Attached files

file filename
EX-2.2 - PSA CROWNROCK LP - LINN ENERGY, INC.exhibit2-2.htm
EX-2.1 - PSA PATRIOT - LINN ENERGY, INC.exhibit2-1.htm
EX-31.2 - CERTIFICATION OF CFO SECTION 302 - LINN ENERGY, INC.exhibit31-2.htm
EX-32.1 - CERTIFICATION OF CEO SECTION 906 - LINN ENERGY, INC.exhibit32-1.htm
EX-32.2 - CERTIFICATION OF CFO SECTION 906 - LINN ENERGY, INC.exhibit32-2.htm
EX-31.1 - CERTIFICATION OF CEO SECTION 302 - LINN ENERGY, INC.exhibit31-1.htm
EX-10.1 - FOURTH AMENDMENT TO FOURTH AMENDED CREDIT AGREE - LINN ENERGY, INC.exhibit10-1.htm
EX-2.3 - PSA ELEMENT PETROLEUM - LINN ENERGY, INC.exhibit2-3.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 September 30, 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  x    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 September 30, 2010, there were 147,419,333 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
 
   
September 30,
 
December 31,
   
2010
 
2009
   
(Unaudited)
     
   
(in thousands,
except unit amounts)
ASSETS
     
Current assets:
           
Cash and cash equivalents
  $ 418,060     $ 22,231  
Accounts receivable – trade, net
    162,432       109,311  
Derivative instruments
    314,456       249,756  
Other current assets
    43,261       28,162  
Total current assets
    938,209       409,460  
                 
Noncurrent assets:
               
Oil and natural gas properties (successful efforts method)
    5,083,662       4,076,795  
Less accumulated depletion and amortization
    (622,216 )     (463,413 )
      4,461,446       3,613,382  
                 
Other property and equipment
    139,445       118,867  
Less accumulated depreciation
    (32,149 )     (23,583 )
      107,296       95,284  
                 
Derivative instruments
    179,125       145,457  
Other noncurrent assets
    132,590       76,673  
      311,715       222,130  
Total noncurrent assets
    4,880,457       3,930,796  
Total assets
  $ 5,818,666     $ 4,340,256  
                 
LIABILITIES AND UNITHOLDERS’ CAPITAL
               
Current liabilities:
               
Accounts payable and accrued expenses
  $ 203,341     $ 124,358  
Derivative instruments
    2,859       51,025  
Other accrued liabilities
    88,920       33,922  
Total current liabilities
    295,120       209,305  
                 
Noncurrent liabilities:
               
Credit facility
          1,100,000  
Senior notes, net
    2,741,735       488,831  
Derivative instruments
    8,733       53,923  
Other noncurrent liabilities
    43,264       36,193  
Total noncurrent liabilities
    2,793,732       1,678,947  
                 
Unitholders’ capital:
               
147,419,333 units and 129,940,617 units issued and outstanding at September 30, 2010, and December 31, 2009, respectively
    2,247,170       2,098,599  
Accumulated income
    482,644       353,405  
      2,729,814       2,452,004  
Total liabilities and unitholders’ capital
  $ 5,818,666     $ 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
September 30,
 
Nine Months Ended
September 30,
   
2010
 
2009
 
2010
 
2009
   
(in thousands, except per unit amounts)
Revenues and other:
                       
Oil, natural gas and natural gas liquids sales
  $ 177,306     $ 102,989     $ 479,887     $ 274,759  
Gains (losses) on oil and natural gas derivatives
    43,505       (14,065 )     263,299       (85,525 )
Natural gas marketing revenues
    635       1,351       3,252       3,050  
Other revenues
    915       150       1,363       1,757  
      222,361       90,425       747,801       194,041  
Expenses:
                               
Lease operating expenses
    41,901       33,453       111,490       100,322  
Transportation expenses
    5,154       6,367       15,030       11,850  
Natural gas marketing expenses
    468       98       2,209       1,318  
General and administrative expenses
    23,751       19,655       71,545       63,247  
Exploration costs
    281       861       4,297       4,625  
Bad debt expenses
    (70 )     500       (89 )     500  
Depreciation, depletion and amortization
    62,482       49,440       169,614       151,934  
Taxes, other than income taxes
    12,011       5,965       32,602       21,414  
(Gains) losses on sale of assets and other, net
    6,073       1,999       5,699       (24,717 )
      152,051       118,338       412,397       330,493  
Other income and (expenses):
                               
Interest expense, net of amounts capitalized
    (53,497 )     (28,025 )     (127,119 )     (65,696 )
Losses on interest rate swaps
    (11,501 )     (25,709 )     (67,908 )     (25,362 )
Other, net
    (1,136 )     (757 )     (5,428 )     (1,987 )
      (66,134 )     (54,491 )     (200,455 )     (93,045 )
Income (loss) from continuing operations before income taxes
    4,176       (82,404 )     134,949       (229,497 )
Income tax expense
    (33 )     (58 )     (5,710 )     (379 )
Income (loss) from continuing operations
    4,143       (82,462 )     129,239       (229,876 )
                                 
Discontinued operations:
                               
Losses on sale of assets, net of taxes
                      (718 )
Loss from discontinued operations, net of taxes
          (1,247 )           (2,186 )
            (1,247 )           (2,904 )
Net income (loss)
  $  4,143     $ (83,709 )   $  129,239     $ (232,780 )
                                 
Income (loss) per unit – continuing operations:
                               
Basic
  $ 0.03     $ (0.69 )   $ 0.91     $ (1.97 )
Diluted
  $ 0.03     $ (0.69 )   $ 0.91     $ (1.97 )
Loss per unit – discontinued operations:
                               
Basic
  $     $ (0.01 )   $     $ (0.03 )
Diluted
  $     $ (0.01 )   $     $ (0.03 )
Net income (loss) per unit:
                               
Basic
  $ 0.03     $ (0.70 )   $ 0.91     $ (2.00 )
Diluted
  $ 0.03     $ (0.70 )   $ 0.91     $ (2.00 )
Weighted average units outstanding:
                               
Basic
    145,956       119,792       140,598       116,610  
Diluted
    146,458       119,792       141,006       116,610  
                                 
Distributions declared per unit
  $ 0.63     $ 0.63     $ 1.89     $ 1.89  
 
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 $17,563
    17,250       413,687                   413,687  
Issuance of units
    724       2,694                   2,694  
Cancellation of units
    (496 )     (11,832 )           11,832        
Purchase of units
                        (11,832 )     (11,832 )
Distributions to unitholders
            (268,343 )                 (268,343 )
Unit-based compensation expenses
            10,546                   10,546  
Excess tax benefit from unit-based compensation
            1,819                   1,819  
Net income
                  129,239             129,239  
September 30, 2010
    147,419     $ 2,247,170     $ 482,644     $     $ 2,729,814  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
   
Nine Months Ended
September 30,
   
2010
 
2009
   
(in thousands)
Cash flow from operating activities:
           
Net income (loss)
  $ 129,239     $ (232,780 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    169,614       151,934  
Unit-based compensation expenses
    10,546       11,473  
Bad debt expenses
    (89 )     500  
Amortization and write-off of deferred financing fees and other
    20,729       14,231  
Gains on sale of assets and other, net
    (619 )     (22,572 )
Deferred income tax
    2,956        
Mark-to-market on derivatives:
               
Total (gains) losses
    (195,391 )     110,887  
Cash settlements
    218,559       299,114  
Cash settlements on canceled derivatives
    (123,865 )     48,977  
Premiums paid for derivatives
    (91,027 )     (93,606 )
Changes in assets and liabilities:
               
(Increase) decrease in accounts receivable – trade, net
    (43,173 )     39,260  
Decrease in other assets
    15,894       365  
Increase (decrease) in accounts payable and accrued expenses
    15,483       (3,232 )
Increase in other liabilities
    54,563       5,573  
Net cash provided by operating activities
    183,419       330,124  
                 
Cash flow from investing activities:
               
Acquisition of oil and natural gas properties, net of cash acquired
    (894,521 )     (116,694 )
Development of oil and natural gas properties
    (104,694 )     (152,149 )
Purchases of other property and equipment
    (15,030 )     (5,832 )
Proceeds from sale of properties and equipment
    696       26,682  
Net cash used in investing activities
    (1,013,549 )     (247,993 )
                 
Cash flow from financing activities:
               
Proceeds from sale of units
    431,250       102,781  
Proceeds from borrowings
    3,170,816       599,203  
Repayments of debt
    (2,020,000 )     (513,893 )
Distributions to unitholders
    (268,343 )     (221,430 )
Financing fees, offering expenses and other, net
    (77,751 )     (64,169 )
Excess tax benefit from unit-based compensation
    1,819        
Purchase of units
    (11,832 )     (2,696 )
Net cash provided by (used in) financing activities
    1,225,959       (100,204 )
                 
Net increase (decrease) in cash and cash equivalents
    395,829       (18,073 )
Cash and cash equivalents:
               
Beginning
    22,231       28,668  
Ending
  $ 418,060     $ 10,595  
 
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, primarily in the Mid-Continent, California, Permian Basin and Michigan.
 
Principles of Consolidation and Reporting
 
The condensed consolidated financial statements at September 30, 2010, and for the three months and nine months ended September 30, 2010, and September 30, 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.  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.  Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.  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
 
Acquisitions – 2010
 
On July 16, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the East Texas Oil Field in Gregg and Rusk counties for a contract price of $95.0 million.  On September 29, 2010, in accordance with the terms of the purchase agreement, the Company sent a notice to the sellers of the Company’s intention to terminate the purchase agreement as a result of certain conditions to closing not being met.  The Company paid a deposit of $9.2 million in July 2010, which is reported in “other current assets” on the condensed consolidated balance sheet at September 30, 2010.  On October 11, 2010, arbitration proceedings were initiated concerning the termination of the purchase agreement and the return of the deposit.
 
On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from Crownrock, LP and Element Petroleum, LP (collectively referred to as “CrownQuest/Element”).  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid $95.8 million in cash and recorded a receivable of $2.3 million, resulting in total consideration for the acquisition of approximately $93.5 million.  The transaction was financed with borrowings under the Company’s Credit Facility (as defined in Note 6).
 
On May 27, 2010, the Company completed the acquisition of interests in Henry Savings LP and Henry Savings Management LLC (collectively referred to as “Henry”) that primarily hold oil and natural gas properties located in the Permian Basin.  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid $317.9 million in cash, including a deposit of $30.5 million paid in March 2010, and recorded a receivable from Henry of $10.1 million, resulting in total consideration for the acquisition of approximately $307.8 million.  The transaction was financed with borrowings under the Company’s Credit Facility.
 
On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount Exploration & Production LLC (“HighMount”) that hold oil and natural gas properties in the Antrim Shale located in northern Michigan.  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid $326.8 million in cash, including a deposit of $33.0 million paid in March 2010.  The transaction was financed with a portion of the net proceeds from the Company’s March 2010 public offering of units (see Note 3).  The acquisition provided the Company with a new operating region in Michigan.
 
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.  The acquisition provided strategic additions to the Company’s positions in the Permian Basin and Mid-Continent.
 
These acquisitions were accounted for under the acquisition method of accounting.  Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred.  The initial accounting for the
 
6

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
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.
 
The following presents the values assigned to the aggregate net assets acquired as of the acquisition dates (in thousands):
 
Assets:
     
Cash acquired
  $ 15,367  
Current and noncurrent assets
    32,170  
Oil and natural gas properties
    864,829  
Total assets acquired
  $ 912,366  
         
Liabilities:
       
Current liabilities
  $ 32,024  
Asset retirement obligations
    4,974  
Total liabilities assumed
  $ 36,998  
Net assets acquired
  $ 875,368  
 
Current and noncurrent assets include trade accounts receivable, inventory, prepaid drilling costs, vehicles, natural gas imbalance receivables, land, natural gas plant and investments in noncontrolled entities.  Current liabilities include trade accounts payable, 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.
 
Acquisition – Subsequent Event
 
On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin, from Crownrock, LP and Patriot Resources Partners LLC (collectively referred to as “CrownQuest/Patriot”) for a combined price of $250.2 million.  The transactions were financed with cash on hand and included a deposit of $12.7 million paid by the Company in September 2010.  The initial accounting for the business combination is not complete pending detailed analyses of the facts and circumstances that existed as of the acquisition date.
 
Acquisition – Pending
 
On September 2, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin for a contract price of $120.0 million.  The Company anticipates the acquisition will close on or before November 16, 2010, subject to closing conditions, and will be financed with cash on hand and proceeds from borrowings under its Credit Facility.
 
7

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
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
 
In December 2008, the Company completed the sale of its deep rights in certain central Oklahoma acreage, which included the Woodford Shale interval.  In the first quarter of 2009, certain post-closing matters were resolved and the Company recorded a gain of $25.4 million, which is included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statement of operations for the nine months ended September 30, 2009.
 
In July 2008, the Company completed the sale of its interests in oil and natural gas properties in the Appalachian Basin and, in March 2008, the Company also exited the drilling and service business in this basin.  The results of these operations were classified as discontinued operations on the condensed consolidated statements of operations and the amounts recorded in 2009 primarily represent 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 of approximately $413.7 million (after underwriting discount of $17.3 million and estimated offering expenses of $0.3 million).  The Company used a portion of the net proceeds from the sale of these units to finance the HighMount acquisition (see Note 2).
 
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, 2010, 486,700 units were repurchased at an average unit price of $23.79 for a total cost of approximately $11.6 million.  All units were subsequently canceled.  At September 30, 2010, approximately $73.8 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.
 
Cancellation of Units
 
During the nine months ended September 30, 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
 
8

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
taxes due on units issued under its equity compensation plan (see Note 5).  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 nine months ended September 30, 2010, are presented on the condensed consolidated statement of unitholders’ capital.  On October 25, 2010, the Company’s Board of Directors declared a cash distribution of $0.66 per unit with respect to the third quarter of 2010, which represents a 5% increase over the previous quarter.  This distribution, totaling approximately $97.3 million, will be paid on November 12, 2010, to unitholders of record as of the close of business on November 4, 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:
 
   
September 30,
2010
 
December 31,
2009
   
(in thousands)
Proved properties:
           
Leasehold acquisition
  $ 4,224,209     $ 3,398,292  
Development
    728,093       600,436  
Unproved properties
    131,360       78,067  
      5,083,662       4,076,795  
Less accumulated depletion and amortization
    (622,216 )     (463,413 )
    $ 4,461,446     $ 3,613,382  
 
(5)
Unit-Based Compensation
 
During the nine months ended September 30, 2010, the Company granted an aggregate 673,754 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $17.3 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
September 30,
 
Nine Months Ended
September 30,
   
2010
 
2009
 
2010
 
2009
   
(in thousands)
                         
General and administrative expenses
  $ 3,070     $ 3,435     $ 10,280     $ 11,204  
Lease operating expenses
    76       84       266       269  
Total unit-based compensation expenses
  $ 3,146     $ 3,519     $ 10,546     $ 11,473  
Income tax benefit
  $ 1,162     $     $ 3,897     $  
 
9

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
(6)
Debt
 
The following summarizes debt outstanding:
 
   
September 30, 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
  $     $           $ 1,100     $ 1,100       2.98 %
11.75% senior notes due 2017
    250       280       12.73 %     250       279       12.73 %
9.875% senior notes due 2018
    256       286       10.25 %     256       271       10.25 %
8.625% senior notes due 2020
    1,300       1,373       9.00 %                  
7.75% senior notes due 2021
    1,000       1,003       8.00 %                  
Less current maturities
                                       
      2,806     $ 2,942               1,606     $ 1,650          
Unamortized discount
    (64 )                     (17 )                
Total debt, net of discount
  $ 2,742                     $ 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
 
The Company’s Fourth Amended and Restated Revolving Credit Facility (“Credit Facility”) provides the Company a $1.50 billion facility with a maturity of April 2015.  In connection with amendments to its Credit Facility during 2010, the Company incurred financing fees and expenses of approximately $16.2 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 consolidated statements of operations.  At September 30, 2010, the borrowing base under the Credit Facility was $1.25 billion and available borrowing capacity was approximately $1.24 billion, which includes a $5.1 million reduction in availability for outstanding letters of credit.  In October 2010, in connection with the regular semi-annual borrowing base redetermination, the borrowing base was increased to $1.50 billion, and at October 25, 2010, available borrowing capacity was approximately $1.49 billion, which includes a $5.1 million reduction in availability for outstanding letters of credit.
 
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 at their sole discretion, based primarily on reserve reports that reflect commodity prices at such time.  The Company also has the right to request one additional borrowing base redetermination per year in connection with certain acquisitions, which right was last exercised in June 2010.  Significant declines in commodity 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 material operating subsidiaries.  The Company is required to maintain the mortgages on properties representing at least 80% of the total value of its oil and natural gas properties.  Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material operating subsidiaries and are required to be guaranteed by any future subsidiaries.
 
10

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
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 quarterly 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 2021
 
On September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (“2021 Notes”) at a price of 98.264%.  The 2021 Notes were sold to a group of initial purchasers (“2021 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 of approximately $962.5 million (after deducting the 2021 Initial Purchasers’ discount and offering expenses).  The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility and to unwind its remaining interest rate swap agreements.  The remaining proceeds will be used to fund or partially fund acquisitions and for general corporate purposes.  In connection with the 2021 Notes, the Company incurred financing fees and expenses of approximately $20.1 million, which will be amortized over the life of the 2021 Notes.  The discount on the 2021 Notes, which totaled $17.4 million, will also be amortized over the life of the 2021 Notes.  Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.
 
The 2021 Notes were issued under an indenture dated September 13, 2010, (“2021 Indenture”), mature February 1, 2021, and bear interest at 7.75%.  Interest is payable semi-annually beginning March 15, 2011.  The 2021 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 has guaranteed the 2021 Notes on a senior unsecured basis.  The 2021 Indenture provides that the Company may redeem: (i) on or prior to September 15, 2013, up to 35% of the aggregate principal amount of the 2021 Notes at a redemption price of 107.75% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to September 15, 2015, all or part of the 2021 Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the 2021 Indenture) and accrued and unpaid interest; and (iii) on or after September 15, 2015, all or part of the 2021 Notes at redemption prices equal to 103.875% in 2015, 102.583% in 2016, 101.292% in 2017 and 100% in 2018 and thereafter, in each case, of the principal amount redeemed, plus accrued and unpaid interest.  The 2021 Indenture also provides that, if a change of control (as defined in the 2021 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2021 Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
 
The 2021 Indenture contains covenants substantially similar to those under the Company’s 11.75% senior notes due 2017, 9.875% senior notes due 2018 and 8.625% senior notes due 2020 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 2021 Notes.
 
11

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
In connection with the issuance and sale of the 2021 Notes, the Company entered into a Registration Rights Agreement (“2021 Registration Rights Agreement”) with the 2021 Initial Purchasers.  Under the 2021 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 2021 Notes in exchange for outstanding 2021 Notes.  Additionally, in certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2021 Notes.  However, the Company will not be obligated to file the registration statements described above if the restrictive legend on the 2021 Notes has been removed and the 2021 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 2021 Notes were issued.  If the Company fails to satisfy its obligations under the 2021 Registration Rights Agreement, the Company may be required to pay additional interest to holders of the 2021 Notes under certain circumstances.
 
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 sold to a group of initial purchasers (“2020 Initial Purchasers”) and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act.  The Company received net proceeds of approximately $1.24 billion (after deducting the 2020 Initial Purchasers’ discount and offering expenses).  The Company used a portion of 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 an amendment to its Credit Facility.  The remaining proceeds were used to fund or partially fund acquisitions and for general corporate purposes.  In connection with the 2020 Notes, the Company incurred financing fees and expenses of approximately $27.5 million, which will be amortized over the life of the 2020 Notes.  The discount on the 2020 Notes, which totaled  $31.8 million, 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, (“2020 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 has guaranteed the 2020 Notes on a senior unsecured basis.  The 2020 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 2020 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 2020 Indenture also provides that, if a change of control (as defined in the 2020 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 Indenture contains covenants substantially similar to those under the Company’s 11.75% senior notes due 2017, 9.875% senior notes due 2018 and 7.75% senior notes due 2021 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
 
12

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
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 (“2020 Registration Rights Agreement”) with the 2020 Initial Purchasers.  Under the 2020 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 2020 Registration Rights Agreement, the Company may be required to pay additional interest to holders of the 2020 Notes under certain circumstances.
 
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%.
 
(7)
Derivatives
 
Commodity Derivatives
 
The Company 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 and natural gas sales.  The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.
 
13

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
The following table summarizes open positions as of September 30, 2010, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:
 
   
September 30 –
December 31,
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Natural gas positions:
                                   
Fixed price swaps:
                                   
Hedged volume (MMMBtu)
    9,891       31,901       49,410       49,275       49,275       49,275  
Average price ($/MMBtu)
  $ 8.90     $ 9.50     $ 5.97     $ 5.97     $ 5.97     $ 5.97  
Puts:
                                               
Hedged volume (MMMBtu)
    1,740       6,960       25,364       25,295              
Average price ($/MMBtu)
  $ 8.50     $ 9.50     $ 6.25     $ 6.25     $     $  
PEPL puts: (1)
                                               
Hedged volume (MMMBtu)
    2,659       13,259                          
Average price ($/MMBtu)
  $ 7.85     $ 8.50     $     $     $     $  
Total:
                                               
Hedged volume (MMMBtu)
    14,290       52,120       74,774       74,570       49,275       49,275  
Average price ($/MMBtu)
  $ 8.66     $ 9.25     $ 6.07     $ 6.07     $ 5.97     $ 5.97  
                                                 
Oil positions:
                                               
Fixed price swaps: (2)
                                               
Hedged volume (MBbls)
    538       2,803       4,484       4,471       4,654       1,643  
Average price ($/Bbl)
  $ 90.00     $ 89.91     $ 95.88     $ 95.88     $ 89.03     $ 87.04  
Puts:
                                               
Hedged volume (MBbls)
    562       2,352       2,196       2,190              
Average price ($/Bbl)
  $ 110.00     $ 75.00     $ 75.00     $ 75.00     $     $  
Collars:
                                               
Hedged volume (MBbls)
    62       276                          
Average floor price ($/Bbl)
  $ 90.00     $ 90.00     $     $     $     $  
Average ceiling price ($/Bbl)
  $ 112.00     $ 112.25     $     $     $     $  
Total:
                                               
Hedged volume (MBbls)
    1,162       5,431       6,680       6,661       4,654       1,643  
Average price ($/Bbl)
  $ 99.68     $ 83.46     $ 89.01     $ 89.01     $ 89.03     $ 87.04  
                                                 
Natural gas basis differential positions:
                                               
PEPL basis swaps: (1)
                                               
Hedged volume (MMMBtu)
    10,791       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 certain outstanding fixed price oil swaps on 8,250 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2015, December 31, 2016, and December 31, 2017, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.
 
14

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
During the first half of 2010, the Company entered into commodity derivative contracts, consisting of oil and natural gas swaps and puts for certain years through 2015, and paid premiums for put options of approximately $91.0 million.  In addition, in September 2010, the Company entered into commodity derivative contracts consisting of oil swaps for 2012 through 2015.
 
Settled derivatives on natural gas production for the three months and nine months ended September 30, 2010, included volumes of 14,290 MMMBtu and 42,870 MMMBtu, respectively, at average contract prices of $8.66 per MMBtu.  Settled derivatives on oil production for the three months and nine months ended September 30, 2010, included volumes of 1,162 MBbls and 3,487 MBbls, respectively, at average contract prices of $99.68 per Bbl.  The natural gas derivatives are settled based on the closing New York Mercantile Exchange (“NYMEX”) futures price of natural gas or on the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month.  The oil derivatives are settled based on the month’s average daily NYMEX price of light oil and settlement occurs on the final day of the production month.
 
In October 2010, the Company entered into commodity derivative contracts, consisting of oil swaps and natural gas swaps and puts for certain years through 2015, and paid premiums for put options of approximately $29.3 million.  At October 25, 2010, the Company had derivative contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and $84.09 per Bbl for oil and $8.66 per MMBtu and $8.24 per MMBtu for natural gas, respectively.  Additionally, the Company has derivative contracts in place covering a substantial portion of its exposure to the Mid-Continent natural gas basis differential through 2015.
 
Interest Rate Swaps
 
The Company may from time to time enter 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 does not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.
 
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 the 2020 Notes (see Note 6).  In conjunction with the repayment of borrowings under its Credit Facility with proceeds from the issuance of the 2020 Notes, during the second quarter of 2010, the Company canceled (before the contract settlement date) certain interest rate swap agreements for 2010 through 2013, resulting in realized losses of approximately $74.3 million.  In September 2010, the Company canceled (before the contract settlement date) all of its remaining interest rate swap agreements in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of the 2021 Notes (see Note 6).  The cancellation of the interest rate swap agreements in September 2010, resulted in a realized loss of approximately $49.6 million.
 
15

LINN 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,
2010
 
December 31,
2009
   
(in thousands)
Assets:
           
Commodity derivatives
  $ 762,142     $ 549,879  
Interest rate swaps
          2,603  
    $ 762,142     $ 552,482  
Liabilities:
               
Commodity derivatives
  $ 280,153     $ 192,573  
Interest rate swaps
          69,644  
    $ 280,153     $ 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 6), which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral.  The Company does not require collateral from its counterparties.  The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $762.1 million at September 30, 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.
 
Gains (Losses) on Derivatives
 
Gains and losses on derivatives are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives” and “losses 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.
 
16

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,
   
2010
 
2009
 
2010
 
2009
   
(in thousands)
Realized gains (losses):
                       
Commodity derivatives
  $ 82,910     $ 97,209     $ 228,573     $ 328,165  
Interest rate swaps
          (10,958 )     (8,021 )     (31,629 )
Canceled derivatives
    (49,590 )     44,780       (123,865 )     48,977  
    $ 33,320     $ 131,031     $ 96,687     $ 345,513  
Unrealized gains (losses):
                               
Commodity derivatives
  $ (39,405 )   $ (156,054 )   $ 34,726     $ (462,727 )
Interest rate swaps
    38,089       (14,751 )     63,978       6,327  
    $ (1,316 )   $ (170,805 )   $ 98,704     $ (456,400 )
Total gains (losses):
                               
Commodity derivatives
  $ 43,505     $ (14,065 )   $ 263,299     $ (85,525 )
Interest rate swaps
    (11,501 )     (25,709 )     (67,908 )     (25,362 )
    $ 32,004     $ (39,774 )   $ 195,391     $ (110,887 )
 
During the three months and nine months ended September 30, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements resulting in realized losses of approximately $49.6 million and $123.9 million, respectively.   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 natural gas production resulting in realized net gains of approximately $44.8 million and $49.0 million, respectively.
 
(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 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:
 
   
September 30, 2010
   
Level 2
 
Netting (1)
 
Total
   
(in thousands)
Assets:
                 
Commodity derivatives
  $ 762,142     $ (268,561 )   $ 493,581  
                         
Liabilities:
                       
Commodity derivatives
  $ 280,153     $ (268,561 )   $ 11,592  
 
 
(1)
Represents counterparty netting under agreements governing such derivatives.
 
17

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
(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.  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 obligations 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 nine months ended September 30, 2010); and (iv) a credit-adjusted risk-free interest rate (average of 8.8% for the nine months ended September 30, 2010).
 
The following presents a reconciliation of the asset retirement obligations (in thousands):
 
Asset retirement obligations at December 31, 2009
  $ 33,135  
Liabilities added from acquisitions
    4,974  
Liabilities added from drilling
    166  
Current year accretion expense
    2,017  
Settlements
    (148 )
Asset retirement obligations at September 30, 2010
  $ 40,144  
 
(10)
Commitments and Contingencies
 
The Company has been named as a defendant in a number of lawsuits and is involved in various other disputes arising in the ordinary course of business, including claims from royalty owners related to disputed royalty payments and royalty valuations.  The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters.  The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
 
(11)
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.
 
18

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, 2010:
                 
Income from continuing operations:
                 
Allocated to units
  $ 4,143              
Allocated to unvested restricted units
    (46 )            
    $ 4,097              
Income per unit:
                   
Basic income per unit
            145,956     $ 0.03  
Dilutive effect of unit equivalents
            502        
Diluted income per unit
            146,458     $ 0.03  
                         
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 )
                         
Nine months ended September 30, 2010:
                       
Income from continuing operations:
                       
Allocated to units
  $ 129,239                  
Allocated to unvested restricted units
    (1,361 )                
    $ 127,878                  
Income per unit:
                       
Basic income per unit
            140,598     $ 0.91  
Dilutive effect of unit equivalents
            408        
Diluted income per unit
            141,006     $ 0.91  
                         
Nine 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 )
 
Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 0.3 million and 0.6 million unit options and warrants for the three months and nine months ended
 
19

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
September 30, 2010, respectively.  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, 2009, respectively.  All equivalent units were anti-dilutive for the three months and nine months ended September 30, 2009, as the Company reported a loss from continuing operations.
 
(12)
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 states of Texas and Michigan, 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 and Michigan and certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  As such, with the exception of the states of Texas and Michigan and certain subsidiaries, 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.  Amounts recognized for these taxes are reported in “income tax expense” on the condensed consolidated statements of operations.
 
(13)
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:
 
   
September 30,
2010
 
December 31,
2009
   
(in thousands)
             
Accrued compensation
  $ 12,922     $ 14,378  
Accrued interest
    75,484       18,332  
Other
    514       1,212  
    $ 88,920     $ 33,922  
 
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
   
Nine Months Ended
September 30,
   
2010
 
2009
   
(in thousands)
             
Cash payments for interest, net of amounts capitalized
  $ 55,404     $ 50,990  
Cash payments for income taxes
  $ 1,785     $ 922  
Noncash investing activities:
               
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
               
Fair value of assets acquired
  $ 896,999     $ 116,882  
Cash paid, net of cash acquired
    (872,621 )     (116,694 )
Receivables from sellers
    12,620       2,729  
Liabilities assumed
  $ 36,998     $ 2,917  
 
20

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
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 $2.7 million and $2.1 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at September 30, 2010, and December 31, 2009, respectively, and represents cash deposited by the Company 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 located in five 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;
 
·
Permian Basin, which includes areas in West Texas and Southeast New Mexico; and
 
·
Michigan, which includes the Antrim Shale formation in the northern part of the state.
 
Results for the three months ended September 30, 2010, included the following:
 
 
·
oil, natural gas and NGL sales of approximately $177.3 million, compared to $103.0 million for the third quarter of 2009;
 
·
average daily production of 283 MMcfe/d, compared to 217 MMcfe/d for the third quarter of 2009;
 
·
realized gains on commodity derivatives of approximately $82.9 million, compared to $142.0 million for the third quarter of 2009;
 
·
adjusted EBITDA of approximately $185.0 million, compared to $142.4 million for the third quarter of 2009;
 
·
adjusted net income of approximately $56.3 million, compared to $45.9 million for the third quarter of 2009;
 
·
capital expenditures, excluding acquisitions, of approximately $74.5 million, compared to $24.5 million for the third quarter of 2009; and
 
·
37 wells drilled (36 successful), compared to six wells drilled (all successful) for the third quarter of 2009.
 
Results for the nine months ended September 30, 2010, included the following:
 
 
·
oil, natural gas and NGL sales of approximately $479.9 million, compared to $274.8 million for the nine months ended September 30, 2009;
 
22

Item 2.             Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
 
·
average daily production of 251 MMcfe/d, compared to 218 MMcfe/d for the nine months ended September 30, 2009;
 
·
realized gains on commodity derivatives of approximately $228.6 million, compared to $377.2 million for the nine months ended September 30, 2009;
 
·
adjusted EBITDA of approximately $511.4 million, compared to $423.8 million for the nine months ended September 30, 2009;
 
·
adjusted net income of approximately $156.3 million, compared to $154.3 million for the nine months ended September 30, 2009;
 
·
capital expenditures, excluding acquisitions, of approximately $147.4 million, compared to $128.0 million for the nine months ended September 30, 2009; and
 
·
75 wells drilled (74 successful), compared to 66 wells drilled (65 successful) for the nine months ended September 30, 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 (gains) losses on derivatives, realized (gains) losses on canceled derivatives, impairment of goodwill and long-lived assets and (gains) losses on sale of assets, net.  See “Non-GAAP Financial Measures” on page 40 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
Acquisition – Pending
 
On September 2, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin for a contract price of $120.0 million.  The Company anticipates the acquisition will close on or before November 16, 2010, subject to closing conditions, and will be financed with cash on hand and proceeds from borrowings under its Credit Facility.
 
Acquisitions – 2010
 
On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin, from CrownQuest/Patriot for a combined price of $250.2 million.  The acquisitions increased the Company’s position in the Permian Basin and included approximately 18 MMBoe (105 Bcfe) of proved reserves as of the acquisition date.  Proved reserves as of the acquisition date were 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.
 
On July 16, 2010, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the East Texas Oil Field in Gregg and Rusk counties for a contract price of $95.0 million.  On September 29, 2010, in accordance with the terms of the purchase agreement, the Company sent a notice to the sellers of the Company’s intention to terminate the purchase agreement as a result of certain conditions to closing not being met.  The Company paid a deposit of $9.2 million in July 2010, which is reported in “other current assets” on the condensed consolidated balance sheet at September 30, 2010.  On October 11, 2010, arbitration proceedings were initiated concerning the termination of the purchase agreement and the return of the deposit.
 
On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from CrownQuest/Element for total consideration of approximately $93.5 million.  The acquisition increased the Company’s position in the Permian Basin and included approximately 7 MMBoe (40 Bcfe) of proved
 
23

Item 2.             Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
reserves as of the acquisition date.  Proved reserves as of the acquisition date were 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.
 
On May 27, 2010, the Company completed the acquisition of interests in Henry that primarily hold oil and natural gas properties located in the Permian Basin for total consideration of approximately $307.8 million.  The acquisition significantly increased the Company’s position in the Permian Basin and included approximately 17 MMBoe (102 Bcfe) of proved reserves as of the acquisition date.  Proved reserves as of the acquisition date were 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 were oil reserves.
 
On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount that hold oil and natural gas properties in the Antrim Shale located in northern Michigan for total consideration of approximately $326.8 million.  The acquisition provided the Company with a new operating region in northern Michigan and included approximately 238 Bcfe of proved reserves as of the acquisition date.  Proved reserves as of the acquisition date were 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 were natural gas reserves.
 
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 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.  Proved reserves as of the acquisition date were 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.
 
Senior Notes Due 2021
 
On September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (“2021 Notes”) and received net proceeds of approximately $962.5 million.  The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility and to unwind its remaining interest rate swap agreements.  The remaining proceeds will be used to fund or partially fund acquisitions and for general corporate purposes.
 
Commodity Derivatives
 
The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas 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 October 2010, the Company entered into commodity derivative contracts, consisting of oil swaps and natural gas swaps and puts for certain years through 2015, and paid premiums for put options of approximately $29.3 million.  At October 25, 2010, the Company had derivative contracts in place for 2010 and 2011 at average prices of $99.68 per Bbl and $84.09 per Bbl for oil and $8.66 per MMBtu and $8.24 per MMBtu for natural gas, respectively.  Additionally, the Company has derivative contracts in place covering a substantial portion of its exposure to the Mid-Continent natural gas basis differential through 2015.
 
24

Item 2.             Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
The following table summarizes open positions as of October 25, 2010, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:
 
   
October 25 – December 31,
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Natural gas positions:
                                   
Fixed price swaps:
                                   
Hedged volume (MMMBtu)
    6,595       31,901       49,410       50,278       54,202       53,837  
Average price ($/MMBtu)
  $ 8.90     $ 9.50     $ 5.97     $ 5.96     $ 5.93     $ 5.95  
Puts:
                                               
Hedged volume (MMMBtu)
    1,160       19,297       25,364       25,295       23,178       23,178  
Average price ($/MMBtu)
  $ 8.50     $ 5.98     $ 6.25     $ 6.25     $ 5.00     $ 5.00  
PEPL puts: (1)
                                               
Hedged volume (MMMBtu)
    1,772       13,259                          
Average price ($/MMBtu)
  $ 7.85     $ 8.50     $     $     $     $  
Total:
                                               
Hedged volume (MMMBtu)
    9,527       64,457       74,774       75,573       77,380       77,015  
Average price ($/MMBtu)
  $ 8.66     $ 8.24     $ 6.07     $ 6.06     $ 5.65     $ 5.66  
                                                 
Oil positions:
                                               
Fixed price swaps: (2)
                                               
Hedged volume (MBbls)
    538       4,737       6,734       7,318       7,026       1,643  
Average price ($/Bbl)
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