epdform10q_033108.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 March 31, 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 435,843,336 common units of Enterprise Products Partners L.P. outstanding at May 1, 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.
2
 
   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
10
 
       4.  Financial Instruments
13
 
       5.  Inventories
17
 
       6.  Property, Plant and Equipment
18
 
       7.  Investments in and Advances to Unconsolidated Affiliates
19
 
       8.  Intangible Assets and Goodwill
20
 
       9.  Debt Obligations
21
 
     10.  Partners’ Equity and Distributions
23
 
     11.  Business Segments
25
 
     12.  Related Party Transactions
29
 
     13.  Earnings Per Unit
32
 
     14.  Commitments and Contingencies
34
 
     15.  Significant Risks and Uncertainties – Weather-Related Risks
36
 
     16.  Supplemental Cash Flow Information
37
 
     17.  Condensed Financial Information of EPO
38
 
     18.  Subsequent Event
39
Item 2.
Management’s Discussion and Analysis of Financial Condition
 
 
   and Results of Operations.
40
Item 3.
Quantitative and Qualitative Disclosures about Market Risk.
55
Item 4.
Controls and Procedures.
58
     
PART II.  OTHER INFORMATION.
Item 1.
Legal Proceedings.
59
Item 1A.
Risk Factors.
59
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
59
Item 3.
Defaults upon Senior Securities.
59
Item 4.
Submission of Matters to a Vote of Security Holders.
59
Item 5.
Other Information.
59
Item 6.
Exhibits.
59
     
Signatures
64











 
1

 

PART I.  FINANCIAL INFORMATION.

Item 1.  Financial Statements.

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

   
March 31,
   
December 31,
 
ASSETS
 
2008
   
2007
 
Current assets:
           
Cash and cash equivalents
  $ 65,559     $ 39,722  
Restricted cash
    --       53,144  
Accounts and notes receivable - trade, net of allowance for doubtful accounts
               
of $19,292 at March 31, 2008 and $21,659 at December 31, 2007
    2,043,161       1,930,762  
Accounts receivable - related parties
    53,547       79,782  
Inventories
    288,798       354,282  
Prepaid and other current assets
    153,191       80,193  
       Total current assets
    2,604,256       2,537,885  
Property, plant and equipment, net
    12,107,790       11,587,264  
Investments in and advances to unconsolidated affiliates
    857,535       858,339  
Intangible assets, net of accumulated amortization of  $364,273 at
               
March 31, 2008 and $341,494 at December 31, 2007
    906,968       917,000  
Goodwill
    591,652       591,652  
Deferred tax asset
    3,194       3,522  
Other assets, including restricted cash of $6,561 at March 31, 2008
               
       and $17,871 at December 31, 2007
    120,688       112,345  
Total assets
  $ 17,192,083     $ 16,608,007  
                 
LIABILITIES AND PARTNERS’ EQUITY
               
Current liabilities:
               
Accounts payable – trade
  $ 198,948     $ 324,999  
Accounts payable – related parties
    23,542       24,432  
Accrued product payables
    2,303,288       2,227,489  
Accrued expenses
    65,087       47,756  
       Accrued interest
    83,800       130,971  
   Other current liabilities
    253,510       289,036  
       Total current liabilities
    2,928,175       3,044,683  
Long-term debt: (see Note 9)
               
       Senior debt obligations – principal
    6,219,500       5,646,500  
       Junior subordinated notes  – principal
    1,250,000       1,250,000  
       Other
    48,996       9,645  
                  Total long-term debt
    7,518,496       6,906,145  
Deferred tax liabilities
    19,078       21,364  
Other long-term liabilities
    75,509       73,748  
Minority interest
    426,774       430,418  
Commitments and contingencies
               
Partners’ equity:
               
Limited partners
               
Common units  (434,208,873 units outstanding at March 31, 2008
               
and 433,608,763 units outstanding at December 31, 2007)
    6,003,075       5,976,947  
Restricted common units (1,634,463 units outstanding at March 31, 2008
               
and 1,688,540 units outstanding at December 31, 2007)
    18,160       15,948  
General partner
    122,848       122,297  
Accumulated other comprehensive income
    79,968       16,457  
 Total partners’ equity
    6,224,051       6,131,649  
Total liabilities and partners’ equity
  $ 17,192,083     $ 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
 
   
Ended March 31,
 
   
2008
   
2007
 
Revenues:
           
     Third parties
  $ 5,383,834     $ 3,258,612  
     Related parties
    300,701       64,242  
         Total revenue
    5,684,535       3,322,854  
Costs and expenses:
               
  Operating costs and expenses:
               
     Third parties
    5,134,584       3,040,533  
     Related parties
    176,606       83,946  
         Total operating costs and expenses
    5,311,190       3,124,479  
  General and administrative costs:
               
     Third parties
    3,463       3,575  
     Related parties
    17,742       13,055  
         Total general and administrative costs
    21,205       16,630  
         Total costs and expenses
    5,332,395       3,141,109  
Equity in income of unconsolidated affiliates
    14,592       6,179  
Operating income
    366,732       187,924  
Other income (expense):
               
  Interest expense
    (91,946 )     (63,358 )
  Interest income
    1,611       2,035  
  Other, net
    (720 )     (107 )
          Total other expense, net
    (91,055 )     (61,430 )
Income before provision for income taxes
               
  and minority interest
    275,677       126,494  
Provision for income taxes
    (3,657 )     (8,788 )
Income before minority interest
    272,020       117,706  
Minority interest
    (12,411 )     (5,661 )
Net income
  $ 259,609     $ 112,045  
                 
Net income allocation: (see Note 10)
               
  Limited partners’ interest in net income
  $ 225,162     $ 85,049  
  General partner interest in net income
  $ 34,447     $ 26,996  
                 
Earning per unit: (see Note 13)
               
  Basic and diluted income per unit
  $ 0.51     $ 0.20  
















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
 
   
Ended March 31,
 
   
2008
   
2007
 
             
Net income
  $ 259,609     $ 112,045  
Other comprehensive income:
               
    Cash flow hedges:
               
       Foreign currency hedge losses
    (1,197 )     --  
       Net commodity financial instrument gains
    93,017       3,967  
       Net interest rate financial instrument gains (losses)
    (26,032 )     10,512  
       Less:  Amortization of cash flow financing hedges
    (1,590 )     (1,089 )
            Total cash flow hedges
    64,198       13,390  
    Foreign currency translation adjustment
    (423 )     401  
Change in funded status of Dixie benefit plans, net of tax
    (264 )     --  
            Total other comprehensive income
    63,511       13,791  
Comprehensive income
  $ 323,120     $ 125,836  


































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 Three Months
 
   
Ended March 31,
 
   
2008
   
2007
 
Operating activities:
           
   Net income
  $ 259,609     $ 112,045  
   Adjustments to reconcile net income to net cash
               
     flows provided by operating activities:
               
      Depreciation, amortization and accretion in operating costs and expenses
    133,922       119,492  
      Depreciation and amortization in general and administrative costs
    1,924       1,597  
      Amortization in interest expense
    130       132  
      Equity in income of unconsolidated affiliates
    (14,592 )     (6,179 )
      Distributions received from unconsolidated affiliates
    28,576       16,947  
      Operating lease expense paid by EPCO, Inc.
    527       526  
      Minority interest
    12,411       5,661  
      Gain on sale of assets
    (165 )     (73 )
      Deferred income tax expense (benefit)
    (913 )     1,596  
      Changes in fair market value of financial instruments
    662       104  
      Effect of pension settlement recognition
    (114 )     --  
  Net effect of changes in operating accounts (see Note 16)
    (156,912 )     168,903  
          Net cash flows provided by operating activities
    265,065       420,751  
Investing activities:
               
   Capital expenditures
    (624,096 )     (614,035 )
   Contributions in aid of construction costs
    6,833       39,145  
   Proceeds from sale of assets
    119       91  
   Decrease in restricted cash
    64,454       4,677  
   Cash used for business combinations
    (1 )     (312 )
   Investments in unconsolidated affiliates
    (7,432 )     (38,973 )
   Advances to unconsolidated affiliates
    (8,446 )     (5,514 )
          Cash used in investing activities
    (568,569 )     (614,921 )
Financing activities:
               
   Borrowings under debt agreements
    1,508,999       1,088,000  
   Repayments of debt
    (936,000 )     (939,000 )
   Debt issuance costs
    --       (510 )
   Distributions paid to partners
    (251,914 )     (233,145 )
   Distributions paid to minority interests
    (16,083 )     (1,053 )
   Net proceeds from initial public offering of Duncan Energy Partners reflected
               
       as a contribution from minority interests (see Notes 1 and 2)
    --       291,872  
   Other contributions from minority interests
    28       7,965  
   Net proceeds from issuance of our common units
    18,331       16,997  
   Settlement of interest rate swaps
    6,251       --  
          Cash provided by financing activities
    329,612       231,126  
Effect of exchange rate changes on cash
    (271 )     (1,338 )
Net change in cash and cash equivalents
    26,108       36,956  
Cash and cash equivalents, January 1
    39,722       22,619  
Cash and cash equivalents, March 31
  $ 65,559     $ 58,237  









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
             
   
Partners
   
Partner
   
AOCI
   
Total
 
Balance, December 31, 2007
  $ 5,992,895     $ 122,297     $ 16,457     $ 6,131,649  
Net income
    225,162       34,447       --       259,609  
Operating leases paid by EPCO, Inc.
    516       11       --       527  
Cash distributions to partners
    (217,621 )     (34,293 )     --       (251,914 )
Non-cash distributions
    (1,220 )     (25 )     --       (1,245 )
Net proceeds from sales of common units
    17,651       360       --       18,011  
Proceeds from exercise of unit options
    314       6       --       320  
Unit option reimbursements to EPCO, Inc.
    (86 )     --       --       (86 )
Change in funded status of Dixie
                               
   benefit plans, net of tax
    --       --       (264 )     (264 )
Amortization of unit-based awards
    3,624       45       --       3,669  
Foreign currency translation adjustment
    --       --       (423 )     (423 )
Cash flow hedges
    --       --       64,198       64,198  
Balance, March 31, 2008
  $ 6,021,235     $ 122,848     $ 79,968     $ 6,224,051  



































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.

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 months ended March 31, 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.  Dixie contributed $0.1 million to its company-sponsored defined contribution plan during each of the three month periods ended March 31, 2008 and 2007. Dixie’s net pension benefit costs were $0.1 million and $0.2 million for the three months ended March 31, 2008 and 2007, respectively.  Dixie’s net postretirement benefit costs were $0.1 million for each of the three month periods ended March 31, 2008 and 2007.  During the remainder of 2008, Dixie expects to contribute approximately $0.3 million to its postretirement benefit plan and approximately $0.5 million to its pension plan.

 
8

 

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 March 31, 2008 and December 31, 2007, our accrued liabilities for environmental remediation projects totaled $24.7 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 change in estimate 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 estimates made in September 2004.  These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.7 billion at March 31, 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 March 31, 2008 and December 31, 2007, minority interest includes $286.8 million and $288.6 million, respectively, attributable to third party owners of Duncan Energy Partners.  Minority interest expense for the three months ended March 31, 2008 and 2007 includes $4.4 million and $2.8 million, respectively, attributable to third party owners of Duncan Energy Partners.

Contributions from minority interests for the three months ended March 31, 2007 includes $291.9 million received from third parties in connection with the initial public offering of Duncan Energy Partners in February 2007 (ultimate net proceeds were $290.5 million). 

Recent Accounting Developments

Certain provisions of Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements,” became effective for us on January 1, 2008.  See Note 4 for information regarding new fair value-related disclosures required in connection with SFAS 157.

 
9

 

During the first quarter of 2008, SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” was issued.  SFAS 161 requires enhanced disclosures regarding (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, results of operations and cash flows.  SFAS 161 requires disclosure of (i) the fair values of derivative instruments and their gains and losses in a tabular format, (ii) derivative features that are credit risk-related and (iii) cross-referencing within the financial statement footnotes to locate important information about derivative instruments.  SFAS 161 is effective for us on January 1, 2009.  Management is currently evaluating the impact that SFAS 161 will have on our financial statement disclosures.  At present, we do not believe that this standard will impact how we record financial instruments.

Also during the first quarter of 2008, Emerging Issues Task Force Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-4”) was issued.  This guidance prescribes the manner in which a master limited partnership (“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.


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 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 compensation amounts by plan during each of the periods indicated:

   
For the Three Months
 
   
Ended March 31,
 
   
2008
   
2007
 
EPCO 1998 Long-Term Incentive Plan (“1998 Plan”)
           
     Unit options
  $ 158     $ 193  
     Restricted units
    1,508       1,274  
          Total 1998 Plan
    1,666       1,467  
Employee Partnerships
    1,183       502  
DEP GP UARs
    --       10  
          Total consolidated expense
  $ 2,849     $ 1,979  

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 March 31, 2008 and the issuance and forfeiture of restricted unit awards through March 31, 2008, a total of 1,418,833 additional common units could be issued under the 1998 Plan.

 
10

 
     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
    2,315,000     $ 26.18              
Exercised
    (10,000 )   $ 22.76              
Forfeited or terminated
    (85,000 )   $ 26.72              
Outstanding at March 31, 2008
    2,220,000     $ 26.17       7.47     $ 2,491  
Options exercisable at:
                               
March 31, 2008
    325,000     $ 22.03       3.70     $ 2,491  
                                 
(1) Aggregate intrinsic value reflects fully vested unit options at March 31, 2008.
 

The total intrinsic value of unit options exercised during the three months ended March 31, 2008 was $0.1 million.  At March 31, 2008, there was an estimated $2.5 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 2.7 years in accordance with the EPCO administrative services agreement.

During the three months ended March 31, 2008 and 2007, we received cash of $0.3 million and $4.2 million, respectively, from the exercise of unit options. Conversely, our option-related reimbursements to EPCO were $0.1 million and $1.6 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)
    5,000     $ 25.34  
Forfeited
    (56,577 )   $ 25.57  
Vested
    (2,500 )   $ 23.79  
Restricted units at March 31, 2008
    1,634,463          
                 
(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 $0.1 million based on a grant date market price of our common units of $30.53 per unit and an estimated forfeiture rate of 17.0%.
 

The total fair value of our restricted unit awards that vested during the three months ended March 31, 2008 was $0.1 million.  As of March 31, 2008, there was $22.9 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 March 31, 2008, these costs are expected to be recognized over a weighted-average period of 2.2 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.

 
11

 
 
  Enterprise Products 2008 Long-Term Incentive Plan
 
On January 29, 2008, our unitholders approved the Enterprise Products 2008 Long-Term Incentive Plan (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 will be administered by EPGP’s Audit, Conflicts and Governance (“ACG”) Committee. Up to 10,000,000 of our common units may be granted as awards under the plan, with such amount subject to adjustment.

The exercise price of unit options or UARs awarded to participants will be 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 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.  As of March 31, 2008, no awards have been issued under the 2008 LTIP.

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.

As of March 31, 2008, there was $25.5 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.  It is currently anticipated that EPCO Holdings will contribute up to an additional $33.0 million to Enterprise Unit; however, EPCO Holdings has no legal obligation to make such additional contributions and may ultimately contribute more or less than this amount to Enterprise Unit.  EPCO Holdings has contributed $23.4 million to Enterprise Unit through April 30, 2008.

As with the awards granted in connection with the other Employee Partnerships, these awards are designed to provide additional long-term incentive compensation for such 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 forfeiture.

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

 
12

 

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.  The risk of forfeiture associated with the Class B limited partner interests in Enterprise Unit will also lapse 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 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 UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash. As of March 31, 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.  The grant date fair value with respect to these UARs is based on an Enterprise GP Holdings’ unit price of $36.68.


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.

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

 
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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 nine interest rate swap agreements outstanding at March 31, 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 (2)
Senior Notes B, 7.50% fixed rate, due Feb. 2011
1
Jan. 2004 to Feb. 2011
Feb. 2011
7.50% to 6.53%
$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013
2
Jan. 2004 to Feb. 2013
Feb. 2013
6.38% to 5.07%
$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014
6
4th Qtr. 2004 to Oct. 2014
Oct. 2014
5.60% to 6.13%
$600 million
(1) The variable rate indicated is the all-in variable rate for the current settlement period.
(2) In April 2008, the interest rate swap associated with Senior Notes B was settled and we received $1.8 million of cash.  In addition, in April 2008 we settled two swaps, each with a notional value of $100.0 million, associated with Senior Notes G and C and we received cash of $5.4 million and $4.8 million, respectively.
 
The aggregate fair value of these nine interest rate swaps at March 31, 2008 was an asset of $48.7 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 March 31, 2008 and 2007 includes a $0.8 million loss and a $2.3 million loss, respectively, resulting from these swap agreements.

In February 2008, we terminated two interest rate swaps, each with a notional value of $100.0 million, related to our Senior Notes K and received $6.3 million of cash.  This amount will be amortized to earnings as a reduction in 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 March 31, 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
2.67%  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 a $60 thousand benefit from these swap agreements during the three months ended March 31, 2008.  The aggregate fair value of these interest rate swaps at March 31, 2008 and December 31, 2007 was a liability of $9.0 million and $3.8 million, respectively. As cash flow hedges, any increase or decrease in fair value (to the extent effective) would be recorded into other comprehensive income and amortized into income based on the settlement period hedged.  Over the next twelve months, we expect to reclassify $3.9 million of this loss to earnings as an increase in interest expense.

Cash Flow Hedges – Treasury Locks. At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. Gains or losses on the termination 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 was designated as a cash flow hedge under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted.

In connection with our issuance of Senior Notes M and N in April 2008 (see Note 18), we terminated all of our outstanding treasury lock financial instruments.  On March 31, 2008, we terminated treasury locks having a notional value of $350.0 million and recognized an other comprehensive loss of $27.7 million.  On April 1, 2008, we terminated the remaining treasury locks, which had an aggregate notional value of $250.0 million.  As a result, we will recognize an additional other comprehensive loss of $12.7 million during the second quarter of 2008.

With respect to our treasury lock transactions (including those terminated in prior periods), we will reclassify $3.3 million of net gains to earnings as a decrease in interest expense over the next twelve months.

 
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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 hedge 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 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.

At March 31, 2008 and December 31, 2007, the fair value of our commodity financial instrument portfolio, which primarily consisted of cash flow hedges, was an asset of $68.3 million and a liability of $19.3 million, respectively.  The change in fair value of this portfolio between March 31, 2008 and December 31, 2007 is primarily due to an increase in natural gas prices.

During the three months ended March 31, 2008, we recorded a loss of $3.8 million related to our commodity financial instruments, which was offset by ineffectiveness of $2.8 million (a benefit).  During the three months ended March 31, 2007, we recorded a loss of $2.6 million related to our commodity financial instruments.  No ineffectiveness was recorded during the three months ended March 31, 2007.  These contracts will terminate during 2008, and any amounts remaining in accumulated other comprehensive income will be reclassified into earnings in 2008.

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.  As of March 31, 2008, $1.6 million of these exchange contracts were outstanding, all of which settled in April 2008.

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

 
15

 
 
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.

§  
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 observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are validated by inputs other than quoted prices (e.g., interest rates 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 March 31, 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 March 31, 2008 there were no Level 1 financial assets or liabilities.

   
Level 2
   
Level 3
   
Total
 
Financial assets:
                 
Commodity financial instruments
  $ 75,394     $ --     $ 75,394  
Foreign currency financial instruments
    111       --       111  
Interest rate financial instruments
    48,748       --       48,748  
Total
  $ 124,253     $ --     $ 124,253  
                         
Financial liabilities:
                       
Commodity financial instruments
  $ 4,490     $ 2,634     $ 7,124  
Foreign currency financial instruments
    18       --       18  
Interest rate financial instruments
    12,744       --       12,744  
Total
  $ 17,252     $ 2,634     $ 19,886  

 
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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.

The following table sets forth a reconciliation of changes in the fair value of our net financial assets and liabilities classified as Level 3 in the fair value hierarchy:
 
   
Net
 
   
Commodity
 
   
Financial
 
   
Instruments
 
Beginning 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  
Transfer in/out of Level 3
    --  
Ending balance, March 31, 2008
  $ (2,634 )
         
Net unrealized losses included in net income
       
for the quarter relating to instruments still held
    393  
at March 31, 2008 (1)
  $ 393  
         
(1) At March 31, 2008, total commodity financial instrument losses included in net income were $2.3 million, of which $0.4 million were unrealized. These amounts were recognized in revenues on our Unaudited Condensed Statement of Consolidated Operations for the three months ended March 31, 2008.
 
 

Note 5.  Inventories

Our inventory amounts were as follows at the dates indicated:
 
   
March 31,
   
December 31,
 
   
2008
   
2007
 
Working inventory (1)
  $ 279,225     $ 342,589  
Forward-sales inventory (2)
    9,573       11,693  
   Total inventory
  $ 288,798     $ 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 $4.9 billion and $2.8 billion for the three months ended March 31, 2008 and 2007, 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 March 31, 2008 and 2007, we recognized LCM adjustments of approximately $4.2 million and $11.0 million, 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
   
March 31,
   
December 31,
 
 
in Years
   
2008
   
2007
 
Plants and pipelines (1)
  3-35 (5)
    $ 11,395,021     $ 10,884,819  
Underground and other storage facilities (2)
  5-35 (6)
      727,668       720,795  
Platforms and facilities (3)
20-31
      634,645       637,812  
Transportation equipment (4)
3-10
      33,210       32,627  
Land
        49,821       48,172  
Construction in progress
        1,288,212       1,173,988  
    Total
        14,128,577       13,498,213  
Less accumulated depreciation
        2,020,787       1,910,949  
    Property, plant and equipment, net
      $ 12,107,790     $ 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
 
   
Ended March 31,
 
   
2008
   
2007
 
Depreciation expense (1)
  $ 109,843     $ 94,980  
Capitalized interest (2)
  $ 18,112     $ 20,742  
                 
(1) Depreciation expense is a component of operating 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 change in estimate 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 estimates made in September 2004.  These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.7 billion as of March 31, 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 months ended March 31, 2008 decreased by approximately $5.0 million, which increased our earnings per unit by $0.02 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
    (4,906 )
Revisions in estimated cash flows
    160  
Accretion expense
    659  
ARO liability balance, March 31, 2008
  $ 36,911  

Property, plant and equipment at March 31, 2008 and December 31, 2007 include $8.5 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
       
   
March 31,
   
March 31,
   
December 31,
 
   
2008
   
2008
   
2007
 
NGL Pipelines & Services:
                 
Venice Energy Service Company L.L.C. (“VESCO”) (1)
   
13.1%
    $ 33,706     $ 40,129  
K/D/S Promix, L.L.C. (“Promix”)
   
50%
      50,068       51,537  
Baton Rouge Fractionators LLC (“BRF”)
    32.3%       25,372       25,423  
Onshore Natural Gas Pipelines & Services:
                       
Jonah Gas Gathering Company (“Jonah”)
    19.4%       246,941       235,837  
Evangeline (2)
    49.5%       3,916       3,490  
Offshore Pipelines & Services:
                       
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)
   
36%
      57,904       58,423  
Cameron Highway Oil Pipeline Company (“Cameron Highway”)
   
50%
      257,176       256,588  
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)
   
50%
      107,646       111,221  
Neptune Pipeline Company, L.L.C. (“Neptune”)
   
25.7%
      54,145       55,468  
Nemo Gathering Company, LLC (“Nemo”)
   
33.9%
      2,944       2,888  
Petrochemical Services:
                       
Baton Rouge Propylene Concentrator, LLC (“BRPC”)
   
30%
      13,621       13,282  
La Porte (3)
   
50%
      4,096       4,053  
Total
          $ 857,535     $ 858,339  
                         
(1) Our investment in VESCO has decreased since December 31, 2007 partially due to $4.0 million of expense associated with certain repair projects.
(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 an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire.  Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates.  At March 31, 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 book

 
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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 month periods ended March 31, 2008 and 2007.

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated:

   
For the Three Months
 
   
Ended March 31,
 
   
2008
   
2007
 
NGL Pipelines & Services
  $ (2,310 )   $ 591  
Onshore Natural Gas Pipelines & Services
    5,827       1,029  
Offshore Pipelines & Services
    10,718       4,075  
Petrochemical Services
    357       484  
Total
  $ 14,592     $ 6,179  

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
 
   
March 31, 2008
   
March 31, 2007
 
         
Operating
   
Net
         
Operating
   
Net
 
   
Revenues
   
Income (Loss)
   
Income
   
Revenues
   
Income
   
Income
 
NGL Pipelines & Services
  $ 68,616     $ (93 )   $ 54     $ 41,732     $ 3,260     $ 3,829  
Onshore Natural Gas Pipelines & Services
    117,594       30,955       29,730       108,898       21,615       20,313  
Offshore Pipelines & Services
    43,224       26,311       25,337       37,193       19,718       12,336  
Petrochemical Services
    5,356       1,483       1,488       5,553       1,887       1,911  


Note 8.  Intangible Assets and Goodwill

Identifiable Intangible Assets

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

   
March 31, 2008
   
December 31, 2007
 
   
Gross
   
Accum.
   
Carrying
   
Gross
   
Accum.
   
Carrying
 
   
Value
   
Amort.
   
Value
   
Value
   
Amort.
   
Value
 
NGL Pipelines & Services
  $ 520,025     $ (156,387 )   $ 363,638     $ 520,025     $ (146,954 )   $ 373,071  
Onshore Natural Gas Pipelines & Services
    476,298       (117,818 )     358,480       463,551       (109,399 )     354,152  
Offshore Pipelines & Services
    207,012       (78,382 )     128,630       207,012       (73,954 )     133,058  
Petrochemical Services
    67,906       (11,686 )     56,220       67,906       (11,187 )     56,719  
        Total
  $ 1,271,241     $ (364,273 )   $ 906,968     $ 1,258,494     $ (341,494 )   $ 917,000  

The following table presents the amortization expense of our intangible assets by segment for the periods indicated:

   
For the Three Months
 
   
Ended March 31,
 
   
2008
   
2007
 
NGL Pipelines & Services
  $ 9,433     $ 9,244  
Onshore Natural Gas Pipelines & Services
    8,419       8,155  
Offshore Pipelines & Services
    4,429       5,082  
Petrochemical Services
    498       498  
Total
  $ 22,779     $ 22,979  

For the remainder of 2008, amortization expense associated with our intangible assets is currently estimated at $65.6 million.

 
20

 

Goodwill

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

   
March 31,
   
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  


Note 9.  Debt Obligations

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

   
March 31,
   
December 31,
 
   
2008
   
2007
 
EPO senior debt obligations:
           
Multi-Year Revolving Credit Facility, variable rate, due November 2012
  $ 1,310,000     $ 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  
Petal GO Zone Bonds, variable rate, due August 2034
    57,500       57,500  
Duncan Energy Partners’ debt obligation:
               
$300 Million Revolving Credit Facility, variable rate, due February 2011
    188,000       200,000  
Dixie Revolving Credit Facility, variable rate, due June 2010
    10,000       10,000  
Total principal amount of senior debt obligations
    6,219,500       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
    7,469,500       6,896,500  
Other, non-principal amounts:
               
Change is fair value of debt-related financial instruments (see Note 4)
    49,581       14,839  
Unamortized discounts, net of premiums
    (6,290 )     (5,194 )
Unamortized deferred net gains related to terminated interest rate swap
    5,705       --  
Total other, non-principal amounts
    48,996       9,645  
Long-term debt
  $ 7,518,496     $ 6,906,145  
                 
Standby letters of credit outstanding
  $ 1,100     $ 1,100  

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the Dixie revolving credit facility and the Duncan Energy Partners’ revolving credit facility.  If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation.

We consolidate the debt of Dixie and Duncan Energy Partners; however, we do not have the obligation to make interest or debt payments with respect to such obligations.

Apart from that discussed below, there have been no significant changes in the terms of our consolidated debt obligations since those reported in our Annual Report on Form 10-K for the year ended December 31, 2007.

 
21

 

In April 2008, EPO sold $400.0 million in principal amount of 5.65% senior notes due 2013 (“Senior Notes M”) and $700.0 million in principal amount of 6.50% senior notes due 2019 (“Senior Notes N”).  See Note 18 for additional information regarding the issuance of these notes.

Covenants

We are in compliance with the covenants of our consolidated debt agreements at March 31, 2008 and December 31, 2007.

Information regarding variable interest rates paid

The following table presents the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the three months ended March 31, 2008.

 
Range of
Weighted-average
 
interest rates
interest rate
 
paid
paid
EPO’s Multi-Year Revolving Credit Facility
3.14% to 6.00%
4.17%
Duncan Energy Partners’ Revolving Credit Facility
3.39% to 6.20%
5.50%
Dixie Revolving Credit Facility
2.86% to 5.50%
4.03%
Petal GO Zone Bonds
1.16% to 3.25%
2.46%

Consolidated debt maturity table

The following table presents the scheduled maturities of principal amounts of our consolidated debt obligations for the next five years and in total thereafter.  This information is presented on a pro forma basis, taking into account the issuance of EPO’s Senior Notes M and N in April 2008 and related use of proceeds (see Note 18).

2008
  $ --  
2009
    500,000  
2010
    599,931  
2011
    638,000  
2012
    174,069  
Thereafter
    5,557,500  
Total scheduled principal payments
  $ 7,469,500  

Debt Obligations of Unconsolidated Affiliates

We have two unconsolidated affiliates with long-term debt obligations.  The following table shows (i) our ownership interest in each entity at March 31, 2008, (ii) total debt of each unconsolidated affiliate at March 31, 2008 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

 
Our
       
Scheduled Maturities of Debt
 
 
Ownership
                                     
After
 
 
Interest
 
Total
   
2008
   
2009
   
2010
   
2011
   
2012
   
2012
 
Poseidon
36.0%
  $ 98,000     $ --     $ --     $ --     $ 98,000     $ --     $ --  
Evangeline
49.5%
    20,650       5,000       5,000       3,150       7,500       --       --  
   Total
    $ 118,650     $ 5,000     $ 5,000     $ 3,150     $ 105,500     $ --     $ --  

The credit agreements of our unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants.  These businesses were in compliance with such covenants at March 31, 2008.  The credit agreements of our unconsolidated affiliates restrict their ability to pay cash dividends if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend is scheduled to be paid.

 
22

 

There have been no significant changes in the terms of the debt obligations of our unconsolidated affiliates since those reported in our Annual Report on Form 10-K for the year ended December 31, 2007.


Note 10.  Partners’ Equity and Distributions

Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Fifth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”).  We are managed by our general partner, EPGP.

In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and limited partners.  The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.

Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and general partner will receive. The Partnership Agreement also contains provisions for the allocation of net earnings and losses to our limited partners and general partner.  For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests.  Normal income and loss allocations according to percentage interests are done only after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner.

Equity Offerings and Registration Statements

In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by EPGP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders).

We have a universal shelf registration statement on file with the SEC registering the issuance of an unlimited amount of equity and debt securities.  In April 2008, EPO sold $1.1 billion in principal amount of senior notes under our universal shelf registration statement.  For additional information regarding this debt offering, see Note 18.

We also have a registration statement with the SEC authorizing the issuance of up to 25,000,000 common units in connection with our distribution reinvestment plan (“DRIP”).  The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units.  A total of 587,610 of our common units were issued in February 2008 in connection with the DRIP and the employee unit purchase plan (“EUPP”).  The issuance of these units generated $18.0 million in net proceeds.












 
23

 

Summary of Changes in Outstanding Units

The following table summarizes changes in our outstanding units since December 31, 2007:

         
Restricted
 
   
Common
   
Common
 
   
Units
   
Units
 
Balance, December 31, 2007
    433,608,763       1,688,540  
Units issued in connection with DRIP and EUPP
    587,610       --  
Units issued in connection with unit-based awards
    10,000       --  
Restricted units issued
    --       5,000  
Vesting of restricted units
    2,500       (2,500 )
Forfeiture of restricted units
    --       (56,577 )
Balance, March 31, 2008
    434,208,873       1,634,463  

Summary of Changes in Limited Partners’ Equity

The following table details the changes in limited partners’ equity since December 31, 2007:

         
Restricted
       
   
Common
   
Common
       
   
units
   
units
   
Total
 
Balance, December 31, 2007
  $ 5,976,947     $ 15,948     $ 5,992,895  
Net income
    224,314       848       225,162  
Operating leases paid by EPCO
    514       2       516  
Cash distributions to partners
    (216,804 )     (817 )     (217,621 )
Non-cash distributions
    (1,220 )     --       (1,220 )
Net proceeds from sales of common units
    17,651       --       17,651  
Proceeds from exercise of unit options
    314       --       314  
Unit option reimbursements to EPCO
    (86 )     --       (86 )
Amortization of unit-based awards
    1,445       2,179       3,624  
Balance, March 31, 2008
  $ 6,003,075     $ 18,160     $ 6,021,235  

Distributions to Partners

The percentage interest of EPGP in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met.  At current distribution rates, we are in the highest tier of such incentive targets.  EPGP’s quarterly incentive distribution thresholds are as follows:

§  
2% of quarterly cash distributions up to $0.253 per unit;
§  
15% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit; and
§  
25% of quarterly cash distributions that exceed $0.3085 per unit.

We paid incentive distributions of $29.9 million and $25.3 million to EPGP during the three months ended March 31, 2008 and 2007, respectively.

On May 7, 2008, we paid a quarterly cash distribution of $0.5075 or $2.03 on an annualized basis per unit to unitholders of record as of April 30, 2008.  Our cash distribution for the first quarter of 2007 was $0.475 per unit.









 
24

 

Accumulated Other Comprehensive Income

The following table presents the components of accumulated other comprehensive income at the dates indicated:
 
   
March 31,
   
December 31,
 
   
2008
   
2007
 
Commodity financial instruments (1)
  $ 71,398     $ (21,619 )
Interest rate financial instruments (1)
    7,358       34,980  
Foreign currency hedges (1)
    111       1,308  
Foreign currency translation adjustment
    777       1,200  
Pension and postretirement benefit plans (2)
    324       588  
    Total accumulated other comprehensive income
  $ 79,968     $ 16,457  
                 
(1) See Note 4 for additional information regarding these components of accumulated other comprehensive income.
(2) See Note 2 for additional information regarding pension and postretirement benefit plans.
 

 
Note 11.  Business Segments

We have four reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Offshore Pipelines & Services and Petrochemical Services.  Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin.  Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations.  This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments.  We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.  The GAAP financial measure most directly comparable to total segment gross operating margin is operating income.  Our non-GAAP financial measure of total segment gross operating margin should not be considered an alternative to GAAP operating income.

We define total segment gross operating margin as consolidated operating income before: (i) depreciation, amortization and accretion expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) general and administrative costs.  Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of change in accounting principle.  Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intersegment and intrasegment transactions.

Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates.  Our consolidated revenues reflect the elimination of intercompany (both intersegment and intrasegment) transactions.

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Our equity investments with industry partners are a vital component of our business strategy.  They are a means by which we conduct our operations to align our interests with those of our customers and/or suppliers.  This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis.  Many of these businesses perform supporting or complementary roles to our other business operations.

 
25

 

Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs, crude oil and certain petrochemicals.  In general, hydrocarbons enter our asset system in a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an NGL fractionator, an NGL storage facility, or an NGL transportation or distribution pipeline.

Many of our equity investees are included within our integrated midstream asset system.  For example, we have ownership interests in several offshore natural gas and crude oil pipelines.  Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our gas plants.  The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities.  Given the integral nature of our equity method investees to our operations, we believe the presentation of earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate.

Historically, substantially all of our consolidated revenues were earned in the United States and derived from a wide customer base.  The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico, Colorado and Wyoming.  Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States, including the Rocky Mountains.  Our marketing activities are headquartered in Houston, Texas and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.

Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are assigned to each segment on the basis of each asset’s or investment’s principal operations.  The principal reconciling difference between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress.  Segment assets represent the net book carrying value of facilities and other assets that contribute to gross operating margin of that particular segment.  Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from segment asset totals until they are placed in service.  Consolidated intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate.

We consolidate the financial statements of Duncan Energy Partners with those of our own.  As a result, our consolidated gross operating margin amounts include 100% of the gross operating margin amounts of Duncan Energy Partners.

The following table presents our measurement of total segment gross operating margin for the periods indicated:
 
     
For the Three Months
 
     
Ended March 31,
 
     
2008
   
2007
 
Revenues (1)
  $ 5,684,535     $ 3,322,854  
Less:
Operating costs and expenses (1)
    (5,311,190 )     (3,124,479 )
Add:
Equity in income of unconsolidated affiliates (1)
    14,592       6,179  
 
Depreciation, amortization and accretion in operating costs and expenses (2)
    133,922       119,492  
 
Operating lease expense paid by EPCO (2)
    527       526  
 
Gain on sale of assets in operating costs and expenses (2)
    (165 )     (73 )
Total segment gross operating margin
  $ 522,221     $ 324,499  
                   
(1) These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations.
(2) These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.
 

 
 
26

 

A reconciliation of our total segment gross operating margin to operating income and income before provision for income taxes and minority interest follows:

   
For the Three Months
 
   
Ended March 31,
 
   
2008
   
2007
 
Total segment gross operating margin
  $ 522,221     $ 324,499  
Adjustments to reconcile total segment gross operating margin
               
to operating income:
               
   Depreciation, amortization and accretion in operating costs and expenses
    (133,922 )     (119,492 )
   Operating lease expense paid by EPCO
    (527 )     (526 )
   Gain on sale of assets in operating costs and expenses
    165       73  
   General and administrative costs
    (21,205 )     (16,630 )
Consolidated operating income
    366,732       187,924  
   Other expense, net
    (91,055 )     (61,430 )
Income before provision for income taxes and minority interest
  $ 275,677     $ 126,494  

The following table summarizes the contribution to consolidated revenues from the sale of NGL, natural gas and petrochemical products for the periods indicated:

   
For the Three Months
 
   
Ended March 31,
 
   
2008
   
2007
 
NGL Pipelines & Services:
           
   Sale of NGL products
  $ 4,062,043     $ 2,191,624  
   Percent of consolidated revenues
    71 %     66 %
Onshore Natural Gas Pipelines & Services:
               
   Sale of natural gas
  $ 646,318     $ 361,031  
   Percent of consolidated revenues
    11 %     11 %
Petrochemical Services:
               
   Sale of petrochemical products
  $ 534,387     $ 387,752  
   Percent of consolidated revenues
    9 %     12 %


























 
27

 

Information by segment, together with reconciliations to our consolidated totals, is presented in the following table:

 
Reportable Segments
             
       
Onshore
                         
 
NGL
   
Natural Gas
   
Offshore
         
Adjustments
       
 
Pipelines
   
Pipelines