fair values of
additions to the asset retirement obligation liability were estimated using
valuation techniques that convert future cash flows to a single discounted
amount.  Significant inputs to the valuation include estimates of:
(i) plug and abandon costs per well; (ii) remaining life per well; and
(iii) a credit-adjusted risk-free interest rate (average of 9.92% for the
nine months ended September 30, 2009).




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




Asset
      retirement obligations at December 31, 2008
            
            $
            28,922Liabilities
      added from acquisitions
            
            
            1,350Liabilities
      added from drilling
            
            
            50Current
      year accretion expense
            
            
            1,789Settlements
            
            
            (509
            )Revision
      of estimates
            
            
            1,037Asset
      retirement obligations at September 30, 2009
            
            $
            32,639


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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)




(10)
            Commitments
      and Contingencies




On
September 15, 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) filed
a voluntary petition for reorganization under Chapter 11 of the United
States Bankruptcy Code (“Chapter 11”) with the United States Bankruptcy Court
for the Southern District of New York (the “Court”).  On
October 3, 2008, Lehman Brothers Commodity Services Inc. (“Lehman Commodity
Services”) also filed a voluntary petition for reorganization under Chapter 11
with the Court.  As of September 30, 2009, and 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.  At
September 30, 2009, and 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” on the condensed consolidated balance sheets
at September 30, 2009, and 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.




(11)
            Earnings
      Per Unit




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


19
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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


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




Income
      (Loss) (Numerator)
              
              Units
      (Denominator)
              
              Per
      Unit Amount(in
      thousands)
 Three
      months ended September 30, 2009:Loss
      from continuing operations:Allocated
      to units
            
            $
            (82,462
            )Allocated
      to unvested restricted units
            
            
            —$
            (82,462
            )Loss
      per unit:Basic
      loss per unit
            
            
            
            
            
            
            119,792
            
            
            $
            (0.69
            )Dilutive
      effect of unit equivalents
            
            
            
            
            
            
            —
            
            
            
            —Diluted
      loss per unit
            
            
            
            
            
            
            119,792
            
            
            $
            (0.69
            )Three
      months ended September 30, 2008:Income
      from continuing operations:Allocated
      to units
            
            $
            921,943Allocated
      to unvested restricted units
            
            
            (6,747
            )$
            915,196Income
      per unit:Basic
      income per unit
            
            
            
            
            
            
            114,321
            
            
            $
            8.01Dilutive
      effect of unit equivalents
            
            
            
            
            
            
            24
            
            
            
            —Diluted
      income per unit
            
            
            
            
            
            
            114,345
            
            
            $
            8.01Nine
      months ended September 30, 2009:Loss
      from continuing operations:Allocated
      to units
            
            $
            (229,876
            )Allocated
      to unvested restricted units
            
            
            —$
            (229,876
            )Loss
      per unit:Basic
      loss per unit
            
            
            
            
            
            
            116,610
            
            
            $
            (1.97
            )Dilutive
      effect of unit equivalents
            
            
            
            
            
            
            —
            
            
            
            —Diluted
      loss per unit
            
            
            
            
            
            
            116,610
            
            
            $
            (1.97
            )Nine
      months ended September 30, 2008:Loss
      from continuing operations:Allocated
      to units
            
            $
            (62,397
            )Allocated
      to unvested restricted units
            
            
            —$
            (62,397
            )Loss
      per unit:Basic
      loss per unit
            
            
            
            
            
            
            114,111
            
            
            $
            (0.55
            )Dilutive
      effect of unit equivalents
            
            
            
            
            
            
            ―
            
            
            
            —Diluted
      loss per unit
            
            
            
            
            
            
            114,111
            
            
            $
            (0.55
            )




Basic
units outstanding excludes the effect of weighted average anti-dilutive unit
equivalents related to 2.2 million and 2.1 million unit options and warrants for
the three months and nine months ended September 30,


20
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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


2009,
respectively.  Basic units outstanding excludes the effect of weighted
average anti-dilutive unit equivalents related to 1.6 million and 1.8 million
unit options and warrants for the three months and nine months ended
September 30, 2008, respectively.  All equivalent units were
anti-dilutive for the three months and nine months ended September 30,
2009, and the nine months ended September 30, 2008.




(12)
            Unit-Based
      Compensation




During
the nine months ended September 30, 2009, the Company granted an aggregate
1,088,755 restricted units and 382,405 unit options to employees, primarily as
part of its annual review of employee compensation, with an aggregate fair value
of approximately $17.6 million.  The unit options and restricted units
vest over three years.  For the three months and nine months ended
September 30, 2009, the Company recorded unit-based compensation expenses
in continuing operations of approximately $3.5 million and $11.5 million,
respectively.  For the three months and nine months ended
September 30, 2008, the Company recorded unit-based compensation expenses
in continuing operations of approximately $3.9 million and $11.4 million,
respectively.  These amounts are included in “lease operating
expenses” or “general and administrative expenses” on the condensed consolidated
statements of operations.




(13)
            Income
      Taxes




The
Company is a limited liability company treated as a partnership for federal and
state income tax purposes, with the exception of the state of Texas, with income
tax liabilities and/or benefits of the Company passed through to
unitholders.  Limited liability companies are subject to state income
taxes in Texas.  As such, with the exception of the state of Texas, it
is not a taxable entity, it does not directly pay federal and state income tax
and recognition has not been given to federal and state income taxes for the
operations of the Company.  In addition, certain of the Company’s
subsidiaries are Subchapter C-corporations subject to federal and state income
taxes.




(14)
            Related
      Party Transactions




During
the nine months ended September 30, 2008, (through July 3), on an
aggregate basis, a group of certain direct or indirect wholly owned subsidiaries
of Lehman Holdings owned more than 10% of the Company’s outstanding
units.  A reference to “Lehman” hereafter in this footnote refers to
Lehman Holdings or one or more of its subsidiaries, as
applicable.  Lehman was considered a related party under the
provisions of GAAP during the period in which its unit ownership exceeded
10%.  Lehman’s subsidiaries provided certain services to the Company,
including participation in the Company’s Third Amended and Restated Credit
Agreement, offering of 2018 Notes (see Note 6) and sale of commodity
derivative instruments (see Note 7), which were all consummated on terms
equivalent to those that prevail in arm’s-length transactions.  During
the nine months ended September 30, 2008, (through July 3), the
Company paid distributions on units to Lehman of approximately $18.5 million,
interest on borrowings of approximately $2.2 million, and financing fees of
approximately $1.8 million.  In addition, during the nine months ended
September 30, 2008, (through July 3), the Company paid Lehman
approximately $18.8 million on settled derivative contracts, and the Company
purchased approximately $1.3 million of oil swap contracts from
Lehman.


21
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 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


(15)
            Supplemental
      Disclosures to the Condensed Consolidated Balance Sheets and Statements of
      Cash Flows




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




September 30,
                2009
            
            December 31,
                2008(in
      thousands)Accrued
      compensation
            
            $
            11,340
            
            
            $
            11,366Accrued
      interest
            
            
            19,512
            
            
            
            14,232Other
            
            
            987
            
            
            
            1,565$
            31,839
            
            
            $
            27,163




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




Nine
      Months Ended
                September 30,2009
            
            2008(in
      thousands)Cash
      payments for interest
            
            $
            50,990
            
            
            $
            78,176Cash
      payments for income taxes
            
            $
            922
            
            
            $
            443Noncash
      investing activities:In
      connection with the acquisition of oil and gas properties, liabilities
      were assumed as follows:Fair
      value of assets acquired
            
            $
            116,882
            
            
            $
            581,712Cash
      paid
            
            
            (116,694
            )
            
            
            (573,096
            )Receivable
      from seller
            
            
            2,729
            
            
            
            —Liabilities
      assumed
            
            $
            2,917
            
            
            $
            8,616Noncash
      financing activities:Units
      issued in connection with the acquisition of oil and gas
      properties
            
            $
            —
            
            
            $
            23,455




For
purposes of the statements of cash flows, the Company considers all highly
liquid short-term investments with original maturities of three months or less
to be cash equivalents.  Restricted cash of $1.9 million and $1.3
million is included in “other noncurrent assets” on the condensed consolidated
balance sheets at September 30, 2009, and December 31, 2008,
respectively, and represents cash the Company has deposited into a separate
account and designated for asset retirement obligations in accordance with
contractual agreements.




(16)
            Recently
      Issued Pronouncements




Codification




In June
2009, the Financial Accounting Standards Board (“FASB”) approved the FASB
Accounting Standards Codification (“Codification”), effective for financial
statements for interim or annual reporting


22
 Table of Contents
 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


periods
ending after September 15, 2009.  The Codification is the single
source of authoritative nongovernmental GAAP, superseding existing FASB,
American Institute of Certified Public Accountants, Emerging Issues Task Force
and related literature.  References herein to prior GAAP standards
that were used to create the Codification have been replaced or supplemented
with references to the relevant section of the Codification and are identified
as “FASB ASC” or “ASC Update.”




Accounting
Standards




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




In May
2009, the FASB issued FASB ASC 855, “Subsequent Events,”which
establishes general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued or
are available to be issued and requires disclosure of the date through which an
entity has evaluated subsequent events.  This standard is effective
for interim and annual periods ending after June 15, 2009, and the Company
adopted it effective June 30, 2009.  The adoption did not have a
material impact on the Company’s results of operations or financial
position.




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




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




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




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


23
 Table of Contents
 LINN
ENERGY, LLC
 NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
 (Unaudited)


significant
assumptions used to estimate the fair value of financial instruments and a
discussion of changes, if any, in the method or methods and significant
assumptions during the period.




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




FASB
ASC 820, “Fair Value
Measurements and Disclosures,” issued in September 2006, provides
guidance for using fair value to measure assets and liabilities.  This
standard applies whenever other standards require (or permit) assets or
liabilities to be measured at fair value and clarifies that for items that are
not actively traded, such as certain kinds of derivatives, fair value should
reflect the price in a transaction with a market participant, including an
adjustment for risk, not just the mark-to-market value.  The Company
adopted the provisions of this standard related to financial assets and
liabilities and nonfinancial assets and liabilities measured on a recurring
basis effective January 1, 2008, and related to nonfinancial assets and
liabilities measured on a nonrecurring basis effective January 1, 2009,
(see Note 2 and Note 9).  There was no impact from the
adoption related to items measured on a nonrecurring basis.




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


·
            nontraditional
      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 SEC is coordinating with the
FASB to obtain the revisions necessary to FASB ASC 932, “Extractive Industries – Oil and
Gas,” to provide consistency with the new rules.  The Company
is currently evaluating the new rules and assessing the impact they will have on
its reported oil and gas reserves.


24
 Table of Contents
 Item 2.
                  Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations


The
following discussion and analysis should be read in conjunction with the
financial statements and related notes included elsewhere in this Quarterly
Report on Form 10-Q and in the Company’s Annual Report on Form 10-K
for the year ended December 31, 2008.  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 in “Cautionary Statement” below and in the 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 Condensed
Consolidated Financial Statements contained in Item 1. “Financial
Statements.”




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 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,
      shallow formations in Oklahoma, and the Permian Basin in Texas and New
      Mexico; and


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




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.




Results
from continuing operations for the three months ended September 30, 2009,
included the following:




·
            oil,
      gas and NGL sales of approximately $103.0 million, compared to $240.6
      million in the third quarter of
2008;


·
            average
      daily production of 217 MMcfe/d, compared to 227 MMcfe/d in the third
      quarter of 2008;


·
            realized
      gains on commodity derivatives of approximately $142.0 million, compared
      to realized losses of $41.4 million in the third quarter of
      2008;


·
            capital
      expenditures, excluding acquisitions, of approximately $24.5 million,
      compared to $59.2 million in the third quarter of 2008;
  and


·
            six
      wells drilled (all successful), compared to 63 wells drilled (all
      successful) in the third quarter of
2008.




Results
from continuing operations for the nine months ended September 30, 2009,
included the following:




·
            oil,
      gas and NGL sales of approximately $274.8 million, compared to $672.1
      million in the nine months ended September 30,
  2008;


·
            average
      daily production of 218 MMcfe/d, compared to 216 MMcfe/d in the nine
      months ended September 30,
2008;


·
            realized
      gains on commodity derivatives of approximately $377.2 million, compared
      to realized losses of $143.6 million in the nine months ended
      September 30, 2008;


·
            capital
      expenditures, excluding acquisitions, of approximately $128.0 million,
      compared to $222.4 million in the nine months ended September 30,
      2008; and


·
            66
      wells drilled (65 successful), compared to 209 wells drilled (207
      successful) in the nine months ended September 30,
    2008.


25
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Public
Offering of Units




In
October 2009, the Company sold 8,625,000 units, representing limited liability
company interests at $21.90 per unit ($21.024 per unit, net of underwriting
discount), for net proceeds (after underwriting discount of $7.6 million and
estimated offering expenses of $0.7 million) of approximately $180.6 million,
which was used to reduce indebtedness under the Company’s Credit
Facility.




Acquisitions




On
August 31, 2009, and September 30, 2009, the Company completed the
acquisitions of certain oil and gas properties located in the Permian Basin in
Texas and New Mexico from Forest for an aggregate contract price of $117.6
million.  The Company paid $116.5 million in cash and recorded a
receivable from Forest of approximately $2.7 million, resulting in total
consideration for the acquisitions of approximately $113.8
million.  See Note 2 for additional details.  The
transactions were financed with borrowings from the Company’s Credit
Facility.  The acquisitions represent a strategic entry into the
Permian Basin for the Company, and include approximately 72 Bcfe of proved
reserves, primarily oil.




Commodity
Derivative Repositioning




In July
2009, the Company repositioned its commodity derivative portfolio to help
protect against sustained weakness in commodity prices.  The Company
canceled oil and gas derivative contracts for years 2012 through 2014 and
realized net gains of approximately $44.8 million, which, along with an
incremental premium payment of approximately $48.8 million, was used to raise
prices for its oil and gas derivative contracts in years 2010 and
2011.




Credit
and Capital Market Conditions




Multiple
events involving numerous financial institutions have restricted current
liquidity within the capital markets throughout the United States and around the
world.  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.  In addition, the Company
cannot be assured that counterparties to the Company’s derivative contracts or
lenders in the Company’s Credit Facility will be able to perform under these
agreements.  For additional information about the Company’s credit
risk related to derivative contracts see “Counterparty Credit Risk” in
“Liquidity and Capital Resources” below.


26
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Results
of Operations – Continuing Operations




Three
Months Ended September 30, 2009, Compared to Three Months Ended
September 30, 2008




Three
      Months Ended
                September 30,2009
            
            2008
            
            Variance(in
      thousands)Revenues
      and other:Gas
      sales
            
            $
            35,208
            
            
            $
            100,558
            
            
            $
            (65,350
            )Oil
      sales
            
            
            50,135
            
            
            
            95,888
            
            
            
            (45,753
            )NGL
      sales
            
            
            17,646
            
            
            
            44,188
            
            
            
            (26,542
            )Total
      oil, gas and NGL sales
            
            
            102,989
            
            
            
            240,634
            
            
            
            (137,645
            )Gain
      (loss) on oil and gas derivatives (1)
            
            
            (14,065
            )
            
            
            845,818
            
            
            
            (859,883
            )Gas
      marketing revenues
            
            
            1,351
            
            
            
            4,647
            
            
            
            (3,296
            )Other
      revenues
            
            
            150
            
            
            
            561
            
            
            
            (411
            )$
            90,425
            
            
            $
            1,091,660
            
            
            $
            (1,001,235
            )Expenses:Lease
      operating expenses
            
            $
            33,453
            
            
            $
            33,503
            
            
            $
            (50
            )Transportation
      expenses
            
            
            6,367
            
            
            
            5,683
            
            
            
            684Gas
      marketing expenses
            
            
            98
            
            
            
            4,061
            
            
            
            (3,963
            )General
      and administrative expenses (2)
            
            
            19,655
            
            
            
            18,692
            
            
            
            963Exploration
      costs
            
            
            861
            
            
            
            268
            
            
            
            593Bad
      debt expenses
            
            
            500
            
            
            
            1,436
            
            
            
            (936
            )Depreciation,
      depletion and amortization
            
            
            49,440
            
            
            
            52,004
            
            
            
            (2,564
            )Taxes,
      other than income taxes
            
            
            5,965
            
            
            
            17,242
            
            
            
            (11,277
            )(Gain)
      loss on sale of assets and other, net
            
            
            1,999
            
            
            
            ―
            
            
            
            1,999$
            118,338
            
            
            $
            132,889
            
            
            $
            (14,551
            )Other
      income and (expenses)
            
            $
            (54,491
            )
            
            $
            (35,826
            )
            
            $
            (18,665
            )Income
      (loss) from continuing operations before income taxes
            
            $
            (82,404
            )
            
            $
            922,945
            
            
            $
            (1,005,349
            )




Notes
to table:




(1)
            During
      the three months ended September 30, 2009, the Company repositioned
      its commodity derivative portfolio to help protect against sustained
      weakness in commodity prices and canceled (before the contract settlement
      date) derivative contracts on estimated future oil and gas production
      resulting in realized net gains of approximately $44.8
      million.  During the three months ended September 30, 2008,
      the Company canceled (before the contract settlement date) derivative
      contracts on estimated future gas production primarily associated with
      properties in the Verden area (see Note 2) resulting in realized
      losses of approximately $13.2
million.




(2)
            General
      and administrative expenses for the three months ended September 30,
      2009, and September 30, 2008, include approximately $3.4 million and
      $3.9 million, respectively, of noncash unit-based compensation
      expenses.


27
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued




Three
      Months Ended
                September 30,2009
            
            2008
            
            VarianceAverage
      daily production:Gas
      (MMcf/d)
            
            
            122
            
            
            
            127
            
            
            
            (4
            )%Oil
      (MBbls/d)
            
            
            8.8
            
            
            
            9.5
            
            
            
            (7
            )%NGL
      (MBbls/d)
            
            
            7.1
            
            
            
            7.3
            
            
            
            (3
            )%Total
      (MMcfe/d)
            
            
            217
            
            
            
            227
            
            
            
            (4
            )%Weighted average prices
      (hedged):(1)Gas
      (Mcf)
            
            $
            8.38
            
            
            $
            8.05
            
            
            
            4
            %Oil
      (Bbl)
            
            $
            109.30
            
            
            $
            85.30
            
            
            
            28
            %NGL
      (Bbl)
            
            $
            27.06
            
            
            $
            65.56
            
            
            
            (59
            )%Weighted average prices
      (unhedged):(2)Gas
      (Mcf)
            
            $
            3.14
            
            
            $
            8.63
            
            
            
            (64
            )%Oil
      (Bbl)
            
            $
            61.90
            
            
            $
            109.96
            
            
            
            (44
            )%NGL
      (Bbl)
            
            $
            27.06
            
            
            $
            65.56
            
            
            
            (59
            )%Representative
      NYMEX oil and gas prices:Gas
      (MMBtu)
            
            $
            3.39
            
            
            $
            10.25
            
            
            
            (67
            )%Oil
      (Bbl)
            
            $
            68.86
            
            
            $
            117.98
            
            
            
            (42
            )%Costs
      per Mcfe of production:Lease
      operating expenses
            
            $
            1.67
            
            
            $
            1.60
            
            
            
            4
            %Transportation
      expenses
            
            $
            0.32
            
            
            $
            0.27
            
            
            
            19
            %General
      and administrative expenses (3)
            
            $
            0.98
            
            
            $
            0.89
            
            
            
            10
            %Depreciation,
      depletion and amortization
            
            $
            2.47
            
            
            $
            2.49
            
            
            
            (1
            )%Taxes,
      other than income taxes
            
            $
            0.30
            
            
            $
            0.82
            
            
            
            (63
            )%




Notes
to table:




(1)
            Includes
      the effect of realized gains (losses) on derivatives of approximately
      $97.2 million (excluding $44.8 million realized net gains on canceled
      contracts) and $(28.2) million (excluding $13.2 million realized losses on
      canceled contracts) for the three months ended September 30, 2009,
      and September 30, 2008, respectively.  The Company utilizes
      oil puts to hedge revenues associated with its NGL production; therefore,
      all realized gains (losses) on oil derivative contracts are included in
      weighted average oil prices, rather than weighted average NGL
      prices.




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




(3)
            General
      and administrative expenses for the three months ended September 30,
      2009, and September 30, 2008, include approximately $3.4 million and
      $3.9 million, respectively, of noncash unit-based compensation
      expenses.  Excluding these amounts, general and administrative
      expenses for the three months ended September 30, 2009, and
      September 30, 2008, were $0.81 per Mcfe and $0.71 per Mcfe,
      respectively.  This is a non-GAAP measure used by management to
      analyze the Company’s performance.


28
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Revenues
and Other




Oil,
Gas and NGL Sales


Oil, gas
and NGL sales decreased by approximately $137.6 million, or 57%, to
approximately $103.0 million for the three months ended September 30, 2009,
from $240.6 million for the three months ended September 30, 2008, due to
lower commodity prices.  Lower gas, oil and NGL prices resulted in a
decrease in revenues of approximately $61.7 million, $38.9 million and $25.1
million, respectively.




Average
daily production decreased to 217 MMcfe/d during the three months ended
September 30, 2009, from 227 MMcfe/d during the three months ended
September 30, 2008.  Volume decreases during the three months
ended September 30, 2009, resulted in a decrease in total oil, gas and NGL
revenues of approximately $11.9 million compared to the three months ended
September 30, 2008.




The
following presents average daily production by region:




Three
      Months Ended
                September 30,2009
            
            2008
            
            VarianceAverage
      daily production (MMcfe/d):Mid-Continent
      Deep
            
            
            132
            
            
            
            147
            
            
            
            (15
            )
            
            
            (10
            )%Mid-Continent
      Shallow
            
            
            71
            
            
            
            65
            
            
            
            6
            
            
            
            9
            %Western
            
            
            14
            
            
            
            15
            
            
            
            (1
            )
            
            
            (7
            )%217
            
            
            
            227
            
            
            
            (10
            )
            
            
            (4
            )%




The 10%
decrease in average daily production in the Mid-Continent Deep region primarily
reflects the Company’s sale of assets in Oklahoma in August 2008 (see
Note 2), its decision to suspend completions on recent wells drilled in the
Granite Wash and shut-in production on certain wells.  The 9% increase
in average daily production in the Mid-Continent Shallow region reflects results
of the Company’s drilling and optimization programs.  The Western
region consists of a very low-decline asset base and continues to produce at
levels consistent with the comparable period of the prior year.




Gain
(Loss) on Oil and Gas Derivatives


The
Company determines the fair value of its oil and gas derivatives utilizing
pricing models that use a variety of techniques, including market quotes and
pricing analysis.  See Note 7 and Note 8 for additional
information about commodity derivatives.  During the three months
ended September 30, 2009, the Company had commodity derivative contracts in
place for approximately 116% of its gas production and 77% of its oil and NGL
production, which resulted in realized gains of approximately $142.0 million
(including realized net gains on canceled contracts of approximately $44.8
million).  In July 2009, the Company repositioned its commodity
derivative portfolio to help protect against sustained weakness in commodity
prices.  The Company canceled oil and gas derivative contracts for
years 2012 through 2014 and used the realized net gains of approximately $44.8
million, along with an incremental premium payment of approximately $48.8
million, to raise prices for oil and gas derivative contracts in years 2010 and
2011.  During the three months ended September 30, 2008, the
Company recorded realized losses of approximately $41.4 million (including
realized losses on canceled contracts of approximately $13.2
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 third quarter
of 2009, expected future oil and gas prices increased, which resulted in
unrealized losses on derivatives of approximately $156.1 million for the three
months ended September 30, 2009.  During the third quarter of
2008, expected future oil and gas prices decreased, which resulted in unrealized
gains on derivatives of approximately $887.2 million for the three months ended
September 30, 2008.  For information about the Company’s credit
risk related to derivative contracts see “Counterparty Credit Risk” in
“Liquidity and Capital Resources” below.  29
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Expenses




Lease
Operating Expenses


Lease
operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies and workover
expenses.  Lease operating expenses were approximately $33.5 million
for the three months ended September 30, 2009, and September 30,
2008.  Lease operating expenses per Mcfe increased, to $1.67 per Mcfe
for the three months ended September 30, 2009, from $1.60 per Mcfe for the
three months ended September 30, 2008, primarily due to decreased
production levels during the three months ended September 30,
2009.




Transportation
Expenses


Transportation
expenses increased by approximately $0.7 million, or 12%, to $6.4 million for
the three months ended September 30, 2009, from $5.7 million for the three
months ended September 30, 2008, primarily due to increased expenses on
nonoperated properties.




General
and Administrative Expenses


General
and administrative expenses are costs not directly associated with field
operations and include costs of employees and executive officers, related
benefits, office leases and professional fees.  General and
administrative expenses increased by approximately $1.0 million, or 5%, to $19.7
million for the three months ended September 30, 2009, from $18.7 million
for the three months ended September 30, 2008.  General and
administrative expenses per Mcfe also increased, to $0.98 per Mcfe for the three
months ended September 30, 2009, from $0.89 per Mcfe for the three months
ended September 30, 2008.  The increase was primarily due to an
increase in salaries and benefits expense of approximately $3.3 million,
partially offset by lower professional fees and insurance expenses.




Exploration
Costs


Exploration
costs were approximately $0.9 million for the three months ended
September 30, 2009, compared to $0.3 million for the three months ended
September 30, 2008.  The increase was primarily due to an
increase in unproved leasehold costs of approximately $0.6 million during the
three months ended September 30, 2009.




Depreciation,
Depletion and Amortization


Depreciation,
depletion and amortization decreased slightly, by approximately $2.6 million, or
5%, to $49.4 million for the three months ended September 30, 2009, from
$52.0 million for the three months ended September 30, 2008, primarily due
to decreased production levels during the three months ended September 30,
2009.  Depreciation, depletion and amortization per Mcfe also
decreased slightly to $2.47 per Mcfe for the three months ended
September 30, 2009, from $2.49 per Mcfe for the three months ended
September 30, 2008.




Taxes,
Other Than Income Taxes


Taxes,
other than income taxes, which consist primarily of production and ad valorem
taxes, decreased by approximately $11.2 million, or 65%, to $6.0 million for the
three months ended September 30, 2009, from $17.2 million for the three
months ended September 30, 2008.  Production taxes, which are a
function of revenues generated from production, decreased by approximately $10.5
million compared to the three months ended September 30, 2008, primarily
due to lower commodity prices.  Ad valorem taxes, which are based on
the value of reserves and production equipment and vary by location, also
decreased slightly compared to the three months ended September 30,
2008.  30
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Other
Income and (Expenses)




Three
      Months Ended
                September 30,2009
            
            2008
            
            Variance(in
      thousands)Interest
      expense, net of amounts capitalized
            
            $
            (28,025
            )
            
            $
            (22,574
            )
            
            $
            (5,451
            )Loss
      on interest rate swaps
            
            
            (25,709
            )
            
            
            (9,694
            )
            
            
            (16,015
            )Other,
      net
            
            
            (757
            )
            
            
            (3,558
            )
            
            
            2,801$
            (54,491
            )
            
            $
            (35,826
            )
            
            $
            (18,665
            )




Other
income and (expenses) increased by approximately $18.7 million, due primarily to
interest rate swap losses.  The unrealized mark-to-market loss on
interest rate swaps increased as the forward curve decreased during the three
months ended September 30, 2009, as compared to the three months ended
September 30, 2008.  Realized losses on interest rate swaps also
increased during the three months ended September 30, 2009, compared to the
three months ended September 30, 2008.




In the
second quarter of 2009, the Company entered into an amended and restated Credit
Facility and issued senior notes due 2017, which resulted in increased interest
expense due to higher interest rates and amortization of financing
fees.  See “Credit Facility” and “Senior Notes Due 2017” in “Liquidity
and Capital Resources” below for additional details.




Income
Tax Expense




Income
tax expense was approximately $0.1 million and $1.0 million for the three months
ended September 30, 2009, and September 30, 2008, respectively, and
primarily represents Texas margin tax expense.  The Company is a
limited liability company treated as a partnership for federal and state income
tax purposes, with the exception of the state of Texas, with income tax
liabilities and/or benefits of the Company passed through to
unitholders.  Limited liability companies are subject to state income
taxes in Texas.  In addition, certain of the Company’s subsidiaries
are Subchapter C-corporations subject to federal and state income
taxes.


31
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Results
of Operations – Continuing Operations




Nine
Months Ended September 30, 2009, Compared to Nine Months Ended
September 30, 2008




Nine
      Months Ended
                September 30,2009
            
            2008
            
            Variance(in
      thousands)Revenues
      and other:Gas
      sales
            
            $
            111,749
            
            
            $
            304,317
            
            
            $
            (192,568
            )Oil
      sales
            
            
            119,171
            
            
            
            257,940
            
            
            
            (138,769
            )NGL
      sales
            
            
            43,839
            
            
            
            109,835
            
            
            
            (65,996
            )Total
      oil, gas and NGL sales
            
            
            274,759
            
            
            
            672,092
            
            
            
            (397,333
            )Loss
      on oil and gas derivatives (1)
            
            
            (85,525
            )
            
            
            (293,780
            )
            
            
            208,255Gas
      marketing revenues
            
            
            3,050
            
            
            
            11,056
            
            
            
            (8,006
            )Other
      revenues
            
            
            1,757
            
            
            
            1,682
            
            
            
            75$
            194,041
            
            
            $
            391,050
            
            
            $
            (197,009
            )Expenses:Lease
      operating expenses
            
            $
            100,322
            
            
            $
            78,154
            
            
            $
            22,168Transportation
      expenses
            
            
            11,850
            
            
            
            12,674
            
            
            
            (824
            )Gas
      marketing expenses
            
            
            1,318
            
            
            
            9,581
            
            
            
            (8,263
            )General
      and administrative expenses (2)
            
            
            63,247
            
            
            
            55,788
            
            
            
            7,459Exploration
      costs
            
            
            4,625
            
            
            
            2,949
            
            
            
            1,676Bad
      debt expenses
            
            
            500
            
            
            
            1,436
            
            
            
            (936
            )Depreciation,
      depletion and amortization
            
            
            151,934
            
            
            
            147,259
            
            
            
            4,675Taxes,
      other than income taxes
            
            
            21,414
            
            
            
            47,843
            
            
            
            (26,429
            )(Gain)
      loss on sale of assets and other, net
            
            
            (24,717
            )
            
            
            —
            
            
            
            (24,717
            )$
            330,493
            
            
            $
            355,684
            
            
            $
            (25,191
            )Other
      income and (expenses)
            
            $
            (93,045
            )
            
            $
            (96,716
            )
            
            $
            3,671Loss
      from continuing operations before income taxes
            
            $
            (229,497
            )
            
            $
            (61,350
            )
            
            $
            (168,147
            )




Notes
to table:




(1)
            During
      the nine months ended September 30, 2009, the Company canceled
      (before the contract settlement date) derivative contracts on estimated
      future oil and gas production resulting in realized net gains of
      approximately $49.0 million, primarily associated with the Company’s
      commodity derivative repositioning in July 2009.  During the
      nine months ended September 30, 2008, the Company canceled (before
      the contract settlement date) derivative contracts on estimated future gas
      production primarily associated with properties in the Verden area and the
      Appalachian Basin (see Note 2) resulting in realized losses of
      approximately $81.4 million.




(2)
            General
      and administrative expenses for the nine months ended September 30,
      2009, and September 30, 2008, include approximately $11.2 million and
      $11.3 million, respectively, of noncash unit-based compensation
      expenses.


32
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued




Nine
      Months Ended
                September 30,2009
            
            2008
            
            VarianceAverage
      daily production:Gas
      (MMcf/d)
            
            
            129
            
            
            
            127
            
            
            
            2
            %Oil
      (MBbls/d)
            
            
            8.8
            
            
            
            8.9
            
            
            
            (1
            )%NGL
      (MBbls/d)
            
            
            6.1
            
            
            
            6.0
            
            
            
            2
            %Total
      (MMcfe/d)
            
            
            218
            
            
            
            216
            
            
            
            1
            %Weighted average prices
      (hedged):(1)Gas
      (Mcf)
            
            $
            8.16
            
            
            $
            8.75
            
            
            
            (7
            )%Oil
      (Bbl)
            
            $
            113.69
            
            
            $
            80.85
            
            
            
            41
            %NGL
      (Bbl)
            
            $
            26.47
            
            
            $
            67.34
            
            
            
            (61
            )%Weighted average prices
      (unhedged):(2)Gas
      (Mcf)
            
            $
            3.18
            
            
            $
            8.78
            
            
            
            (64
            )%Oil
      (Bbl)
            
            $
            49.68
            
            
            $
            106.06
            
            
            
            (53
            )%NGL
      (Bbl)
            
            $
            26.47
            
            
            $
            67.34
            
            
            
            (61
            )%Representative
      NYMEX oil and gas prices:Gas
      (MMBtu)
            
            $
            3.93
            
            
            $
            9.74
            
            
            
            (60
            )%Oil
      (Bbl)
            
            $
            57.19
            
            
            $
            113.29
            
            
            
            (50
            )%Costs
      per Mcfe of production:Lease
      operating expenses
            
            $
            1.69
            
            
            $
            1.32
            
            
            
            28
            %Transportation
      expenses
            
            $
            0.20
            
            
            $
            0.21
            
            
            
            (5
            )%General
      and administrative expenses (3)
            
            $
            1.06
            
            
            $
            0.94
            
            
            
            13
            %Depreciation,
      depletion and amortization
            
            $
            2.56
            
            
            $
            2.49
            
            
            
            3
            %Taxes,
      other than income taxes
            
            $
            0.36
            
            
            $
            0.81
            
            
            
            (56
            )%




Notes
to table:




(1)
            Includes
      the effect of realized gains (losses) on derivatives of approximately
      $328.2 million (excluding $49.0 million realized net gains on canceled
      contracts) and $(62.2) million (excluding $81.4 million realized losses on
      canceled contracts) for the nine months ended September 30, 2009, and
      September 30, 2008, respectively.  The Company utilizes oil
      puts to hedge revenues associated with its NGL production; therefore, all
      realized gains (losses) on oil derivative contracts are included in
      weighted average oil prices, rather than weighted average NGL
      prices.




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




(3)
            General
      and administrative expenses for the nine months ended September 30,
      2009, and September 30, 2008, include approximately $11.2 million and
      $11.3 million, respectively, of noncash unit-based compensation
      expenses.  Excluding these amounts, general and administrative
      expenses for the nine months ended September 30, 2009, and
      September 30, 2008, were $0.88 per Mcfe and $0.75 per Mcfe,
      respectively.  This is a non-GAAP measure used by management to
      analyze the Company’s performance.


33
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Revenues
and Other




Oil,
Gas and NGL Sales


Oil, gas
and NGL sales decreased by approximately $397.3 million, or 59%, to
approximately $274.8 million for the nine months ended September 30, 2009,
from $672.1 million for the nine months ended September 30, 2008, due to
lower commodity prices.  Lower gas, oil and NGL prices resulted in a
decrease in revenues of approximately $196.1 million, $135.3 million and $67.7
million, respectively.




Average
daily production increased to 218 MMcfe/d during the nine months ended
September 30, 2009, from 216 MMcfe/d during the nine months ended
September 30, 2008.  Volume increases during the nine months
ended September 30, 2009, resulted in an increase in total oil, gas and NGL
revenues of approximately $1.8 million compared to the nine months ended
September 30, 2008.




The
following presents average daily production by region:




Nine
      Months Ended
                September 30,2009
            
            2008
            
            VarianceAverage
      daily production (MMcfe/d):Mid-Continent
      Deep
            
            
            137
            
            
            
            141
            
            
            
            (4
            )
            
            
            (3
            )%Mid-Continent
      Shallow
            
            
            67
            
            
            
            61
            
            
            
            6
            
            
            
            10
            %Western
            
            
            14
            
            
            
            14
            
            
            
            —
            
            
            
            —218
            
            
            
            216
            
            
            
            2
            
            
            
            1
            %




The 3%
decrease in average daily production in the Mid-Continent Deep region reflects
results of the Company’s sale of assets in Oklahoma in August 2008 (see
Note 2), its decision to suspend completions on recent wells drilled in the
Granite Wash and shut-in production on certain wells.  The 10%
increase in average daily production in the Mid-Continent Shallow region
reflects results of the Company’s drilling and optimization
programs.  The Western region consists of a very low-decline asset
base and continues to produce at levels consistent with the comparable period of
the prior year.




Gain
(Loss) on Oil and Gas Derivatives


The
Company determines the fair value of its oil and gas derivatives utilizing
pricing models that use a variety of techniques, including market quotes and
pricing analysis.  See Note 7 and Note 8 for additional
information about commodity derivatives.  During the nine months ended
September 30, 2009, the Company had commodity derivative contracts in place
for approximately 111% of its gas production and 84% of its oil and NGL
production, which resulted in realized gains of approximately $377.2 million
(including realized net gains on canceled contracts of approximately $49.0
million).  In July 2009, the Company repositioned its commodity
derivative portfolio to help protect against sustained weakness in commodity
prices.  The Company canceled oil and gas derivative contracts for
years 2012 through 2014 and used the realized net gains of approximately $44.8
million, along with an incremental premium payment of approximately $48.8
million, to raise prices for oil and gas derivative contracts in years 2010 and
2011.  During the nine months ended September 30, 2008, the
Company recorded realized losses of approximately $143.6 million (including
realized losses on canceled contracts of approximately $81.4
million).  Unrealized gains and losses result from changes in market
valuations of derivatives as future commodity price expectations change compared
to the contract prices on the derivatives.  During the first nine
months of 2009 and 2008, expected future oil and gas prices increased, which
resulted in unrealized losses on derivatives of approximately $462.7 million and
$150.1 million for the nine months ended September 30, 2009, and
September 30, 2008, respectively.  For information about the
Company’s credit risk related to derivative contracts see “Counterparty Credit
Risk” in “Liquidity and Capital Resources” below.


34
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Expenses




Lease
Operating Expenses


Lease
operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies and workover
expenses.  Lease operating expenses increased by approximately $22.1
million, or 28%, to $100.3 million for the nine months ended September 30,
2009, from $78.2 million for the nine months ended September 30,
2008.  Lease operating expenses per Mcfe also increased, to $1.69 per
Mcfe for the nine months ended September 30, 2009, from $1.32 per Mcfe for
the nine months ended September 30, 2008.  Lease operating
expenses increased primarily due to costs associated with properties acquired in
the first quarter of 2008 in the Mid-Continent Shallow region (see Note 2),
as well as materials and service cost increases across all operating
regions.  In addition, higher chemical and treating costs associated
with certain wells drilled in late 2008 contributed to the
increase.




Transportation
Expenses


Transportation
expenses decreased by approximately $0.8 million, or 6%, to $11.9 million for
the nine months ended September 30, 2009, from $12.7 million for the nine
months ended September 30, 2008, driven primarily by lower fuel
costs.




General
and Administrative Expenses


General
and administrative expenses are costs not directly associated with field
operations and include costs of employees and executive officers, related
benefits, office leases and professional fees.  General and
administrative expenses increased by approximately $7.4 million, or 13%, to
$63.2 million for the nine months ended September 30, 2009, from $55.8
million for the nine months ended September 30, 2008.  General
and administrative expenses per Mcfe also increased, to $1.06 per Mcfe for the
nine months ended September 30, 2009, from $0.94 per Mcfe for the nine
months ended September 30, 2008.  The increase was primarily due
to an increase in salaries and benefits expense of approximately $6.5
million.




Exploration
Costs


Exploration
costs increased by approximately $1.7 million, or 59%, to $4.6 million for the
nine months ended September 30, 2009, from $2.9 million for the nine months
ended September 30, 2008.  The increase was primarily due to an
increase in unproved leasehold costs of approximately $3.9 million, partially
offset by decreases in 3-D seismic and data library expenses.




Depreciation,
Depletion and Amortization


Depreciation,
depletion and amortization increased by approximately $4.6 million, or 3%, to
$151.9 million for the nine months ended September 30, 2009, from $147.3
million for the nine months ended September 30, 2008.  Higher
total production levels and higher depletion rates associated with downward
year-end price-related reserve revisions were the main reason for the
increase.  Depreciation, depletion and amortization per Mcfe increased
to $2.56 per Mcfe for the nine months ended September 30, 2009, from $2.49
per Mcfe for the nine months ended September 30, 2008.




Taxes,
Other Than Income Taxes


Taxes,
other than income taxes, which consist primarily of production and ad valorem
taxes, decreased by approximately $26.4 million, or 55%, to $21.4 million for
the nine months ended September 30, 2009, from $47.8 million for the nine
months ended September 30, 2008.  Production taxes, which are a
function of revenues generated from production, decreased by approximately $26.6
million compared to the nine months ended September 30, 2008, primarily due
to lower commodity prices.  Ad valorem taxes, which are based on the
value of reserves and production equipment and vary by location, increased
slightly compared to the nine months ended September 30, 2008.




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


The
increase in (gain) loss on sale of assets and other, net for the nine months
ended September 30, 2009, was primarily due to a gain of $25.4 million from
the sale of Woodford Shale assets (see Note 2).  35
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Other
Income and (Expenses)




Nine
      Months Ended
                September 30,2009
            
            2008
            
            Variance(in
      thousands)Interest
      expense, net of amounts capitalized
            
            $
            (65,696
            )
            
            $
            (71,199
            )
            
            $
            5,503Loss
      on interest rate swaps
            
            
            (25,362
            )
            
            
            (17,483
            )
            
            
            (7,879
            )Other,
      net
            
            
            (1,987
            )
            
            
            (8,034
            )
            
            
            6,047$
            (93,045
            )
            
            $
            (96,716
            )
            
            $
            3,671




Other
income and (expenses) decreased by approximately $3.7 million during the nine
months ended September 30, 2009, compared to the nine months ended
September 30, 2008.  Interest expense decreased, driven by lower
interest rates on the Credit Facility due to lower LIBOR
rates.  Realized losses on interest rate swaps increased, as the
average settlement interest rate decreased during the nine months ended
September 30, 2009.  These losses were partially offset by
unrealized mark-to-market gains on interest rate swaps during the nine months
ended September 30, 2009, compared to unrealized losses during the nine
months ended September 30, 2008.  In addition, the Company wrote
off deferred financing fees of approximately $4.6 million during the nine months
ended September 30, 2008.




Income
Tax Expense




Income
tax expense was approximately $0.4 million and $1.0 million for the nine months
ended September 30, 2009, and September 30, 2008, respectively, and
primarily represents Texas margin tax expense.  The Company is a
limited liability company treated as a partnership for federal and state income
tax purposes, with the exception of the state of Texas, with income tax
liabilities and/or benefits of the Company passed through to
unitholders.  Limited liability companies are subject to state income
taxes in Texas.  In addition, certain of the Company’s subsidiaries
are Subchapter C-corporations subject to federal and state income
taxes.


36
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Liquidity
and Capital Resources




Overview




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.  For
the nine months ended September 30, 2009, the Company’s capital
expenditures, excluding acquisitions, were approximately $128.0
million.  For 2009, the Company estimates its capital expenditures,
excluding acquisitions, will be approximately $150.0 million.  This
estimate is under continuous review and is subject to ongoing
adjustment.  The Company expects to fund these capital expenditures
with cash flow from operations.




As the
Company pursues growth, it continually monitors the capital resources available
to meet future financial obligations and planned capital
expenditures.  The Company’s future success in growing reserves and
production 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.  In April 2009, the Company entered into an amended
and restated Credit Facility with a maturity of August 2012.  See
“Credit Facility” below for additional details.  At October 30,
2009, the Company had $535.0 million in available borrowing capacity under its
Credit Facility.  The Company’s Credit Facility, 2017 Notes and 2018
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.




Cash
Flows




The
following presents a comparative cash flow summary:




Nine
      Months Ended
                September 30,2009
            
            2008
            
            Variance(in
      thousands)Net
      cash:Provided
      by operating activities(1)
            
            $
            330,124
            
            
            $
            42,788
            
            
            $
            287,336Used
      in investing activities
            
            
            (247,993
            )
            
            
            (84,105
            )
            
            
            (163,888
            )Provided
      by (used in) financing activities
            
            
            (100,204
            )
            
            
            87,145
            
            
            
            (187,349
            )Net
      increase (decrease) in cash and cash equivalents
            
            $
            (18,073
            )
            
            $
            45,828
            
            
            $
            (63,901
            )




(1)
            The
      nine months ended September 30, 2009, and September 30, 2008,
      include premiums paid for derivatives of approximately $93.6 million and
      $129.5 million, respectively.




Operating
Activities


Cash
provided by operating activities for the nine months ended September 30,
2009, was approximately $330.1 million, compared to $42.8 million for the nine
months ended September 30, 2008.  The increase in operating cash
flow was driven by increased cash from working capital as cash collections on
accounts receivable increased because of higher commodity prices in the fourth
quarter of 2008.  Higher realized gains from oil and gas derivatives,
partially offset by reduced oil and gas revenues associated with lower commodity
prices in 2009, also contributed to the increase in operating cash
flow.  37
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Premiums
paid were for commodity derivative contracts that hedge future
production.  These derivative contracts provide the Company long-term
cash flow predictability to pay distributions, service debt and manage its
business and are primarily funded through the Company’s Credit
Facility.  See Note 7 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


The
primary use of cash in investing activities is for capital spending, which is
offset by proceeds from asset sales.  Cash used in investing
activities was approximately $248.0 million for the nine months ended
September 30, 2009, compared to $84.1 million for the nine months ended
September 30, 2008.  The increase in cash used in investing
activities was primarily due to reduced divestiture activity during the nine
months ended September 30, 2009, compared to the nine months ended
September 30, 2008.  Cash used in investing activities for the
nine months ended September 30, 2009, includes approximately $116.5 million
for the acquisition of Permian Basin properties in the Mid-Continent Shallow
region (see Note 2).  The following provides a comparative summary of
cash flow from investing activities:




Nine
      Months Ended
                September 30,2009
            
            2008(in
      thousands)Cash
      flow from investing activities:Acquisition
      of oil and gas properties
            
            $
            (116,694
            )
            
            $
            (573,096
            )Capital
      expenditures
            
            
            (157,981
            )
            
            
            (255,142
            )Proceeds
      from sale of properties and equipment
            
            
            26,682
            
            
            
            744,133$
            (247,993
            )
            
            $
            (84,105
            )





Financing
Activities


Cash used
in financing activities was approximately $100.2 million for the nine months
ended September 30, 2009, compared to cash provided by financing activities
of $87.1 million for the nine months ended September 30,
2008.  The change in financing cash flow was primarily due to
increased operating cash flow and decreased acquisition and development activity
during the nine months ended September 30, 2009, which resulted in lower
net borrowings compared to the same period of 2008.  The following
provides a comparative summary of proceeds from borrowings and repayments of
debt:




Nine
      Months Ended
                September 30,2009
            
            2008(in
      thousands)Proceeds
      from borrowings:Credit
      facility
            
            $
            361,500
            
            
            $
            772,000Senior
      notes
            
            
            237,703
            
            
            
            250,000Term
      loan
            
            
            —
            
            
            
            400,000$
            599,203
            
            
            $
            1,422,000Repayments
      of debt:Credit
      facility
            
            $
            (513,893
            )
            
            $
            (693,607
            )Term
      loan
            
            
            —
            
            
            
            (400,000
            )Notes
      payable
            
            
            —
            
            
            
            (1,509
            )$
            (513,893
            )
            
            $
            (1,095,116
            )


38
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


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 nine months ended September 30,
2009:




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




On
October 21, 2009, the Company’s Board of Directors declared a cash
distribution of $0.63 per unit with respect to the third quarter of
2009.  The distribution, totaling approximately $81.9 million, will be
paid November 13, 2009, to unitholders of record as of the close of
business November 6, 2009.




Credit
Facility




On
April 28, 2009, the Company entered into a Credit Facility with an initial
borrowing base of $1.75 billion and a maturity of August 2012, which amended and
restated the Company’s existing credit facility, which had a maturity of August
2010.  The terms of the Credit Facility required that, upon the
issuance of the senior notes due 2017 in May 2009 (see below) and cancelation of
certain commodity derivatives in July 2009 (see Note 7), the borrowing base
be decreased by approximately $62.5 million and $45.0 million,
respectively.  At October 30, 2009, available borrowing capacity
was $535.0 million, which includes a $5.5 million reduction in availability for
outstanding letters of credit.  In connection with the amended and
restated Credit Facility, during the nine months ended September 30, 2009,
the Company paid approximately $52.7 million in financing fees and expenses,
which were deferred and will be amortized over the life of the Credit
Facility.




Redetermination
of the borrowing base under the Credit Facility occurs semi-annually, in April
and October, as well as upon the occurrence of certain events, by the lenders in
their sole discretion, based primarily on reserve reports that reflect oil and
gas prices at such time.  Significant declines in oil, gas or NGL
prices may result in a decrease in the borrowing base.  The Company’s
obligations under the Credit Facility are secured by mortgages on its oil and
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 material operating subsidiaries and may
be guaranteed by any future subsidiaries.




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




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


39
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


earnings
to interest expense and current liquidity financial ratios.  The
Company is in compliance with all financial and other covenants of its Credit
Facility.




Senior
Notes Due 2017




On
May 12, 2009, the Company entered into a purchase agreement with a group of
Initial Purchasers, pursuant to which the Company agreed to issue $250.0 million
in aggregate principal amount of the Company’s senior notes due
2017.  The 2017 Notes were offered and sold to the Initial Purchasers
and then resold to qualified institutional buyers, each in transactions exempt
from the registration requirements of the Securities Act.  The Company
used the net proceeds (after deducting the Initial Purchasers’ discounts and
offering expenses) of approximately $230.8 million to reduce indebtedness under
its Credit Facility.  In connection with the 2017 Notes, the Company
incurred financing fees and expenses of approximately $6.9 million, which will
be amortized over the life of the 2017 Notes; the expense is recorded in
“interest expense, net of amounts capitalized” on the
condensed consolidated statements of operations.  The $12.3
million discount on the 2017 Notes will be amortized over the life of the 2017
Notes; the expense is recorded in “interest expense, net of amounts capitalized”
on the condensed consolidated statements of operations.




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




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




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


40
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Senior
Notes Due 2018




On
June 24, 2008, the Company entered into a purchase agreement with a group
of 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.  The 2018 Notes were offered and sold to the Initial Purchasers
and then resold to qualified institutional buyers, each in transactions exempt
from the registration requirements of the Securities Act.  The Company
used the net proceeds (after deducting the Initial Purchasers’ discounts and
offering expenses) of approximately $243.6 million to repay an outstanding term
loan.  In connection with the 2018 Notes, the Company incurred
financing fees and expenses of approximately $7.8 million, which will be
amortized over the life of the 2018 Notes; the expense is recorded in “interest
expense, net of amounts capitalized” on the condensed consolidated
statements of operations.  The $5.9 million discount on the 2018 Notes
will be amortized over the life of the 2018 Notes; the expense is recorded in
“interest expense, net of amounts capitalized” on the
condensed consolidated statements of operations.




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




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




Counterparty
Credit Risk




The
Company accounts for its commodity and interest rate derivatives at fair value
(see Note 7).  The Company’s counterparties are participants or
affiliates of participants in its Credit Facility (see Note 6), which is
secured by the Company’s oil and gas reserves; therefore, the Company is not
required to post any collateral.  The Company does not require
collateral from its counterparties.  The Company minimizes the credit
risk in derivative instruments by: (i) limiting its exposure to any single
counterparty; (ii) entering into derivative instruments only with
counterparties that meet the Company’s minimum credit quality standard, or have
a guarantee from an affiliate that meets the Company’s minimum credit quality
standard; and (iii) monitoring the creditworthiness of the Company’s
counterparties on an ongoing basis.  In accordance with the Company’s
standard practice, its commodity and interest rate derivatives are subject to
counterparty netting under agreements governing such derivatives and therefore
the risk of loss due to counterparty nonperformance is somewhat
mitigated.




Off-Balance
Sheet Arrangements




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


41
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


Contingencies




In
September 2008 and October 2008, Lehman Holdings and Lehman Commodity Services,
respectively, filed voluntary petitions for reorganization under
Chapter 11.  As of September 30, 2009, and 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, 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” on the
condensed consolidated balance sheets at September 30, 2009, and
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 nine months ended September 30, 2009, and September 30, 2008, the
Company made no significant payments to settle any legal, environmental or tax
proceedings.  The Company regularly analyzes current information and
accrues for probable liabilities on the disposition of certain matters, as
necessary.  Liabilities for loss contingencies arising from claims,
assessments, litigation or other sources are recorded when it is probable that a
liability has been incurred and the amount can be reasonably
estimated.




Commitments
and Contractual Obligations




The
Company has contractual obligations for long-term debt, operating leases and
other long-term liabilities that were summarized in a table of contractual
obligations in the 2008 Annual Report on Form 10-K.  With the
exception of $250.0 million of 2017 Notes, as of September 30, 2009, there
have been no significant changes to the Company’s contractual obligations from
December 31, 2008.  See “Senior Notes Due 2017” above for
additional details.




Critical
Accounting Policies and Estimates




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


42
 Table of Contents
 Item
2.Management’s Discussion
and Analysis of Financial Condition and Results of Operations -
Continued


With the
exception of accounting policies related to acquisition accounting as detailed
in Note 2, there have been no significant changes with regard to the critical
accounting policies disclosed in the Company’s Annual Report on Form 10-K
for the year ended December 31, 2008.  The policies disclosed
include the accounting for oil and gas properties, revenue recognition and
derivative instruments.




New
Accounting Standards




See
Note 11 and Note 16 for details regarding implementation of new
accounting standards.




Cautionary
Statement




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




·
            business
      strategy;


·
            acquisition
      strategy;


·
            financial
      strategy;


·
            drilling
      locations;


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




The
forward-looking statements contained in this Quarterly Report on Form 10-Q
are largely based on Company expectations, which reflect estimates and
assumptions made by Company management.  These estimates and
assumptions reflect management’s best judgment based on currently known market
conditions and other factors.  Although the Company believes such
estimates and assumptions to be reasonable, they are inherently uncertain and
involve a number of risks and uncertainties beyond its control.  In
addition, management’s assumptions may prove to be inaccurate.  The
Company cautions that the forward-looking statements contained in this Quarterly
Report on Form 10-Q are not guarantees of future performance, and it cannot
assure any reader that such statements will be realized or the forward-looking
statements or events will occur.  Actual results may differ materially
from those anticipated or implied in forward-looking statements due to factors
listed in “Item 1A. Risk Factors” in the Company’s Annual Report on
Form 10-K for the year ended December 31, 2008, and elsewhere in the
Annual Report.  The forward-looking statements speak only as of the
date made and, other than as required by law, the Company undertakes no
obligation to publicly update or revise any forward-looking statement, whether
as a result of new information, future events or otherwise.


43
 Table of Contents
 Item 3.Quantitative and Qualitative
Disclosures About Market Risk


The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about potential exposure to market
risks.  The term “market risk” refers to the risk of loss arising from
adverse changes in 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
trading.




The
following should be read in conjunction with the financial statements and
related notes included elsewhere in this Quarterly Report on Form 10-Q and
in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2008.  A reference to a “Note” herein refers to the
accompanying Notes to Condensed Consolidated Financial Statements contained in
Item 1. “Financial Statements.”




Commodity
Price Risk




The
Company enters into derivative contracts with respect to a portion of its
projected production through various transactions that provide an economic hedge
of the risk related to the future prices received.  The Company does
not enter into derivative contracts for trading purposes (see
Note 7).  At September 30, 2009, the fair value of contracts
that settle during the next 12 months was an asset of approximately $260.6
million and a liability of $5.4 million for a net asset of approximately $255.2
million.  A 10% increase in the index oil and gas prices above the
September 30, 2009, prices for the next 12 months would result in a net
asset of approximately $170.0 million which represents a decrease in the fair
value of approximately $85.2 million; conversely, a 10% decrease in the index
oil and gas prices would result in a net asset of approximately $341.9 million
which represents an increase in the fair value of approximately $86.7
million.




Interest
Rate Risk




At
September 30, 2009, the Company had long-term debt outstanding under its
Credit Facility of approximately $1.25 billion, which incurred interest at
floating rates (see Note 6).  A 1% increase in LIBOR would result
in an estimated $12.5 million increase in annual interest
expense.  The Company has entered into interest rate swap agreements
based on LIBOR to minimize the effect of fluctuations in interest rates (see
Note 7).




Counterparty
Credit Risk




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




At
September 30, 2009, the average public bond yield spread utilized to
estimate the impact of the Company’s credit risk on derivative liabilities was
approximately 4.90%.  A 1% increase in the average public bond yield
spread would result in an estimated $1.1 million increase in net income for the
three months and nine months ended September 30, 2009.  At
September 30, 2009, the credit default swap spreads utilized to estimate
the impact of counterparties’ credit risk on derivative assets ranged between 0%
and 2.02%.  A 1% increase in each of the counterparties’ credit
default swap spreads would result in an estimated $4.7 million decrease in net
income for the three months and nine months ended September 30,
2009.


44
 Table of Contents
 Item 4.Controls and
Procedures


Evaluation
of Disclosure Controls and Procedures




The
Company maintains disclosure controls and procedures that are designed to ensure
that information required to be disclosed in the Company’s reports under the
Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded,
processed, summarized and reported within the time periods specified in the
SEC’s rules and forms, and that such information is accumulated and communicated
to management, including the Company’s Chief Executive Officer and Chief
Financial Officer and, as appropriate, the Company’s Audit Committee of the
Board of Directors, 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 September 30, 2009.




Changes
in the Company’s Internal Control Over Financial Reporting




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




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




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


45
 Table of Contents
 PART II – OTHER INFORMATION


Item
1.              
Legal Proceedings




Not
applicable.




Item
1A.            Risk
Factors




Our
business has many risks.  Factors that could materially adversely
affect our business, financial position, results of operations, liquidity or the
trading price of our units are described in “Item 1A. Risk Factors” in our
Annual Report on Form 10-K for the year ended December 31,
2008.  Except as set forth below, as of the date of this report, these
risk factors have not changed materially.  This information should be
considered carefully, together with other information in this report and other
reports and materials we file with the SEC.




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




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




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




Issuer
Purchases of Equity Securities




In
October 2008, the Board of Directors of the Company authorized the repurchase of
up to $100.0 million of the Company’s outstanding units from time to time on the
open market or in negotiated purchases.  The repurchase plan does not
obligate the Company to acquire any specific number of units and may be
discontinued at any time.  The Company did not repurchase any units
during the three months ended September 30, 2009.  At
September 30, 2009, approximately $85.4 million was available for unit
repurchase under the program.




Item
3.              Defaults Upon Senior
Securities




None.




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




None.




Item
5.              
Other Information




None.


46
 Table of Contents
 PART
II – OTHER INFORMATION - Continued


Item
6.              
Exhibits




Exhibit Number
            
            
            
            Description2
            .1†*
            
            —
            
            Agreement
      for Purchase and Sale of Assets, dated August 5, 2009, between Linn
      Operating, Inc. and Linn Energy Holdings, LLC, as purchasers, and Forest
      Oil Corporation and Forest Oil Permian Corporation, as
    sellers31
            .1†
            
            —
            
            Section 302
      Certification of Michael C. Linn, Chairman 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 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.


47
 Table of Contents


SIGNATURE




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




LINN
      ENERGY, LLC(Registrant)Date:
      November 4, 2009
            /s/  David
      B. RottinoDavid
      B. RottinoSenior
      Vice President and Chief Accounting Officer(As
      Duly Authorized Officer and Chief Accounting
  Officer)