epdform10q_063008.htm


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2008

OR

o  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:  1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of Registrant as Specified in Its Charter)

Delaware
76-0568219
(State or Other Jurisdiction of
(I.R.S. Employer Identification No.)
Incorporation or Organization)
 
     
 
1100 Louisiana, 10th Floor
 
 
Houston, Texas 77002
 
 
    (Address of Principal Executive Offices, Including Zip Code)
 
     
 
(713) 381-6500
 
 
(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 þ   No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
                    
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer   o (Do not check if a smaller reporting company)
Smaller reporting company o

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

There were 434,896,002 common units and 2,262,563 restricted common units of Enterprise Products Partners L.P. outstanding at August 11, 2008.  These common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

 
 

 

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

   
Page No.
PART I.  FINANCIAL INFORMATION.
Item 1.
Financial Statements.
 
 
   Unaudited Condensed Consolidated Balance Sheets
2
 
   Unaudited Condensed Statements of Consolidated Operations
3
 
   Unaudited Condensed Statements of Consolidated Comprehensive Income
4
 
   Unaudited Condensed Statements of Consolidated Cash Flows
5
 
   Unaudited Condensed Statements of Consolidated Partners’ Equity
6
 
   Notes to Unaudited Condensed Consolidated Financial Statements:
 
 
       1.  Partnership Organization
7
 
       2.  General Accounting Policies and Related Matters
8
 
       3.  Accounting for Unit-Based Awards
11
 
       4.  Financial Instruments
15
 
       5.  Inventories
20
 
       6.  Property, Plant and Equipment
21
 
       7.  Investments in and Advances to Unconsolidated Affiliates
22
 
       8.  Intangible Assets and Goodwill
23
 
       9.  Debt Obligations
25
 
     10.  Partners’ Equity and Distributions
27
 
     11.  Business Segments
29
 
     12.  Related Party Transactions
33
 
     13.  Earnings Per Unit
38
 
     14.  Commitments and Contingencies
39
 
     15.  Significant Risks and Uncertainties – Weather-Related Risks
42
 
     16.  Supplemental Cash Flow Information
43
 
     17.  Condensed Financial Information of EPO
44
 
     18.  Subsequent Events
45
Item 2.
Management’s Discussion and Analysis of Financial Condition
 
 
   and Results of Operations.
46
Item 3.
Quantitative and Qualitative Disclosures about Market Risk.
66
Item 4.
Controls and Procedures.
70
     
PART II.  OTHER INFORMATION.
Item 1.
Legal Proceedings.
71
Item 1A.
Risk Factors.
71
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
71
Item 3.
Defaults upon Senior Securities.
71
Item 4.
Submission of Matters to a Vote of Security Holders.
72
Item 5.
Other Information.
72
Item 6.
Exhibits.
72
     
Signatures
77
 
 
1

 

PART I.  FINANCIAL INFORMATION.

Item 1.  Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
 (Dollars in thousands)

   
June 30,
   
December 31,
 
ASSETS
 
2008
   
2007
 
Current assets:
           
 Cash and cash equivalents
  $ 24,710     $ 39,722  
 Restricted cash
    --       53,144  
 Accounts and notes receivable - trade, net of allowance for doubtful accounts
               
  of $14,979 at June 30, 2008 and $21,659 at December 31, 2007
    2,525,084       1,930,762  
 Accounts receivable - related parties
    53,323       79,782  
 Inventories
    463,721       354,282  
 Prepaid and other current assets
    263,421       80,193  
        Total current assets
    3,330,259       2,537,885  
Property, plant and equipment, net
    12,407,006       11,587,264  
Investments in and advances to unconsolidated affiliates
    869,177       858,339  
Intangible assets, net of accumulated amortization of  $386,453 at
               
 June 30, 2008 and $341,494 at December 31, 2007
    888,164       917,000  
Goodwill
    591,652       591,652  
Deferred tax asset
    3,015       3,522  
Other assets, including restricted cash of $17,871 at December 31, 2007
    91,583       112,345  
 Total assets
  $ 18,180,856     $ 16,608,007  
                 
LIABILITIES AND PARTNERS’ EQUITY
               
Current liabilities:
               
 Accounts payable – trade
  $ 346,994     $ 324,999  
 Accounts payable – related parties
    61,009       24,432  
 Accrued product payables
    2,703,391       2,227,489  
 Accrued expenses
    64,990       47,756  
 Accrued interest
    139,456       130,971  
 Other current liabilities
    312,810       289,036  
       Total current liabilities
    3,628,650       3,044,683  
Long-term debt: (see Note 9)
               
    Senior debt obligations – principal
    6,499,500       5,646,500  
    Junior subordinated notes  – principal
    1,250,000       1,250,000  
    Other
    19,007       9,645  
                 Total long-term debt
    7,768,507       6,906,145  
Deferred tax liabilities
    20,986       21,364  
Other long-term liabilities
    69,282       73,748  
Minority interest
    422,664       430,418  
Commitments and contingencies
               
Partners’ equity:
               
 Limited partners
               
 Common units  (434,896,002 units outstanding at June 30, 2008
               
and 433,608,763 units outstanding at December 31, 2007)
    6,028,864       5,976,947  
 Restricted common units (2,265,163 units outstanding at June 30, 2008
               
and 1,688,540 units outstanding at December 31, 2007)
    20,526       15,948  
 General partner
    123,395       122,297  
 Accumulated other comprehensive income (see Note 10)
    97,982       16,457  
       Total partners’ equity
    6,270,767       6,131,649  
 Total liabilities and partners’ equity
  $ 18,180,856     $ 16,608,007  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.

 
2

 

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Dollars in thousands, except per unit amounts)

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2008
   
2007
   
2008
   
2007
 
Revenues:
                       
     Third parties
  $ 6,116,868     $ 4,076,573     $ 11,500,702     $ 7,335,185  
     Related parties
    222,747       136,233       523,448       200,475  
         Total revenues
    6,339,615       4,212,806       12,024,150       7,535,660  
Costs and expenses:
                               
  Operating costs and expenses:
                               
     Third parties
    5,824,684       3,875,050       10,959,268       6,915,583  
     Related parties
    135,254       85,622       311,860       169,568  
         Total operating costs and expenses
    5,959,938       3,960,672       11,271,128       7,085,151  
  General and administrative costs:
                               
     Third parties
    10,490       10,628       13,953       14,203  
     Related parties
    13,486       20,733       31,228       33,788  
         Total general and administrative costs
    23,976       31,361       45,181       47,991  
         Total costs and expenses
    5,983,914       3,992,033       11,316,309       7,133,142  
Equity in earnings of unconsolidated affiliates
    18,569       (6,211 )     33,161       (32 )
Operating income
    374,270       214,562       741,002       402,486  
Other income (expense):
                               
  Interest expense
    (95,809 )     (71,275 )     (187,755 )     (134,633 )
  Interest income
    1,002       2,408       2,613       4,443  
  Other, net
    (331 )     339       (1,051 )     232  
         Total other expense, net
    (95,138 )     (68,528 )     (186,193 )     (129,958 )
Income before provision for income taxes and minority interest
    279,132       146,034       554,809       272,528  
  Provision for income taxes
    (6,926 )     1,860       (10,583 )     (6,928 )
Income before minority interest
    272,206       147,894       544,226       265,600  
  Minority interest
    (8,936 )     (5,740 )     (21,347 )     (11,401 )
Net income
  $ 263,270     $ 142,154     $ 522,879     $ 254,199  
                                 
Net income allocation: (see Note 10)
                               
  Limited partners’ interest in net income
  $ 227,707     $ 113,527     $ 452,869     $ 198,576  
  General partner interest in net income
  $ 35,563     $ 28,627     $ 70,010     $ 55,623  
                                 
Earning per unit: (see Note 13)
                               
  Basic and diluted income per unit
  $ 0.52     $ 0.26     $ 1.03     $ 0.46  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.

 
3

 

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED
COMPREHENSIVE INCOME
(Dollars in thousands)

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2008
   
2007
   
2008
   
2007
 
                         
Net income
  $ 263,270     $ 142,154     $ 522,879     $ 254,199  
Other comprehensive income:
                               
   Cash flow hedges:
                               
       Foreign currency hedge losses
    (111 )     --       (1,308 )     --  
       Net commodity financial instrument gains (losses)
    14,229       (3,121 )     107,246       846  
       Net interest rate financial instrument gains (losses)
    4,991       29,752       (21,041 )     40,264  
       Less:  Amortization of cash flow financing hedges
    (1,593 )     (1,180 )     (3,183 )     (2,269 )
            Total cash flow hedges
    17,516       25,451       81,714       38,841  
   Foreign currency translation adjustment
    498       148       75       549  
   Change in funded status of Dixie benefit plans, net of tax
    --       --       (264 )     --  
            Total other comprehensive income
    18,014       25,599       81,525       39,390  
Comprehensive income
  $ 281,284     $ 167,753     $ 604,404     $ 293,589  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.

 
4

 

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
 (Dollars in thousands)

   
For the Six Months
 
   
Ended June 30,
 
   
2008
   
2007
 
Operating activities:
           
   Net income
  $ 522,879     $ 254,199  
   Adjustments to reconcile net income to net cash
               
     flows provided by operating activities:
               
Depreciation, amortization and accretion in operating costs and expenses
    270,184       240,653  
Depreciation and amortization in general and administrative costs
    5,208       4,259  
Amortization in interest expense
    (1,112 )     201  
Equity in earnings of unconsolidated affiliates
    (33,161 )     32  
Distributions received from unconsolidated affiliates
    56,010       35,026  
Operating lease expense paid by EPCO, Inc.
    1,053       1,053  
Minority interest
    21,347       11,401  
Loss (gain) on sale of assets
    (852 )     5,664  
Deferred income tax expense
    2,529       4,088  
Changes in fair market value of financial instruments
    9,580       (302 )
Effect of pension settlement recognition
    (114 )     --  
Net effect of changes in operating accounts (see Note 16)
    (156,843 )     (4,225 )
          Net cash flows provided by operating activities
    696,708       552,049  
Investing activities:
               
   Capital expenditures
    (1,091,165 )     (1,129,263 )
   Contributions in aid of construction costs
    17,761       48,570  
   Proceeds from sale of assets
    514       1,015  
   Decrease in restricted cash
    71,014       308  
   Cash used for business combinations
    (1 )     (785 )
   Acquisition of intangible assets
    (5,126 )     --  
   Investments in unconsolidated affiliates
    (19,560 )     (294,598 )
   Advances to unconsolidated affiliates
    (5,485 )     (12,434 )
          Cash used in investing activities
    (1,032,048 )     (1,387,187 )
Financing activities:
               
   Borrowings under debt agreements
    3,914,686       3,048,734  
   Repayments of debt
    (3,063,000 )     (2,063,374 )
   Debt issuance costs
    (8,649 )     (9,261 )
   Distributions paid to partners
    (508,969 )     (470,561 )
   Distributions paid to minority interests
    (29,129 )     (9,416 )
   Contributions from Duncan Energy Partners reflected
               
       as part of minority interests (see Notes 1 and 2)
    --       291,044  
   Other contributions from minority interests
    28       12,506  
   Net proceeds from issuance of our common units
    38,029       35,899  
   Repurchase of option awards
    --       (1,568 )
   Acquisition of treasury units
    (650 )     --  
   Monetization of interest rate hedging financial instruments (see Note 4)
    (22,144 )     42,269  
          Cash provided by financing activities
    320,202       876,272  
Effect of exchange rate changes on cash
    126       (390 )
Net change in cash and cash equivalents
    (15,138 )     41,134  
Cash and cash equivalents, January 1
    39,722       22,619  
Cash and cash equivalents, June 30
  $ 24,710     $ 63,363  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.

 
5

 

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY
(See Note 10 for Unit History and Detail of Changes in Limited Partners’ Equity)
(Dollars in thousands)

   
Limited
   
General
   
AOCI
       
   
Partners
   
Partner
   
(see Note 10)
   
Total
 
Balance, December 31, 2007
  $ 5,992,895     $ 122,297     $ 16,457     $ 6,131,649  
Net income
    452,869       70,010       --       522,879  
Operating leases paid by EPCO, Inc.
    1,031       22       --       1,053  
Cash distributions to partners
    (438,809 )     (69,723 )     --       (508,532 )
Non-cash distributions
    (2,688 )     (55 )     --       (2,743 )
Net proceeds from sales of common units
    36,676       749       --       37,425  
Proceeds from exercise of unit options
    598       6       --       604  
Unit option reimbursements to EPCO, Inc.
    (524 )     --       --       (524 )
Acquisition of treasury units
    (637 )     (13 )     --       (650 )
Change in funded status of Dixie benefit plans, net of tax
    --       --       (264 )     (264 )
Amortization of unit-based awards
    7,979       102       --       8,081  
Foreign currency translation adjustment
    --       --       75       75  
Cash flow hedges
    --       --       81,714       81,714  
Balance, June 30, 2008
  $ 6,049,390     $ 123,395     $ 97,982     $ 6,270,767  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.

 
6

 

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.


Note 1.  Partnership Organization

Partnership Organization

Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”).  We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating LLC (“EPO”).  We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “EPGP”).  EPGP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “EPE.”  The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which are owned by Dan L. Duncan.  We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.”  References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries.  References to “LE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity.  On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity.  Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.

References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”) and Enterprise Unit L.P. (“Enterprise Unit”), collectively, which are private company affiliates of EPCO.

On February 5, 2007, a consolidated subsidiary of ours, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 12).  Duncan Energy Partners owns equity interests in certain of our midstream energy businesses.  References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments.  We control Duncan Energy Partners through our ownership of its general partner.  Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners.  Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements.  The borrowings of Duncan Energy Partners are presented as part of our

 
7

 

consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

Basis of Presentation

Our results of operations for the three and six months ended June 30, 2008 are not necessarily indicative of results expected for the full year.

Essentially all of our assets, liabilities, revenues and expenses are recorded at EPO’s level in our consolidated financial statements.  Enterprise Products Partners L.P. acts as guarantor of certain of EPO’s debt obligations.  See Note 17 for condensed consolidated financial information of EPO.

In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation.  Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).  These Unaudited Condensed Consolidated Financial Statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2007 (Commission File No. 1-14323).


Note 2.  General Accounting Policies and Related Matters

Consolidation Policy

We evaluate our financial interests in companies to determine if they represent variable interest entities where we are the primary beneficiary.  If such criteria are met, we consolidate the financial statements of such businesses with those of our own.  Our financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling financial or equity interest, after the elimination of intercompany accounts and transactions.

If an investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the investee’s operating and financial policies.  For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies.  In consolidation, we eliminate our proportionate share of profits and losses from transactions with our equity method unconsolidated affiliates to the extent such amounts are material and remain on our balance sheet (or those of our equity method investees) in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

Dixie Employee Benefit Plans

Dixie Pipeline Company (“Dixie”), a consolidated subsidiary of EPO, directly employs the personnel that operate its pipeline system.  Certain of these employees are eligible to participate in Dixie’s defined contribution plan and pension and postretirement benefit plans.

Defined Contribution Plan.  Dixie contributed $0.1 million to its company-sponsored defined contribution plan during each of the three month periods ended June 30, 2008 and 2007.  During each of the six month periods ended June 30, 2008 and 2007, Dixie contributed $0.2 million to its company-sponsored defined contribution plan.

 
8

 
 
Pension and Postretirement Benefit Plans.  Dixie’s net pension benefit costs were $0.1 million for each of the three month periods ended June 30, 2008 and 2007.  For each of the six month periods ended June 30, 2008 and 2007, Dixie’s net pension benefit costs were $0.3 million.  Dixie’s net postretirement benefit costs were $0.1 million for each of the three month periods ended June 30, 2008 and 2007. For each of the six month periods ended June 30, 2008 and 2007, Dixie’s net postretirement benefit costs were $0.2 million.  During the remainder of 2008, Dixie expects to contribute approximately $0.2 million to its postretirement benefit plan and approximately $0.5 million to its pension plan.
 
Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements.  Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop.  Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.  Ongoing environmental compliance costs are charged to expense as incurred.  In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable.  Expenditures to mitigate or prevent future environmental contamination are capitalized.

At June 30, 2008 and December 31, 2007, our accrued liabilities for environmental remediation projects totaled $22.9 million and $26.5 million, respectively.  These amounts were derived from a range of reasonable estimates based upon studies and site surveys.  Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities.  Our actual results could differ from these estimates.  On an ongoing basis, management reviews its estimates based on currently available information.  Changes in facts and circumstances may result in revised estimates. 

We revised the remaining useful lives of certain assets, most notably the assets that constitute our Texas Intrastate System, effective January 1, 2008.  This revision adjusted the remaining useful life of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since our original determination made in September 2004.  These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.72 billion at January 1, 2008.  For additional information regarding this change in estimate, see Note 6.

Minority Interest

As presented in our Unaudited Condensed Consolidated Balance Sheets, minority interest represents third-party and affiliate ownership interests in the net assets of our consolidated subsidiaries.  For financial reporting purposes, the assets and liabilities of our controlled subsidiaries, including Duncan Energy Partners, are consolidated with those of our own, with any third-party or affiliate ownership interests in such amounts presented as minority interest.

At June 30, 2008 and December 31, 2007, minority interest includes $285.4 million and $288.6 million, respectively, attributable to third party owners of Duncan Energy Partners.  Minority interest expense for the three months ended June 30, 2008 and 2007 includes $4.8 million and $3.3 million, respectively, attributable to third party owners of Duncan Energy Partners.  For the six months ended June 30, 2008 and 2007 minority interest expense attributable to third party owners of Duncan Energy Partners

 
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was $9.1 million and $6.1 million, respectively.  The remaining minority interest expense amounts for 2008 and 2007 are attributable to our other consolidated affiliates.

Contributions from minority interests for the six months ended June 30, 2007 includes approximately $291 million received from third parties in connection with the initial public offering of Duncan Energy Partners in February 2007.

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Annual Report on Form 10-K for the year ended December 31, 2007 that will or may affect our future financial statements.

Statement of Financial Accounting Standards (“SFAS”) No. 161, Disclosures about Derivative Instruments and Hedging Activities - An Amendment of FASB Statement No. 133.  Issued in March, 2008, SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities with the intent to provide users of financial statements with an enhanced understanding of (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.  SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements.  This statement has the same scope as SFAS 133, and accordingly applies to all entities.  SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption.  SFAS 161 only affects disclosure requirements; therefore, our adoption of this statement effective January 1, 2009 will not impact our financial position or results of operations.

SFAS 162, The Hierarchy of Generally Accepted Accounting Principles.  In May 2008, the FASB issued SFAS 162, which establishes a consistent framework, or hierarchy, for selecting the accounting principles used to prepare financial statements of nongovernmental entities in conformity with GAAP.  SFAS 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (PCAOB) amendments to its Interim Auditing Standards.  We do not expect SFAS 162 to have a material impact on the preparation of our consolidated financial statements.

EITF 07-4, Application of the Two Class Method Under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships ("MLP").  EITF 07-4 was issued during the first quarter of 2008 and prescribes the manner in which a MLP should allocate and present earnings per unit using the two-class method set forth in SFAS 128, “Earnings Per Share.”  Under the two-class method, current period earnings are allocated to the general partner (including earnings attributable to any embedded incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement.  EITF 07-4 is effective for us on January 1, 2009.  Management is currently evaluating the impact that EITF 07-4 will have on our earnings per unit computations and disclosures.

FASB Staff Position (“FSP”) No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.  FSP EITF 03-6-1 was issued in June 2008.  FSP EITF 03-6-1 clarifies that unvested share-based payment awards constitute participating securities, if such awards include nonforfeitable rights to dividends or dividend equivalents.  Consequently, awards that are deemed to be participating securities must be allocated earnings in the computation of earnings per share under the two-class method.  FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008.  We intend to adopt FSP EITF 03-6-1 effective January 1, 2009 and are currently evaluating the impact of adoption on our consolidated financial statements.

 
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FSP No. FAS 157-2, Effective Date of FASB Statement No. 157.  FSP 157-2 defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  As allowed under FSP 157-2, we have not applied the provisions of SFAS 157 to our nonfinancial assets and liabilities measured at fair value, which include certain assets and liabilities acquired in business combinations.  We are currently evaluating the impact of our adoption of FSP 157-2 effective January 1, 2009 on our consolidated financial statements.

On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities.   See Note 4 for these fair value disclosures.

FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets.  In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142, Goodwill and Other Intangible Assets.  This change is intended to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141(R) and other GAAP. FSP 142-3 is effective for us on January 1, 2009.  The requirement for determining useful lives must be applied prospectively to intangible assets acquired after January 1, 2009 and the disclosure requirements must be applied prospectively to all intangible assets recognized as of, and subsequent to, January 1, 2009.  We are evaluating the impact that FSP 142-3 will have on our future financial statements.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity financial instruments portfolio and physical natural gas purchases made on the New York Mercantile Exchange.  In addition, at December 31, 2007, restricted cash included amounts held by a third party trustee charged with disbursing proceeds from our Petal GO Zone bond offering.   The following table presents the components of our restricted cash balances at the periods indicated:

   
June 30,
   
December 31,
 
   
2008
   
2007
 
Amounts held in brokerage accounts related to
           
  commodity hedging activities and physical natural gas purchases
  $ --     $ 53,144  
Proceeds from Petal GO Zone bonds reserved for construction costs
    --       17,871  
Total restricted cash
  $ --     $ 71,015  

Due to market conditions at June 30, 2008, no cash was restricted to meet commodity exchange deposit requirements with respect to our commodity risk hedging activities and physical natural gas purchases; however, cash may be restricted in the future to maintain our positions as commodity prices fluctuate or deposit requirements change.   As of June 30, 2008, all proceeds from the Petal GO Zone bonds had been released by the trustee to fund construction costs associated with the expansion of our Petal, Mississippi storage facility.  See Note 4 for information about our hedging activities and related changes in restricted cash balances subsequent to June 30, 2008.


Note 3.  Accounting for Unit-Based Awards

We account for unit-based awards in accordance with SFAS 123(R), “Share-Based Payment.”  SFAS 123(R) requires us to recognize compensation expense related to unit-based awards based on the fair value of the award at grant date.  The fair value of restricted unit awards is based on the market price of the underlying common units on the date of grant. The fair value of other unit-based awards is estimated using the Black-Scholes option pricing model.  The fair value of an equity-classified award (such as a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards (such as unit appreciation rights (“UARs”)) is

 
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recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period.  Liability-type awards are cash settled upon vesting.

The following table summarizes our unit-based compensation amounts by plan during each of the periods indicated:

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2008
   
2007
   
2008
   
2007
 
EPCO 1998 Long-Term Incentive Plan (“1998 Plan”)
                       
     Unit options
  $ 55     $ 3,916     $ 213     $ 4,109  
     Restricted units
    2,044       2,384       3,552       3,658  
          Total 1998 Plan (1)
    2,099       6,300       3,765       7,767  
Enterprise Products 2008 Long-Term Incentive Plan
                               
  (“2008 LTIP”)
                               
     Unit options
    14       --       14       --  
          Total 2008 LTIP
    14       --       14       --  
Employee Partnerships
    1,376       676       2,559       1,178  
DEP GP UARs
    6       25       6       35  
          Total consolidated expense
  $ 3,495     $ 7,001     $ 6,344     $ 8,980  
                                 
(1)   Amounts presented for the three and six months ended June 30, 2007 include $­­4.6 million associated with the resignation of our former chief executive officer.
 

1998 Plan

The 1998 Plan provides for the issuance of up to 7,000,000 of our common units.   After giving effect to outstanding option awards at June 30, 2008 and the issuance and forfeiture of restricted unit awards through June 30, 2008, a total of 768,154 additional common units could be issued under the 1998 Plan.

Unit option awards.  Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of our common units may be granted to key employees of EPCO who perform management, administrative or operational functions for us.  The following table presents unit option activity under the 1998 Plan for the periods indicated:

               
Weighted-
       
         
Weighted-
   
Average
       
         
Average
   
Remaining
   
Aggregate
 
   
Number of
   
Strike Price
   
Contractual
   
Intrinsic
 
   
Units
   
(dollars/unit)
   
Term (in years)
   
Value (1)
 
Outstanding at December 31, 2007 (2)
    2,315,000     $ 26.18              
Exercised
    (47,500 )   $ 20.25              
Forfeited or terminated
    (85,000 )   $ 26.72              
Outstanding at June 30, 2008
    2,182,500     $ 26.29       5.68     $ 4,260  
Options exercisable at:
                               
June 30, 2008
    517,500     $ 21.31       4.42     $ 4,260  
                                 
(1)   Aggregate intrinsic value reflects fully vested unit options at June 30, 2008.
(2)   During 2008, we amended the terms of certain of our outstanding unit options. In general, the expiration dates of these awards were modified from May and August 2017 to December 2012.
 

The total intrinsic value of unit options exercised during the three and six months ended June 30, 2008 was $0.4 million and $0.5 million, respectively.  At June 30, 2008, there was an estimated $2.2 million of total unrecognized compensation cost related to nonvested unit options granted under the 1998 Plan.  We expect to recognize our share of this cost over a weighted-average period of 2.6 years in accordance with the EPCO administrative services agreement.

 
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During the six months ended June 30, 2008 and 2007, we received cash of $0.6 million and $7.3 million, respectively, from the exercise of unit options. Conversely, our option-related reimbursements to EPCO were $0.5 million and $2.8 million, respectively.

Restricted unit awards. Under the 1998 Plan, we may also issue restricted common units to key employees of EPCO and directors of our general partner.  The following table summarizes information regarding our restricted common units for the periods indicated:

         
Weighted-
 
         
Average Grant
 
   
Number of
   
Date Fair Value
 
   
Units
   
per Unit (1)
 
Restricted units at December 31, 2007
    1,688,540        
Granted (2)
    718,800     $ 25.64  
Forfeited
    (72,177 )   $ 25.88  
Vested
    (70,000 )   $ 19.35  
Restricted units at June 30, 2008
    2,265,163          
                 
(1)   Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued.
(2)   Aggregate grant date fair value of restricted common unit awards issued during 2008 was $18.4 million based on a grant date market price of our common units ranging from $30.38 to $32.31 per unit and an estimated forfeiture rate of 17%.
 

The total fair value of our restricted unit awards that vested during the three and six months ended June 30, 2008 was $1.3 million and $1.4 million, respectively.  As of June 30, 2008, there was $37.8 million of total unrecognized compensation cost related to restricted common units.  We will recognize our share of such costs in accordance with the EPCO administrative services agreement.  At June 30, 2008, these costs are expected to be recognized over a weighted-average period of 2.6 years.

Phantom unit awards.  The 1998 Plan also provides for the issuance of phantom unit awards.  These liability awards are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at redemption dates in each award.  No phantom unit awards have been issued to date under the 1998 Plan.

2008 LTIP

On January 29, 2008, our unitholders approved the 2008 LTIP, which provides for awards of our common units and other rights to our non-employee directors and to consultants and employees of EPCO and its affiliates providing services to us.  Awards under the 2008 LTIP may be granted in the form of restricted units, phantom units, unit options, UARs and distribution equivalent rights.  The 2008 LTIP is administered by EPGP’s Audit, Conflicts and Governance (“ACG”) Committee.  The 2008 LTIP provides for the issuance of up to 10,000,000 of our common units.  After giving effect to option awards outstanding at June 30, 2008, a total of 9,205,000 additional common units could be issued under the 2008 LTIP.

The 2008 LTIP may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, the rules of the NYSE require that any material amendment, such as a significant increase in the number of common units available under the plan or a change in the types of awards available under the plan, would require the approval of our unitholders.  The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in, awards under the plan in specified circumstances.  The 2008 LTIP is effective until the earlier of January 29, 2018 or the time which all available units under the incentive plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.
 
 
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Unit option awards.  The exercise price of unit options awarded to participants is determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of our common units at the date of grant.  The following table presents unit option activity under the 2008 LTIP for the periods indicated:

               
Weighted-
 
         
Weighted-
   
Average
 
         
Average
   
Remaining
 
   
Number of
   
Strike Price
   
Contractual
 
   
Units
   
(dollars/unit)
   
Term (in years)
 
Outstanding at January 1, 2008
    --              
Granted (1)
    795,000     $ 30.93        
Outstanding at June 30, 2008
    795,000     $ 30.93       5.51  
                         
(1)   Aggregate grant date fair value of these unit options issued during the second quarter of 2008 was $1.6 million based on a grant date market price of our common units of $30.93 per unit and an estimated forfeiture rate of 17.0%.
 

At June 30, 2008, there was an estimated $1.5 million of total unrecognized compensation cost related to nonvested unit options granted under the 2008 LTIP.  We expect to recognize our share of this cost over a weighted-average period of 3.9 years in accordance with the EPCO administrative services agreement.

Employee Partnerships

EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in the Employee Partnerships.  Currently, there are four Employee Partnerships: EPE Unit I, EPE Unit II, EPE Unit III and Enterprise Unit.  EPE Unit I was formed in August 2005 in connection with Enterprise GP Holdings’ initial public offering and EPE Unit II was formed in December 2006.  EPE Unit III was formed in May 2007 and Enterprise Unit was formed in February 2008.  For a detailed description of EPE Unit I, EPE Unit II and EPE Unit III, see our Annual Report on Form 10-K for the year ended December 31, 2007.  See Note 18 regarding amendments to EPE Unit I, EPE Unit II and EPE Unit III, which were effective July 2008.

As of June 30, 2008, there was $26.1 million of total unrecognized compensation cost related to the four Employee Partnerships.  We will recognize our share of these costs in accordance with the EPCO administrative services agreement over a weighted-average period of 3.7 years.

On February 20, 2008, EPCO formed Enterprise Unit to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in Enterprise Unit.  On that date, EPCO Holdings, Inc. (“EPCO Holdings”) agreed to contribute $18.0 million in the aggregate (the “Initial Contribution”) to Enterprise Unit and was admitted as the Class A limited partner.  Certain key employees of EPCO, including our Chief Executive Officer and Chief Financial Officer, were issued Class B limited partner interests and admitted as Class B limited partners of Enterprise Unit without any capital contributions.  EPCO Holdings may make capital contributions to Enterprise Unit in addition to its Initial Contribution.  Through July 31, 2008, EPCO Holdings has contributed a total of $51.5 million to Enterprise Unit.  EPCO Holdings has no legal obligation to make additional contributions.

As with the awards granted in connection with the other Employee Partnerships, these awards are designed to provide additional long-term incentive compensation for certain employees.  The profits interest awards (or Class B limited partner interests) in Enterprise Unit entitle the holder to participate in the appreciation in value of Enterprise GP Holdings’ units and our common units and are subject to early vesting or forfeiture upon the occurrence of certain events.

An allocated portion of the fair value of these equity awards will be charged to us under the EPCO administrative services agreement as a non-cash expense.  We will not reimburse EPCO, Enterprise Unit or

 
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any of their affiliates or partners, through the administrative services agreement or otherwise, in cash for any expenses related to Enterprise Unit, including the Initial Contribution by EPCO Holdings.
   
The Class B limited partner interests in Enterprise Unit that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to February 20, 2014, with customary exceptions for death, disability and certain retirements that will result in early vesting.  The risk of forfeiture associated with the Class B limited partner interests in Enterprise Unit will also lapse (i.e. the interests will become vested) upon certain change of control events.
 
Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners of Enterprise Unit, Enterprise Unit will terminate at the earlier of February 20, 2014 (six years from the date of the agreement) or a change in control of us or Enterprise GP Holdings.  Enterprise Unit has the following material terms regarding its quarterly cash distribution to partners:

§  
Distributions of cash flow Each quarter, 100% of the cash distributions received by Enterprise Unit from Enterprise GP Holdings and us will be distributed to the Class A limited partner until EPCO Holdings has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by Enterprise Unit will be distributed to the Class B limited partners.  The Class A preferred return equals the Class A capital base (as defined below) multiplied by 5.0% per annum.  The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to Enterprise Unit, plus any unpaid Class A preferred return from prior periods, less any distributions made by Enterprise Unit of proceeds from the sale of units owned by Enterprise Unit (as described below).

§  
Liquidating Distributions Upon liquidation of Enterprise Unit, units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, plus any accrued and unpaid Class A preferred return for the quarter in which liquidation occurs.  Any remaining units will be distributed to the Class B limited partners.

§  
Sale Proceeds If Enterprise Unit sells any units that it beneficially owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.

DEP GP UARs

The non-employee directors of DEP GP, the general partner of Duncan Energy Partners, have been granted UARs in the form of letter agreements.  These liability awards are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings or us.  These UARs entitle each non-employee director to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date fair value.  These UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.  At June 30, 2008 and December 31, 2007, we had a total of 90,000 outstanding UARs granted to non-employee directors of DEP GP that cliff vest in 2012.  If a director resigns prior to vesting, his UAR awards are forfeited.


Note 4.  Financial Instruments

We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange rates.  We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions.  In general, the types of risks we attempt to hedge are those related to (i) the variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates.


 
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Interest Rate Risk Hedging Program

Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements.  We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

Fair Value Hedges – Interest Rate Swaps. As summarized in the following table, we had six interest rate swap agreements outstanding at June 30, 2008 that were accounted for as fair value hedges.

 
Number
Period Covered
Termination
Fixed to
Notional
Hedged Fixed Rate Debt
of Swaps
by Swap
Date of Swap
Variable Rate (1)
Value
Senior Notes C, 6.375% fixed rate, due Feb. 2013
1
Jan. 2004 to Feb. 2013
Feb. 2013
6.38% to 5.08%
$100.0 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014
5
4th Qtr. 2004 to Oct. 2014
Oct. 2014
5.60% to 3.64%
$500.0 million
(1)   The variable rate indicated is the all-in variable rate for the current settlement period.

The aggregate fair value of the six interest rate swaps at June 30, 2008 was an asset of $8.9 million, with an offsetting decrease in the fair value of the underlying debt.  There were eleven interest rate swaps outstanding at December 31, 2007 having an aggregate fair value of $14.8 million (an asset).  Interest expense for the three months ended June 30, 2008 and 2007 includes a $2.2 million benefit and a $2.3 million loss, respectively, resulting from these interest rate swap agreements.  For the six months ended June 30, 2008 and 2007, interest expense reflects a benefit of $1.3 million and a loss of $4.6 million, respectively, from these interest rate swap agreements.

The following table summarizes the termination of our interest rate swaps during 2008 (dollars in millions):

   
Notional
   
Cash
 
   
Value
   
Gains (1)
 
Interest rate swap  portfolio, December 31, 2007
  $ 1,050.0     $ --  
First quarter of 2008 terminations
    (200.0 )     6.3  
Second quarter of 2008 terminations
    (250.0 )     12.0  
Interest rate swap portfolio, June 30, 2008
  $ 600.0     $ 18.3  
                 
(1)   Cash gains resulting from the termination, or monetization, of interest rate swaps will be amortized to earnings as a reduction to interest expense over the remaining life of the underlying debt.
 

Cash Flow Hedges – Interest Rate Swaps. Duncan Energy Partners had three floating-to-fixed interest rate swap agreements outstanding at June 30, 2008 that were accounted for as cash flow hedges.

 
Number
Period Covered
Termination
Variable to
Notional
Hedged Variable Rate Debt
of Swaps
by Swap
Date of Swap
Fixed Rate (1)
Value
Duncan Energy Partners’ Revolver, due Feb. 2011
3
Sep. 2007 to Sep. 2010
Sep. 2010
2.80% to 4.62%
$175.0 million
           
(1)   Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).

We recognized losses of $0.9 million and $0.8 million from these swap agreements during the three and six months ended June 30, 2008, respectively.  The aggregate fair value of these interest rate swaps at June 30, 2008 and December 31, 2007 was a liability of $4.1 million and $3.8 million, respectively.  As cash flow hedges, any increase or decrease in fair value of the financial instrument (to the extent effective) would be recorded as other comprehensive income and amortized into earnings based on the settlement period being hedged.  Over the next twelve months, we expect to reclassify $2.4 million of losses to earnings as an increase in interest expense.
 
 
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Cash Flow Hedges – Treasury Locks. We occasionally use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt.  Cash gains or losses on the termination, or monetization, of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.  Each of our treasury lock transactions were designated as a cash flow hedge.  The following table summarizes changes in our treasury lock portfolio since December 31, 2007 (dollars in millions).

   
Notional
   
Cash
 
   
Value
   
Losses (1)
 
Treasury lock portfolio, December 31, 2007
  $ 600.0     $ --  
First quarter of 2008 terminations
    (350.0 )     27.7  
Second quarter of 2008 terminations
    (250.0 )     12.7  
Treasury lock portfolio, June 30, 2008
  $ --     $ 40.4  
                 
(1)   Cash losses are included in net interest rate financial instrument losses on Unaudited Condensed Statements of Consolidated Comprehensive Income.
 

We expect to reclassify $2.1 million of cumulative net gains from the monetization of treasury lock financial instruments to earnings (as a decrease in interest expense) over the next twelve months.  This includes financial instruments that were settled in years prior to 2008.

Commodity Risk Hedging Program

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.  In order to manage the price risks associated with such products, we may enter into commodity financial instruments.

The primary purpose of our commodity risk management activities is to reduce our exposure to price risks associated with (i) natural gas purchases, (ii) the value of NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas, NGLs or certain petrochemical products.  From time to time, we inject natural gas into storage and may utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

We have segregated our commodity financial instruments portfolio between those financial instruments utilized in connection with our natural gas marketing activities and those used in connection with our NGL and petrochemical operations.

Natural gas marketing activities.  At June 30, 2008 and December 31, 2007, the aggregate fair value of those financial instruments utilized in connection with our natural gas marketing activities was an asset of $9.6 million and a liability of $0.3 million, respectively.   Our natural gas marketing business and its related use of financial instruments has increased significantly since December 31, 2007. We utilize mark-to-market accounting for substantially all of the instruments utilized in connection with our natural gas marketing activities.
 
The following table presents gains and losses recognized in earnings from this portion of the commodity financial instruments portfolio for the periods indicated (dollars in millions):

Three months ended June 30, 2008
Losses
  $ (6.1 )
Three months ended June 30, 2007
Gains
  $ 0.9  
Six months ended June 30, 2008
Losses
  $ (5.4 )
Six months ended June 30, 2007
Gains
  $ 0.5  
 
 
17

 

NGL and petrochemical operations.  At June 30, 2008 and December 31, 2007, the aggregate fair value of those financial instruments utilized in connection with our NGL and petrochemical operations was an asset of $82.1 million and a liability of $19.0 million, respectively.  The change in fair value between December 31, 2007 and June 30, 2008 is primarily due to an increase in the price of natural gas and volumes hedged .  Almost all of the financial instruments within this portion of the commodity financial instruments portfolio are accounted for as cash flow hedges, with a lesser number accounted for using mark-to-market accounting.
 
The following table presents gains and losses recognized in earnings from this portion of the commodity financial instruments portfolio for the periods indicated (dollars in millions):

Three months ended June 30, 2008
Gains
  $ 13.4  
Three months ended June 30, 2007
Gains
  $ 0.2  
Six months ended June 30, 2008 (1)
Gains
  $ 8.9  
Six months ended June 30, 2007
Losses
  $ (1.8 )
           
(1)   Includes ineffectiveness of $2.7 million (a benefit).
 
 
The fair value of the NGL and petrochemical portfolio was a liability of $95.4 million as of August 5, 2008.  The change in fair value of this portfolio is primarily due to a decrease in natural gas prices.  A significant number of the financial instruments in this portfolio hedge the purchase of physical natural gas.  If natural gas prices fall below the price stipulated in such financial instruments, we recognize a liability for the difference; however, if prices partially or fully recover, this liability would be reduced or eliminated, as appropriate.  Our restricted cash balance increased from none at June 30, 2008 to $191.2 million as of August 5, 2008 in order to meet commodity exchange deposit requirements and the negative change in the fair value of our commodity positions.
 
Foreign Currency Hedging Program

We are exposed to foreign currency exchange rate risk primarily through our Canadian NGL marketing subsidiary.  As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar.  We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate.  Mark-to-market accounting is utilized for these contracts, which typically have a duration of one month.  During the three and six months ended June 30, 2008, we recorded minimal gains from these financial instruments.

Adoption of SFAS 157 - Fair Value Measurements

On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities. We will adopt the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009.  SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date.

Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability.   These assumptions include estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates.   These inputs may be either readily observable, corroborated by market data, or generally unobservable.  In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible.  Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values.  The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.  The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:

§  
Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date.  Active markets are defined as those in which transactions for identical assets or liabilities occur in sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYSE or New York Mercantile Exchange).  Level 1 primarily consists of financial assets and liabilities such as exchange-traded financial instruments, publicly-traded equity securities and U.S. government treasury securities.

 
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§  
Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date.  Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies.  Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors for stocks, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these assumptions are (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals).  Level 2 includes non-exchange-traded instruments such as over-the-counter forward contracts, options, and repurchase agreements.

§  
Level 3 fair values are based on unobservable inputs.  Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk).  Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally-developed data.  The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort.  Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value.  Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at June 30, 2008.  These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.  At June 30, 2008 there were no Level 1 financial assets or liabilities.

   
Level 2
   
Level 3
   
Total
 
Financial assets:
                 
Commodity financial instruments
  $ 149,905     $ --     $ 149,905  
Interest rate financial instruments
    8,901       --       8,901  
Total
  $ 158,806     $ --     $ 158,806  
                         
Financial liabilities:
                       
Commodity financial instruments
  $ 53,519     $ 4,669     $ 58,188  
Total
  $ 53,519     $ 4,669     $ 58,188  

Fair values associated with our interest rate, commodity and foreign currency financial instrument portfolios were developed using available market information and appropriate valuation techniques in accordance with SFAS 157.
 
 
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The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities for the periods indicated:

Balance, January 1, 2008
  $ (4,660 )
Total gains (losses) included in:
       
Net income (1)
    (2,254 )
Other comprehensive income
    2,419  
Purchases, issuances, settlements
    1,861  
Balance, March 31, 2008
    (2,634 )
Total gains (losses) included in:
       
Net income (1)
    322  
Other comprehensive income
    (2,428 )
Purchases, issuances, settlements
    71  
Ending balance, June 30, 2008
  $ (4,669 )
         
(1)   Net income includes commodity financial instrument gains of $0.3 million and losses of $1.9 million, respectively, recorded in revenue for the three and six months ended June 30, 2008. There were no unrealized gains included in such amounts.
 


Note 5.  Inventories

Our inventory amounts were as follows at the dates indicated:

   
June 30,
   
December 31,
 
   
2008
   
2007
 
Working inventory (1)
  $ 435,686     $ 342,589  
Forward-sales inventory (2)
    28,035       11,693  
   Total inventory
  $ 463,721     $ 354,282  
                 
(1)   Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services.
(2)   Forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts.
 

Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs.  We value our inventories at the lower of average cost or market.

Operating costs and expenses, as presented on our Unaudited Condensed Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories.  Our cost of sales amounts were $5.51 billion and $3.58 billion for the three months ended June 30, 2008 and 2007, respectively. For the six months ended June 30, 2008 and 2007, our cost of sales were $10.41 billion and $6.36 billion, respectively.

Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value.  These non-cash charges are a component of cost of sales in the period they are recognized. For the three months ended June 30, 2008 and 2007, we recognized LCM adjustments of approximately $0.7 million and $2.1 million, respectively. We recognized LCM adjustments of $4.8 million and $13.1 million for the six months ended June 30, 2008 and 2007, respectively.
 
 
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Note 6.  Property, Plant and Equipment

Our property, plant and equipment values and related accumulated depreciation balances were as follows at the dates indicated:

   
Estimated
             
   
Useful Life
   
June 30,
   
December 31,
 
   
in Years
   
2008
   
2007
 
Plants and pipelines (1)
   
3-35 (5)
    $ 11,703,858     $ 10,884,819  
Underground and other storage facilities (2)
   
5-35 (6)
      730,391       720,795  
Platforms and facilities (3)
   
20-31
      634,820       637,812  
Transportation equipment (4)
   
3-10
      32,981       32,627  
Land
            50,305       48,172  
Construction in progress
            1,388,484       1,173,988  
    Total
            14,540,839       13,498,213  
Less accumulated depreciation
            2,133,833       1,910,949  
    Property, plant and equipment, net
          $ 12,407,006     $ 11,587,264  
                         
(1)   Plants and pipelines include processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets.
(2)   Underground and other storage facilities include underground product storage caverns; storage tanks; water wells; and related assets.
(3)   Platforms and facilities include offshore platforms and related facilities and other associated assets.
(4)   Transportation equipment includes vehicles and similar assets used in our operations.
(5)   In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-35 years; and laboratory and shop equipment, 5-35 years.
(6)   In general, the estimated useful lives of major components of this category are as follows: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).
 

The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2008
   
2007
   
2008
   
2007
 
Depreciation expense (1)
  $ 113,972     $ 99,086     $ 223,815     $ 194,066  
Capitalized interest (2)
  $ 17,623     $ 20,397     $ 35,735     $ 41,139  
                                 
(1)   Depreciation expense is a component of costs and expenses as presented in our Unaudited Condensed Statements of Consolidated Operations.
(2)   Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.
 

We reviewed assumptions underlying the estimated remaining useful lives of certain of our assets during the first quarter of 2008.  As a result of our review, effective January 1, 2008, we revised the remaining useful lives of these assets, most notably the assets that constitute our Texas Intrastate System.  This revision increased the remaining useful life of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since our original determination made in September 2004.  These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.72 billion as of January 1, 2008.  On average, we extended the life of these assets by 3.1 years.  As a result of this change in estimate, depreciation expense included in operating income and net income for the three and six months ended June 30, 2008 decreased by approximately $5.0 million and $10.0 million, respectively, which increased our earnings per unit by $0.01 and $0.02, respectively, from what it would have been absent the change.  

 
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Asset retirement obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of a tangible long-lived asset that results from its acquisition, construction, development or normal operation or a combination of these factors.  The following table summarizes amounts recognized in connection with AROs since December 31, 2007:

ARO liability balance, December 31, 2007
  $ 40,614  
Liabilities incurred
    384  
Liabilities settled
    (5,473 )
Revisions in estimated cash flows
    2,308  
Accretion expense
    1,169  
ARO liability balance, June 30, 2008
  $ 39,002  

Property, plant and equipment at June 30, 2008 and December 31, 2007 includes $9.4 million and $10.6 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.


Note 7.  Investments In and Advances to Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting.  Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate.  See Note 11 for a general discussion of our business segments.  The following table presents our investments in and advances to unconsolidated affiliates at the dates indicated.

   
Ownership
       
   
Percentage at
       
   
June 30,
   
June 30,
   
December 31,
 
   
2008
   
2008
   
2007
 
NGL Pipelines & Services:
                 
Venice Energy Service Company L.L.C. (“VESCO”)
 
 13.1%
  $ 36,040     $ 40,129  
K/D/S Promix, L.L.C. (“Promix”)
 
 50%
    51,044       51,537  
Baton Rouge Fractionators LLC (“BRF”)
 
 32.3%
    24,575       25,423  
White River Hub, LLC (“White River Hub”) (1)
 
 50%
    14,592       --  
Onshore Natural Gas Pipelines & Services:
 
 
               
Jonah Gas Gathering Company (“Jonah”)
 
 19.4%
    245,117       235,837  
Evangeline (2)
 
 49.5%
    4,182       3,490  
Offshore Pipelines & Services:
 
 
               
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)
 
 36%
    59,640       58,423  
Cameron Highway Oil Pipeline Company (“Cameron Highway”)
 
 50%
    256,724       256,588  
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)
 
 50%
    107,876       111,221  
Neptune Pipeline Company, L.L.C. (“Neptune”)
 
 25.7%
    51,442       55,468  
Nemo Gathering Company, LLC (“Nemo”)
 
 33.9%
    789       2,888  
Petrochemical Services:
                   
Baton Rouge Propylene Concentrator, LLC (“BRPC”)
 
 30%
    13,192       13,282  
La Porte (3)
   50%     3,964       4,053  
Total
          $ 869,177     $ 858,339  
                         
(1)   During the second quarter of 2008 we acquired a 50% ownership interest in White River Hub.
(2)   Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.
(3)   Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.
 

On occasion, the price we pay to acquire a non-controlling ownership interest in a company exceeds the underlying book value of the net assets we acquire.  Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates.  At June 30, 2008 and December 31, 2007, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Jonah included excess cost amounts totaling $44.4 million and $43.8 million, respectively.  These amounts are attributable to the excess of the fair value of each entity’s tangible assets over their respective

 
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book carrying values at the time we acquired an interest in each entity. Amortization of such excess cost amounts was $0.5 million during each of the three months ended June 30, 2008 and 2007.  For each of the six months ended June 30, 2008 and 2007, amortization of such amounts was $1.0 million.

The following table presents our equity in earnings of unconsolidated affiliates by business segment for the periods indicated:

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2008
   
2007
   
2008
   
2007
 
NGL Pipelines & Services
  $ 1,589     $ 1,089     $ (721 )   $ 1,680  
Onshore Natural Gas Pipelines & Services
    5,458       1,212       11,285       2,241  
Offshore Pipelines & Services
    11,209       (8,846 )     21,927       (4,771 )
Petrochemical Services
    313       334       670       818  
Total
  $ 18,569     $ (6,211 )   $ 33,161     $ (32 )

Summarized Financial Information of Unconsolidated Affiliates

The following table presents unaudited income statement data for our current unconsolidated affiliates, aggregated by business segment, for the periods indicated (on a 100% basis).

   
Summarized Income Statement Information for the Three Months Ended
 
   
June 30, 2008
   
June 30, 2007
 
         
Operating
   
Net
         
Operating
   
Net
 
   
Revenues
   
Income
   
Income
   
Revenues
   
Income (Loss)
   
Income (Loss)
 
NGL Pipelines & Services
  $ 74,098     $ 8,100     $ 8,207     $ 59,056     $ (779 )   $ (74 )
Onshore Natural Gas Pipelines & Services
    185,974       28,769       27,654       125,132       25,198       24,102  
Offshore Pipelines & Services
    39,868       23,240       19,889       40,433       24,146       1,894  
Petrochemical Services
    5,640       1,303       1,308       4,969       1,403       1,429  

   
Summarized Income Statement Information for the Six Months Ended
 
   
June 30, 2008
   
June 30, 2007
 
         
Operating
   
Net
         
Operating
   
Net
 
   
Revenues
   
Income
   
Income
   
Revenues
   
Income
   
Income
 
NGL Pipelines & Services
  $ 142,714     $ 8,007     $ 8,261     $ 100,788     $ 2,481     $ 3,755  
Onshore Natural Gas Pipelines & Services
    303,568       59,724       57,384       234,030       46,813       44,415  
Offshore Pipelines & Services
    83,092       49,551       45,226       77,626       43,864       14,230  
Petrochemical Services
    10,996       2,786       2,796       10,522       3,290       3,340  


Note 8.  Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets at the dates indicated:

   
June 30, 2008
   
December 31, 2007
 
   
Gross
   
Accum.
   
Carrying
   
Gross
   
Accum.
   
Carrying
 
   
Value
   
Amort.
   
Value
   
Value
   
Amort.
   
Value
 
NGL Pipelines & Services
  $ 523,401     $ (165,658 )   $ 357,743     $ 520,025     $ (146,954 )   $ 373,071  
Onshore Natural Gas Pipelines & Services
    476,298       (125,948 )     350,350       463,551       (109,399 )     354,152  
Offshore Pipelines & Services
    207,012       (82,662 )     124,350       207,012       (73,954 )     133,058  
Petrochemical Services
    67,906       (12,185 )     55,721       67,906       (11,187 )     56,719  
        Total
  $ 1,274,617     $ (386,453 )   $ 888,164     $ 1,258,494     $ (341,494 )   $ 917,000  
 
 
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The following table presents the amortization expense of our intangible assets by segment for the periods indicated:

   
For the Three Months
   
For the Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2008
   
2007
   
2008
   
2007
 
NGL Pipelines & Services
  $ 9,275     $ 8,801     $ 18,705     $ 18,042  
Onshore Natural Gas Pipelines & Services
    8,128       8,049       16,550       16,209  
Offshore Pipelines & Services
    4,279       4,908       8,708       9,988  
Petrochemical Services
    498       498       996       996  
Total
  $ 22,180     $ 22,256     $ 44,959     $ 45,235  

For the remainder of 2008, amortization expense associated with our intangible assets is currently estimated at $43.4 million.

Goodwill

The following table summarizes our goodwill amounts by segment at the dates indicated:

   
June 30,
   
December 31,
 
   
2008
   
2007
 
NGL Pipelines & Services
  $ 153,706     $ 153,706  
Onshore Natural Gas Pipelines & Services
    282,121       282,121  
Offshore Pipelines & Services
    82,135       82,135  
Petrochemical Services
    73,690       73,690  
Totals
  $ 591,652     $ 591,652  
 
 
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Note 9.  Debt Obligations

Our consolidated debt obligations consisted of the following at the dates indicated:

   
June 30,
   
December 31,
 
   
2008
   
2007
 
EPO senior debt obligations:
           
Multi-Year Revolving Credit Facility, variable rate, due November 2012
  $ 470,000     $ 725,000  
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010
    54,000       54,000  
Senior Notes B, 7.50% fixed-rate, due February 2011
    450,000       450,000  
Senior Notes C, 6.375% fixed-rate, due February 2013
    350,000       350,000  
Senior Notes D, 6.875% fixed-rate, due March 2033
    500,000       500,000  
Senior Notes F, 4.625% fixed-rate, due October 2009
    500,000       500,000  
Senior Notes G, 5.60% fixed-rate, due October 2014
    650,000       650,000  
Senior Notes H, 6.65% fixed-rate, due October 2034
    350,000       350,000  
Senior Notes I, 5.00% fixed-rate, due March 2015
    250,000       250,000  
Senior Notes J, 5.75% fixed-rate, due March 2035
    250,000       250,000  
Senior Notes K, 4.950% fixed-rate, due June 2010
    500,000       500,000  
Senior Notes L, 6.30%  fixed-rate, due September 2017
    800,000       800,000  
Senior Notes M, 5.65% fixed-rate, due April 2013
    400,000       --  
Senior Notes N, 6.50% fixed-rate, due January 2019
    700,000       --  
Petal GO Zone Bonds, variable rate, due August 2037
    57,500       57,500  
Duncan Energy Partners’ debt obligation:
               
$300 Million Revolving Credit Facility, variable rate, due February 2011
    208,000       200,000  
Dixie Revolving Credit Facility, variable rate, due June 2010
    10,000       10,000  
     Total principal amount of senior debt obligations
    6,499,500       5,646,500  
EPO Junior Subordinated Notes A, due August 2066
    550,000       550,000  
EPO Junior Subordinated Notes B, due January 2068
    700,000       700,000  
             Total principal amount of senior and junior debt obligations
    7,749,500       6,896,500  
Other, non-principal amounts: