Attached files

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EX-2.2 - PURCHASE AND SALE AGREEMENT HENRY - LINN ENERGY, INC.exhibit2-2.htm
EX-2.1 - PURCHASE AND SALE AGREEMENT HIGHMOUNT - LINN ENERGY, INC.exhibit2-1.htm
EX-32.1 - CERTIFICATION OF CEO SECTION 906 - LINN ENERGY, INC.exhibit32-1.htm
EX-31.2 - CERTIFICATION OF CFO SECTION 302 - LINN ENERGY, INC.exhibit31-2.htm
EX-31.1 - CERTIFICATION OF CEO SECTION 302 - LINN ENERGY, INC.exhibit31-1.htm
EX-32.2 - CERTIFICATION OF CFO SECTION 906 - LINN ENERGY, INC.exhibit32-2.htm

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q


x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended March 31, 2010
 
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 Logo
 
LINN ENERGY, LLC
(Exact name of registrant as specified in its charter)


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


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

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

 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer  x      Accelerated filer   ¨      Non-accelerated filer  ¨      Smaller reporting company  ¨
 
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

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


 
 

 

   
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As commonly used in the oil and natural gas industry and as used in this Quarterly Report on Form 10-Q, the following terms have the following meanings:
 
Bbl.  One stock tank barrel or 42 United States gallons liquid volume.
 
Bcf.  One billion cubic feet.
 
Bcfe.  One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
 
Btu.  One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
 
MBbls.  One thousand barrels of oil or other liquid hydrocarbons.
 
MBbls/d. MBbls per day.
 
Mcf.  One thousand cubic feet.
 
Mcfe.  One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
 
MMBbls.  One million barrels of oil or other liquid hydrocarbons.
 
MMBoe.  One million barrels of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf.
 
MMBtu.  One million British thermal units.
 
MMcf.  One million cubic feet.
 
MMcf/d. MMcf per day.
 
MMcfe.  One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
 
MMcfe/d. MMcfe per day.
 
MMMBtu.  One billion British thermal units.
 
Tcfe.  One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
CONDENSED CONSOLIDATED BALANCE SHEETS
 
   
March 31,
 
December 31,
   
2010
 
2009
   
(Unaudited)
     
   
(in thousands,
except unit amounts)
ASSETS
     
Current assets:
           
Cash and cash equivalents
  $ 16,129     $ 22,231  
Accounts receivable – trade, net
    126,329       109,311  
Derivative instruments
    299,136       249,756  
Other current assets
    24,474       28,162  
Total current assets
    466,068       409,460  
                 
Noncurrent assets:
               
Oil and natural gas properties (successful efforts method)
    4,255,310       4,076,795  
Less accumulated depletion and amortization
    (509,181 )     (463,413 )
      3,746,129       3,613,382  
                 
Other property and equipment
    121,607       118,867  
Less accumulated depreciation
    (26,350 )     (23,583 )
      95,257       95,284  
                 
Derivative instruments
    126,845       145,457  
Other noncurrent assets
    120,591       76,673  
      247,436       222,130  
Total noncurrent assets
    4,088,822       3,930,796  
Total assets
  $ 4,554,890     $ 4,340,256  
                 
LIABILITIES AND UNITHOLDERS’ CAPITAL
               
Current liabilities:
               
Accounts payable and accrued expenses
  $ 137,945     $ 124,358  
Derivative instruments
    47,901       51,025  
Other accrued liabilities
    26,575       33,922  
Total current liabilities
    212,421       209,305  
                 
Noncurrent liabilities:
               
Credit facility
    905,000       1,100,000  
Senior notes, net
    489,176       488,831  
Derivative instruments
    54,691       53,923  
Other noncurrent liabilities
    38,851       36,193  
Total noncurrent liabilities
    1,487,718       1,678,947  
                 
Unitholders’ capital:
               
147,820,443 units and 129,940,617 units issued and outstanding at March 31, 2010, and December 31, 2009, respectively
    2,436,036       2,098,599  
Accumulated income
    418,715       353,405  
      2,854,751       2,452,004  
Total liabilities and unitholders’ capital
  $ 4,554,890     $ 4,340,256  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
   
Three Months Ended
March 31,
   
2010
 
2009
   
(in thousands, except per unit amounts)
Revenues and other:
           
Oil, natural gas and natural gas liquid sales
  $ 149,386     $ 79,864  
Gain on oil and natural gas derivatives
    96,003       161,315  
Natural gas marketing revenues
    1,394       516  
Other revenues
    253       966  
      247,036       242,661  
Expenses:
               
Lease operating expenses
    31,222       33,732  
Transportation expenses
    4,620       2,967  
Natural gas marketing expenses
    969       340  
General and administrative expenses
    24,488       23,301  
Exploration costs
    3,861       1,565  
Bad debt expenses
    189        
Depreciation, depletion and amortization
    49,191       52,104  
Taxes, other than income taxes
    10,200       7,567  
(Gain) loss on sale of assets and other, net
    (322 )     (26,711 )
      124,418       94,865  
Other income and (expenses):
               
Interest expense, net of amounts capitalized
    (27,653 )     (14,409 )
Loss on interest rate swaps
    (23,162 )     (11,571 )
Other, net
    (601 )     (393 )
      (51,416 )     (26,373 )
Income from continuing operations before income taxes
    71,202       121,423  
Income tax expense
    (5,892 )     (136 )
Income from continuing operations
    65,310       121,287  
                 
Discontinued operations:
               
Loss on sale of assets, net of taxes
          (1,048 )
Loss from discontinued operations, net of taxes
          (838 )
            (1,886 )
Net income   $ 65,310     $ 119,401  
                 
Income per unit – continuing operations:
               
Basic
  $ 0.50     $ 1.06  
Diluted
  $ 0.50     $ 1.06  
Loss per unit – discontinued operations:
               
Basic
  $     $ (0.02 )
Diluted
  $     $ (0.02 )
Net income per unit:
               
Basic
  $ 0.50     $ 1.04  
Diluted
  $ 0.50     $ 1.04  
Weighted average units outstanding:
               
Basic
    129,533       113,473  
Diluted
    129,922       113,502  
                 
Distributions declared per unit
  $ 0.63     $ 0.63  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL
(Unaudited)
 
   
Units
 
Unitholders’
Capital
 
Accumulated
Income
 
Treasury
Units
(at Cost)
 
Total
Unitholders’
Capital
   
(in thousands)
                               
December 31, 2009
    129,941     $ 2,098,599     $ 353,405     $     $ 2,452,004  
Sale of units, net of underwriting discounts and expenses of $17,633
    17,250       413,617                   413,617  
Issuance of units
    638       434                   434  
Cancellation of units
    (9 )     (252 )           252        
Purchase of units
                        (252 )     (252 )
Distributions to unitholders
            (82,274 )                 (82,274 )
Unit-based compensation expenses
            4,135                   4,135  
Excess tax benefit from unit-based compensation
            1,777                   1,777  
Net income
                  65,310             65,310  
March 31, 2010
    147,820     $ 2,436,036     $ 418,715     $     $ 2,854,751  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
   
Three Months Ended
March 31,
   
2010
 
2009
   
(in thousands)
Cash flow from operating activities:
           
Net income
  $ 65,310     $ 119,401  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    49,191       52,104  
Unit-based compensation expenses
    4,135       4,303  
Bad debt expenses
    189        
Amortization and write-off of deferred financing fees and other
    8,916       2,487  
(Gain) loss on sale of assets, net
    (3 )     (24,663 )
Deferred income tax
    3,623        
Mark-to-market on derivatives:
               
Total gains
    (72,841 )     (149,744 )
Cash settlements
    54,713       104,430  
Cash settlements on canceled derivatives
          4,257  
Premiums paid for derivatives
    (14,996 )      
Changes in assets and liabilities:
               
(Increase) decrease in accounts receivable – trade, net
    (15,161 )     42,371  
(Increase) decrease in other assets
    1,140       (20,150 )
Increase (decrease) in accounts payable and accrued expenses
    3,288       (30,020 )
Decrease in other liabilities
    (7,772 )     (9,806 )
Net cash provided by operating activities
    79,732       94,970  
                 
Cash flow from investing activities:
               
Acquisition of oil and natural gas properties
    (199,539 )      
Development of oil and natural gas properties
    (22,860 )     (67,984 )
Purchases of other property and equipment
    (2,089 )     (2,767 )
Proceeds from sale of properties and equipment
    3       11,934  
Net cash used in investing activities
    (224,485 )     (58,817 )
                 
Cash flow from financing activities:
               
Proceeds from sale of units
    431,250        
Proceeds from borrowings
    250,000       75,000  
Repayments of debt
    (445,000 )     (50,000 )
Distributions to unitholders
    (82,274 )     (72,538 )
Financing fees, offering expenses and other, net
    (16,850 )     8,075  
Excess tax benefit from unit-based compensation
    1,777        
Purchase of units
    (252 )     (2,465 )
Net cash provided by (used in) financing activities
    138,651       (41,928 )
                 
Net decrease in cash and cash equivalents
    (6,102 )     (5,775 )
                 
Cash and cash equivalents:
               
Beginning
    22,231       28,668  
Ending
  $ 16,129     $ 22,893  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
 
4

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1)
Basis of Presentation
 
Nature of Business
 
Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company.  LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  The Company’s properties are located in the United States, and are currently located primarily in the Mid-Continent, California and the Permian Basin.
 
Principles of Consolidation and Reporting
 
The condensed consolidated financial statements at March 31, 2010, and for the three months ended March 31, 2010, and March 31, 2009, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods.  Subsequent events were evaluated through the issuance date of the financial statements.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with United States generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations, and as such this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.  The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
 
The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.  All significant intercompany transactions and balances have been eliminated upon consolidation.  Unless otherwise indicated, information about the condensed consolidated statements of operations that is presented herein relates only to continuing operations.
 
Use of Estimates
 
The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events.  These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.  The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, fair values of commodity and interest rate derivatives, and fair values of assets acquired and liabilities assumed.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results could differ from these estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
 
5

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

(2)
Acquisitions and Divestitures
 
Acquisition – 2010
 
On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico, from certain affiliates of Merit Energy Company (“Merit”).  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid $152.0 million in cash, including a deposit of $15.5 million paid in November 2009, and recorded a receivable from Merit of $1.0 million, resulting in total consideration for the acquisition of approximately $151.0 million.  The transaction was financed with borrowings under the Company’s Credit Facility (as defined in Note 7).  The acquisition provided strategic additions to the Company’s positions in the Permian Basin and Mid-Continent.
 
The Merit acquisition was accounted for under the acquisition method of accounting.  Accordingly, the Company conducted an assessment of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.  The initial accounting for the business combination is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date.
 
The following presents the values assigned to the net assets acquired from Merit as of the acquisition date (in thousands):
 
Assets:
     
Current and other assets
  $ 4,400  
Oil and natural gas properties
    156,801  
Total assets acquired
  $ 161,201  
         
Liabilities:
       
Current liabilities
  $ 7,932  
Asset retirement obligations
    2,285  
Total liabilities assumed
  $ 10,217  
Net assets acquired
  $ 150,984  
 
Current and other assets include vehicles, natural gas imbalance receivables, natural gas plant and inventory of oil produced but not yet sold.  Current liabilities include natural gas imbalance payables, ad valorem taxes payable and environmental liabilities.
 
The fair values of oil and natural gas properties were measured using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.
 
Acquisitions – Pending
 
On March 21, 2010, the Company executed a definitive purchase and sale agreement to acquire the outstanding membership interests in two wholly owned subsidiaries of HighMount Exploration &
 
6

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Production LLC (“HighMount”) that hold oil and natural gas properties in the Antrim Shale located in northern Michigan, for a contract price of $330.0 million, subject to closing conditions.  The Company paid a deposit of $33.0 million to HighMount in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010.  The Company anticipates that the acquisition will close April 30, 2010, and will be financed with a portion of the net proceeds from its March 2010 public offering of units (see Note 3).  The acquisition will provide the Company with a new operating region in northern Michigan.
 
On March 28, 2010, the Company executed a definitive purchase and sale agreement to acquire interests of Henry Savings LP and Henry Savings Management LLC (collectively referred to as “Henry”) that are primarily comprised of oil and natural gas properties located in the Permian Basin, for a contract price of $305.0 million, subject to closing conditions.  The Company paid a deposit of $30.5 million to Henry in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010.  The Company anticipates that the acquisition will close May 27, 2010, and will be financed with borrowings under its Credit Facility.  The acquisition will increase the Company’s position in the Permian Basin.
 
Acquisitions – 2009
 
On August 31, 2009, and September 30, 2009, the Company completed the acquisitions of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian Corporation (collectively referred to as “Forest”) for aggregate total consideration of $113.8 million.  The results of operations of these properties have been included in the condensed consolidated financial statements since these dates.  The transactions were financed with borrowings under the Company’s Credit Facility.  The acquisitions represented a strategic entry into the Permian Basin for the Company.
 
Divestitures
 
On December 4, 2008, the Company completed the sale of its deep rights in certain central Oklahoma acreage, which includes the Woodford Shale interval, to Devon Energy Production Company, LP.  In the first quarter of 2009, certain post-closing matters were resolved and the Company recorded a gain of $25.4 million, which is recorded in “(gain) loss on sale of assets and other, net” on the condensed consolidated statements of operations for the three months ended March 31, 2009.
 
On July 1, 2008, the Company completed the sale of its interests in oil and natural gas properties located in the Appalachian Basin to XTO Energy, Inc.  In addition, in March 2008, the Company exited the drilling and service business in the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic Well Service, Inc.  The results of these operations have been classified as discontinued operations on the condensed consolidated statements of operations for all periods presented.  Discontinued operations activity for 2009 primarily represents activity related to post-closing adjustments.
 
(3)
Unitholders’ Capital
 
Public Offering of Units
 
On March 29, 2010, the Company sold 17,250,000 units representing limited liability company interests at $25.00 per unit ($24.00 per unit, net of underwriting discount) for net proceeds (after underwriting discount of $17.3 million and estimated offering expenses of $0.3 million) of approximately $413.6 million.  The Company intends to use a portion of the net proceeds to finance the pending acquisition from HighMount
 
7

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
(see Note 2).  Pending the close of the HighMount acquisition, all of the net proceeds were used to repay indebtedness under the Credit Facility.
 
Issuance and Cancellation of Units
 
During the three months ended March 31, 2010, the Company purchased 9,055 units for approximately $0.3 million, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan (see Note 6).  All units were subsequently canceled.
 
Distributions
 
Under the Company’s limited liability company agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses.  Distributions paid by the Company during the three months ended March 31, 2010, are presented on the condensed consolidated statement of unitholders’ capital.  On April 27, 2010, the Company’s Board of Directors declared a cash distribution of $0.63 per unit with respect to the first quarter of 2010.  This distribution, totaling approximately $93.2 million, will be paid on May 14, 2010, to unitholders of record as of the close of business on May 7, 2010.
 
(4)
Oil and Natural Gas Capitalized Costs
 
Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
 
   
March 31,
2010
 
December 31,
2009
   
(in thousands)
Proved properties:
           
Leasehold acquisition
  $ 3,556,793     $ 3,398,292  
Development
    624,810       600,436  
Unproved properties
    73,707       78,067  
      4,255,310       4,076,795  
Less accumulated depletion and amortization
    (509,181 )     (463,413 )
    $ 3,746,129     $ 3,613,382  
 
(5)
Business and Credit Concentrations
 
For the three months ended March 31, 2010, the Company’s three largest customers represented 20%, 17% and 14%, respectively, of the Company’s sales.  For the three months ended March 31, 2009, the Company’s three largest customers represented 19%, 17% and 16%, respectively, of the Company’s sales.
 
At March 31, 2010, trade accounts receivable from three customers accounted for more than 10% of the Company’s total trade accounts receivable.  At March 31, 2010, trade accounts receivable from these customers represented approximately 20%, 15% and 14%, respectively, of the Company’s receivables.  At December 31, 2009, trade accounts receivable from three customers accounted for more than 10% of the Company’s total trade accounts receivable.  At December 31, 2009, trade accounts receivable from these customers represented approximately 25%, 15% and 15%, respectively, of the Company’s receivables.
 
8

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
(6)
Unit-Based Compensation
 
During the three months ended March 31, 2010, the Company granted an aggregate 638,554 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $16.3 million.  The restricted units vest over three years.  A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:
 
   
Three Months Ended
March 31,
   
2010
 
2009
   
(in thousands)
             
General and administrative expenses
  $ 4,014     $ 4,201  
Lease operating expenses
    121       102  
Total unit-based compensation expenses
  $ 4,135     $ 4,303  
Income tax benefit
  $ 1,635     $  
 
(7)
Debt
 
The following summarizes debt outstanding:
 
   
March 31, 2010
 
December 31, 2009
   
Carrying
Value
 
Fair
Value (1)
 
Interest
Rate (2)
 
Carrying
Value
 
Fair
Value (1)
 
Interest
Rate (2)
   
(in millions, except percentages)
 
                                         
Credit facility
  $ 905     $ 905       3.01 %     $ 1,100     $ 1,100       2.98 %  
11.75% senior notes due 2017
    250       285       12.73 %       250       279       12.73 %  
9.875% senior notes due 2018
    256       274       10.25 %       256       271       10.25 %  
Less current maturities
                                           
      1,411     $ 1,464                 1,606     $ 1,650            
Unamortized discount
    (17 )                       (17 )                  
Total debt, net of discount
  $ 1,394                       $ 1,589                    
 
 
(1)
The carrying value of the Credit Facility is estimated to be substantially the same as its fair value.  Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.
 
 
(2)
Represents variable interest rate for the Credit Facility and effective interest rates for the senior notes.
 
Credit Facility
 
At March 31, 2010, the Company had a borrowing base of $1.64 billion and a maturity of August 2012 under its Fourth Amended and Restated Credit Agreement (“Credit Facility”).  On April 6, 2010, the Company entered into an amendment to its Credit Facility that provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015.  In connection with the amendment to its Credit Facility, the Company incurred financing fees and expenses of approximately $14.8 million, which will be amortized over the life of the Credit Facility.  Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed
 
9

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
consolidated statements of operations.  At March 31, 2010, available borrowing capacity was $732.6 million, which includes a $4.9 million reduction in availability for outstanding letters of credit.  Subsequent to the Credit Facility amendment and the issuance of the 2020 Notes (as defined below), at April 15, 2010, the Company had approximately $1.37 billion in available borrowing capacity under its Credit Facility, a portion of which the Company anticipates using to fund pending acquisitions (see Note 2).
 
Redetermination of the borrowing base under the Credit Facility occurs semi-annually, in April and October, as well as upon the occurrence of certain events, by the lenders in their sole discretion, based primarily on reserve reports that reflect commodity prices at such time.  Significant declines in prices may result in a decrease in the borrowing base.  The Company’s obligations under the Credit Facility are secured by mortgages on its oil and natural gas properties as well as a pledge of all ownership interests in its operating subsidiaries.  The Company is required to maintain the mortgages on properties representing at least 80% of its properties.  Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material operating subsidiaries and may be guaranteed by any future subsidiaries.
 
At the Company’s election, interest on borrowings under the Credit Facility, as amended in April 2010, is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or the alternate base rate (“ABR”) plus an applicable margin between 1.00% and 2.00% per annum.  Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans.  The Company is required to pay a fee of 0.5% per annum on the unused portion of the borrowing base under the Credit Facility.  The Credit Facility contains various covenants, substantially similar to those included prior to the amendment.  The Company is in compliance with all financial and other covenants of the Credit Facility.
 
Senior Notes Due 2017 and Senior Notes Due 2018
 
On May 18, 2009, the Company issued $250.0 million in aggregate principal amount of 11.75% senior notes due May 15, 2017, at a price of 95.081%.  On June 27, 2008, the Company issued $255.9 million in aggregate principal amount of 9.875% senior notes due July 1, 2018, at a price of 97.684%.
 
Senior Notes Due 2020
 
On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (“2020 Notes”) at a price of 97.552%.  The 2020 Notes were offered and sold to a group of initial purchasers (“Initial Purchasers”) and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”).  The Company received net proceeds (after deducting the Initial Purchasers’ discounts and estimated offering expenses) of approximately $1.24 billion.  The Company used the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility.  The excess will be used to fund or partially fund acquisitions and for general corporate purposes.  In connection with the 2020 Notes, the Company incurred financing fees and estimated expenses of approximately $26.6 million, which will be amortized over the life of the 2020 Notes.  The $31.8 million discount on the 2020 Notes will also be amortized over the life of the 2020 Notes.  Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.
 
The 2020 Notes were issued under an Indenture dated April 6, 2010, (“Indenture”), mature April 15, 2020, and bear interest at 8.625%.  Interest is payable semi-annually beginning October 15, 2010.  The 2020 Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness.  Each of the Company’s material subsidiaries have guaranteed the 2020 Notes on a senior
 
10

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
unsecured basis.  The Indenture provides that the Company may redeem: (i) on or prior to April 15, 2013, up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 108.625% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to April 15, 2015, all or part of the 2020 Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the Indenture) and accrued and unpaid interest; and (iii) on or after April 15, 2015, all or part of the 2020 Notes at redemption prices equal to 104.313% in 2015, 102.875% in 2016, 101.438% in 2017 and 100% in 2018 and thereafter, in each case, of the principal amount redeemed, plus accrued and unpaid interest.  The Indenture also provides that, if a change of control (as defined in the Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2020 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
 
The 2020 Notes’ Indenture contains covenants substantially similar to those under the Company’s 11.75% senior notes due 2017 and 9.875% senior notes due 2018 that, among other things, limit the Company’s ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.  The Company is in compliance with all financial and other covenants of the 2020 Notes.
 
In connection with the issuance and sale of the 2020 Notes, the Company entered into a Registration Rights Agreement (“Registration Rights Agreement”) with the Initial Purchasers.  Under the Registration Rights Agreement, the Company agreed, in certain circumstances, to use its reasonable best efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the 2020 Notes in exchange for outstanding 2020 Notes.  Additionally, in certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2020 Notes.  However, the Company will not be obligated to file the registration statements described above if the restrictive legend on the 2020 Notes has been removed and the 2020 Notes are freely tradable (in each case, other than with respect to persons that are affiliates of the Company) pursuant to Rule 144 of the Securities Act, as of the 366th day after the 2020 Notes were issued.  If the Company fails to satisfy its obligations under the Registration Rights Agreement, the Company may be required to pay additional interest to holders of the 2020 Notes under certain circumstances.
 
(8)
Derivatives
 
Commodity Derivatives
 
The Company sells oil, natural gas and NGL in the normal course of its business and utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements.  The Company enters into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales.  Oil puts are also used to economically hedge NGL sales.  The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 9 for fair value disclosures about oil and natural gas commodity derivatives.
 
11

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
The following table summarizes open positions as of March 31, 2010, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:
 
   
March 31 –
December 31,
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Natural gas positions:
                                   
Fixed price swaps:
                                   
Hedged volume (MMMBtu)
    29,674       31,901       18,300       18,250       18,250       18,250  
Average price ($/MMBtu)
  $ 8.90     $ 9.50     $ 6.37     $ 6.37     $ 6.37     $ 6.37  
Puts:
                                               
Hedged volume (MMMBtu)
    5,220       6,960       7,064       7,045              
Average price ($/MMBtu)
  $ 8.50     $ 9.50     $ 6.25     $ 6.25     $     $  
PEPL puts: (1)
                                               
Hedged volume (MMMBtu)
    7,976       13,259                          
Average price ($/MMBtu)
  $ 7.85     $ 8.50     $     $     $     $  
Total:
                                               
Hedged volume (MMMBtu)
    42,870       52,120       25,364       25,295       18,250       18,250  
Average price ($/MMBtu)
  $ 8.66     $ 9.25     $ 6.33     $ 6.33     $ 6.37     $ 6.37  
                                                 
Oil positions:
                                               
Fixed price swaps: (2)
                                               
Hedged volume (MBbls)
    1,613       2,073       3,020       3,011              
Average price ($/Bbl)
  $ 90.00     $ 90.00     $ 100.00     $ 100.00     $     $  
Puts: (3)
                                               
Hedged volume (MBbls)
    1,687       2,352                          
Average price ($/Bbl)
  $ 110.00     $ 75.00     $     $     $     $  
Collars:
                                               
Hedged volume (MBbls)
    187       276                          
Average floor price ($/Bbl)
  $ 90.00     $ 90.00     $     $     $     $  
Average ceiling price ($/Bbl)
  $ 112.00     $ 112.25     $     $     $     $  
Total:
                                               
Hedged volume (MBbls)
    3,487       4,701       3,020       3,011              
Average price ($/Bbl)
  $ 99.68     $ 82.50     $ 100.00     $ 100.00     $     $  
                                                 
Natural gas basis differential positions:
                                               
PEPL basis swaps: (1)
                                               
Hedged volume (MMMBtu)
    32,374       35,541       34,066       31,700              
Hedged differential ($/MMBtu)
  $ (0.97 )   $ (0.96 )   $ (0.95 )   $ (1.01 )   $     $  
 
 
(1)
Settle on the Panhandle Eastern Pipeline (“PEPL”) spot price of natural gas to hedge basis differential associated with natural gas production in the Mid-Continent Deep and Mid-Continent Shallow regions.
 
 
(2)
As presented in the table above, the Company has outstanding fixed price oil swaps on 8,250 Bbls of daily production at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013.  The Company has derivative contracts that extend these swaps at a price of $100.00 per Bbl for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other future years.
 
 
(3)
The Company utilizes oil puts to hedge revenues associated with its NGL production.
 
12

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
In March 2010, the Company entered into commodity derivative contracts, consisting of natural gas swaps and puts for 2012 through 2015, and paid premiums of approximately $15.0 million.  In addition, in April 2010, the Company entered into commodity derivative contracts, consisting of oil and natural gas swaps and puts for 2011 through 2015, and paid premiums of approximately $76.0 million.
 
Settled derivatives on natural gas production for the three months ended March 31, 2010, included a volume of 14,290 MMMBtu at an average contract price of $8.66 per MMBtu.  Settled derivatives on oil and NGL production for the three months ended March 31, 2010, included a volume of 1,162 MBbls at an average contract price of $99.68 per Bbl.  The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or on the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month.  The oil derivatives are settled based on the month’s average daily NYMEX price of light oil and settlement occurs on the final day of the production month.
 
Interest Rate Swaps
 
The Company has entered into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates.  If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparty the difference, and conversely, the counterparty is required to pay the Company if LIBOR is higher than the fixed rate in the contract.  The Company did not designate the interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 9 for fair value disclosures about interest rate swaps.
 
The following presents the settlement terms of the interest rate swaps at March 31, 2010:
 
   
2010
 
2011
 
2012
 
2013 (1)
   
(dollars in thousands)
                         
Notional amount
  $ 1,212,000     $ 1,212,000     $ 1,212,000     $ 1,212,000  
Fixed rate
    3.85 %     3.85 %     3.85 %     3.85 %
 
 
(1)
Actual settlement term is through January 6, 2014.
 
In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of 2020 Notes (see Note 7).  The Company canceled (before the contract settlement date) all of its interest rate swap agreements for the remainder of 2010, resulting in realized losses of approximately $35.6 million.
 
13

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Balance Sheet Presentation
 
The Company’s commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets.  The following summarizes the fair value of derivatives outstanding on a gross basis:
 
   
March 31,
2010
 
December 31,
2009
   
(in thousands)
Assets:
           
Commodity derivatives
  $ 674,848     $ 549,879  
Interest rate swaps
    1,209       2,603  
    $ 676,057     $ 552,482  
Liabilities:
               
Commodity derivatives
  $ 272,341     $ 192,573  
Interest rate swaps
    80,327       69,644  
    $ 352,668     $ 262,217  
 
By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk.  The Company’s counterparties are current or former participants or affiliates of current or former participants in its Credit Facility (see Note 7), which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral.  The Company does not require collateral from its counterparties.  The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $676.1 million at March 31, 2010.  The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated.
 
Gain (Loss) on Derivatives
 
Gains and losses on derivatives are reported on the condensed consolidated statements of operations in “gain on oil and natural gas derivatives” and “loss on interest rate swaps” and include realized and unrealized gains (losses).  Realized gains (losses), excluding canceled derivatives, represent amounts related to the settlement of derivative instruments, and for commodity derivatives, are aligned with the underlying production.  Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.
 
14

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
The following presents the Company’s reported gains and losses on derivative instruments:
 
   
Three Months Ended
March 31,
   
2010
 
2009
   
(in thousands)
Realized gains (losses):
           
Commodity derivatives
  $ 62,503     $ 119,812  
Interest rate swaps
    (8,021 )     (10,114 )
Canceled derivatives
          4,257  
    $ 54,482     $ 113,955  
Unrealized gains (losses):
               
Commodity derivatives
  $ 33,500     $ 37,246  
Interest rate swaps
    (15,141 )     (1,457 )
    $ 18,359     $ 35,789  
Total gains (losses):
               
Commodity derivatives
  $ 96,003     $ 161,315  
Interest rate swaps
    (23,162 )     (11,571 )
    $ 72,841     $ 149,744  
 
During the three months ended March 31, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future natural gas production resulting in realized gains of $4.3 million.
 
(9)
Fair Value Measurements on a Recurring Basis
 
The Company accounts for its commodity and interest rate derivatives at fair value (see Note 8) on a recurring basis.  The fair value of derivative instruments is determined utilizing pricing models for substantially similar instruments.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity and interest rate derivatives.
 
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
 
   
March 31, 2010
   
Level 2
 
Netting (1)
 
Total
   
(in thousands)
Assets:
                 
Commodity derivatives
  $ 674,848     $ (248,867 )   $ 425,981  
Interest rate swaps
  $ 1,209     $ (1,209 )   $  
                         
Liabilities:
                       
Commodity derivatives
  $ 272,341     $ (248,867 )   $ 23,474  
Interest rate swaps
  $ 80,327     $ (1,209 )   $ 79,118  
 
 
(1)
Represents counterparty netting under agreements governing such derivatives.
 
15

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
(10)
Asset Retirement Obligations
 
Asset retirement obligations associated with retiring tangible long-lived assets, are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the condensed consolidated balance sheets.  Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations.  The fair value of additions to the asset retirement obligation liability is estimated using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the three months ended March 31, 2010); and (iv) a credit-adjusted risk-free interest rate (average of 8.4% for the three months ended March 31, 2010).
 
The following presents a reconciliation of the asset retirement obligation liability (in thousands):
 
Asset retirement obligations at December 31, 2009
  $ 33,135  
Liabilities added from acquisitions
    2,285  
Liabilities added from drilling
    42  
Current year accretion expense
    597  
Settlements
    (94 )
Asset retirement obligations at March 31, 2010
  $ 35,965  
 
(11)
Commitments and Contingencies
 
From time to time, the Company is a party to various legal proceedings or is subject to industry rulings that could bring rise to claims in the ordinary course of business.  The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its business, financial position, results of operations or liquidity.
 
(12)
Earnings Per Unit
 
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period.  Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents.  The Company uses the treasury stock method to determine the dilutive effect.
 
16

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for income from continuing operations:
 
   
Income
(Numerator)
 
Units
(Denominator)
 
Per Unit
Amount
   
(in thousands)
     
Three months ended March 31, 2010:
                 
Income from continuing operations:
                 
Allocated to units
  $ 65,310              
Allocated to unvested restricted units
    (750 )            
    $ 64,560              
Income per unit:
                   
Basic income per unit
            129,533     $ 0.50  
Dilutive effect of unit equivalents
            389        
Diluted income per unit
            129,922     $ 0.50  
                         
Three months ended March 31, 2009:
                       
Income from continuing operations:
                       
Allocated to units
  $ 121,287                  
Allocated to unvested restricted units
    (1,485 )                
    $ 119,802                  
Income per unit:
                       
Basic income per unit
            113,473     $ 1.06  
Dilutive effect of unit equivalents
            29        
Diluted income per unit
            113,502     $ 1.06  
 
Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 0.6 million and 2.0 million unit options and warrants for the three months ended March 31, 2010, and March 31, 2009, respectively.
 
(13)
Income Taxes
 
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders.  As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company.  Limited liability companies are subject to state income taxes in Texas and certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  Amounts recognized for these taxes are reported in “income tax expense” on the condensed consolidated statements of operations.
 
17

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
(14)
Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows
 
“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:
 
   
March 31,
2010
 
December 31,
2009
   
(in thousands)
             
Accrued compensation
  $ 5,941     $ 14,378  
Accrued interest
    19,263       18,332  
Other
    1,371       1,212  
    $ 26,575     $ 33,922  
 
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
   
Three Months Ended
March 31,
   
2010
 
2009
   
(in thousands)
             
Cash payments for interest, net of amounts capitalized
  $ 21,653     $ 20,610  
Cash payments for income taxes
  $ 563     $ 1  
Noncash investing activities:
               
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
               
Fair value of assets acquired
  $ 145,911     $  
Cash paid
    (136,039 )      
Receivable from seller
    337        
Liabilities assumed
  $ 10,209     $  
 
“Acquisition of oil and natural gas properties” presented on the condensed consolidated statements of cash flows includes deposits paid of approximately $63.5 million for pending acquisitions (see Note 2).
 
For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.  Restricted cash of $2.3 million and $2.1 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010, and December 31, 2009, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance.  The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control.  The Company’s actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2009, and elsewhere in the Annual Report.  In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
 
The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.  A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”  Unless otherwise indicated, results of operations information presented herein relates only to continuing operations.
 
Executive Overview
 
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006.  The Company’s properties are currently located in four regions in the United States:
 
 
·
Mid-Continent Deep, which includes the Texas Panhandle Deep Granite Wash formation and deep formations in Oklahoma and Kansas;
 
·
Mid-Continent Shallow, which includes the Texas Panhandle Brown Dolomite formation and shallow formations in Oklahoma, Louisiana and Illinois;
 
·
California, which includes the Brea Olinda Field of the Los Angeles Basin; and
 
·
Permian Basin, which includes areas in West Texas and Southeast New Mexico.
 
Results for the three months ended March 31, 2010, included the following:
 
 
·
oil, natural gas and NGL sales of approximately $149.4 million, compared to $79.9 million in the first quarter of 2009;
 
·
average daily production of 213 MMcfe/d, compared to 217 MMcfe/d in the first quarter of 2009;
 
·
realized gains on commodity derivatives of approximately $62.5 million, compared to $124.1 million in the first quarter of 2009;
 
·
adjusted EBITDA of $151.5 million, compared to $138.2 million in the first quarter of 2009;
 
·
adjusted net income of $47.4 million, compared to $55.5 million in the first quarter of 2009;
 
·
capital expenditures, excluding acquisitions, of approximately $27.1 million, compared to $73.3 million in the first quarter of 2009; and
 
·
13 wells drilled (all successful), compared to 41 wells drilled (40 successful) in the first quarter of 2009.
 
Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance.  Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions.  The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives and depreciation, depletion and amortization.  Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gain) loss on derivatives, realized (gain) loss on canceled derivatives, impairment of goodwill and long-lived assets and (gain)
 
19

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
loss on sale of assets, net.  See “Non-GAAP Financial Measures” on page 31 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
Acquisitions
 
On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico from Merit for total consideration of approximately $151.0 million.  The acquisition was financed with borrowings under the Company’s Credit Facility.  The acquisition provided strategic additions to the Company’s positions in the Permian Basin and Mid-Continent, and included approximately 12 MMBoe (73 Bcfe) of proved reserves as of the acquisition date, estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.  The majority of the reserves were oil reserves.  See Note 2 for additional details.
 
On March 21, 2010, the Company executed a definitive purchase and sale agreement to acquire the outstanding membership interests in two wholly owned subsidiaries of HighMount that hold oil and natural gas properties in the Antrim Shale located in northern Michigan, for a contract price of $330.0 million, subject to closing conditions.  The Company paid a deposit of $33.0 million to HighMount in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010.  The Company anticipates that the acquisition will close April 30, 2010, and will be financed with net proceeds from its March 2010 public offering of units (see Note 3).  The acquisition will provide the Company with a new operating region in northern Michigan and includes approximately 238 Bcfe of proved reserves as of the acquisition date, estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.  Proved reserves as of the effective date, March 1, 2010, estimated using forward strip oil and natural gas prices, were 266 Bcfe.  The majority of the reserves are natural gas reserves.
 
On March 28, 2010, the Company executed a definitive purchase and sale agreement to acquire interests of Henry that are primarily comprised of oil and natural gas properties located in the Permian Basin, for a contract price of $305.0 million, subject to closing conditions.  The Company paid a deposit of $30.5 million to Henry in March 2010, and this amount is reported in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2010.  The Company anticipates that the acquisition will close May 27, 2010, and will be financed with borrowings under its Credit Facility.  The acquisition will significantly increase the Company’s positions in the Permian Basin and includes approximately 17 MMBoe (102 Bcfe) of proved reserves as of the acquisition date, estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.  Proved reserves as of the effective date, April 1, 2010, estimated using forward strip oil and natural gas prices, were 18 MMBoe (108 Bcfe).  The majority of the reserves are oil reserves.
 
Commodity Derivatives
 
The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil, natural gas and NGL and provide long-term cash flow predictability to pay distributions, service debt and manage its business.  By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices.
 
In April 2010, the Company entered into commodity derivative contracts, consisting of oil and natural gas swaps and puts for 2011 through 2015, and paid premiums of approximately $76.0 million.  At April 15, 2010, the Company had derivative contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and $83.46 per Bbl for oil and $8.66 per MMBtu and $9.25 per MMBtu for natural gas, respectively.  Additionally, the Company has derivative contracts in place covering substantially all of its exposure to the Mid-Continent natural gas basis differential through 2013.
 
20

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
The following table summarizes open positions as of April 15, 2010, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:
 
   
April 15 –
December 31,
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Natural gas positions:
                                   
Fixed price swaps:
                                   
Hedged volume (MMMBtu)
    26,377       31,901       31,110       31,025       31,025       31,025  
Average price ($/MMBtu)
  $ 8.90     $ 9.50     $ 6.25     $ 6.25     $ 6.25     $ 6.25  
Puts:
                                               
Hedged volume (MMMBtu)
    4,640       6,960       25,364       25,295              
Average price ($/MMBtu)
  $ 8.50     $ 9.50     $ 6.25     $ 6.25     $     $  
PEPL puts: (1)
                                               
Hedged volume (MMMBtu)
    7,089       13,259                          
Average price ($/MMBtu)
  $ 7.85     $ 8.50     $     $     $     $  
Total:
                                               
Hedged volume (MMMBtu)
    38,106       52,120       56,474       56,320       31,025       31,025  
Average price ($/MMBtu)
  $ 8.66     $ 9.25     $ 6.25     $ 6.25     $ 6.25     $ 6.25  
                                                 
Oil positions:
                                               
Fixed price swaps: (2)
                                               
Hedged volume (MBbls)
    1,613       2,803       3,386       3,376              
Average price ($/Bbl)
  $ 90.00     $ 89.91     $ 98.92     $ 98.92     $     $  
Puts: (3)
                                               
Hedged volume (MBbls)
    1,687       2,352       2,196       2,190              
Average price ($/Bbl)
  $ 110.00     $ 75.00     $ 75.00     $ 75.00     $     $  
Collars:
                                               
Hedged volume (MBbls)
    187       276                          
Average floor price ($/Bbl)
  $ 90.00     $ 90.00     $     $     $     $  
Average ceiling price ($/Bbl)
  $ 112.00     $ 112.25     $     $     $     $  
Total:
                                               
Hedged volume (MBbls)
    3,487       5,431       5,582       5,566              
Average price ($/Bbl)
  $ 99.68     $ 83.46     $ 89.51     $ 89.51     $     $  
                                                 
Natural gas basis differential positions:
                                               
PEPL basis swaps: (1)
                                               
Hedged volume (MMMBtu)
    28,777       35,541       34,066       31,700              
Hedged differential ($/MMBtu)
  $ (0.97 )   $ (0.96 )   $ (0.95 )   $ (1.01 )   $     $  
 
(1)
Settle on the Panhandle Eastern Pipeline (“PEPL”) spot price of natural gas to hedge basis differential associated with natural gas production in the Mid-Continent Deep and Mid-Continent Shallow regions.
 
(2)
As presented in the table above, the Company has outstanding fixed price oil swaps on 8,250 Bbls of daily production at a price of $100.00 per Bbl for the years ending December 31, 2012, and December 31, 2013.  The Company has derivative contracts that extend these swaps at a price of $100.00 per Bbl for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other future years.
 
(3)
The Company utilizes oil puts to hedge revenues associated with its NGL production.
 
21

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Interest Rate Swap Restructuring
 
In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of 2020 Notes (see Note 7).  The Company canceled (before the contract settlement date) all of its interest rate swap agreements for the remainder of 2010, resulting in realized losses of approximately $35.6 million.  In the second quarter of 2010, the Company expects to restructure its interest rate swap portfolio for 2011, 2012 and 2013 based on the balance outstanding under its Credit Facility after closing pending acquisitions (see Note 2).
 
The following presents the settlement terms of the interest rate swaps at April 15, 2010:
 
   
2011
 
2012
 
2013 (1)
   
(dollars in thousands)
                   
Notional amount
  $ 1,212,000     $ 1,212,000     $ 1,212,000  
Fixed rate
    3.85 %     3.85 %     3.85 %
 
(1)
Actual settlement term is through January 6, 2014.
 
Financing and Liquidity
 
The Company recently took steps to further strengthen its liquidity and extend its weighted average debt maturities.  On April 6, 2010, the Company entered into an amendment to its Credit Facility, which provides the Company a $1.50 billion facility with an initial borrowing base of $1.375 billion and extends the maturity from August 2012 to April 2015.  The Company expects the borrowing base under its Credit Facility to increase to $1.50 billion in the second quarter of 2010 as a result of the anticipated increased value of its oil and natural gas reserves after closing pending acquisitions (see Note 2).  On April 6, 2010, the Company also issued $1.30 billion in aggregate principal of 8.625% senior notes due 2020 and used the net proceeds of approximately $1.24 billion to repay all of the outstanding indebtedness under its Credit Facility, to unwind certain interest rate swap agreements and to fund financing fees associated with the amendment to its Credit Facility.  The excess will be used to fund or partially fund acquisitions and for general corporate purposes.  In addition, on March 29, 2010, the Company completed a public offering of units for net proceeds of approximately $413.6 million, a portion of which the Company intends to use to finance the pending acquisition from HighMount.  At April 15, 2010, the Company had approximately $1.37 billion in available borrowing capacity under its Credit Facility, a portion of which the Company anticipates using to fund pending acquisitions.
 
22

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Results of Operations – Continuing Operations
 
Three Months Ended March 31, 2010, Compared to Three Months Ended March 31, 2009
 
   
Three Months Ended March 31,
     
   
2010
 
2009
 
Variance
   
(in thousands)
Revenues and other:
                 
Natural gas sales
  $ 52,862     $ 42,228     $ 10,634  
Oil sales
    65,940       26,770       39,170  
NGL sales
    30,584       10,866       19,718  
Total oil, natural gas and NGL sales
    149,386       79,864       69,522  
Gain on oil and natural gas derivatives
    96,003       161,315       (65,312 )
Natural gas marketing revenues
    1,394       516       878  
Other revenues
    253       966       (713 )
    $ 247,036     $ 242,661     $ 4,375  
Expenses:
                       
Lease operating expenses
  $ 31,222     $ 33,732     $ (2,510 )
Transportation expenses
    4,620       2,967       1,653  
Natural gas marketing expenses
    969       340       629  
General and administrative expenses (1)
    24,488       23,301       1,187  
Exploration costs
    3,861       1,565       2,296  
Bad debt expenses
    189             189  
Depreciation, depletion and amortization
    49,191       52,104       (2,913 )
Taxes, other than income taxes
    10,200       7,567       2,633  
(Gain) loss on sale of assets and other, net
    (322 )     (26,711 )     26,389  
    $ 124,418     $ 94,865     $ 29,553  
Other income and (expenses)
  $ (51,416 )   $ (26,373 )   $ (25,043 )
Income from continuing operations before income taxes
  $ 71,202     $ 121,423     $ (50,221 )
                         
Adjusted EBITDA (2)
  $ 151,509     $ 138,161     $ 13,348  
Adjusted net income (2)
  $ 47,365     $ 55,530     $ (8,165 )
 
(1)
General and administrative expenses for the three months ended March 31, 2010, and March 31, 2009, include approximately $4.0 million and $4.2 million, respectively, of noncash unit-based compensation expenses.
 
(2)
This is a non-GAAP measure used by management to analyze Company performance.  See “Non-GAAP Financial Measures” on page 31 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
23

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
 
   
Three Months Ended
March 31,
     
   
2010
 
2009
 
Variance
Average daily production:
                 
Natural gas (MMcf/d)
    110       133       (17 )%
Oil (MBbls/d)
    9.8       8.8       11 %
NGL (MBbls/d)