XNAS:LINE Linn Energy LLC Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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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, 2012
 
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 March 31, 2012, there were 199,330,596 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.
CONDENSED CONSOLIDATED BALANCE SHEETS
   
March 31,
2012
 
December 31,
2011
   
(Unaudited)
     
   
(in thousands,
except unit amounts)
ASSETS
     
Current assets:
           
Cash and cash equivalents
  $ 24,184     $ 1,114  
Accounts receivable – trade, net
    290,528       284,565  
Derivative instruments
    343,764       255,063  
Other current assets
    83,799       80,734  
Total current assets
    742,275       621,476  
                 
Noncurrent assets:
               
Oil and natural gas properties (successful efforts method)
    9,128,856       7,835,650  
Less accumulated depletion and amortization
    (1,145,113 )     (1,033,617 )
      7,983,743       6,802,033  
                 
Other property and equipment
    413,308       197,235  
Less accumulated depreciation
    (52,228 )     (48,024 )
      361,080       149,211  
                 
Derivative instruments
    357,836       321,840  
Other noncurrent assets
    132,158       105,577  
      489,994       427,417  
Total noncurrent assets
    8,834,817       7,378,661  
Total assets
  $ 9,577,092     $ 8,000,137  
                 
LIABILITIES AND UNITHOLDERS’ CAPITAL
               
Current liabilities:
               
Accounts payable and accrued expenses
  $ 403,756     $ 403,450  
Derivative instruments
    16,991       14,060  
Other accrued liabilities
    95,704       75,898  
Total current liabilities
    516,451       493,408  
                 
Noncurrent liabilities:
               
Credit facility
    75,000       940,000  
Senior notes, net
    4,854,542       3,053,657  
Derivative instruments
    4,214       3,503  
Other noncurrent liabilities
    99,467       80,659  
Total noncurrent liabilities
    5,033,223       4,077,819  
                 
Commitments and contingencies (Note 10)
               
                 
Unitholders’ capital:
               
199,330,596 units and 177,364,558 units issued and outstanding at March 31, 2012, and December 31, 2011, respectively
    3,356,064       2,751,354  
Accumulated income
    671,354       677,556  
      4,027,418       3,428,910  
Total liabilities and unitholders’ capital
  $ 9,577,092     $ 8,000,137  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
   
Three Months Ended
March 31,
   
2012
 
2011
   
(in thousands, except per unit amounts)
Revenues and other:
           
Oil, natural gas and natural gas liquids sales
  $ 348,895     $ 240,707  
Gains (losses) on oil and natural gas derivatives
    2,031       (369,476 )
Marketing revenues
    1,290       1,173  
Other revenues
    1,874       1,123  
      354,090       (126,473 )
Expenses:
               
Lease operating expenses
    71,636       45,901  
Transportation expenses
    10,562       5,855  
Marketing expenses
    692       809  
General and administrative expenses
    43,321       30,560  
Exploration costs
    410       445  
Bad debt expenses
    16       (38 )
Depreciation, depletion and amortization
    117,276       66,366  
Taxes, other than income taxes
    25,195       15,727  
Losses on sale of assets and other, net
    1,478       614  
      270,586       166,239  
Other income and (expenses):
               
Loss on extinguishment of debt
          (84,562 )
Interest expense, net of amounts capitalized
    (77,519 )     (63,464 )
Other, net
    (3,269 )     (1,746 )
      (80,788 )     (149,772 )
Income (loss) before income taxes
    2,716       (442,484 )
Income tax expense
    (8,918 )     (4,198 )
Net loss
  $ (6,202 )   $ (446,682 )
                 
Net loss per unit:
               
Basic
  $ (0.04 )   $ (2.75 )
Diluted
  $ (0.04 )   $ (2.75 )
Weighted average units outstanding:
               
Basic
    193,256       163,107  
Diluted
    193,256       163,107  
                 
Distributions declared per unit
  $ 0.69     $ 0.66  
 
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
   
Total
Unitholders’
Capital
   
(in thousands)
                         
December 31, 2011
    177,365     $ 2,751,354     $ 677,556     $ 3,428,910  
Sale of units, net of underwriting discounts and expenses of $29,819
    21,090       731,542             731,542  
Issuance of units
    876                    
Distributions to unitholders
            (137,590 )           (137,590 )
Unit-based compensation expenses
            8,171             8,171  
Excess tax benefit from unit-based compensation
            2,587             2,587  
Net loss
                  (6,202 )     (6,202 )
March 31, 2012
    199,331     $ 3,356,064     $ 671,354     $ 4,027,418  
 
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,
   
2012
 
2011
   
(in thousands)
Cash flow from operating activities:
           
Net loss
  $ (6,202 )   $ (446,682 )
Adjustments to reconcile net loss to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    117,276       66,366  
Unit-based compensation expenses
    8,171       5,638  
Loss on extinguishment of debt
          84,562  
Amortization and write-off of deferred financing fees and other
    7,433       5,732  
(Gains) losses on sale of assets and other, net
    (692 )     10  
Deferred income tax
    6,253       100  
Mark-to-market on derivatives:
               
Total (gains) losses
    (2,031 )     369,476  
Cash settlements
    58,517       65,450  
Premiums paid for derivatives
    (177,541 )      
Changes in assets and liabilities:
               
(Increase) decrease in accounts receivable – trade, net
    15,606       (36,230 )
Increase in other assets
    (4,336 )     (560 )
Increase (decrease) in accounts payable and accrued expenses
    (5,237 )     9,355  
Increase (decrease) in other liabilities
    18,296       (15,251 )
Net cash provided by operating activities
    35,513       107,966  
                 
Cash flow from investing activities:
               
Acquisition of oil and natural gas properties
    (1,230,304 )     (257,349 )
Development of oil and natural gas properties
    (220,571 )     (93,086 )
Purchases of other property and equipment
    (9,895 )     (6,375 )
Proceeds from sale of properties and equipment and other
    215       (1,258 )
Net cash used in investing activities
    (1,460,555 )     (358,068 )
                 
Cash flow from financing activities:
               
Proceeds from sale of units
    761,362       648,971  
Proceeds from borrowings
    2,634,802       160,000  
Repayments of debt
    (1,700,000 )     (408,397 )
Distributions to unitholders
    (137,590 )     (105,673 )
Financing fees, offering expenses and other, net
    (113,049 )     (89,394 )
Excess tax benefit from unit-based compensation
    2,587       3,918  
Net cash provided by financing activities
    1,448,112       209,425  
                 
Net increase (decrease) in cash and cash equivalents
    23,070       (40,677 )
Cash and cash equivalents:
               
Beginning
    1,114       236,001  
Ending
  $ 24,184     $ 195,324  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
 
4

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
Note 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 (“U.S.”), primarily in the Mid-Continent, the Permian Basin, the Hugoton Basin, Michigan, Illinois, the Williston/Powder River Basin and California.  Effective January 1, 2012, the Company realigned its regions as follows: Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of Texas Panhandle (including Granite Wash and Cleveland horizontal plays), the Permian Basin, the Hugoton Basin, Michigan/Illinois, the Williston/Powder River Basin and California.  The realignment had no effect on the Company’s operations.
 
Principles of Consolidation and Reporting
 
The condensed consolidated financial statements at March 31, 2012, and for the three months ended March 31, 2012, and March 31, 2011, 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 U.S. 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, 2011.  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.
 
The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation.  Such reclassifications have no impact on previously reported net income (loss) or unitholders’ capital.
 
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, certain revenues and operating expenses, fair values of commodity 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)
 
Recently Issued Accounting Standards
 
In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement.  The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013.  The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.
 
In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements.  The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements.  The ASU is to be applied prospectively and is effective for periods beginning after December 15, 2011.  The Company adopted the ASU effective January 1, 2012.  The adoption of the requirements of the ASU, which expanded disclosures, had no effect on the Company’s results of operations or financial position.
 
Note 2 – Acquisitions and Divestitures
 
Acquisitions – 2012
 
On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin in Kansas from BP America Production Company (“BP”).  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid approximately $1.17 billion in total consideration for these properties.  The transaction was financed primarily with proceeds from the March 2012 debt offering, as described below.
 
During the first quarter of 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions.  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates.  The Company, in the aggregate, paid approximately $63 million in total consideration for these properties.
 
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 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.
 
6

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):
 
Assets:
     
Current
  $ 7,358  
Noncurrent
    207,735  
Oil and natural gas properties
    1,042,672  
Total assets acquired
  $ 1,257,765  
         
Liabilities:
       
Current liabilities
  $ 9,764  
Asset retirement obligations
    18,469  
Total liabilities assumed
  $ 28,233  
         
Net assets acquired
  $ 1,229,532  
 
Current assets include receivables and inventory and noncurrent assets include other property and equipment.  Current liabilities include payables, ad valorem taxes payable and environmental liabilities.
 
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs.  The fair values of oil and natural gas properties and asset retirement obligations 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; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate.  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
 
The revenues and expenses related to certain properties acquired from BP, Plains Exploration & Production Company (“Plains”), Panther Energy Company, LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther”), SandRidge Exploration and Production, LLC (“SandRidge”) and an affiliate of Concho Resources Inc. (“Concho”) are included in the condensed consolidated results of operations of the Company as of March 30, 2012, December 15, 2011, June 1, 2011, April 1, 2011, and March 31, 2011, respectively.  The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the three months ended March 31, 2012, and March 31, 2011, assuming the acquisition from BP had been completed as of January 1, 2011, and the acquisitions from Plains, Panther, SandRidge and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired.  The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.
 
7

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
   
Three Months Ended
March 31,
   
2012
 
2011
   
(in thousands, except
per unit amounts)
             
Total revenues and other
  $ 410,972     $ (7,608 )
Total operating expenses
  $ 318,546     $ 246,692  
Net loss
  $ (16,667 )   $ (435,800 )
                 
Net loss per unit:
               
Basic
  $ (0.09 )   $ (2.57 )
Diluted
  $ (0.09 )   $ (2.57 )
 
Acquisition – Subsequent Event
 
On April 3, 2012, the Company entered into a joint-venture agreement with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby LINN Energy will participate as a partner in the CO2 enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming.  Anadarko assigned LINN Energy 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs.  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 March 7, 2012, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in east Texas for a contract price of $175 million.  The Company anticipates the acquisition will close May 1, 2012, subject to closing conditions, and will be financed with borrowings under its Credit Facility, as defined in Note 6.
 
Acquisition – 2011
 
On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Williston Basin from Concho.  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid $194 million in cash and recorded a receivable from Concho of $2 million, resulting in total consideration for the acquisition of approximately $192 million.  The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.
 
Note 3 – Unitholders’ Capital
 
Equity Distribution Agreement
 
In August 2011, the Company entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million.  Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent.  The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
 
8

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions and professional service expenses).  The Company used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility.  At March 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.
 
Public Offering of Units
 
In January 2012, the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $29 million).  The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.
 
In March 2011, the Company sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million).  The Company used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Senior Notes and 2018 Senior Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Senior Notes and 2018 Senior Notes (see Note 6).  The Company used the remaining net proceeds from the sale of units to finance a portion of the March 31, 2011, acquisition in the Williston/Powder River Basin region.
 
Distributions
 
Under the Company’s limited liability company agreement, the Company’s 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, 2012, are presented on the condensed consolidated statement of unitholders’ capital.  On April 24, 2012, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the first quarter of 2012, which represents a 5% increase over the previous quarter.  The distribution, totaling approximately $145 million, will be paid on May 15, 2012, to unitholders of record as of the close of business on May 8, 2012.
 
Note 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,
2012
 
December 31,
2011
   
(in thousands)
Proved properties:
           
Leasehold acquisition
  $ 7,060,195     $ 6,040,239  
Development
    1,733,729       1,484,486  
Unproved properties
    334,932       310,925  
      9,128,856       7,835,650  
Less accumulated depletion and amortization
    (1,145,113 )     (1,033,617 )
    $ 7,983,743     $ 6,802,033  
 
9

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Note 5 – Unit-Based Compensation
 
During the three months ended March 31, 2012, the Company granted an aggregate 913,663 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $34 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,
   
2012
 
2011
   
(in thousands)
             
General and administrative expenses
  $ 7,622     $ 5,404  
Lease operating expenses
    549       234  
Total unit-based compensation expenses
  $ 8,171     $ 5,638  
                 
Income tax benefit
  $ 3,019     $ 2,083  
 
Note 6 – Debt
 
The following summarizes debt outstanding:
 
   
March 31, 2012
 
December 31, 2011
   
Carrying
Value
 
Fair
Value (1)
 
Interest
Rate (2)
 
Carrying
Value
 
Fair
Value (1)
 
Interest
Rate (2)
   
(in millions, except percentages)
 
                                     
Credit facility
  $ 75     $ 75       2.00 %   $ 940     $ 940       2.57 %
11.75% senior notes due 2017
    41       46       12.73 %     41       46       12.73 %
9.875% senior notes due 2018
    14       16       10.25 %     14       16       10.25 %
6.50% senior notes due May 2019
    750       732       6.62 %     750       742       6.62 %
6.25% senior notes due November 2019
    1,800       1,739       6.25 %                  
8.625% senior notes due 2020
    1,300       1,401       9.00 %     1,300       1,406       9.00 %
7.75% senior notes due 2021
    1,000       1,034       8.00 %     1,000       1,036       8.00 %
Less current maturities
                                       
      4,980     $ 5,043               4,045     $ 4,186          
Unamortized discount
    (50 )                     (51 )                
Total debt, net of discount
  $ 4,930                     $ 3,994                  
 
(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, which are characteristic of Level 2 fair value measurement inputs.
 
(2)
Represents variable interest rate for the Credit Facility and effective interest rates for the senior notes.
 
10

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Credit Facility
 
The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount.  In October 2011, as part of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with a maximum commitment amount of $1.5 billion.  In February 2012, lenders approved an increase in the maximum commitment amount to $2.0 billion.  As a result of the Company’s March 2012 debt offering, the borrowing base was reduced from $3.0 billion to $2.6 billion, but the Company’s availability under the facility remains at the maximum commitment amount of $2.0 billion.  The maturity date is April 2016.
 
During 2012, in connection with amendments to its Credit Facility, the Company incurred financing fees and expenses of approximately $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 March 31, 2012, available borrowing capacity under the Credit Facility was $1.9 billion, which includes a $4 million reduction in availability for outstanding letters of credit.
 
Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion.  The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions.  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 and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries.  The Company and its subsidiaries are required to maintain the mortgages on properties representing at least 80% of the total value of its and its subsidiaries’ oil and natural gas properties.  Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.
 
At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Credit Facility).  Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR.  The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum equal to 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base.  The Company is in compliance with all financial and other covenants of the Credit Facility.
 
Senior Notes Due November 2019
 
On March 2, 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (“November 2019 Senior Notes”) at a price of 99.989%.  The November 2019 Senior Notes were sold to a group of 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 $1.77 billion (after deducting the initial purchasers’ discount of $198,000 and offering expenses of approximately $29 million).  The Company used the net proceeds to fund the BP acquisition (see Note 2).  The remaining proceeds were used to repay indebtedness under its Credit Facility and for general corporate purposes.  The financing fees and expenses of approximately $29 million incurred in connection
 
11

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
with the November 2019 Senior Notes will be amortized over the life of the notes.  Such amortized expenses and discount are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.
 
The November 2019 Senior Notes were issued under an indenture dated March 2, 2012 (“November 2019 Indenture”), mature November 1, 2019, and bear interest at 6.25%.  Interest is payable semi-annually on May 1 and November 1, beginning November 1, 2012.  The November 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness.  Each of the Company’s material subsidiaries has guaranteed the November 2019 Senior Notes on a senior unsecured basis.  The November 2019 Indenture provides that the Company may redeem: (i) on or prior to November 1, 2015, up to 35% of the aggregate principal amount of the November 2019 Senior Notes at a redemption price of 106.25% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the November 2019 Indenture) and accrued and unpaid interest; and (iii) on or after November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to 103.125%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest.  The November 2019 Indenture also provides that, if a change of control (as defined in the November 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the November 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
 
The November 2019 Indenture contains covenants substantially similar to those under the Company’s May 2019 Senior Notes, 2010 Issued Senior Notes and Original Senior Notes, as defined below, 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 November 2019 Senior Notes.
 
In connection with the issuance and sale of the November 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“November 2019 Registration Rights Agreement”) with the initial purchasers.  Under the November 2019 Registration Rights Agreement, the Company agreed to use its reasonable 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 November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued.  In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the November 2019 Senior Notes.  If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the November 2019 Senior Notes under certain circumstances.
 
Senior Notes Due May 2019
 
On May 13, 2011, the Company issued $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “May 2019 Senior Notes”).  The indentures related to the May 2019 Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes.
 
12

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Senior Notes Due 2020 and Senior Notes Due 2021
 
The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”).  The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes.  However, in 2011, the Company caused the trustee to remove the restrictive legends from each of the 2010 Issued Senior Notes making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s obligations under each of the registration rights agreements entered into in connection with the issuance of the 2010 Issued Senior Notes.
 
Senior Notes Due 2017 and Senior Notes Due 2018
 
The Company also has $41 million (originally $250 million) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Senior Notes”) and $14 million (originally $256 million) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 2017 Senior Notes, the “Original Senior Notes”).  The indentures related to the Original Senior Notes initially contained redemption provisions and covenants that were substantially similar to those of the November 2019 Senior Notes; however, in conjunction with the tender offers in 2011, the indentures were amended and most of the covenants and certain default provisions were eliminated.  The amendments became effective upon the execution of the supplemental indentures to the indentures governing the Original Senior Notes.
 
In March 2011, in accordance with the indentures related to the Original Senior Notes, the Company redeemed and also repurchased through cash tender offers, a portion of the Original Senior Notes.  In connection with the redemptions and cash tender offers of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $85 million for the three months ended March 31, 2011.
 
Note 7 – Derivatives
 
Commodity Derivatives
 
The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements.  The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales.  The Company did not designate any of 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 March 31, 2012, and represents, as of such date, derivatives in place through December 31, 2016, on annual production volumes:
 
   
April 1 –
December 31,
2012
 
2013
 
2014
 
2015
 
2016
Natural gas positions:
                             
Fixed price swaps:
                             
Hedged volume (MMMBtu)
    55,416       81,815       90,904       99,937       20,240  
Average price ($/MMBtu)
  $ 5.40     $ 5.31     $ 5.35     $ 5.43     $ 4.06  
Puts: (1)
                                       
Hedged volume (MMMBtu)
    49,984       64,298       56,998       58,714       24,297  
Average price ($/MMBtu)
  $ 5.48     $ 5.49     $ 5.00     $ 5.00     $ 5.00  
Total:
                                       
Hedged volume (MMMBtu)
    105,400       146,113       147,902       158,651       44,537  
Average price ($/MMBtu)
  $ 5.44     $ 5.39     $ 5.21     $ 5.27     $ 4.57  
                                         
Oil positions:
                                       
Fixed price swaps: (2)
                                       
Hedged volume (MBbls)
    6,508       9,523       9,523       10,070        
Average price ($/Bbl)
  $ 97.57     $ 98.19     $ 95.67     $ 98.38     $  
Puts:
                                       
Hedged volume (MBbls)
    1,742       2,440       513              
Average price ($/Bbl)
  $ 100.00     $ 100.00     $ 100.00     $     $  
Total:
                                       
Hedged volume (MBbls)
    8,250       11,963       10,036       10,070        
Average price ($/Bbl)
  $ 98.08     $ 98.56     $ 95.89     $ 98.38     $  
                                         
Natural gas basis differential positions: (3)
                                       
Panhandle basis swaps:
                                       
Hedged volume (MMMBtu)
    56,191       77,800       79,388       87,162       19,764  
Hedged differential ($/MMBtu)
  $ (0.56 )   $ (0.56 )   $ (0.33 )   $ (0.33 )   $ (0.31 )
MichCon basis swaps:
                                       
Hedged volume (MMMBtu)
    7,315       9,600       9,490       9,344        
Hedged differential ($/MMBtu)
  $ 0.12     $ 0.10     $ 0.08     $ 0.06     $  
Houston Ship Channel basis swaps:
                                       
Hedged volume (MMMBtu)
    4,190       5,731       5,256       4,891       4,575  
Hedged differential ($/MMBtu)
  $ (0.10 )   $ (0.10 )   $ (0.10 )   $ (0.10 )   $ (0.10 )
Permian basis swaps:
                                       
Hedged volume (MMMBtu)
    3,410       4,636       4,891       5,074        
Hedged differential ($/MMBtu)
  $ (0.19 )   $ (0.20 )   $ (0.21 )   $ (0.21 )   $  
                                         
Oil timing differential positions:
                                       
Trade month roll swaps: (4)
                                       
Hedged volume (MBbls)
    4,617       6,315       6,315       840        
Hedged differential ($/Bbl)
  $ 0.21     $ 0.21     $ 0.21     $ 0.17     $  
 
(1)
Includes certain outstanding natural gas puts of approximately 7,964 MMMBtu for the period April 1, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.
 
14

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
(2)
Includes certain outstanding fixed price oil swaps on 14,750 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, 2016, December 31, 2017, and December 31, 2018, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.
 
(3)
Settle on the respective pricing index to hedge basis differential associated with natural gas production.
 
(4)
The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions.  In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).
 
During the three months ended March 31, 2012, the Company entered into commodity derivative contracts consisting of oil and natural gas swaps and puts for April 2012 through December 2016, and paid premiums for put options of approximately $178 million.  Also during the three months ended March 31, 2012, the Company entered into natural gas basis swaps for April 2012 through December 2016.
 
Settled derivatives on natural gas production for the three months ended March 31, 2012, included volumes of 23,642 MMMBtu, at an average contract price of $5.84 per MMBtu.  Settled derivatives on oil production for the three months ended March 31, 2012, included volumes of 2,578 MBbls at an average contract price of $97.93 per Bbl.  Settled derivatives on natural gas production for the three months ended March 31, 2011, included volumes of 16,072 MMMBtu, at an average contract price of $8.25 per MMBtu.  Settled derivatives on oil production for the three months ended March 31, 2011, included volumes of 1,807 MBbls at an average contract price of $84.20 per Bbl.  The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month.  The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.
 
Balance Sheet Presentation
 
The Company’s commodity 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,
2012
 
December 31,
2011
   
(in thousands)
Assets:
           
Commodity derivatives
  $ 1,092,739     $ 880,175  
                 
Liabilities:
               
Commodity derivatives
  $ 412,344     $ 320,835  
 
By using derivative instruments to economically hedge exposures to changes in commodity prices, 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 participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives.  The Credit Facility 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 receive 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
 
15

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
instruments, was approximately $1.1 billion at March 31, 2012.  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 derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.
 
Gains (Losses) on Derivatives
 
Gains and losses on derivatives, including realized and unrealized gains and losses, are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”  Realized gains (losses), excluding canceled derivatives, represent amounts related to the settlement of derivative instruments and are aligned with the underlying production.  Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.
 
The following presents the Company’s reported gains and losses on derivative instruments:
 
   
Three Months Ended
March 31,
   
2012
 
2011
   
(in thousands)
Realized gains:
           
Commodity derivatives
  $ 55,255     $ 55,809  
Unrealized losses:
               
Commodity derivatives
    (53,224 )     (425,285 )
Total gains (losses):
               
Commodity derivatives
  $ 2,031     $ (369,476 )
 
Note 8 – Fair Value Measurements on a Recurring Basis
 
The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis.  The Company uses certain pricing models to determine the fair value of its derivative financial instruments.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets.  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 derivatives.
 
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
 
   
March 31, 2012
   
Level 2
 
Netting (1)
 
Total
   
(in thousands)
Assets:
                 
Commodity derivatives
  $ 1,092,739     $ (391,139 )   $ 701,600  
                         
Liabilities:
                       
Commodity derivatives
  $ 412,344     $ (391,139 )   $ 21,205  
 
(1)
Represents counterparty netting under agreements governing such derivatives.
 
16

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Note 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% for the three months ended March 31, 2012); and (iv) a credit-adjusted risk-free interest rate (average of 7.35% for the three months ended March 31, 2012).  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
 
The following presents a reconciliation of the asset retirement obligations (in thousands):
 
Asset retirement obligations at December 31, 2011
  $ 71,142  
Liabilities added from acquisitions
    18,469  
Liabilities added from drilling
    274  
Current year accretion expense
    1,385  
Settlements
    (1,043 )
Asset retirement obligations at March 31, 2012
  $ 90,227  
 
Note 10 – Commitments and Contingencies
 
The Company has been named as a defendant in a number of lawsuits, 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.  For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company.  Discovery in this dispute is ongoing and is not complete.  As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.  In addition, the Company is involved in various other disputes arising 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 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.
 
In 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York.  In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”).  In December 2011, a Chapter 11 Plan (“Plan”) was approved by the Bankruptcy Court.  Based on the recovery estimates described in the approved disclosure statement relating to the Plan, the Company expects to ultimately receive a substantial portion of the Company Claim.  At March 31, 2012, the Company had a net receivable, which was valued based on market expectations, of approximately $7 million from Lehman Commodity Services related to canceled derivative contracts, and is included in “other current assets” on the consolidated balance sheets.  An initial distribution under the Plan of approximately $25 million was received by the Company on April 19, 2012.
 
17

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Note 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.
 
The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss:
 
   
  Net Loss
(Numerator)
 
Units
(Denominator)
   
Per Unit
Amount
 
      (in thousands)          
Three months ended March 31, 2012:
                         
Net loss:
                         
Allocated to units
    $ (6,202 )                  
Allocated to unvested restricted units
      (1,375 )                  
      $ (7,577 )                  
Net loss per unit:
                           
Basic net loss per unit
                193,256       $ (0.04 )  
Dilutive effect of unit equivalents
                           
Diluted net loss per unit
                193,256       $ (0.04 )  
                                 
Three months ended March 31, 2011:
                               
Net loss:
                               
Allocated to units
    $ (446,682 )                      
Allocated to unvested restricted units
      (1,219 )                      
      $ (447,901 )                      
Net loss per unit:
                               
Basic net loss per unit
                163,107       $ (2.75 )  
Dilutive effect of unit equivalents
                           
Diluted net loss per unit
                163,107       $ (2.75 )  
 
Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 2 million unit options and warrants for the three months ended March 31, 2012, and March 31, 2011.  All equivalent units were anti-dilutive for the three months ended March 31, 2012, and March 31, 2011.
 
Note 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 state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders.  Limited liability companies are subject to Texas margin tax.  Limited liability companies were also subject to state income taxes in Michigan during the three months ended March 31, 2011.  In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  As such, with the exception of the state of Texas 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.
 
18

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Note 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:
 
   
March 31,
2012
 
December 31,
2011
   
(in thousands)
             
Accrued compensation
  $ 8,762     $ 19,581  
Accrued interest
    84,796       55,170  
Other
    2,146       1,147  
    $ 95,704     $ 75,898  
 
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
   
Three Months Ended
March 31,
   
2012
 
2011
   
(in thousands)
             
Cash payments for interest, net of amounts capitalized
  $ 42,517     $ 62,983  
Cash payments for income taxes
  $ 20     $ 557  
Noncash investing activities:
               
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
               
Fair value of assets acquired
  $ 1,257,765     $ 234,482  
Cash paid, net of cash acquired
    (1,230,304 )     (237,349 )
Receivables from sellers
    772       2,087  
Payables to sellers
          (1,456 )
Liabilities assumed
  $ 28,233     $ (2,236 )
 
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 approximately $4 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2012, and December 31, 2011, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
 
The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility.  At December 31, 2011, approximately $54 million was included in “accounts payable and accrued expenses” on the consolidated balance sheet which represents reclassified net outstanding checks.  There was no such balance at March 31, 2012.  The Company presents these net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.
 
19

Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
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, 2011, 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, 2011.  A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”
 
Executive Overview
 
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its IPO in January 2006.  The Company’s properties are located in six operating regions in the United States (“U.S.”):
 
 
·
Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of Texas Panhandle (including Granite Wash and Cleveland horizontal plays);
 
·
Permian Basin, which includes areas in west Texas and southeast New Mexico;
 
·
Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle;
 
·
Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;
 
·
Williston/Powder River Basin, which includes the Bakken formation in North Dakota; and
 
·
California, which includes the Brea Olinda Field of the Los Angeles Basin.
 
Results for the three months ended March 31, 2012, included the following:
 
 
·
oil, natural gas and NGL sales of approximately $349 million compared to $241 million for the first quarter of 2011;
 
·
average daily production of 471 MMcfe/d compared to 312 MMcfe/d for the first quarter of 2011;
 
·
realized gains on commodity derivatives of approximately $55 million compared to $56 million for the first quarter of 2011;
 
·
adjusted EBITDA of approximately $302 million compared to $210 million for the first quarter of 2011;
 
·
adjusted net income of approximately $48 million compared to $62 million for the first quarter of 2011;
 
·
capital expenditures, excluding acquisitions, of approximately $259 million compared to $113 million for the first quarter of 2011; and
 
·
81 wells drilled (79 successful) compared to 46 wells drilled (44 successful) for the first quarter of 2011.
 
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 long-lived assets, loss on extinguishment of debt and (gains) losses on sale of assets, net.  See “Non-GAAP Financial Measures” on page 34 for a
 
20

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
Acquisitions
 
On April 3, 2012, the Company entered into a joint-venture agreement with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby LINN Energy will participate as a partner in the CO2 enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming.  Anadarko assigned LINN Energy 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs.  The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the agreement date.
 
On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin in Kansas from BP America Production Company (“BP”) for total consideration of approximately $1.17 billion.  The acquisition included approximately 701 Bcfe of proved reserves as of the acquisition date.
 
During the first quarter of 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions.  The Company, in the aggregate, paid approximately $63 million in total consideration for these properties.
 
Proved reserves as of the acquisition date for all of the above referenced acquisitions 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.
 
Acquisition – Pending
 
On March 7, 2012, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in east Texas for a contract price of $175 million.  The Company anticipates the acquisition will close May 1, 2012, subject to closing conditions, and will be financed with borrowings under its Credit Facility, as defined in Note 6.
 
Financing and Liquidity
 
In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions).  The Company used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility.  At March 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.
 
In January 2012, the Company completed a public offering of units for net proceeds of approximately $674 million.  The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.
 
The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount.  In February 2012, lenders approved an increase in the maximum commitment amount from $1.5 billion to $2.0 billion.  The maturity date is April 2016.
 
In March 2, 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (see Note 6) and used the net proceeds of approximately $1.77 billion to fund the Hugoton acquisition (see Note 2).  The remaining proceeds were used to repay indebtedness under its Credit Facility and for general corporate purposes.
 
21

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
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.
 
22

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
In April 2012, the Company entered into commodity derivative contracts consisting of oil and natural gas swaps for 2016 and 2017 and oil puts for 2014 and 2015, and paid premiums for put options of approximately $50 million.  The following table summarizes open positions as of April 22, 2012, and represents, as of such date, derivatives in place through December 31, 2017, on annual production volumes:
 
   
April 23 –
December 31,
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Natural gas positions:
                                   
Fixed price swaps:
                                   
Hedged volume (MMMBtu)
    49,686       81,815       90,904       99,937       79,898       70,445  
Average price ($/MMBtu)
  $ 5.39     $ 5.31     $ 5.35     $ 5.43     $ 4.28     $ 4.37  
Puts: (1)
                                               
Hedged volume (MMMBtu)
    44,801       64,298       56,998       58,714       24,297        
Average price ($/MMBtu)
  $ 5.47     $ 5.49     $ 5.00     $ 5.00     $ 5.00     $  
Total:
                                               
Hedged volume (MMMBtu)
    94,487       146,113       147,902       158,651       104,195       70,445  
Average price ($/MMBtu)
  $ 5.43     $ 5.39     $ 5.21     $ 5.27     $ 4.45     $ 4.37  
                                                 
Oil positions:
                                               
Fixed price swaps: (2)
                                               
Hedged volume (MBbls)
    6,508       9,523       9,523       10,070       7,448       3,650  
Average price ($/Bbl)
  $ 97.57     $ 98.19     $ 95.67     $ 98.38     $ 91.57     $ 91.04  
Puts:
                                               
Hedged volume (MBbls)
    1,742       2,440       3,287       1,764              
Average price ($/Bbl)
  $ 100.00     $ 100.00     $ 91.56     $ 90.00     $     $  
Total:
                                               
Hedged volume (MBbls)
    8,250       11,963       12,810       11,834       7,448       3,650  
Average price ($/Bbl)
  $ 98.08     $ 98.56     $ 94.61     $ 97.13     $ 91.57     $ 91.04  
                                                 
Natural gas basis differential positions: (3)
                                               
Panhandle basis swaps:
                                               
Hedged volume (MMMBtu)
    50,010       77,800       79,388       87,162       19,764        
Hedged differential ($/MMBtu)
  $ (0.55 )   $ (0.56 )   $ (0.33 )   $ (0.33 )   $ (0.31 )   $  
MichCon basis swaps:
                                               
Hedged volume (MMMBtu)
    6,517       9,600       9,490       9,344              
Hedged differential ($/MMBtu)
  $ 0.12     $ 0.10     $ 0.08     $ 0.06     $     $  
Houston Ship Channel basis swaps:
                                               
Hedged volume (MMMBtu)
    4,190       5,731       5,256       4,891       4,575        
Hedged differential ($/MMBtu)
  $ (0.10 )   $ (0.10 )   $ (0.10 )   $ (0.10 )   $ (0.10 )   $  
Permian basis swaps:
                                               
Hedged volume (MMMBtu)
    3,038       4,636       4,891       5,074              
Hedged differential ($/MMBtu)
  $ (0.19 )   $ (0.20 )   $ (0.21 )   $ (0.21 )   $     $  
                                                 
Oil timing differential positions:
                                               
Trade month roll swaps: (4)
                                               
Hedged volume (MBbls)
    4,167       6,315       6,315       840              
Hedged differential ($/Bbl)
  $ 0.21     $ 0.21     $ 0.21     $ 0.17     $     $  
 
(1)
Includes certain outstanding natural gas puts of approximately 7,095 MMMBtu for the period April 23, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.
 
23

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
(2)
Includes certain outstanding fixed price oil swaps which may be extended annually on 8,000 Bbls of daily production for the year ending December 31, 2016, 14,750 Bbls of daily production for the years ending December 31, 2017, and December 31, 2018, and 6,750 Bbls of daily production for the year ending December 31, 2019, at prices of $100.00 per Bbl for 2016, 2017 and 2018 and $90.00 per Bbl for 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.
 
(3)
Settle on the respective pricing index to hedge basis differential associated with natural gas production.
 
(4)
The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions.  In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).
 
24

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Results of Operations
 
Three Months Ended March 31, 2012, Compared to Three Months Ended March 31, 2011
 
   
Three Months Ended
March 31,
     
   
2012
 
2011
 
Variance
   
(in thousands)
Revenues and other:
                 
Natural gas sales
  $ 65,785     $ 66,798     $ (1,013 )
Oil sales
    231,165       138,638       92,527  
NGL sales
    51,945       35,271       16,674  
Total oil, natural gas and NGL sales
    348,895       240,707       108,188  
Gains (losses) on oil and natural gas derivatives
    2,031       (369,476 )     371,507  
Marketing revenues
    1,290       1,173       117  
Other revenues
    1,874       1,123       751  
    $ 354,090     $ (126,473 )   $ 480,563  
Expenses:
                       
Lease operating expenses
  $ 71,636     $ 45,901     $ 25,735  
Transportation expenses
    10,562       5,855       4,707  
Marketing expenses
    692       809       (117 )
General and administrative expenses (1)
    43,321       30,560       12,761  
Exploration costs
    410       445       (35 )
Bad debt expenses
    16       (38 )     54  
Depreciation, depletion and amortization
    117,276       66,366       50,910  
Taxes, other than income taxes
    25,195       15,727       9,468  
Losses on sale of assets and other, net
    1,478       614       864  
    $ 270,586     $ 166,239     $ 104,347  
                         
Other income and (expenses)
  $ (80,788 )   $ (149,772 )   $ 68,984  
                         
Income (loss) before income taxes
  $ 2,716     $ (442,484 )   $ 445,200  
                         
Adjusted EBITDA (2)
  $ 302,139     $ 209,996     $ 92,143