Attached files

file filename
EX-2.2 - PSA SANDRIDGE EXPLORATION AND PRODUCTION - ROAN RESOURCES, INC.exhibit2-2.htm
EX-2.1 - PSA COG OPERATING LLC - ROAN RESOURCES, INC.exhibit2-1.htm
EX-10.1 - AMENDMENT NO 1 TO FIRST AMEND EMPLOYEE AGREEMENT - ROAN RESOURCES, INC.exhibit10-1.htm
EX-31.2 - CERTIFICATION OF CFO SECTION 302 - ROAN RESOURCES, INC.exhibit31-2.htm
EX-31.1 - CERTIFICATION OF CEO SECTION 302 - ROAN RESOURCES, INC.exhibit31-1.htm
EX-32.1 - CERTIFICATION OF CEO SECTION 906 - ROAN RESOURCES, INC.exhibit32-1.htm
EX-32.2 - CERTIFICATION OF CFO SECTION 906 - ROAN RESOURCES, INC.exhibit32-2.htm
EXCEL - IDEA: XBRL DOCUMENT - ROAN RESOURCES, INC.Financial_Report.xls


 
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, 2011
 
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, 2011, there were 176,792,351 units outstanding.


 
 

 

     
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As commonly used in the oil and natural gas industry and as used in this Quarterly Report on Form 10-Q, the following terms have the following meanings:
 
Bbl.  One stock tank barrel or 42 United States gallons liquid volume.
 
Bcf.  One billion cubic feet.
 
Bcfe.  One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
 
Btu.  One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
 
MBbls.  One thousand barrels of oil or other liquid hydrocarbons.
 
MBbls/d. MBbls per day.
 
Mcf.  One thousand cubic feet.
 
Mcfe.  One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
 
MMBbls.  One million barrels of oil or other liquid hydrocarbons.
 
MMBoe.  One million barrels of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf.
 
MMBtu.  One million British thermal units.
 
MMcf.  One million cubic feet.
 
MMcf/d. MMcf per day.
 
MMcfe.  One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
 
MMcfe/d. MMcfe per day.
 
MMMBtu.  One billion British thermal units.
 
Tcfe.  One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
CONDENSED CONSOLIDATED BALANCE SHEETS
 
   
March 31,
2011
 
December 31,
2010
   
(Unaudited)
     
   
(in thousands,
except unit amounts)
ASSETS
     
Current assets:
           
Cash and cash equivalents
  $ 195,324     $ 236,001  
Accounts receivable – trade, net
    214,654       184,624  
Derivative instruments
    135,640       234,675  
Other current assets
    56,914       55,609  
Total current assets
    602,532       710,909  
                 
Noncurrent assets:
               
Oil and natural gas properties (successful efforts method)
    6,002,884       5,664,503  
Less accumulated depletion and amortization
    (779,795 )     (719,035 )
      5,223,089       4,945,468  
                 
Other property and equipment
    147,266       139,903  
Less accumulated depreciation
    (38,252 )     (35,151 )
      109,014       104,752  
                 
Derivative instruments
    11,309       56,895  
Other noncurrent assets
    121,216       115,124  
      132,525       172,019  
Total noncurrent assets
    5,464,628       5,222,239  
Total assets
  $ 6,067,160     $ 5,933,148  
                 
LIABILITIES AND UNITHOLDERS’ CAPITAL
               
Current liabilities:
               
Accounts payable and accrued expenses
  $ 231,872     $ 219,830  
Derivative instruments
    44,551       12,839  
Other accrued liabilities
    67,966       82,439  
Total current liabilities
    344,389       315,108  
                 
Noncurrent liabilities:
               
Credit facility
    160,000        
Senior notes, net
    2,347,806       2,742,902  
Derivative instruments
    298,390       39,797  
Other noncurrent liabilities
    48,080       47,125  
Total noncurrent liabilities
    2,854,276       2,829,824  
                 
Commitments and contingencies (Note 10)
               
                 
Unitholders’ capital:
               
176,792,351 units and 159,009,795 units issued and outstanding at March 31, 2011, and December 31, 2010, respectively
    3,076,060       2,549,099  
Accumulated income (loss)
    (207,565 )     239,117  
      2,868,495       2,788,216  
Total liabilities and unitholders’ capital
  $ 6,067,160     $ 5,933,148  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
   
Three Months Ended
March 31,
   
2011
 
2010
   
(in thousands, except per unit amounts)
Revenues and other:
           
Oil, natural gas and natural gas liquids sales
  $ 240,707     $ 149,386  
Gains (losses) on oil and natural gas derivatives
    (369,476 )     96,003  
Marketing revenues
    1,173       1,394  
Other revenues
    1,123       253  
      (126,473 )     247,036  
Expenses:
               
Lease operating expenses
    45,901       31,222  
Transportation expenses
    5,855       4,620  
Marketing expenses
    809       969  
General and administrative expenses
    30,560       24,488  
Exploration costs
    445       3,861  
Bad debt expenses
    (38 )     189  
Depreciation, depletion and amortization
    66,366       49,191  
Taxes, other than income taxes
    15,727       10,200  
(Gains) losses on sale of assets and other, net
    614       (322 )
      166,239       124,418  
Other income and (expenses):
               
Loss on extinguishment of debt
    (84,562 )      
Interest expense, net of amounts capitalized
    (63,464 )     (27,653 )
Losses on interest rate swaps
          (23,162 )
Other, net
    (1,746 )     (601 )
      (149,772 )     (51,416 )
Income (loss) before income taxes
    (442,484 )     71,202  
Income tax expense
    (4,198 )     (5,892 )
Net income (loss)
  $ (446,682 )   $ 65,310  
                 
Net income (loss) per unit:
               
Basic
  $ (2.75 )   $ 0.50  
Diluted
  $ (2.75 )   $ 0.50  
Weighted average units outstanding:
               
Basic
    163,107       129,533  
Diluted
    163,107       129,922  
                 
Distributions declared per unit
  $ 0.66     $ 0.63  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL
(Unaudited)
 
   
Units
 
Unitholders’
Capital
 
Accumulated
Income (Loss)
 
Total Unitholders’
Capital
   
(in thousands)
                         
December 31, 2010
    159,010     $ 2,549,099     $ 239,117     $ 2,788,216  
Sale of units, net of underwriting discounts and expenses of $26,256
    16,726       622,715             622,715  
Issuance of units
    1,056       363             363  
Distributions to unitholders
            (105,673 )           (105,673 )
Unit-based compensation expenses
            5,638             5,638  
Excess tax benefit from unit-based compensation
            3,918             3,918  
Net loss
                  (446,682 )     (446,682 )
March 31, 2011
    176,792     $ 3,076,060     $ (207,565 )   $ 2,868,495  
 
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,
   
2011
 
2010
   
(in thousands)
Cash flow from operating activities:
           
Net income (loss)
  $ (446,682 )   $ 65,310  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    66,366       49,191  
Unit-based compensation expenses
    5,638       4,135  
Loss on extinguishment of debt
    84,562        
Amortization and write-off of deferred financing fees and other
    5,732       8,916  
(Gains) losses on sale of assets and other, net
    48       (3 )
Bad debt expenses
    (38 )     189  
Deferred income tax
    100       3,623  
Mark-to-market on derivatives:
               
Total (gains) losses
    369,476       (72,841 )
Cash settlements
    65,450       54,713  
Premiums paid for derivatives
          (14,996 )
Changes in assets and liabilities:
               
Increase in accounts receivable – trade, net
    (36,230 )     (15,161 )
(Increase) decrease in other assets
    (560 )     1,140  
Increase in accounts payable and accrued expenses
    9,355       3,288  
Decrease in other liabilities
    (15,251 )     (7,772 )
Net cash provided by operating activities
    107,966       79,732  
                 
Cash flow from investing activities:
               
Acquisition of oil and natural gas properties
    (257,349 )     (199,539 )
Development of oil and natural gas properties
    (93,086 )     (22,860 )
Purchases of other property and equipment
    (6,375 )     (2,089 )
Proceeds from sale of properties and equipment and other
    (1,258 )     3  
Net cash used in investing activities
    (358,068 )     (224,485 )
                 
Cash flow from financing activities:
               
Proceeds from sale of units
    648,971       431,250  
Proceeds from borrowings
    160,000       250,000  
Repayments of debt
    (408,397 )     (445,000 )
Distributions to unitholders
    (105,673 )     (82,274 )
Financing fees, offering expenses and other, net
    (89,394 )     (16,850 )
Excess tax benefit from unit-based compensation
    3,918       1,777  
Purchase of units
          (252 )
Net cash provided by financing activities
    209,425       138,651  
                 
Net decrease in cash and cash equivalents
    (40,677 )     (6,102 )
Cash and cash equivalents:
               
Beginning
    236,001       22,231  
Ending
  $ 195,324     $ 16,129  
 
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, Michigan and California.
 
Principles of Consolidation and Reporting
 
The condensed consolidated financial statements at March 31, 2011, and for the three months ended March 31, 2011, and March 31, 2010, 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, 2010.  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.
 
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 derivatives and, when applicable, 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)
 
Note 2 – Acquisitions and Divestitures
 
Acquisitions – 2011
 
On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Bakken play, located in the Williston Basin of North Dakota, from an affiliate of Concho Resources Inc. (“Concho”).  The results of operations of these properties will be included in the condensed consolidated financial statements from the acquisition date.  The Company paid $196 million in cash and recorded a receivable from Concho of $2 million, resulting in total consideration for the acquisition of approximately $194 million.  The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.
 
During the first quarter of 2011, 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 $43 million in total consideration for these properties with cash on hand.
 
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.
 
The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):
 
Assets:
     
Current
  $ 344  
Noncurrent
    54  
Oil and natural gas properties
    234,084  
Total assets acquired
  $ 234,482  
         
Liabilities:
       
Current liabilities
  $ (2,411 )
Asset retirement obligations
    175  
Total liabilities assumed
  $ (2,236 )
Net assets acquired
  $ 236,718  
 
Current assets include receivables, prepaids and inventory of oil produced but not yet sold and noncurrent assets include other property and equipment.  Current liabilities include payables, ad valorem taxes payable and environmental liabilities.
 
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.
 
6

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Other
 
In July 2010, the Company entered into a definitive purchase and sale agreement (“PSA”) to acquire certain oil and natural gas properties for a contract price of $95 million.  Upon the execution of the PSA, the Company paid a deposit of approximately $9 million.  In September 2010, in accordance with the terms of the PSA, the Company terminated the PSA as a result of certain conditions to closing not being met.  On March 28, 2011, an arbitration panel granted a favorable final ruling to the Company with regard to the termination of the PSA and the return of the deposit.  The $9 million deposit is included in “other current assets” on the Company’s condensed consolidated balance sheet at March 31, 2011.
 
Acquisitions – Subsequent Events
 
On April 1, 2011, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin.  The Company paid $200 million in cash, including a deposit of $20 million paid in February 2011 which is reported in “other noncurrent assets” on the condensed consolidated balance sheet at March 31, 2011.  The transaction was financed with cash on hand and borrowings under the Company’s Credit Facility (as defined in Note 6).
 
On April 5, 2011, the Company completed an additional acquisition of certain oil and natural gas properties located in the Permian Basin and paid approximately $38 million in cash.  The transaction was financed with borrowings under the Company’s Credit Facility.
 
On April 13, 2011, and April 14, 2011, the Company entered into two definitive purchase and sale agreements to acquire certain oil and natural gas properties in North Dakota for a combined contract price of $163 million, subject to closing conditions.  The Company anticipates that the acquisitions will close on May 2, 2011, and will be financed with borrowings under its Credit Facility.
 
Acquisition – 2010
 
On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico from certain affiliates of Merit Energy Company (“Merit”).  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid $152 million in cash and recorded a receivable from Merit of $1 million, resulting in total consideration for the acquisition of approximately $151 million.  The transaction was financed with borrowings under the Company’s Credit Facility.
 
Note 3 – Unitholders’ Capital
 
Public Offering of Units
 
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 the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Notes and 2018 Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Notes and 2018 Notes (see Note 6).  The Company used the remaining net proceeds from the sale of units to finance a portion of the acquisition in the Williston Basin.
 
7

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
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, 2011, are presented on the condensed consolidated statement of unitholders’ capital.  On April 26, 2011, the Company’s Board of Directors declared a cash distribution of $0.66 per unit with respect to the first quarter of 2011.  The distribution, totaling approximately $117 million, will be paid on May 13, 2011, to unitholders of record as of the close of business on May 6, 2011.
 
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,
2011
 
December 31,
2010
   
(in thousands)
Proved properties:
           
Leasehold acquisition
  $ 4,923,197     $ 4,695,704  
Development
    945,912       840,175  
Unproved properties
    133,775       128,624  
      6,002,884       5,664,503  
Less accumulated depletion and amortization
    (779,795 )     (719,035 )
    $ 5,223,089     $ 4,945,468  
 
Note 5 – Unit-Based Compensation
 
During the three months ended March 31, 2011, the Company granted an aggregate 1,042,502 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $40 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,
   
2011
 
2010
   
(in thousands)
             
General and administrative expenses
  $ 5,404     $ 4,014  
Lease operating expenses
    234       121  
Total unit-based compensation expenses
  $ 5,638     $ 4,135  
Income tax benefit
  $ 2,083     $ 1,635  
 
8

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Note 6 – Debt
 
The following summarizes debt outstanding:
 
   
March 31, 2011
 
December 31, 2010
   
Carrying
Value
 
Fair
Value (1)
 
Interest
Rate (2)
 
Carrying
Value
 
Fair
Value (1)
 
Interest
Rate (2)
   
(in millions, except percentages)
                                     
Credit facility
  $ 160     $ 160       2.25 %   $     $        
11.75% senior notes due 2017
    58       69       12.73 %     250       288       12.73 %
9.875% senior notes due 2018
    40       46       10.25 %     256       279       10.25 %
8.625% senior notes due 2020
    1,300       1,438       9.00 %     1,300       1,396       9.00 %
7.75% senior notes due 2021
    1,000       1,064       8.00 %     1,000       1,021       8.00 %
Less current maturities
                                       
      2,558     $ 2,777               2,806     $ 2,984          
Unamortized discount
    (50 )                     (63 )                
Total debt, net of discount
  $ 2,508                     $ 2,743                  
 
(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 maturity of April 2015.  At March 31, 2011, the borrowing capacity under the Credit Facility was approximately $1.33 billion, which includes a $5 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 material operating subsidiaries.
 
At the Company’s election, interest on borrowings under the Credit Facility, as amended, 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 Company is in compliance with all financial and other covenants of the Credit Facility.
 
9

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Senior Notes Due 2020 and Senior Notes Due 2021
 
The Company has $1.30 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 Senior Notes”).  In each case, the 2010 Senior Notes were sold in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”).
 
The 2010 Senior Notes were issued under indentures with respective maturities of April 15, 2020, and February 1, 2021 (“Indentures”).  The 2010 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 2010 Senior Notes on a senior unsecured basis.
 
The Indentures provide that for each of the 2020 Senior Notes and the 2021 Senior Notes, the Company may redeem: (i) on or prior to April 15, 2013, and September 15, 2013, respectively, up to 35% of the aggregate principal amount of each of the 2010 Senior Notes at a redemption price of 108.625% and 107.75% of the principal amount redeemed, respectively, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to April 15, 2015, and September 15, 2015, respectively, all or part of the 2010 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the Indentures) and accrued and unpaid interest; and (iii) on or after April 15, 2015, and September 15, 2015, respectively, all or part of the 2010 Senior Notes at respective redemption prices equal to 104.313% and 103.875% of the principal amount and percentages decreasing each year thereafter to par, in each case, of the principal amount redeemed, plus accrued and unpaid interest.
 
The Indentures also provide that, if a change of control (as defined in the Indentures) occurs, the holders have a right to require the Company to repurchase all or part of the 2010 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
 
The Indentures contain covenants that, among other things, limit the Company’s ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.  The Company is in compliance with all financial and other covenants of the 2010 Senior Notes.
 
In connection with the issuance and sale of each of the 2010 Senior Notes, the Company entered into Registration Rights Agreements (“Registration Rights Agreements”).  Under each of the Registration Rights Agreements, 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 each of the 2010 Senior Notes in exchange for each of the outstanding 2010 Senior Notes.  Additionally, in certain circumstances, the Company may be required to file a shelf registration statement to cover resales of each of the 2010 Senior Notes.  However, the Company will not be obligated to file the registration statements described above if the restrictive legend on each of the 2010 Senior Notes has been removed and the 2010 Senior 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 each of the 2010 Senior Notes were issued.  If the Company fails to satisfy its obligations under the Registration Rights Agreements, the Company may be required to pay additional interest to holders of the 2010 Senior Notes under certain circumstances.
 
10

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
Effective April 6, 2011, the Company instructed the trustee for the 2020 Senior Notes to remove the restrictive legend on the 2020 Senior Notes, causing them to be freely tradeable as of that date.
 
Senior Notes Due 2017 and Senior Notes Due 2018
 
The Company also has $58 million (originally $250 million) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Notes”) and $40 million (originally $256 million) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Notes” and together with the 2017 Notes, the “Original Senior Notes”).  The indentures related to the Original Senior Notes originally contained redemption provisions and covenants that are substantially similar to those of the 2010 Senior Notes; however, in connection with the tender offers described below, the indentures were amended and most of the covenants and certain default provisions were eliminated.
 
Redemptions of Original Senior Notes
 
In accordance with the provisions of the indentures related to the 2017 Notes and the 2018 Notes, in March 2011, the Company redeemed 35%, or $87 million and $90 million, respectively, of each of the original aggregate principal amount of the 2017 Notes and 2018 Notes.  After the redemptions, $163 million and $166 million, respectively, of the 2017 Notes and 2018 Notes remained outstanding.
 
Tender Offers for Original Senior Notes
 
On February 28, 2011, the Company commenced cash tender offers (“Offers”) and related consent solicitations to purchase any and all of its outstanding 2017 Notes and 2018 Notes.  The Offers expired on March 25, 2011.  Holders who validly tendered 2017 Notes and 2018 Notes on or before March 14, 2011, received the total consideration of $1,212.50 and $1,172.50, respectively, for each $1,000 principal amount of such notes accepted for purchase.  Total consideration included a consent payment of $30.00 per $1,000 principal amount of notes accepted for purchase.  Holders who validly tendered 2017 Notes and 2018 Notes after March 14, 2011, but before March 25, 2011, received $1,182.50 and $1,142.50, respectively, for each $1,000 principal amount of such notes accepted for purchase.
 
During March 2011, the Company accepted and purchased: 1) $105 million of the aggregate principal amount of the outstanding 2017 Notes (or 65% of the remaining outstanding principal amount of the 2017 Notes), and 2) $126 million of the aggregate principal amount of the outstanding 2018 Notes (or 76% of the remaining outstanding principal amount of the 2018 Notes).  After giving effect to the purchase of the 2017 Notes and the 2018 Notes, aggregate principal amounts of $58 million and $40 million, respectively, remain outstanding at March 31, 2011.
 
In conjunction with each tender offer, the Company received consents to amendments to the indentures to the 2017 Notes and 2018 Notes, which eliminated most of the covenants and certain default provisions applicable to the series of notes issued under such indentures.  The amendments became effective upon the execution of the supplemental indentures to the indentures governing each of the 2017 Notes and the 2018 Notes.
 
In connection with the redemptions and cash tenders of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $85 million.
 
Note 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, natural gas and NGL sales.  The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.
 
11

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
The following table summarizes open positions as of March 31, 2011, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:
 
   
April 1 –
December 31,
2011
 
2012
 
2013
 
2014
 
2015
Natural gas positions:
                             
Fixed price swaps:
                             
Hedged volume (MMMBtu)
    23,926       49,410       50,278       54,202       53,837  
Average price ($/MMBtu)
  $ 9.50     $ 5.97     $ 5.96     $ 5.93     $ 5.95  
Puts:
                                       
Hedged volume (MMMBtu)
    14,515       25,364       25,295       23,178       23,178  
Average price ($/MMBtu)
  $ 5.98     $ 6.25     $ 6.25     $ 5.00     $ 5.00  
PEPL puts: (1)
                                       
Hedged volume (MMMBtu)
    9,944                          
Average price ($/MMBtu)
  $ 8.50     $     $     $     $  
Total:
                                       
Hedged volume (MMMBtu)
    48,385       74,774       75,573       77,380       77,015  
Average price ($/MMBtu)
  $ 8.24     $ 6.07     $ 6.06     $ 5.65     $ 5.66  
                                         
Oil positions:
                                       
Fixed price swaps: (2)
                                       
Hedged volume (MBbls)
    4,114       7,466       7,683       8,121       2,738  
Average price ($/Bbl)
  $ 90.79     $ 94.33     $ 97.83     $ 94.70     $ 92.84  
Puts:
                                       
Hedged volume (MBbls)
    1,764       2,196       2,190              
Average price ($/Bbl)
  $ 75.00     $ 75.00     $ 75.00     $     $  
Collars:
                                       
Hedged volume (MBbls)
    207                          
Average floor price ($/Bbl)
  $ 90.00     $     $     $     $  
Average ceiling price ($/Bbl)
  $ 112.25     $     $     $     $  
Total:
                                       
Hedged volume (MBbls)
    6,085       9,662       9,873       8,121       2,738  
Average price ($/Bbl)
  $ 86.19     $ 89.93     $ 92.76     $ 94.70     $ 92.84  
                                         
Natural gas basis differential positions:
                                       
PEPL basis swaps: (1)
                                       
Hedged volume (MMMBtu)
    26,656       37,735       38,854       42,194       42,194  
Hedged differential ($/MMBtu)
  $ (0.96 )   $ (0.89 )   $ (0.89 )   $ (0.39 )   $ (0.39 )
 
(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 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, 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.
 
In March 2011, the Company entered into commodity derivative contracts consisting of oil swaps for certain years through 2015.  Settled derivatives on natural gas production for the three months ended March 31, 2011, included
 
12

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
volumes of 16,072 MMMBtu at an average contract price of $8.25.  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.  The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month.  The oil derivatives are settled based on the month’s average daily NYMEX price of light oil and settlement occurs on the final day of the production month.
 
Interest Rate Swaps
 
The Company 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.  At March 31, 2011, the Company had no outstanding interest rate swap agreements.
 
Balance Sheet Presentation
 
The Company’s commodity derivatives and, when applicable, its interest rate swap derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets.  The following summarizes the fair value of derivatives outstanding on a gross basis:
 
   
March 31,
2011
 
December 31,
2010
   
(in thousands)
Assets:
           
Commodity derivatives
  $ 422,142     $ 637,836  
                 
Liabilities:
               
Commodity derivatives
  $ 618,134     $ 398,902  
 
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 $422 million at March 31, 2011.  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 and, when applicable, its interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated.
 
13

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
 
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” and “losses on interest rate swaps.”  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.
 
The following presents the Company’s reported gains and losses on derivative instruments:
 
   
Three Months Ended
March 31,
   
2011
 
2010
   
(in thousands)
Realized gains (losses):
           
Commodity derivatives
  $ 55,809     $ 62,503  
Interest rate swaps
          (8,021 )
    $ 55,809     $ 54,482  
Unrealized gains (losses):
               
Commodity derivatives
  $ (425,285 )   $ 33,500  
Interest rate swaps
          (15,141 )
    $ (425,285 )   $ 18,359  
Total gains (losses):
               
Commodity derivatives
  $ (369,476 )   $ 96,003  
Interest rate swaps
          (23,162 )
    $ (369,476 )   $ 72,841  
 
Note 8 – Fair Value Measurements on a Recurring Basis
 
The Company accounts for its commodity derivatives and, when applicable, its interest rate derivatives at fair value (see Note 7) on a recurring basis.  The fair value of derivative instruments is determined utilizing pricing models for significantly similar instruments.  Inputs to the pricing models include publicly available prices and forward 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 derivatives and, when applicable, its interest rate derivatives.
 
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
 
   
March 31, 2011
   
Level 2
 
Netting (1)
 
Total
   
(in thousands)
Assets:
                 
Commodity derivatives
  $ 422,142     $ (275,193 )   $ 146,949  
                         
Liabilities:
                       
Commodity derivatives
  $ 618,134     $ (275,193 )   $ 342,941  
 
(1)
Represents counterparty netting under agreements governing such derivatives.
 
14

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 (2.0% for the three months ended March 31, 2011); and (iv) a credit-adjusted risk-free interest rate (average of 7.5% for the three months ended March 31, 2011).
 
The following presents a reconciliation of the asset retirement obligations (in thousands):
 
Asset retirement obligations at December 31, 2010
  $ 42,945  
Liabilities added from acquisitions
    175  
Liabilities added from drilling
    433  
Current year accretion expense
    887  
Settlements
    (589 )
Asset retirement obligations at March 31, 2011
  $ 43,851  
 
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.
 
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.
 
15

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 net income (loss):
 
   
Net Income (Loss)
(Numerator)
 
Units
(Denominator)
 
Per Unit
Amount
   
(in thousands)
     
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 )
                         
Three months ended March 31, 2010:
                       
Net income:
                       
Allocated to units
  $ 65,310                  
Allocated to unvested restricted units
    (750 )                
    $ 64,560                  
Net income per unit:
                       
Basic net income per unit
            129,533     $ 0.50  
Dilutive effect of unit equivalents
            389        
Diluted net income per unit
            129,922     $ 0.50  
 
Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to 2 million and 1 million unit options and warrants for the three months ended March 31, 2011, and March 31, 2010, respectively.  All equivalent units were anti-dilutive for the three months ended 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 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.
 
16

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,
2011
 
December 31,
2010
   
(in thousands)
             
Accrued compensation
  $ 8,658     $ 18,931  
Accrued interest
    58,161       62,999  
Other
    1,147       509  
    $ 67,966     $ 82,439  
 
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
   
Three Months Ended
March 31,
   
2011
 
2010
   
(in thousands)
             
Cash payments for interest, net of amounts capitalized
  $ 62,983     $ 21,653  
Cash payments for income taxes
  $ 557     $ 563  
                 
Noncash investing activities:
               
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
               
Fair value of assets acquired
  $ 234,482     $ 145,911  
Cash paid, net of cash acquired
    (237,349 )     (136,039 )
Receivables from sellers
    2,087       337  
Payables to sellers
    (1,456 )      
Liabilities assumed
  $ (2,236 )   $ 10,209  
 
“Acquisition of oil and natural gas properties” presented on the condensed consolidated statements of cash flows for the three months ended March 31, 2011, includes deposits paid of approximately $20 million for pending acquisitions (see Note 2).
 
For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.  Restricted cash of approximately $3 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2011, and December 31, 2010, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
 
17

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, 2010, 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, 2010.  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 primarily located in five operating regions in the United States (“U.S.”):
 
 
·
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;
 
·
Permian Basin, which includes areas in West Texas and Southeast New Mexico;
 
·
Michigan, which includes the Antrim Shale formation in the northern part of the state; and
 
·
California, which includes the Brea Olinda Field of the Los Angeles Basin.
 
Results for the three months ended March 31, 2011, included the following:
 
 
·
oil, natural gas and NGL sales of approximately $241 million compared to $149 million in the first quarter of 2010;
 
·
average daily production of 312 MMcfe/d compared to 213 MMcfe/d in the first quarter of 2010;
 
·
realized gains on commodity derivatives of approximately $56 million compared to $63 million in the first quarter of 2010;
 
·
adjusted EBITDA of approximately $210 million compared to $152 million in the first quarter of 2010;
 
·
adjusted net income of approximately $62 million compared to $47 million in the first quarter of 2010;
 
·
capital expenditures, excluding acquisitions, of approximately $113 million compared to $27 million in the first quarter of 2010; and
 
·
46 wells drilled (44 successful) compared to 13 wells drilled (all successful) in the first quarter of 2010.
 
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, loss on extinguishment of debt and (gains) losses on sale of assets, net.  See “Non-GAAP Financial Measures” on page 28
 
18

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
Acquisitions – 2011
 
On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Bakken play, located in the Williston Basin of North Dakota, from an affiliate of Concho Resources Inc. (“Concho”) for total consideration of approximately $194 million.  The acquisition included approximately 8 MMBoe (50 Bcfe) of proved reserves as of the acquisition date.  The majority of the reserves were oil reserves.
 
During the first quarter of 2011, 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 $43 million in total consideration for these properties.
 
Acquisitions – Subsequent Event
 
On April 1, 2011, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin for total consideration of approximately $200 million.  The acquisition included approximately 10 MMBoe (60 Bcfe) of proved reserves as of the acquisition date.  The majority of the reserves were oil reserves.
 
On April 5, 2011, the Company completed an additional acquisition of certain oil and natural gas properties located in the Permian Basin and paid approximately $38 million in cash.  The transaction was financed with borrowings under the Company’s Credit Facility.
 
On April 13, 2011, and April 14, 2011, the Company entered into two definitive purchase and sale agreements to acquire certain oil and natural gas properties in North Dakota for a combined contract price of $163 million, subject to closing conditions.  The Company anticipates that the acquisitions will close on May 2, 2011, and will be financed with borrowings under its Credit Facility.
 
Financing and Liquidity
 
In accordance with the provisions of the indentures related to the 2017 Notes and the 2018 Notes, in March 2011, the Company redeemed 35%, or $87 million and $90 million, respectively, of each of the original aggregate principal amount of the Original Notes, as defined in Note 6.
 
In addition, on February 28, 2011, the Company commenced cash tender offers and related consent solicitations to purchase any and all of its outstanding 2017 Notes and 2018 Notes.  In March 2011, the Company accepted and purchased: 1) $105 million of the aggregate principal amount of the outstanding 2017 Notes (or 65% of the remaining outstanding principal amount of 2017 Notes), and 2) $126 million aggregate principal amount of the outstanding 2018 Notes (or 76% of the remaining outstanding principal amount of 2018 Notes).
 
In March 2011, the Company completed a public offering of units for net proceeds of approximately $623 million.  The Company used the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Notes and 2018 Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Notes and 2018 Notes (see Note 6).  The Company used the remaining net proceeds from the sale of units to finance a portion of the acquisition in the Williston Basin.
 
19

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Results of Operations
 
Three Months Ended March 31, 2011, Compared to Three Months Ended March 31, 2010
 
   
Three Months Ended
March 31,
     
   
2011
 
2010
 
Variance
   
(in thousands)
Revenues and other:
                 
Natural gas sales
  $ 66,798     $ 52,862     $ 13,936  
Oil sales
    138,638       65,940       72,698  
NGL sales
    35,271       30,584       4,687  
Total oil, natural gas and NGL sales
    240,707       149,386       91,321  
Gains (losses) on oil and natural gas derivatives
    (369,476 )     96,003       (465,479 )
Marketing revenues
    1,173       1,394       (221 )
Other revenues
    1,123       253       870  
    $ (126,473 )   $ 247,036     $ (373,509 )
Expenses:
                       
Lease operating expenses
  $ 45,901     $ 31,222     $ 14,679  
Transportation expenses
    5,855       4,620       1,235  
Marketing expenses
    809       969       (160 )
General and administrative expenses (1)
    30,560       24,488       6,072  
Exploration costs
    445       3,861       (3,416 )
Bad debt expenses
    (38 )     189       (227 )
Depreciation, depletion and amortization
    66,366       49,191       17,175  
Taxes, other than income taxes
    15,727       10,200       5,527  
Gains (losses) on sale of assets and other, net
    614       (322 )     936  
    $ 166,239     $ 124,418     $ 41,821  
Other income and (expenses)
  $ (149,772 )   $ (51,416 )   $ (98,356 )
Income (loss) before income taxes
  $ (442,484 )   $ 71,202     $ (513,686 )
                         
Adjusted EBITDA (2)
  $ 209,996     $ 151,509     $ 58,487  
Adjusted net income (2)
  $ 62,307     $ 47,365     $ 14,942  
 
(1)
General and administrative expenses for the three months ended March 31, 2011, and March 31, 2010, include approximately $5 million and $4 million, respectively, of noncash unit-based compensation expenses.
 
(2)
This is a non-GAAP measure used by management to analyze the Company’s performance.  See “Non-GAAP Financial Measures” on page 28 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
20

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
 
   
Three Months Ended
March 31,
     
   
2011
 
2010
 
Variance
Average daily production:
                 
Natural gas (MMcf/d)
    158       110       44 %
Oil (MBbls/d)
    17.2       9.8       76 %
NGL (MBbls/d)
    8.6       7.5       15 %
Total (MMcfe/d)
    312       213       46 %
                         
Weighted average prices (hedged): (1)
                       
Natural gas (Mcf)
  $ 8.99     $ 9.21       (2 )%
Oil (Bbl)
  $ 86.24     $ 102.39       (16 )%
NGL (Bbl)
  $ 45.81     $ 45.51       1 %
                         
Weighted average prices (unhedged): (2)
                       
Natural gas (Mcf)
  $ 4.71     $ 5.35       (12 )%
Oil (Bbl)
  $ 89.44     $ 74.76       20 %
NGL (Bbl)
  $ 45.81     $ 45.51       1 %
                         
Average NYMEX prices:
                       
Natural gas (MMBtu)
  $ 4.13     $ 5.30       (22 )%
Oil (Bbl)
  $ 94.10     $ 78.72       20 %
                         
Costs per Mcfe of production:
                       
Lease operating expenses
  $ 1.63     $ 1.63        
Transportation expenses
  $ 0.21     $ 0.24       (13 )%
General and administrative expenses (3)
  $ 1.09     $ 1.28       (15 )%
Depreciation, depletion and amortization
  $ 2.36     $ 2.56       (8 )%
Taxes, other than income taxes
  $ 0.56     $ 0.53       6 %
 
(1)
Includes the effect of realized gains on derivatives of approximately $56 million and approximately $63 million for the three months ended March 31, 2011, and March 31, 2010, respectively.
 
(2)
Does not include the effect of realized gains (losses) on derivatives.
 
(3)
General and administrative expenses for the three months ended March 31, 2011, and March 31, 2010, include approximately $5 million and $4 million, respectively, of noncash unit-based compensation expenses.  Excluding these amounts, general and administrative expenses for the three months ended March 31, 2011, and March 31, 2010, were $0.90 per Mcfe and $1.07 per Mcfe, respectively.  This is a non-GAAP measure used by management to analyze the Company’s performance.
 
21

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Revenues and Other
 
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased approximately $92 million or 61% to approximately $241 million for the three months ended March 31, 2011, from approximately $149 million for the three months ended March 31, 2010, due to higher oil and NGL prices and higher production volumes partially offset by lower natural gas prices.  Higher oil and NGL prices resulted in an increase in revenues of approximately $23 million and $200,000, respectively.  Lower natural gas prices resulted in a decrease in revenues of approximately $9 million.
 
Average daily production volumes increased to 312 MMcfe/d during the three months ended March 31, 2011, from 213 MMcfe/d during the three months ended March 31, 2010.  Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $50 million, $23 million and $4 million, respectively.
 
The following sets forth average daily production by region:
 
   
Three Months Ended
March 31,
           
   
2011
 
2010
 
Variance
Average daily production (MMcfe/d):
                       
Mid-Continent Deep
    143       124       19       16 %
Mid-Continent Shallow
    63       64       (1 )     (2 )%
Permian Basin
    58       12       46       382 %
Michigan
    34             34        
California
    14       13       1       4 %
      312       213       99       46 %
 
The 16% increase in average daily production in the Mid-Continent Deep region primarily reflects the Company’s 2010 and 2011 capital drilling programs in the Deep Granite Wash formation.  The 2% decrease in average daily production in the Mid-Continent Shallow region reflects the effects of natural declines and weather-related downtime, partially offset by the results of the Company’s drilling and optimization programs.  Average daily production volumes in the Permian Basin region reflect the impact of the acquisitions in 2010 and subsequent development capital spending.  Average daily production volumes in the Michigan region reflect the impact of the acquisitions in the second and fourth quarters of 2010.  The California region consists of a low-decline asset base and continues to produce at consistent levels.
 
Gains (Losses) on Oil and Natural Gas Derivatives
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk,” Note 7 and Note 8 for additional information about the Company’s commodity derivatives.  During the three months ended March 31, 2011, the Company had commodity derivative contracts for approximately 113% of its natural gas production and 117% of its oil production and recognized realized gains of approximately $56 million.  During the three months ended March 31, 2010, the Company had commodity derivative contracts for approximately 145% of its natural gas production and 75% of its oil and NGL production and recognized realized gains of approximately $63 million.  Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives.  If the expected future commodity prices increase compared to the contract prices on the derivatives, unrealized losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains are recognized.  During the first quarter of 2011, expected future oil and natural gas prices increased, which resulted in net unrealized losses on derivatives of approximately $425 million for the three months ended March 31, 2011.  During the first quarter of 2010, expected future oil and natural gas prices decreased, which resulted in net unrealized gains on derivatives of approximately $34 million for the three months ended March 31, 2010.  For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.
 
22

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Expenses
 
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses.  Lease operating expenses increased approximately $15 million or 47% to approximately $46 million for the three months ended March 31, 2011, from approximately $31 million for the three months ended March 31, 2010.  Lease operating expenses increased primarily due to costs associated with properties acquired in the Permian Basin and Michigan regions during 2010 (see Note 2).  Although lease operating expenses increased, expenses per Mcfe remained unchanged at $1.63 per Mcfe for the three months ended March 31, 2011, compared to the same period in 2010, due to the increase in production volumes.
 
Transportation Expenses
Transportation expenses increased approximately $1 million or 27% to approximately $6 million for the three months ended March 31, 2011, from approximately $5 million for the three months ended March 31, 2010, primarily due to higher production volumes.
 
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and include costs of employees including executive officers, related benefits, office leases and professional fees.  General and administrative expenses increased approximately $7 million or 25% to approximately $31 million for the three months ended March 31, 2011, from approximately $24 million for the three months ended March 31, 2010.  The increase was primarily due to an increase in salaries and benefits expense of approximately $4 million, driven primarily by increased employee headcount, and professional services expense of approximately $1 million.  General and administrative expenses per Mcfe decreased to $1.09 per Mcfe for the three months ended March 31, 2011, from $1.28 per Mcfe for the three months ended March 31, 2010.
 
Exploration Costs
Exploration costs decreased approximately $3 million or 89% to approximately $1 million for the three months ended March 31, 2011, from approximately $4 million for the three months ended March 31, 2010.  The decrease was primarily due to lower impairment expense on unproved properties.
 
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased approximately $17 million or 35% to approximately $66 million for the three months ended March 31, 2011, from approximately $49 million for the three months ended March 31, 2010.  Higher total production levels and oil and natural gas property acquisitions were the primary reasons for the increased expense.  Depreciation, depletion and amortization per Mcfe decreased to $2.36 per Mcfe for the three ended March 31, 2011, from $2.56 per Mcfe for the three months ended March 31, 2010.  The decrease per Mcfe is primarily due to higher reserves resulting from higher commodity prices and drilling activity in the Mid-Continent Deep region, including the Deep Granite Wash formation.
 
Taxes, Other Than Income Taxes
Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased approximately $6 million or 54% to approximately $16 million for the three months ended March 31, 2011, from approximately $10 million for the three months ended March 31, 2010.  Severance taxes, which are a function of revenues generated from production, increased approximately $6 million compared to the three months ended March 31, 2010, primarily due to higher commodity prices and production volumes.  Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, were essentially flat compared to the three months ended March 31, 2010.
 
23

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Other Income and (Expenses)
 
   
Three Months Ended
March 31,
     
   
2011
   2010
 
Variance
   
(in thousands)
                   
Loss on extinguishment of debt
  $ (84,562 )   $     $ (84,562 )
Interest expense, net of amounts capitalized
    (63,464 )     (27,653 )     (35,811 )
Realized losses on interest rate swaps
          (8,021 )     8,021  
Unrealized losses on interest rate swaps
          (15,141 )     15,141  
Other, net
    (1,746 )     (601 )     (1,145 )
    $ (149,772 )   $ (51,416 )   $ (98,356 )
 
Other income and (expenses) increased approximately $98 million during the three months ended March 31, 2011, compared to the three months ended March 31, 2010.  Interest expense increased primarily due to higher interest rates and higher amortization of financing fees associated with the 2010 Senior Notes, as defined in Note 6.  In addition, for the three months ended March 31, 2011, the Company recorded a loss on extinguishment of debt of approximately $85 million as a result of the redemptions of and tender offers for a portion of the 2017 Notes and 2018 Notes.
 
Income Tax Expense
 
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the 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.  In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  The Company recognized an income tax expense of approximately $4 million and approximately $6 million for the three months ended March 31, 2011, and March 31, 2010, respectively.  Income tax expense decreased primarily due to a Texas margin tax benefit resulting from lower pre-tax income during the three months ended March 31, 2011, compared to the same period in 2010.
 
Adjusted EBITDA
 
Adjusted EBITDA (a non-GAAP financial measure) increased approximately $58 million or 39% to approximately $210 million for the three months ended March 31, 2011, from approximately $152 million for the three months ended March 31, 2010.  The increase was primarily due to higher production revenues resulting from higher production volumes and higher commodity prices, partially offset by higher expenses.  See “Non-GAAP Financial Measures” on page 28 for a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
Liquidity and Capital Resources
 
The Company utilizes funds from equity and debt offerings, bank borrowings and cash generated from operations for capital resources and liquidity.  To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties.  For the three months ended March 31, 2011, the Company’s capital expenditures, excluding acquisitions, were approximately $113 million.  For 2011, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $610 million, including additional capital related to recently announced acquisitions.  Total capital expenditures include $570 million related to the Company's oil and natural gas capital program and $23 million related to its plant and pipeline capital.  This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustment.  The Company expects to fund these capital expenditures primarily with cash flow from operations and cash on hand.
 
24

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures.  The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves.  The Company actively reviews acquisition opportunities on an ongoing basis.  If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts under its Credit Facility, if available, or obtain additional debt or equity financing.  The Company’s Credit Facility and Indentures governing its 2010 Senior Notes and Original Senior Notes impose certain restrictions on the Company’s ability to obtain additional debt financing.  Based upon current expectations, the Company believes liquidity and capital resources will be sufficient to conduct its business and operations.
 
Statements of Cash Flows
 
The following is a comparative cash flow summary:
 
   
Three Months Ended
March 31,
     
   
2011
 
2010
 
Variance
   
(in thousands)
Net cash:
                 
Provided by operating activities (1)
  $ 107,966     $ 79,732     $ 28,234  
Used in investing activities
    (358,068 )     (224,485 )     (133,583 )
Provided by financing activities
    209,425       138,651       70,774  
Net decrease in cash and cash equivalents
  $ (40,677 )   $ (6,102 )   $ (34,575 )
 
(1)
The three months ended March 31, 2010, includes premiums paid for commodity derivatives of approximately $15 million.
 
Operating Activities
Cash provided by operating activities for the three months ended March 31, 2011, was approximately $108 million, compared to approximately $80 million for the three months ended March 31, 2010.  The increase was primarily due to higher net income, excluding noncash mark-to-market activities related to derivatives contracts and other noncash items, partially offset by higher working capital needs.  Additionally, during the three months ended March 31, 2011, no premiums were paid for derivative contracts; however, approximately $15 million of premiums were paid for derivative contracts during the same period in 2010.
 
Premiums paid during the three months ended March 31, 2010, related to commodity derivative contracts that hedge future production and were primarily funded through the Company’s Credit Facility.  These derivative contracts provide the Company long-term cash flow predictability to manage its business, service debt and pay distributions.  The production volumes attributed to the derivative contracts the Company enters into in the future will be directly related to expected future production.  See Note 7 and Note 8 for additional details about the Company’s commodity derivatives.
 
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
 
   
Three Months Ended
March 31,
   
2011
 
2010
   
(in thousands)
Cash flow from investing activities:
           
Acquisition of oil and natural gas properties, net of cash acquired
  $ (257,349 )   $ (199,539 )
Capital expenditures
    (99,461 )     (24,949 )
Proceeds from sale of properties and equipment and other
    (1,258 )     3  
    $ (358,068 )   $ (224,485 )

 
25

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
The primary use of cash in investing activities is for capital spending.  Cash used in investing activities for the three months ended March 31, 2011, primarily relates to the acquisitions of properties in the Williston Basin in North Dakota and the Permian Basin.  See Note 2 for additional details.
 
Capital expenditures were higher for the three months ended March 31, 2011, compared to the same period in 2010, primarily due to an increase in drilling activities in the Mid-Continent Deep and Permian Basin regions.  Excluding acquisitions, capital expenditures for full year 2011 are expected to be approximately $610 million, including additional capital related to recently announced acquisitions.
 
Financing Activities
Cash provided by financing activities was approximately $209 million for the three months ended March 31, 2011, compared to approximately $139 million for the three months ended March 31, 2010.  The increase in financing cash flows was primarily attributable to higher proceeds from the sale of units by the Company in March 2011 as described below and lower repayments of debt, partially offset by lower proceeds from borrowings, higher financing and offering expenses including expenses related to the extinguishment of debt, and higher distributions to unitholders.  The following provides a comparative summary of proceeds from borrowings and repayments of debt:
 
   
Three Months Ended
March 31,
   
2011
 
2010
   
(in thousands)
Proceeds from borrowings:
           
Credit facility
  $ 160,000     $ 250,000  
                 
Repayments of debt:
               
Credit facility
  $     $ (445,000 )
Senior notes
    (408,397 )      
    $ (408,397 )   $ (445,000 )
 
Debt
 
The Company’s Credit Facility has a borrowing base of $1.50 billion and a maturity of April 2015.  At March 31, 2011, the borrowing capacity under the Credit Facility was approximately $1.33 billion, which includes a $5 million reduction in availability for outstanding letters of credit.  In accordance with the provisions of the indentures related to the 2017 Notes and the 2018 Notes, in March 2011, the Company redeemed 35%, or $87 million and $90 million, respectively, of each of the original aggregate principal amount of the 2017 Notes and 2018 Notes.  After the redemptions, $163 million and $166 million, respectively, of the 2017 Notes and 2018 Notes remained outstanding.  In addition, on February 28, 2011, the Company commenced cash tender offers and related consent solicitations to purchase any and all of its outstanding 2017 Notes and 2018 Notes.  In March 2011, the Company accepted and purchased: 1) $105 million of the aggregate principal amount of the outstanding 2017 Notes (or 65% of the remaining outstanding principal amount of 2017 Notes), and 2) $126 million of the aggregate principal amount of the outstanding 2018 Notes (or 76% of the remaining outstanding principal amount of 2018 Notes).  After giving effect to the purchase of the 2017 Notes and the 2018 Notes, aggregate principal amounts of $58 million and $40 million, respectively, remain outstanding at March 31, 2011.
 
The Company depends, in part, on its Credit Facility for future capital needs.  In addition, the Company has drawn on the Credit Facility to fund or partially fund quarterly cash distribution payments, since it uses operating cash flow primarily for investing activities and borrows as cash is needed.  Absent such borrowings, the Company would have at times experienced a shortfall in cash available to pay the declared quarterly cash distribution amount.  If an event of default occurs and is continuing under the Credit Facility, the Company would be unable to make borrowings to fund distributions.  For additional information about this matter and other risk factors that could affect the Company, see Item 1A. “Risk Factors.”
 
26

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
Counterparty Credit Risk
 
The Company accounts for its commodity derivatives and, when applicable, its interest rate derivatives at fair value.  The Company’s counterparties are current or former participants or affiliates of current or former participants in its Credit Facility, which is secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral.  The Company does not require collateral from its counterparties.  The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity derivatives and, when applicable, its interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
 
Public Offering of Units
 
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 the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Notes and 2018 Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Notes and 2018 Notes (see Note 6).  The Company used the remaining net proceeds from the sale of units to finance a portion of the acquisition in the Williston Basin.
 
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.  The following provides a summary of distributions paid by the Company during the three months ended March 31, 2011:
 
Date Paid
 
Period Covered by Distribution
 
Distribution
Per Unit
 
Total
Distribution
             
(in millions)
                 
February 2011
 
October 1 – December 31, 2010
  $ 0.66     $ 106  
 
On April 26, 2011, the Company’s Board of Directors declared a cash distribution of $0.66 per unit, or $2.64 per unit on an annualized basis, with respect to the first quarter of 2011.  The distribution, totaling approximately $117 million, will be paid on May 13, 2011, to unitholders of record as of the close of business on May 6, 2011.
 
Off-Balance Sheet Arrangements
 
The Company does not currently have any off-balance sheet arrangements.
 
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
 
27

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
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.
 
During the three months ended March 31, 2011, and March 31, 2010, the Company made no significant payments to settle any legal, environmental or tax proceedings.  The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary.  Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
 
Commitments and Contractual Obligations
 
The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2010 Annual Report on Form 10-K.  With the exception of the redemptions and cash tender offers and related consent solicitations in which the Company purchased 77% and 84% of the outstanding principal amounts of 2017 Notes and 2018 Notes, respectively, there have been no significant changes to the Company’s contractual obligations from December 31, 2010.  See Note 6 for additional information about the Company’s debt instruments.
 
Non-GAAP Financial Measures
 
The non-GAAP financial measures of adjusted EBITDA and adjusted net income, as defined by the Company, may not be comparable to similarly titled measures used by other companies.  Therefore, these non-GAAP measures should be considered in conjunction with net income and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities.  Adjusted EBITDA and adjusted net income should not be considered in isolation or as a substitute for GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.
 
Adjusted EBITDA (Non-GAAP Measure)
 
Adjusted EBITDA is a measure used by Company management to indicate (prior to the establishment of any reserves by its Board of Directors) the cash distributions the Company expects to make to its unitholders.  Adjusted EBITDA is also a quantitative measure used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.
 
The Company defines adjusted EBITDA as net income (loss) plus the following adjustments:
 
 
·
Net operating cash flow from acquisitions and divestitures, effective date through closing date;
 
·
Interest expense;
 
·
Depreciation, depletion and amortization;
 
·
Impairment of goodwill and long-lived assets;
 
·
Write-off of deferred financing fees and other;
 
·
(Gains) losses on sale of assets and other, net;
 
·
Provision for legal matters;
 
·
Loss on extinguishment of debt;
 
·
Unrealized (gains) losses on commodity derivatives;
 
·
Unrealized (gains) losses on interest rate derivatives;
 
·
Realized (gains) losses on interest rate derivatives;
 
·
Realized (gains) losses on canceled derivatives;
 
·
Unit-based compensation expenses;
 
28

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
 
 
·
Exploration costs; and
 
·
Income tax (benefit) expense.
 
The following presents a reconciliation of net income (loss) to adjusted EBITDA:
 
   
Three Months Ended
March 31,
   
2011
 
2010
   
(in thousands)
             
Net income (loss)
  $ (446,682 )   $ 65,310  
Plus:
               
Net operating cash flow from acquisitions and divestitures, effective date through closing date
    7,051