EX-99.3 13 exhibit99_3.htm EXHIBIT 99.3 exhibit99_3.htm
Exhibit 99.3
ENTERPRISE GP HOLDINGS L.P.
INDEX TO FINANCIAL STATEMENTS

   
Page No.
     
     
 
 
     
 
 
     
 
 
     
 
 
     
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 














To the Board of Directors of EPE Holdings, LLC and
Unitholders of Enterprise GP Holdings L.P.
Houston, Texas

We have audited the accompanying consolidated balance sheets of Enterprise GP Holdings L.P. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related statements of consolidated operations, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2009.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements based on our audits.  We did not audit the financial statements of Energy Transfer Equity L.P., an investment of the Company, which is accounted for by the use of the equity method.  The Company’s equity in Energy Transfer Equity L.P.’s net income of $77.7 million and $65.6 million (with both amounts prior to the Company’s excess cost amortization – see Note 9) for the years ended December 31, 2009 and 2008, respectively, is included in the accompanying consolidated financial statements.  Energy Transfer Equity L.P.’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Energy Transfer Equity L.P., is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Enterprise GP Holdings L.P. and subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010 expresses an unqualified opinion on the Company's internal control over financial reporting.

The consolidated financial statements give retroactive effect to the acquisition of TEPPCO Partners, L.P. (“TEPPCO”) and Texas Eastern Products Pipeline Company, LLC (“TEPPCO GP”) by Enterprise Products Partners L.P. on October 26, 2009, which has been accounted for at historical cost as a reorganization of entities under common control as described in Notes 1 and 11 to the consolidated financial statements.  Also, as discussed in Note 1 to the consolidated financial statements, the disclosures in the accompanying consolidated financial statements have been retrospectively adjusted for a change in the composition of reportable segments as a result of the acquisition of TEPPCO and TEPPCO GP by Enterprise Products Partners L.P. 
 
/s/ DELOITTE & TOUCHE LLP
 
Houston, Texas
March 1, 2010





ENTERPRISE GP HOLDINGS L.P.
(Dollars in millions)

   
December 31,
  
ASSETS
  
2009
     2008*  
Current assets:
              
Cash and cash equivalents
   $ 55.3     $ 56.8  
Restricted cash
     63.6       203.8  
Accounts and notes receivable – trade, net of allowance for doubtful accounts
 of $16.8 at December 31, 2009 and $17.7 at December 31, 2008
     3,099.0       1,993.5  
Accounts receivable – related parties
     38.4       35.2  
Inventories
     711.9       405.0  
Derivative assets
     113.8       218.5  
Prepaid and other current assets
     167.6       151.5  
Total current assets
     4,249.6       3,064.3  
Property, plant and equipment, net
     17,689.2       16,732.8  
Investments in unconsolidated affiliates
     2,416.2       2,510.7  
Intangible assets, net of accumulated amortization of $795.0 at
   December 31, 2009 and $675.1 at December 31, 2008
     1,064.8       1,182.9  
Goodwill
     2,018.3       2,019.6  
Other assets
     248.2       270.1  
Total assets
   $ 27,686.3     $ 25,780.4  
                 
LIABILITIES AND EQUITY
                
Current liabilities:
                
Accounts payable – trade
   $ 410.6     $ 381.5  
Accounts payable – related parties
     70.8       17.6  
Accrued product payables
     3,393.0       1,845.6  
Accrued expenses
     108.5       65.7  
Accrued interest
     231.7       197.4  
Derivative liabilities
     106.1       316.2  
Other current liabilities
     233.2       292.2  
Total current liabilities
     4,553.9       3,116.2  
Long-term debt (see Note 12)
     12,427.9       12,714.9  
Deferred tax liabilities
     71.7       66.1  
Other long-term liabilities
     159.7       123.8  
Commitments and contingencies
                
Equity: (see Note 13)
                
Enterprise GP Holdings L.P. partners’ equity:
                
Limited Partners:
                
Units (139,191,640 Units outstanding at December 31, 2009
and 123,191,640 Units outstanding at December 31, 2008)
     1,972.4       1,650.5  
Class C Units (16,000,000 Class C Units outstanding at December 31, 2008)
     --       380.7  
General partner
     **       **  
Accumulated other comprehensive loss
     (33.3 )     (53.2 )
Total Enterprise GP Holdings L.P. partners’ equity
     1,939.1       1,978.0  
Noncontrolling interest
     8,534.0       7,781.4  
Total equity
     10,473.1       9,759.4  
Total liabilities and equity
   $ 27,686.3     $ 25,780.4  


** Amount is negligible.





See Notes to Consolidated Financial Statements.
*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.


ENTERPRISE GP HOLDINGS L.P.
 (Dollars in millions, except per unit amounts)

   
For Year Ended December 31,
  
   
2009
     2008*     2007*  
Revenues:
                      
Third parties
   $ 24,911.9     $ 34,454.2     $ 26,128.6  
Related parties
     599.0       1,015.4       585.2  
Total revenues (see Note 14)
     25,510.9       35,469.6       26,713.8  
Costs and expenses:
                        
Operating costs and expenses:
                        
Third parties
     22,547.6       32,861.9       24,938.2  
Related parties
     1,018.2       757.0       463.9  
Total operating costs and expenses
     23,565.8       33,618.9       25,402.1  
General and administrative costs:
                        
Third parties
     85.6       49.8       48.9  
Related parties
     97.2       95.0       83.0  
Total general and administrative costs
     182.8       144.8       131.9  
Total costs and expenses
     23,748.6       33,763.7       25,534.0  
Equity in income of unconsolidated affiliates
     92.3       66.2       13.6  
Operating income
     1,854.6       1,772.1       1,193.4  
Other income (expense):
                        
Interest expense
     (687.3 )     (608.3 )     (487.4 )
Interest income
     2.3       7.4       11.4  
Other, net
     (4.0 )     4.9       60.4  
Total other expense, net
     (689.0 )     (596.0 )     (415.6 )
Income before provision for income taxes
     1,165.6       1,176.1       777.8  
Provision for income taxes
     (25.3 )     (31.0 )     (15.8 )
Net income
     1,140.3       1,145.1       762.0  
Net income attributable to noncontrolling interest (see Note 13)
     (936.2 )     (981.1 )     (653.0 )
Net income attributable to Enterprise GP Holdings L.P.
   $ 204.1     $ 164.0     $ 109.0  
                         
Net income allocated to: (see Note 13)
                        
Limited partners
   $ 204.1     $ 164.0     $ 109.0  
General partner
   $ **     $ **     $ **  
                         
Earnings per unit: (see Note 17)
                        
Basic and diluted earnings per unit
   $ 1.48     $ 1.33     $ 0.97  

** Amount is negligible.















See Notes to Consolidated Financial Statements.
*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.


ENTERPRISE GP HOLDINGS L.P.
(Dollars in millions)

   
For Year Ended December 31,
  
   
2009
     2008*     2007*  
Net income
   $ 1,140.3     $ 1,145.1     $ 762.0  
Other comprehensive income (loss):
                        
Cash flow hedges:
                        
Commodity derivative instrument losses during period
     (179.6 )     (170.2 )     (46.9 )
Reclassification adjustment for losses included in net income
related to commodity derivative instruments
     294.2       96.3       9.5  
Interest rate derivative instrument gains (losses) during period
     12.5       (73.0 )     (18.2 )
Reclassification adjustment for (gains) losses included in net income
related to interest rate derivative instruments
     26.4       5.5       (6.6 )
Foreign currency derivative gains (losses)
     (10.2 )     9.3       1.3  
Total cash flow hedges
     143.3       (132.1 )     (60.9 )
Foreign currency translation adjustment
     2.1       (2.5 )     2.0  
Change in funded status of pension and postretirement plans, net of tax
     --       (1.3 )     --  
    Proportionate share of other comprehensive income (loss) of unconsolidated affiliate
     2.5       (9.9 )     (3.8 )
Total other comprehensive income (loss)
     147.9       (145.8 )     (62.7 )
Comprehensive income
     1,288.2       999.3       699.3  
Comprehensive income attributable to noncontrolling interest
     (1,064.2 )     (866.1 )     (614.3 )
Comprehensive income attributable to Enterprise GP Holdings L.P.
   $ 224.0     $ 133.2     $ 85.0  
































See Notes to Consolidated Financial Statements.
*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.


ENTERPRISE GP HOLDINGS L.P.
(Dollars in millions)

   
For Year Ended December 31,
  
   
2009
     2008*     2007*  
Operating activities:
                      
Net income
   $ 1,140.3     $ 1,145.1     $ 762.0  
Adjustments to reconcile net income to net cash
 flows provided by operating activities:
                        
Depreciation, amortization and accretion
     836.8       740.1       662.8  
Non-cash impairment charges
     33.5       --       --  
Equity in income of unconsolidated affiliates
     (92.3 )     (66.2 )     (13.6 )
Distributions received from unconsolidated affiliates
     169.3       157.2       116.9  
Operating lease expenses paid by EPCO
     0.7       2.0       2.1  
Gain from asset sales and related transactions
     --       (4.0 )     (67.4 )
Loss on forfeiture of investment in Texas Offshore Port System
     68.4       --       --  
Loss on early extinguishment of debt
     --       1.6       1.6  
Deferred income tax expense
     4.5       6.2       7.6  
Changes in fair market value of derivative instruments
     (0.9 )     (0.9 )     3.3  
Effect of pension settlement recognition
     (0.1 )     (0.1 )     0.6  
Unamortized debt issuance costs
     --       --       3.3  
Net effect of changes in operating accounts (see Note 20)
     250.1       (414.6 )     457.6  
Net cash flows provided by operating activities
     2,410.3       1,566.4       1,936.8  
Investing activities:
                        
Capital expenditures
     (1,584.3 )     (2,539.6 )     (2,749.1 )
Contributions in aid of construction costs
     17.8       27.2       57.7  
Decrease (increase) in restricted cash
     140.2       (132.8 )     (47.3 )
Cash used for business combinations (see Note 10)
     (107.3 )     (553.5 )     (35.9 )
Acquisition of intangible assets
     (1.4 )     (5.8 )     (14.5 )
Investments in unconsolidated affiliates
     (19.6 )     (64.7 )     (1,921.1 )
Proceeds from asset sales and related transactions
     3.6       22.3       169.1  
    Other investing activities
     3.3       --       --  
Cash used in investing activities
     (1,547.7 )     (3,246.9 )     (4,541.1 )
Financing activities:
                        
Borrowings under debt agreements
     7,494.2       13,255.5       11,416.7  
Repayments of debt
     (7,766.7 )     (10,514.9 )     (8,652.0 )
Debt issuance costs
     (14.9 )     (27.5 )     (39.2 )
Cash distributions paid to partners
     (266.7 )     (213.1 )     (159.0 )
Cash distributions paid to noncontrolling interest
     (1,322.1 )     (1,182.1 )     (1,073.9 )
Cash contributions from noncontrolling interest
     1,014.2       446.4       372.7  
Cash contributions from partners
     --       --       0.1  
Net cash proceeds from issuance of our Units, net
     --       --       739.4  
Cash distributions paid to former owners of TEPPCO interests
     --       --       (29.8 )
Repurchase of restricted units and options by subsidiary
     --       --       (1.6 )
Acquisition of treasury units by subsidiary
     (2.1 )     (1.9 )     --  
Monetization of interest rate derivative instruments (see Note 6)
     0.2       (66.5 )     49.1  
Cash provided by (used in) financing activities
     (863.9 )     1,695.9       2,622.5  
Effect of exchange rate changes on cash flows
     (0.2 )     (0.5 )     0.4  
Net change in cash and cash equivalents
     (1.3 )     15.4       18.2  
Cash and cash equivalents, January 1
     56.8       41.9       23.3  
Cash and cash equivalents, December 31
   $ 55.3     $ 56.8     $ 41.9  






See Notes to Consolidated Financial Statements.
*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.


ENTERPRISE GP HOLDINGS L.P.
(See Note 13 for Unit History, Detail of Changes in Limited Partners’ Equity and Accumulated Other Comprehensive Income (Loss))
(Dollars in millions)

   
Enterprise GP Holdings L.P.
              
               
Accumulated
              
               
Other
              
   
Limited
    
General
    
Comprehensive
    
Noncontrolling
        
   
Partners
    
Partner
    
Income (Loss)
    
Interest
    
Total
  
Balance, December 31, 2006*
   $ 1,418.8     $ **     $ 0.5     $ 7,549.7     $ 8,969.0  
Net income
     109.0       **       --       653.0       762.0  
Operating lease expenses paid by EPCO
     0.1       --       --       2.0       2.1  
Cash distributions paid to partners
     (159.0 )     **       --       --       (159.0 )
Cash distributions to former owners of TEPPCO GP interests
     (29.8 )     --       --       --       (29.8 )
Net cash proceeds from issuance of Units
     739.4       --       --       --       739.4  
Cash distributions paid to noncontrolling interest
     --       --       --       (1,073.9 )     (1,073.9 )
Cash contributions from noncontrolling interest
     --       --       --       372.7       372.7  
Repurchase of restricted units and options by subsidiary
     --       --       --       (1.6 )     (1.6 )
Amortization of equity awards
     0.6       --       --       10.4       11.0  
Foreign currency translation adjustment
     --       --       0.1       1.9       2.0  
Cash flow hedges
     --       --       (19.2 )     (41.7 )     (60.9 )
Proportionate share of other comprehensive loss of
     unconsolidated affiliates
     --       --       (3.8 )     --       (3.8 )
Other
     --       --       0.1       1.0       1.1  
Balance, December 31, 2007*
     2,079.1       **       (22.3 )     7,473.5       9,530.3  
Net income
     164.0       **       --       981.1       1,145.1  
Operating lease expenses paid by EPCO
     0.1       --       --       1.9       2.0  
Cash distributions paid to partners
     (213.1 )     **       --       --       (213.1 )
Cash distributions paid to noncontrolling interest
     --       --       --       (1,182.1 )     (1,182.1 )
Cash contributions from noncontrolling interest
     --       --       --       446.4       446.4  
Acquisition of treasury units by subsidiary
     --       --       --       (1.9 )     (1.9 )
Issuance of units by subsidiary in connection with
an acquisition (see Note 10)
     --       --       --       186.6       186.6  
Amortization of equity awards
     1.1       --       --       13.1       14.2  
Acquisition of additional noncontrolling interests in affiliates
     --       --       --       (22.3 )     (22.3 )
Change in funded status of pension and postretirement plans,
 net of tax
     --       --       (0.1 )     (1.2 )     (1.3 )
Foreign currency translation adjustment
     --       --       (0.1 )     (2.4 )     (2.5 )
Cash flow hedges
     --       --       (20.8 )     (111.3 )     (132.1 )
Proportionate share of other comprehensive loss of
     unconsolidated affiliates
     --       --       (9.9 )     --       (9.9 )
Balance, December 31, 2008*
     2,031.2       **       (53.2 )     7,781.4       9,759.4  
Net income
     204.1       **       --       936.2       1,140.3  
Operating lease expenses paid by EPCO
     --       --       --       0.7       0.7  
Cash distributions paid to partners
     (266.7 )     **       --       --       (266.7 )
Cash distributions paid to noncontrolling interest
     --       --       --       (1,322.1 )     (1,322.1 )
Cash contributions from noncontrolling interest
     --       --       --       1,014.2       1,014.2  
Acquisition of treasury units by subsidiary
     --       --       --       (2.1 )     (2.1 )
Deconsolidation of Texas Offshore Port System
     --       --       --       (33.4 )     (33.4 )
Acquisition of interest in subsidiary
     --       --       --       10.3       10.3  
Amortization of equity awards
     3.8       --       --       20.8       24.6  
Foreign currency translation adjustment
     --       --       0.1       2.0       2.1  
Cash flow hedges
     --       --       17.3       126.0       143.3  
Proportionate share of other comprehensive income of
     unconsolidated affiliates
     --       --       2.5       --       2.5  
Balance, December 31, 2009
   $ 1,972.4     $ **     $ (33.3 )   $ 8,534.0     $ 10,473.1  

** Amount is negligible.


See Notes to Consolidated Financial Statements.
*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.


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 millions of dollars.

SIGNIFICANT RELATIONSHIPS REFERENCED IN THESE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise GP Holdings” or the “Partnership” are intended to mean the business and operations of Enterprise GP Holdings L.P. and its consolidated subsidiaries.

References to the “Parent Company” mean Enterprise GP Holdings L.P., individually as the parent company, and not on a consolidated basis.  References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of the Parent Company and a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which are owned by Dan L. Duncan.

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., 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,” and its consolidated subsidiaries.  Enterprise Products Partners has no business activities outside those conducted by its operating subsidiary, Enterprise Products Operating LLC (“EPO”).  On October 26, 2009, Enterprise Products Partners completed the mergers of TEPPCO Partners, L.P. (“TEPPCO”) and Texas Eastern Products Pipeline Company, LLC (“TEPPCO GP”) (such related mergers referred to herein individually and together as the “TEPPCO Merger”).  References to “EPGP” refer to Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners.  EPGP is owned by the Parent Company.

References to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a consolidated subsidiary of EPO.  Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.”  References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and wholly owned by EPO.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”).  Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.”  ETP is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETP.”  The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”).  The Parent Company owns noncontrolling interests in both Energy Transfer Equity and LE GP that it accounts for using the equity method of accounting.

References to “EPCO” mean Enterprise Products Company (formerly EPCO, Inc.) and its privately held affiliates. The Parent Company, EPE Holdings, Enterprise Products Partners, EPO, EPGP, Duncan Energy Partners and DEP GP are affiliates under the common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.  We do not control Energy Transfer Equity or LE GP.

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”), Enterprise Unit L.P. (“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of which are privately held affiliates of EPCO.


Note 1.  Partnership Organization and Basis of Presentation

Partnership Organization

The Parent Company is a publicly traded Delaware limited partnership, the limited partnership interests (the “Units”) of which are listed on the NYSE under the ticker symbol “EPE.”  Our business consists of the ownership of general and limited partner interests of publicly traded partnerships engaged in


the midstream energy industry and related businesses.  Our goal is to increase cash distributions to unitholders.  The Parent Company is owned 99.99% by its limited partners and 0.01% by its general partner, EPE Holdings.

Basis of Presentation

Our consolidated financial statements and business segments were recast in connection with the TEPPCO Merger. On October 26, 2009, the related mergers of wholly owned subsidiaries of Enterprise Products Partners with TEPPCO and TEPPCO GP were completed.  Under terms of the merger agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners, and each of TEPPCO’s unitholders, except for a privately held affiliate of EPCO, were entitled to receive 1.24 common units of Enterprise Products Partners for each TEPPCO unit.  In total, Enterprise Products Partners issued an aggregate of 126,932,318 common units and 4,520,431 Class B units (described below) as consideration in the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership interests.  TEPPCO’s units, which had been trading on the NYSE under the ticker symbol “TPP,” have been delisted and are no longer publicly traded.  On October 27, 2009, the TEPPCO and TEPPCO GP equity interests were contributed by Enterprise Products Partners to EPO, and TEPPCO and TEPPCO GP became wholly owned subsidiaries of EPO.

A privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based on the 1.24 exchange rate, for 4,520,431 Class B units of Enterprise Products Partners in lieu of common units.  The Class B units are not entitled to regular quarterly cash distributions for the first sixteen quarters following the closing date of the merger.  The Class B units automatically convert into the same number of common units on the date immediately following the payment date for the sixteenth quarterly distribution following the closing date of the merger.  The Class B units are entitled to vote together with the common units as a single class on partnership matters and, except for the payment of distributions, have the same rights and privileges as Enterprise Products Partners’ common units.

Under the terms of the TEPPCO Merger agreements, the Parent Company received 1,331,681 common units of Enterprise Products Partners and an increase in the capital account of EPGP to maintain its 2% general partner interest in Enterprise Products Partners as consideration for 100% of the membership interests of TEPPCO GP.

Since Enterprise Products Partners, TEPPCO and TEPPCO GP are under common control of EPCO and its affiliates, the TEPPCO Merger was accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests.  The inclusion of TEPPCO and TEPPCO GP in our consolidated financial statements was effective January 1, 2005 since an affiliate of EPCO under common control with Enterprise Products Partners originally acquired ownership interests in TEPPCO GP in February 2005.

Our consolidated financial statements prior to the TEPPCO Merger reflect the combined financial information of Enterprise Products Partners, TEPPCO and TEPPCO GP on a 100% basis.  Third-party and related party ownership interests in TEPPCO and TEPPCO GP are reflected as “Former owners of TEPPCO,” a component of noncontrolling interest.

Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).  The financial statements of TEPPCO and TEPPCO GP were prepared from the separate accounting records maintained by TEPPCO and TEPPCO GP.  All intercompany balances and transactions have been eliminated in consolidation.

We revised our business segments and related disclosures to reflect the TEPPCO Merger.  Our reorganized business segments reflect the manner in which these businesses are managed and reviewed by the chief executive officer of our general partner.  Under our new business segment structure, we have six reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; (v) Petrochemical & Refined Products Services and (vi) Other Investments.


General Purpose Consolidated and Parent Company-Only Information.  In accordance with rules and regulations of the U.S Securities and Exchange Commission (“SEC”) and various other accounting standard-setting organizations, our general purpose financial statements reflect the consolidation of the financial information of businesses that we control through the ownership of general partner interests (e.g., Enterprise Products Partners).  Our general purpose consolidated financial statements present those investments in which we do not have a controlling interest as unconsolidated affiliates (e.g., Energy Transfer Equity and LE GP).  As presented in our consolidated financial statements, noncontrolling interest reflects third-party and related party ownership of our consolidated subsidiaries, which include the third-party and related party unitholders of Enterprise Products Partners and Duncan Energy Partners other than the Parent Company.

In order for the unitholders of Enterprise GP Holdings L.P. and others to more fully understand the Parent Company’s business and financial statements on a standalone basis, Note 22 includes information devoted exclusively to the Parent Company apart from that of our consolidated Partnership.  A key difference between the non-consolidated Parent Company financial information and those of our consolidated Partnership is that the Parent Company views each of its investments (e.g., in Enterprise Products Partners and Energy Transfer Equity) as unconsolidated affiliates and records its share of the net income of each as equity income in the Parent Company income information.  In accordance with GAAP, we eliminate the equity income related to Enterprise Products Partners in the preparation of our consolidated financial statements.

Presentation of Investments.  The Parent Company owns common units of Enterprise Products Partners and 100% of the membership interests of EPGP, which is entitled to 2% of the cash distributions paid by Enterprise Products Partners as well as the associated incentive distribution rights (“IDRs”) of Enterprise Products Partners.  At December 31, 2009 and 2008, the Parent Company owned 21,167,783 and 13,670,925 common units, respectively, of Enterprise Products Partners.

The Parent Company owns 38,976,090 common units of Energy Transfer Equity.  In addition, at December 31, 2009 and 2008, the Parent Company owned approximately 40.6% and 34.9%, respectively, of the membership interests of LE GP.  Energy Transfer Equity owns limited partner interests and the general partner interest of ETP.  We account for our investments in Energy Transfer Equity and LE GP using the equity method of accounting.  See Note 9 for additional information regarding these unconsolidated affiliates.

In May 2007, private company affiliates of EPCO contributed equity interests in TEPPCO and TEPPCO GP to the Parent Company.  As a result of such contributions, the Parent Company owned 4,400,000 units of TEPPCO and all of the membership interests of TEPPCO GP, which was entitled to 2% of the cash distributions of TEPPCO as well as the IDRs of TEPPCO.  On October 26, 2009, the TEPPCO Merger was completed and TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners.  As a result, the Parent Company’s ownership interests in the TEPPCO units were converted to 5,456,000 common units of Enterprise Products Partners.  In addition, the Parent Company’s membership interests in TEPPCO GP were exchanged for (i) 1,331,681 common units of Enterprise Products Partners and (ii) EPGP (on behalf of the Parent Company as a wholly owned subsidiary of the Parent Company) was credited in its Enterprise Products Partners’ capital account an amount to maintain its 2% general partner interest in Enterprise Products Partners.


Note 2.  Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts.  Our procedure for determining the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers.  In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy


proceedings and similar financial difficulties.  On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses.  Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts.

The following table presents the activity of our allowance for doubtful accounts for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Balance at beginning of period
   $ 17.7     $ 21.8     $ 23.5  
Charges to expense
     0.1       3.5       2.6  
Payments
     (1.0 )     (7.6 )     (4.3 )
Balance at end of period
   $ 16.8     $ 17.7     $ 21.8  

See “Credit Risk Due to Industry Concentrations” in Note 19 for additional information.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.

Consolidation Policy

Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions.  We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership.  We evaluate our financial interests in business enterprises 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.  Third-party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests.  See Note 13 for information regarding noncontrolling interest.

If the entity 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 entity’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 entity’s operating and financial policies.  In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts.

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

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur.  Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment.  In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.


If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements.  If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Current Assets and Current Liabilities

We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and liabilities, respectively.

Deferred Revenues

Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.  At December 31, 2009 and 2008, deferred revenues totaled $106.8 million and $118.5 million, respectively, and were recorded as a component of other current and long-term liabilities, as appropriate, on our Consolidated Balance Sheets.  See Note 4 for information regarding our revenue recognition policies.

Derivative Instruments

We use derivative instruments such as swaps, forwards and other contracts to manage price risks associated with inventories, firm commitments, interest rates, foreign currency and certain anticipated transactions.  To qualify for hedge accounting, the item to be hedged must expose us to risk and the related derivative instrument must reduce that exposure and meet specific documentation requirements.  We formally designate a derivative instrument as a hedge and document and assess the effectiveness of the hedge at inception and thereafter on a quarterly basis.  We also apply the normal purchases/normal sales exception for certain of our derivative instruments, which precludes the recognition of changes in mark-to-market value for these items on the balance sheet or income statement.  Revenues and costs for these transactions are recognized when volumes are physically delivered or received.  See Note 6 for additional information regarding our derivative instruments and related hedging activities.

Earnings Per Unit

Earnings per unit (“EPU”) is based on the amount of income allocated to limited partners and the weighted-average number of units outstanding during the period.  See Note 17 for additional information regarding our earnings per unit.

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.  Expenditures to mitigate or prevent future environmental contamination are capitalized.  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.  At December 31, 2009, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.



The following table presents the activity of our environmental reserves for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Balance at beginning of period
   $ 22.3     $ 30.5     $ 26.0  
Charges to expense
     1.9       3.1       4.2  
Acquisition-related additions and other
     --       2.9       6.7  
Payments
     (5.1 )     (8.3 )     (6.1 )
Adjustments
     (2.4 )     (5.9 )     (0.3 )
Balance at end of period
   $ 16.7     $ 22.3     $ 30.5  

At December 31, 2009 and 2008, $6.4 million and $5.3 million, respectively, of our environmental reserves were classified as current liabilities.

Equity Awards

See Note 5 for information regarding our accounting for equity awards.

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.

Exchange Contracts

Exchanges are contractual agreements for the movements of natural gas liquids (“NGLs”) and certain petrochemical products between parties to satisfy timing and logistical needs of the parties.  Net exchange volumes borrowed from us under such agreements are valued at market-based prices and included in accounts receivable.  Net exchange volumes loaned to us under such agreements are valued at market-based prices and accrued as a liability in accrued product payables.

Receivables and payables arising from exchange transactions are settled with movements of products rather than with cash.  When payment or receipt of monetary consideration is required for product differentials and service costs, such items are recognized in our consolidated financial statements on a net basis.

Fair Value Information

Cash and cash equivalents and restricted cash, accounts receivable, accounts payable and accrued expenses, and other current liabilities are carried at amounts which reasonably approximate their fair values due to their short-term nature.  The estimated fair values of our fixed-rate debt are based on quoted market prices for such debt or debt of similar terms and maturities.  The carrying amounts of our variable-rate debt obligations reasonably approximate their fair values due to their variable interest rates.  See Note 6 for fair value information associated with our derivative instruments.










The following table presents the estimated fair values of our financial instruments at the dates indicated:

   
December 31, 2009
    
December 31, 2008
  
   
Carrying
    
Fair
    
Carrying
    
Fair
  
Financial Instruments
  
Value
    
Value
    
Value
    
Value
  
Financial assets:
                        
Cash and cash equivalents and restricted cash
   $ 118.9     $ 118.9     $ 260.6     $ 260.6  
Accounts receivable
     3,137.4       3,137.4       2,028.7       2,028.7  
Financial liabilities:
                                
Accounts payable and accrued expenses
     4,214.6       4,214.6       2,507.8       2,507.8  
Other current liabilities
     233.2       233.2       292.2       292.2  
Fixed-rate debt (principal amount)
     10,586.7       11,056.2       9,704.3       8,192.2  
Variable-rate debt
     1,791.8       1,791.8       2,935.5       2,935.5  

Foreign Currency Translation

We own an NGL marketing business located in Canada.  The financial statements of this foreign subsidiary are translated into U.S. dollars from the Canadian dollar, which is the subsidiary’s functional currency, using the current rate method.  Its assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, while revenue and expense items are translated at average rates of exchange during the reporting period.  Exchange gains and losses arising from foreign currency translation adjustments are reflected as separate components of accumulated other comprehensive loss (“AOCI”) in the accompanying Consolidated Balance Sheets.  Our net cash flows from this Canadian subsidiary may be adversely affected by changes in foreign currency exchange rates.  See Note 6 for information regarding our foreign currency derivative instruments.

Impairment Testing for Goodwill

Our goodwill amounts are assessed for impairment (i) on a routine annual basis or (ii) when impairment indicators are present.  If such indicators occur (e.g., the loss of a significant customer, economic obsolescence of plant assets, etc.), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its book value.  If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required.  If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value.  See Note 6 for information regarding impairment charges related to goodwill during 2009.

Impairment Testing for Long-Lived Assets

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.

Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values.  The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset.  If the asset carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded.  Fair value is defined as the amount at which an asset or liability could be bought or settled in an arm’s length transaction.  We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.  See Note 6 for information regarding impairment charges related to long-lived assets during 2009.




Impairment Testing for Unconsolidated Affiliates

We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline.  Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry.  In the event we determine that the loss in value of an investment is other than a temporary decline, we record a charge to equity earnings to adjust the carrying value of the investment to its estimated fair value.  See Note 9 for information regarding impairment charges related to our unconsolidated affiliates during 2007.

Income Taxes

Provision for income taxes is primarily applicable to our state tax obligations under the Revised Texas Franchise Tax and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie Pipeline Company (“Dixie”), both of which are consolidated subsidiaries of ours.  Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

Since we are structured as a pass-through entity, we are not subject to federal income taxes.  As a result, our partners are individually responsible for paying federal income taxes on their share of our taxable income.  Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.

We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable.  If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement.  See Note 16 for additional information regarding our income taxes.

Inventories

Inventories primarily consist of natural gas, NGLs, crude oil, refined products, lubrication oils and certain petrochemical products that are valued at the lower of average cost or market (“LCM”).  We capitalize, as a cost of inventory, shipping and handling charges associated with such purchase volumes, terminal storage fees, vessel inspection costs, demurrage charges and other related costs.  As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses.  Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred.  See Note 7 for additional information regarding our inventories.

Natural Gas Imbalances

In the natural gas pipeline transportation business, imbalances frequently result from differences in natural gas volumes received from and delivered to our customers.  Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period.  We have various fee-based agreements with customers to transport their natural gas through our pipelines.  Our customers retain ownership of their natural gas shipped through our pipelines.  As such, our pipeline transportation activities are not intended to create physical volume differences that would result in significant accounting or economic events for either our customers or us during the course of the arrangement.

We settle pipeline gas imbalances through either (i) physical delivery of in-kind gas or (ii) in cash.  These settlements follow contractual guidelines or common industry practices.  As imbalances occur, they may be settled: (i) on a monthly basis, (ii) at the end of the agreement or (iii) in accordance with industry practice, including negotiated settlements.  Certain of our natural gas pipelines have a regulated tariff rate mechanism requiring customer imbalance settlements each month at current market prices.


However, the vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to or received from a customer.  Such in-kind deliveries are ongoing and take place over several periods.  In some cases, settlements of imbalances built up over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time.  For those gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which we believe is representative of the value of the imbalances upon final settlement.  Changes in natural gas prices may impact our estimates.

The following table presents our natural gas imbalance receivables/payables at the dates indicated:

   
December 31,
  
   
2009
    
2008
  
Natural gas imbalance receivables (1)
   $ 24.1     $ 63.4  
Natural gas imbalance payables (2)
     19.0       50.8  
(1)   Reflected as a component of “Accounts and notes receivable – trade” on our Consolidated Balance Sheets.
(2)   Reflected as a component of “Accrued product payables” on our Consolidated Balance Sheets.
  

Property, Plant and Equipment

Property, plant and equipment is recorded at cost.  Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred.  When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in the results of operations for the respective period.

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits.  The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of the assets.  Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets.  At the time we place our assets in service, we believe such assumptions are reasonable.  Under our depreciation policy for midstream energy assets, the remaining economic lives of such assets are limited to the estimated life of the natural resource basins (based on proved reserves at the time of the analysis) from which such assets derive their throughput or processing volumes.  Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration.  Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes.

                Leasehold improvements are recorded as a component of property, plant and equipment.  The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of the remaining lease term or the estimated useful lives of the improvements.  We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms.
          
Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would change our depreciation amounts prospectively.  Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values; or (iv) significant changes in the forecast life of proved reserves of applicable resource basins, if any.  See Note 8 for additional information regarding our property, plant and equipment.

Certain of our plant operations entail periodic planned outages for major maintenance activities.  These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items.  We use the expense-as-


incurred method for our planned major maintenance activities; however, the cost of annual planned major maintenance projects are deferred and recognized ratably over the remaining portion of the calendar year in which such projects occur.

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation.  When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset.  Over time, the liability is accreted to its present value (accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset.  We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and related physical natural gas and NGL purchases.  Additional cash may be restricted to maintain this portfolio as commodity prices fluctuate or deposit requirements change.  At December 31, 2009 and 2008, our restricted cash amounts were $63.6 million and $203.8 million, respectively.  See Note 6 for information regarding derivative instruments and hedging activities.

Revenue Recognition

In general, we recognize revenue from our customers when all of the following criteria are met:  (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectability is reasonably assured.  See Note 4 for additional information regarding our revenue recognition policies.


Note 3.  Recent Accounting Developments

The accounting standard setting bodies have recently issued the following guidance that will or may affect our future financial statements:

Fair Value Measurements.  In January 2010, the Financial Accounting Standards Board (“FASB”) issued new guidance to improve disclosures about fair value measurements.  This new guidance requires the following:

§  
Effective with the first quarter of 2010, additional disclosures will be required regarding the reporting of transfers of fair value information between the three levels of the fair value hierarchy (i.e., Levels 1, 2 and 3).

§  
Effective with the first quarter of 2011, companies will need to present purchases, sales, issuances and settlements whose fair values are based on unobservable inputs on a gross basis.

Other than requiring enhanced fair value disclosures, we do not expect our adoption of this guidance will have a material impact on our consolidated financial statements.

Consolidation of Variable Interest Entities.  In June 2009, the FASB amended its consolidation guidance regarding variable interest entities.  In general, this new guidance places more emphasis on a qualitative analysis, rather than a purely quantitative approach, in determining which company should consolidate a variable interest entity.  Our adoption of this guidance on January 1, 2010 did not have any impact on our consolidated financial statements.
 
 




Note 4.  Revenue Recognition

The following information provides a general description of our underlying revenue recognition policies by business segment:

NGL Pipelines & Services

Our NGL Pipelines & Services include our (i) natural gas processing business and related NGL marketing activities; (ii) NGL pipelines aggregating approximately 16,300 miles; (iii) NGL and related product storage and terminal facilities and (iv) NGL fractionation facilities.  This segment also includes our import and export terminal operations.

In our natural gas processing business, we enter into percent-of-liquids contracts, percent-of-proceeds contracts, fee-based contracts, hybrid-contracts (i.e. a combination of percent-of-liquids and fee-based contract terms), keepwhole contracts and margin-band contracts.  Under keepwhole and margin-band contracts, we take ownership of mixed NGLs extracted from the producer’s natural gas stream and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts.  In the same way, revenue is recognized under our percent-of-liquids contracts except that the volume of NGLs we extract and sell is less than the total amount of NGLs extracted from the producers’ natural gas.  Under a percent-of-liquids contract, the producer retains title to the remaining percentage of mixed NGLs we extract.  Under a percent-of-proceeds contract, we share in the proceeds generated from the sale of the mixed NGLs we extract on the producer’s behalf.  If a cash fee for natural gas processing services is stipulated by the contract, we record revenue when the natural gas has been processed and delivered to the producer.

Our NGL marketing activities generate revenues from the sale and delivery of NGLs obtained through our processing activities and spot and contract purchases from third parties.  Revenues from these sales contracts are recognized when the NGLs are delivered to customers.  In general, sales prices referenced in these contracts are market-based and may include pricing differentials for such factors as delivery location.

Under our NGL pipeline transportation contracts and tariffs, revenue is recognized when volumes have been delivered to customers.  Revenue from these contracts and tariffs is generally based upon a fixed fee per gallon of liquids transported multiplied by the volume delivered.  Transportation fees charged under these arrangements are either contractual or regulated by governmental agencies such as the Federal Energy Regulatory Commission (“FERC”).

We collect storage revenues under our NGL and related product storage contracts based on the number of days a customer has volumes in storage multiplied by a storage rate (as defined in each contract).  Under these contracts, revenue is recognized ratably over the length of the storage period.  With respect to capacity reservation agreements, we collect a fee for reserving storage capacity for certain customers in our underground storage wells.  Under these agreements, revenue is recognized ratably over the specified reservation period.  Excess storage fees are collected when customers exceed their reservation amounts and are recognized in the period of occurrence.  In addition, we charge other customers throughput fees based on volumes delivered into and subsequently withdrawn from storage, which are recognized as the service is provided.

We enter into fee-based arrangements and percent-of-liquids contracts for the NGL fractionation services we provide to customers.  Under such fee-based arrangements, revenue is recognized in the period services are provided.  Such fee-based arrangements typically include a base-processing fee (usually stated in cents per gallon) that is contractually subject to adjustment for changes in certain fractionation expenses (e.g. natural gas fuel costs).  Certain of our NGL fractionation facilities generate revenues using percent-of-liquids contracts.  Such contracts allow us to retain a contractually determined percentage of the customer’s fractionated NGL products as payment for services rendered.  Revenue is recognized from such arrangements when we sell and deliver the retained NGLs to customers.


Revenues from product terminaling activities are recorded in the period such services are provided.  Customers are typically billed a fee per unit of volume loaded or unloaded.  With respect to our export terminal operations, revenues may also include demand payments charged to customers who reserve the use of our export facilities and later fail to use them.  Demand fee revenues are recognized when the customer fails to utilize the specified export facility as required by contract.

Onshore Natural Gas Pipelines & Services

Our Onshore Natural Gas Pipelines & Services include approximately 19,200 miles of onshore natural gas pipeline systems that provide for the gathering and transportation of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.  We own two salt dome natural gas storage facilities located in Mississippi and lease natural gas storage facilities located in Texas and Louisiana.  This segment also includes our natural gas marketing activities.

Our onshore natural gas pipelines typically generate revenues from transportation agreements where shippers are billed a fee per unit of volume transported (typically per million British thermal units, or “MMBtu”) multiplied by the volume gathered or delivered.  The transportation fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC.  Certain of our onshore natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractually stated fee based on the level of throughput capacity reserved in our pipelines whether or not the shipper actually utilizes such capacity.  Revenues under firm capacity reservation agreements are recognized in the period the services are provided.

Revenues from natural gas storage contracts typically have two components: (i) monthly demand payments, which are associated with a customer’s storage capacity reservations, and (ii) storage fees per unit of volume stored at our facilities.  Revenues from demand payments are recognized during the period the customer reserves capacity.  Revenues from storage fees are recognized in the period the services are provided.

Our natural gas marketing activities generate revenues from the sale and delivery of natural gas purchased from third parties on the open market.  Revenues from these sales contracts are recognized when the natural gas is delivered to customers.  In general, sales prices referenced in these contracts are market-based and may include pricing differentials for such factors as delivery location.

Onshore Crude Oil Pipelines & Services

Our Onshore Crude Oil Pipelines & Services include approximately 4,400 miles of onshore crude oil pipelines and 10.5 million barrels (“MMBbls”) of above-ground storage tank capacity.  This segment includes our crude oil marketing activities.

Revenue from crude oil transportation is generally based upon a fixed fee per barrel transported multiplied by the volume delivered.  The transportation fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC.  Revenues associated with these arrangements are recognized when volumes have been delivered.

Under our crude oil terminaling agreements, we charge customers for crude oil storage based on the number of days a customer has volumes in storage multiplied by a contractual storage rate.  Under these contracts, revenue is recognized ratably over the length of the storage period.  With respect to storage capacity reservation agreements, we collect a fee for reserving storage capacity for customers at our terminals.  Under these agreements, revenue is recognized ratably over the specified reservation period.  In addition, we charge our customers throughput (or “pumpover”) fees based on volumes withdrawn from our terminals.  Crude oil storage revenues are recognized ratably over the length of the storage period.  Revenues are also generated from fee-based trade documentation services and are recognized as services are completed.


Our crude oil marketing activities generate revenues from the sale and delivery of crude oil obtained from producers or on the open market.  These sales contracts generally settle with the physical delivery of crude oil to customers.  In general, the sales prices referenced in these contracts are market-based and may include pricing differentials for such factors as delivery location.

Offshore Pipelines & Services

Our Offshore Pipelines & Services include our (i) offshore natural gas pipelines, (ii) offshore Gulf of Mexico crude oil pipeline systems and (iii) six multi-purpose offshore hub platforms which serve production areas including some of the most active drilling and development regions in the Gulf of Mexico.

Revenues from our offshore pipelines are derived from fee-based agreements whereby the customer is charged a fee per unit of volume gathered or transported (typically per MMBtu of natural gas or per barrel of crude oil) multiplied by the volume delivered.  Revenues associated with these fee-based contracts and tariffs are recognized when volumes have been delivered.

Revenues from offshore platform services generally consist of demand fees and commodity charges.  Revenues from platform services are recognized in the period the services are provided.  Demand fees represent charges to customers served by our offshore platforms regardless of the volume the customer actually delivers to the platform.  Revenues from commodity charges are based on a fixed-fee per unit of volume delivered to the platform (typically per million cubic feet of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered.  Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.  Our Independence Hub offshore platform earns a significant amount of demand revenues.  The Independence Hub platform will earn $54.6 million of demand fees annually through March 2012.

Petrochemical & Refined Products Services

Our Petrochemical & Refined Products Services consist of (i) propylene fractionation plants and related activities, (ii) butane isomerization facilities, (iii) an octane enhancement facility, (iv) refined products pipelines, including our Products Pipeline System, and related activities and (v) marine transportation assets and other services.

Our propylene fractionation and butane isomerization facilities generate revenues through fee-based arrangements, which typically include a base-processing fee per gallon (or other unit of measurement) subject to adjustment for changes in natural gas, electricity and labor costs, which are the primary costs of propylene fractionation and butane isomerization.  Revenues resulting from such agreements are recognized in the period the services are provided.
 
Our petrochemical marketing activities generate revenues from the sale and delivery of products obtained through our propylene fractionation activities and purchases of petrochemical products from third parties on the open market.  Revenues from these sales contracts are recognized when such products are delivered to customers.  In general, we sell our petrochemical products at market-based prices, which may include pricing differentials for such factors as delivery location.

Our refined products pipelines, including our Products Pipeline System, generate revenues through fee-based contracts or tariffs as customers are billed a fixed fee per barrel of liquids transported multiplied by the volume delivered.  Transportation fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC.  Revenues associated with these fee-based contracts and tariffs are recognized when volumes have been delivered.  Revenues from our refined products storage facilities are based on the number of days a customer has volumes in storage multiplied by a contractual storage rate.  Under these contracts, revenue is recognized ratably over the length of the storage period.  Revenues from product terminaling activities are recorded in the period such services are provided.  Customers are typically billed a fee per unit of volume loaded.


Revenue is also generated from the provision of inland and offshore transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges.  Under our marine services transportation contracts, revenue is recognized over the transit time of individual tows as determined on an individual contract basis, which is generally less than ten days in duration.  Revenue from these contracts is typically based on set day rates or a set fee per cargo movement.  Most of the marine services transportation contracts include escalation provisions to recover increased operating costs such as incremental increases in labor.  The costs of fuel, substantially all of which is a pass through expense, and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts.

The results of operations from the distribution of lubrication oils and specialty chemicals and the bulk transportation of fuels are dependent on the sales price or transportation fees that we charge our customers.  Revenue is recognized for sales transactions and transportation arrangements when the product is delivered.


Note 5.  Equity-based Awards

The following table summarizes the expense we recognized in connection with equity-based awards for the periods presented:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Restricted unit awards (1)
   $ 13.6     $ 11.3     $ 8.9  
Unit option awards (1)
     2.0       0.7       4.5  
Unit appreciation rights (2)
     --       --       0.2  
Phantom units (2)
     0.2       (0.5 )     2.3  
Profits interests awards (1)
     9.2       6.6       4.4  
Total compensation expense
   $ 25.0     $ 18.1     $ 20.3  
                         
(1)   Accounted for as equity-classified awards.
(2)   Accounted for as liability-classified awards.
  

The fair value of an equity-classified award (e.g., 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 (e.g., 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-classified awards are settled in cash upon vesting.

At December 31, 2009, our active long-term incentive plans are the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”), the TEPPCO 1999 Phantom Unit Retention Plan (“1999 Plan”), the Enterprise Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”) and the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008 Plan”).  Two plans were dissolved during 2009:  TEPPCO 2000 Long-Term Incentive Plan (“2000 Plan”) and TEPPCO 2005 Phantom Unit Plan (“2005 Plan”).

The 1998 Plan provides for awards of Enterprise Products Partners’ common units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us.  Awards under the 1998 Plan may be granted in the form of unit options, restricted units, phantom units, UARs and distribution equivalent rights (“DERs”).  Up to 7,000,000 of Enterprise Products Partners’ common units may be issued as awards under the 1998 Plan.  After giving effect to awards granted under the plan through December 31, 2009, a total of 652,543 additional common units could be issued.

The 1999 Plan provided key employees of EPCO who work on our behalf with phantom unit awards.  This plan terminated in January 2010.


The 2006 Plan currently provides for awards of Enterprise Products Partners’ common units (formerly of TEPPCO units) and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us.  Awards under the 2006 Plan may be granted in the form of unit options, restricted units, phantom units, UARs and DERs.  Effective upon the consummation of the TEPPCO Merger (see Note 1), Enterprise Products Partners assumed the vested and unvested options, restricted units and UAR awards outstanding on October 26, 2009 under the 2006 Plan and converted them into Enterprise Products Partners’ options, restricted units and UAR awards based on the TEPPCO Merger exchange ratio.  The vesting terms of each award and other provisions of the plan remain unchanged.

 The 2008 Plan provides for awards of Enterprise Products Partners’ 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 Plan may be granted in the form of unit options, restricted units, phantom units, UARs and DERs.  Up to 10,000,000 of Enterprise Products Partners’ common units may be issued as awards under the 2008 Plan.  After giving effect to awards granted under the plan through December 31, 2009, a total of 7,865,000 additional common units could be issued.

An allocated portion of the fair value of these long-term incentive plan equity-based awards is charged to us under the administrative services agreement (“ASA”).  See Note 15 for a general description of the ASA with EPCO.  With the exception of certain amounts recorded in connection with EPCO Unit, as defined later in this note, we are not responsible for reimbursing EPCO for any expenses associated with such awards.  We recognize an expense for our allocated share of the grant date fair value of such awards, with an offsetting amount recorded in equity.  Beginning in February 2009, the ASA was amended to provide that we and other affiliates of EPCO will reimburse EPCO for our allocated share of distributions of cash or securities made to the Class B limited partners of EPCO Unit.  Our reimbursements to EPCO during 2009 in connection with EPCO Unit were $0.7 million.

On December 10, 2009, the board of directors of DEP GP unanimously approved a resolution adopting both the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan (“2010 Plan”) and the DEP Unit Purchase Plan (“DEP EUPP”).  The 2010 Plan provides for awards of options to purchase Duncan Energy Partners’ common units, restricted common units, UARs, phantom units and DERs to employees, directors or consultants providing services to Duncan Energy Partners.  The DEP EUPP provides eligible employees the opportunity to purchase common units at a discount through withholdings from eligible compensation.  On December 30, 2009, the action taken by the board of directors of DEP GP regarding the plans was approved by written consent of EPO, which held approximately 58.6% of Duncan Energy Partners’ outstanding common units as of that date.  Because EPO held a majority of Duncan Energy Partners’ common units as of December 30, 2009, no other votes were necessary to adopt the plans.  In February 2010, Duncan Energy Partners filed a registration statement with the SEC authorizing the issuance of up to 500,000 common units in connection with the 2010 Plan and 500,000 common units in connection with the DEP EUPP.  The plans became effective on February 11, 2010. 

Restricted Unit Awards

Restricted unit awards allow recipients to acquire common units of Enterprise Products Partners (at no cost to the recipient) once a defined vesting period expires, subject to customary forfeiture provisions.  The restrictions on such awards generally lapse four years from the date of grant.  The fair value of restricted units is based on the market price per unit of the underlying security on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures.  As used in the context of our long-term incentive plans, the term “restricted unit” represents a time-vested unit.  Such awards are non-vested until the required service period expires.







The following table summarizes information regarding our restricted unit awards for the periods indicated:

         
Weighted-
  
         
Average Grant
  
   
Number of
    
Date Fair Value
  
   
Units
    
per Unit (1)
  
Restricted units at December 31, 2006
     1,105,237     $ 24.79  
Granted (2)
     738,040     $ 30.64  
Vested
     (4,884 )   $ 25.28  
Settled or forfeited (3)
     (149,853 )   $ 23.31  
Restricted units at December 31, 2007
     1,688,540     $ 27.23  
Granted (4)
     766,200     $ 30.73  
Vested
     (285,363 )   $ 23.11  
Forfeited
     (88,777 )   $ 26.98  
Restricted units at December 31, 2008
     2,080,600     $ 29.09  
Granted (5)
     1,025,650     $ 24.89  
Vested
     (281,500 )   $ 26.70  
Forfeited
     (411,884 )   $ 28.37  
Awards assumed in connection with TEPPCO Merger
     308,016     $ 27.64  
Restricted units at December 31, 2009
     2,720,882     $ 27.70  
                 
(1)   Determined by dividing the aggregate grant date fair value of awards before an allowance for forfeitures by the number of awards issued. With respect to restricted unit awards assumed in connection with the TEPPCO Merger, the weighted-average grant date fair value per unit was determined by dividing the aggregate grant date fair value of the assumed awards before an allowance for forfeitures by the number of awards assumed.
(2)   Aggregate grant date fair value of restricted unit awards issued during 2007 was $22.6 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $28.00 to $31.83 per unit. Estimated forfeiture rates ranging between 4.6% and 17% were applied to these awards.
(3)   Reflects the settlement of 113,053 restricted units in connection with the resignation of EPGP’s former chief executive officer.
(4)   Aggregate grant date fair value of restricted unit awards issued during 2008 was $23.5 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $25.00 to $32.31 per unit. An estimated forfeiture rate of 17% was applied to these awards.
(5)   Aggregate grant date fair value of restricted unit awards issued during 2009 was $25.5 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $20.08 to $28.73 per unit. Estimated forfeiture rates ranging between 4.6% and 17% were applied to these awards.
  

Each recipient is also entitled to cash distributions equal to the product of the number of restricted units outstanding for the participant and the cash distribution per unit paid by the respective issuer.  Since restricted units are issued securities of Enterprise Products Partners, such distributions are reflected as a component of cash distributions to noncontrolling interest as shown on our Statements of Consolidated Cash Flows.  The following table presents cash distributions with respect to Enterprise Products Partners’ restricted units and supplemental information regarding its restricted units for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Cash distributions paid to restricted unit holders
   $ 5.2     $ 3.9     $ 2.6  
Total fair value of restricted unit awards vesting during period
   $ 7.5     $ 6.6     $ 0.1  

On a gross basis, the total unrecognized compensation cost of such awards was $37.9 million at December 31, 2009, of which our share is currently estimated to be $37.3 million.  We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.3 years.







Unit Option Awards

Certain of our long-term incentive plans provide for the issuance of non-qualified incentive options to purchase a fixed number of Enterprise Products Partners’ common units.  When issued, the exercise price of each option grant may be no less than the market price of the underlying security on the date of grant.  In general, options granted under the EPCO plans have a vesting period of four years and remain exercisable for five to ten years, as applicable, from the date of grant.

The fair value of each unit option is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including expected life of the options, risk-free interest rates, expected distribution yield on Enterprise Products Partners’ common units, and expected unit price volatility of Enterprise Products Partners’ common units.  In general, our assumption of expected life of the options represents the period of time that the options are expected to be outstanding based on an analysis of historical option activity.  Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable terms.  The expected distribution yield and unit price volatility is estimated based on several factors, which include an analysis of Enterprise Products Partners’ historical unit price volatility and distribution yield over a period equal to the expected life of the option.

During 2008, in response to changes in the federal tax code applicable to certain types of equity awards, Enterprise Products Partners amended the terms of certain of its outstanding unit options.  In general, the expiration dates of these awards were modified from May and August 2017 to December 2012.

In order to fund its unit option-related obligations, EPCO may purchase common units at fair value either in the open market or directly from Enterprise Products Partners.  When employees exercise unit options, Enterprise Products Partners reimburses EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.































The following table presents unit option activity under the EPCO plans 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, 2006
     2,416,000     $ 23.32              
Granted (2)
     895,000       30.63              
Exercised
     (256,000 )     19.26              
Settled or forfeited (3)
     (740,000 )     24.62              
Outstanding at December 31, 2007
     2,315,000       26.18              
Granted (4)
     795,000       30.93              
Exercised
     (61,500 )     20.38              
Forfeited
     (85,000 )     26.72              
Outstanding at December 31, 2008
     2,963,500       27.56              
Granted (5)
     1,460,000       23.46              
Exercised
     (261,000 )     19.61              
Forfeited
     (930,540 )     26.69              
Awards assumed in connection
    with TEPPCO Merger
     593,960       26.12              
Outstanding at December 31, 2009 (6)
     3,825,920       26.52       4.6     $ 2.8  
Options exercisable at:
                                
December 31, 2007
     335,000     $ 22.06       4.0     $ 3,.3  
December 31, 2008
     548,500     $ 21.47       4.1     $ --  
December 31, 2009 (6)
     447,500     $ 25.09       4.8     $ 2.8  
                                 
(1)   Aggregate intrinsic value reflects fully vested unit options at the date indicated.
(2)   Aggregate grant date fair value of these unit options issued during 2007 was $2.4 million based on the following assumptions: (i) a weighted-average grant date market price of our common units of $30.63 per unit; (ii) expected life of options of 7.0 years; (iii) weighted-average risk-free interest rate of 4.8%; (iv) weighted-average expected distribution yield on Enterprise Products Partners’ common units of 8.4% and (v) weighted-average expected unit price volatility on Enterprise Products Partners’ common units of 23.2%.
(3)   Includes the settlement of 710,000 options in connection with the resignation of EPGP’s former chief executive officer.
(4)   Aggregate grant date fair value of these unit options issued during 2008 was $1.9 million based on the following assumptions: (i) a grant date market price of Enterprise Products Partners’ common units of $30.93 per unit; (ii) expected life of options of 4.7 years; (iii) risk-free interest rate of 3.3%; (iv) expected distribution yield on Enterprise Products Partners’ common units of 7.0% and (v) expected unit price volatility on Enterprise Products Partners’ common units of 19.8%. An estimated forfeiture rate of 17.0% was applied to awards granted during 2008.
(5)   Aggregate grant date fair value of these unit options issued during 2009 was $8.1 million based on the following assumptions: (i) a weighted-average grant date market price of Enterprise Products Partners’ common units of $23.46 per unit; (ii) weighted-average expected life of options of 4.8 years; (iii) weighted-average risk-free interest rate of 2.1%; (iv) weighted-average expected distribution yield on Enterprise Products Partners’ common units of 9.4% and (v) weighted-average expected unit price volatility on Enterprise Products Partners’ common units of 57.4%. An estimated forfeiture rate of 17.0% was applied to awards granted during 2009.
(6)   Enterprise Products Partners was committed to issue 3,825,920 and 2,963,500 of its common units at December 31, 2009 and 2008, respectively, if all outstanding options awarded (as of these dates) were exercised. Of the option awards outstanding at December 31, 2009, an additional 410,000, 712,280, 736,000 and 1,520,140 are exercisable in 2010, 2012, 2013 and 2014, respectively.
  

The following table presents supplemental information regarding our unit options:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Total intrinsic value of option awards exercised during period
   $ 2.4     $ 0.6     $ 3.0  
Cash received from EPCO in connection with the
exercise of unit option awards
     1.7       0.7       7.5  
Option-related reimbursements to EPCO
     2.4       0.6       3.0  

On a gross basis, the total unrecognized compensation cost of such awards was $7.3 million at December 31, 2009 of which our share is currently estimated to be $7.0 million.  We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.9 years.


Profits Interests Awards

As long-term incentive arrangements, EPCO has granted its key employees who perform services on behalf of us, EPCO and other affiliated companies, “profits interests” in several limited partnerships (the “Employee Partnerships”), all of which are private company affiliates of EPCO.  At December 31, 2009, the Employee Partnerships are EPE Unit I, EPE Unit II, EPE Unit III, Enterprise Unit and EPCO Unit.  TEPPCO Unit L.P. and TEPPCO Unit II L.P. were dissolved during 2009.

Profits interests awards entitle each holder to participate in the expected long-term appreciation in value of the equity securities owned by each Employee Partnership.  The Employee Partnerships in which our named executive officers participate own either units of the Parent Company or Enterprise Products Partners or a combination of both.  The profits interests awards are subject to customary forfeiture provisions.

Each Employee Partnership has a single Class A limited partner, which is a privately held indirect subsidiary of EPCO, and a varying number of Class B limited partners.  At formation, the Class A limited partner either contributes cash or limited partner units it owns to the Employee Partnership.  If cash is contributed, the Employee Partnership uses these funds to acquire limited partner units on the open market.  In general, the Class A limited partner earns a preferred return (either fixed or variable depending on the partnership agreement) on its investment (or “Capital Base”) in the Employee Partnership and residual quarterly cash amounts, if any, are distributed to the Class B limited partners.  Upon liquidation, Employee Partnership assets having a fair market value equal to the Class A limited partner’s Capital Base, plus any preferred return for the period in which liquidation occurs, will be distributed to the Class A limited partner.  Any remaining assets will be distributed to the Class B limited partner(s) as a residual profits interest and are a factor of the appreciation in value of the partnership’s assets since its formation date.

The grant date fair value of each Employee Partnership is based on (i) the estimated value of the remaining assets, as determined using a Black-Scholes option pricing model, that would be distributed to the Class B limited partners upon dissolution of the Employee Partnership and (ii) the value, based on a discounted cash flow analysis using appropriate discount rates, of the residual quarterly cash amounts that the Class B limited partners are expected to receive over the life of the Employee Partnership.

The following table summarizes key elements of each Employee Partnership as of December 31, 2009.  As used in the table in reference to the description of assets, “EPE” means Enterprise GP Holdings L.P. and “EPD” means Enterprise Products Partners L.P.

   
Initial
Class A
      
   
Class A
Partner
  
Grant Date
Unrecognized
Employee
Description
Capital
Preferred
Liquidation
Fair Value
Compensation
Partnership
of Assets
Base
Return
     Date (1)
  of Awards
Cost
             
EPE Unit I
1,821,428 EPE units
$51.0 million
4.50%  to 5.725%
February
2016
$21.5 million
$12.1 million
             
EPE Unit II
40,725 EPE units
$1.5 million
4.50%  to 5.725%
February
2016
$0.4 million
$0.3 million
             
EPE Unit III
4,421,326 EPE units
$170.0 million
3.80%
February
2016
$42.8 million
$30.8 million
             
Enterprise Unit
881,836 EPE units
844,552 EPD units
$51.5 million
5.00%
February
2016
$6.5 million
$5.3 million
             
EPCO Unit
779,102 EPD units
$17.0 million
4.87%
February
2016
$8.1 million
$6.5 million
             
(1)   The liquidation date may be accelerated for change of control and other events as described in the underlying partnership agreements.



The total unrecognized compensation cost of the profits interests awards was $55.0 million at December 31, 2009 of which our share is currently estimated to be $47.6 million.  We expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 6.1 years.

In December 2009, the expected liquidation date for each Employee Partnership was extended to February 2016.  This modification follows a similar set of modifications made in July 2008 for EPE Unit I, EPE Unit II and EPE Unit III that extended liquidation dates as well as reduced the Class A limited partner’s preferred return rates.  These modifications are intended to align the interests of the employee partners of the Employee Partnerships with the long-term interests of EPCO and other unitholders in the relevant underlying publicly traded partnerships, which also hold indirectly a significant ownership interest in both us and our subsidiaries.

The following table presents the impact of modifications (e.g., extension of liquidation dates) and other changes on the aggregate grant date fair value (on an unallocated basis) of the Employee Partnerships for the periods presented.

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Aggregate grant date fair values at beginning of period
   $ 64.6     $ 35.4     $ 12.8  
New Employee Partnership grants (1,2)
     --       14.6       23.0  
Award modifications
     19.5       15.0       --  
Other adjustments, primarily forfeiture and regrant activity (2)
     (4.8 )     (0.4 )     (0.4 )
Aggregate grant date fair value at end of period
   $ 79.3     $ 64.6     $ 35.4  
                         
(1)   EPE Unit III was formed in 2007 and EPCO Unit and Enterprise Unit were formed in 2008.
(2)   TEPPCO Unit and TEPPCO Unit II were formed during 2008 and dissolved during 2009.
  

The following table summarizes the assumptions we used in deriving that portion of the estimated grant date fair value for each Employee Partnership using a Black-Scholes option pricing model:

 
Expected
Risk-Free
Expected
Expected Unit
Employee
Life
Interest
Distribution
Price
Partnership
of Award
Rate
Yield
Volatility
         
EPE Unit I
3 to 6 years
1.2% to 5.0%
3.0% to 6.7%
16.6% to 35.0%
EPE Unit II
4 to 6 years
1.6% to 4.4%
3.8% to 6.4%
18.7% to 31.7%
EPE Unit III
4 to 6 years
1.4% to 4.9%
4.0% to 6.4%
16.6% to 32.2%
Enterprise Unit
4 to 6 years
1.4% to 3.9%
4.5% to 8.4%
15.3% to 31.7%
EPCO Unit
4 to 6 years
1.6% to 2.4%
8.1% to 11.1%
27.0% to 50.0%

Phantom Units

Certain of our long-term incentive plans provide for the issuance of phantom unit awards.  These awards are automatically redeemed for cash based on the fair value of the vested portion of phantom units at redemption dates in each award.  The fair value of each phantom unit award is equal to the closing market price of the underlying security on the redemption date.  Each participant is required to redeem their phantom units as they vest, which typically is three to four years from the date the award is granted.  Our phantom units are accounted for as liability awards.

Certain of our long-term incentive plans also provide for the award of DERs in tandem with phantom unit awards.  A DER entitles the participant to cash distributions equal to the product of the number of awards outstanding for the participant and the cash distribution rate per unit paid by the issuer to its unitholders.  Such amounts are expensed when paid.





The following table presents additional information regarding our phantom unit awards for the periods indicated:

   
Phantom Unit Awards Issued by
  
   
TEPPCO
    
Enterprise
Products
Partners
    
Total
  
Phantom units at December 31, 2006
     154,479       --       154,479  
Granted
     259       --       259  
Vested
     (13,533 )     --       (13,533 )
Settled or forfeited
     (13,800 )     --       (13,800 )
Phantom units at December 31, 2007
     127,405       --       127,405  
Granted
     1,698       4,400       6,098  
Vested
     (58,168 )     --       (58,168 )
Settled or forfeited
     (1,600 )     --       (1,600 )
Phantom units at December 31, 2008
     69,335       4,400       73,735  
Granted
     124       6,200       6,324  
Vested
     (61,519 )     --       (61,519 )
Settled or forfeited
     (4,447 )     --       (4,447 )
Awards assumed in connection with TEPPCO Merger
     (3,493 )     4,327       834  
Phantom units at December 31, 2009
     --       14,927       14,927  

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Accrued liability for phantom unit awards, at end of period
   $ 0.2     $ 1.2     $ 4.5  
Liabilities paid for phantom unit awards
     1.2       2.5       0.6  

At December 31, 2009, only the 2008 Plan and the 1999 Plan had significant phantom units outstanding.  These awards will settle as follows:  4,327 in 2010, 4,400 in 2011 and 6,200 in 2012.  The 2000 Plan and 2005 Plan also issued phantom units, all of which had vested and settled prior to December 31, 2009.  The 3,472 phantom units outstanding under the 1999 Plan were settled in January 2010 and the plan terminated.

Unit Appreciation Rights

UARs entitle a participant to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of the underlying security (determined as of a future vesting date) over the grant date fair value of the award.  UARs are accounted for as liability awards.  The following table presents additional information regarding our UARs for the periods indicated:

   
UARs Issued by
  
   
TEPPCO
    
Enterprise
Products
Partners
    
EPE
    
Total
  
UARs at December 31, 2006
     --       --       90,000       90,000  
     Granted
     404,704       --       90,000       494,704  
     Settled or forfeited
     (2,756 )     --       --       (2,756 )
UARs at December 31, 2007
     401,948       --       180,000       581,948  
     Granted
     29,429       --       --       29,429  
UARs at December 31, 2008
     431,377       --       180,000       611,377  
     Settled or forfeited
     (166,217 )     (186,614 )     (90,000 )     (442,831 )
     Awards assumed in connection with the TEPPCO Merger
     (265,160 )     328,810       --       63,650  
UARs at December 31, 2009
     --       142,196       90,000       232,196  

   
At December 31,
  
   
2009
    
2008
    
2007
  
Accrued liability for UARs
   $ 0.3     $ 0.2     $ 0.2  

At December 31, 2009, 142,196 UARs had been granted under the 2006 Plan to certain employees of EPCO who work on our behalf.  These awards are subject to five year cliff vesting requirements and are


expected to settle in 2012.  The grant date fair value with respect to these UARs is based on Enterprise Products Partners’ unit price of $37.00.  If the employee resigns prior to vesting, these UAR awards are forfeited.

Prior to the TEPPCO Merger, 95,654 UARs had been granted to the non-employee former directors of TEPPCO under the 2006 Plan.  The awards were settled in October 2009 and $0.1 million in cash was paid to the former directors.

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, the Parent Company, Duncan Energy Partners or Enterprise Products Partners.  The compensation expense associated with these awards is recognized by DEP GP, which is our consolidated subsidiary.  At December 31, 2009, 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 the Parent Company’s unit price of $36.68.

UARs formerly issued to non-employee directors of EPGP in the form of letter grants were terminated during the second quarter of 2009.


Note 6.  Derivative Instruments, Hedging Activities and Fair Value Measurements

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates.  In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments.  Derivatives are instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values.  Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced sale.  Typical derivative instruments include futures, forward contracts, swaps, options and other instruments with similar characteristics.  Substantially all of our derivatives are used for non-trading activities.

We are required to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet.  While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments are reported in different ways depending on the nature and effectiveness of the hedging activities to which they are related.  After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of:

§  
Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment - In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.

§  
Variable cash flows of a forecasted transaction - In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income or loss (“OCI”) and is reclassified into earnings when the forecasted transaction affects earnings.

§  
Foreign currency exposure - A foreign currency hedge can be treated as either a fair value hedge or a cash flow hedge depending on the risk being hedged.

An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship.  The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period.  Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item.  Any ineffectiveness


associated with a hedge relationship is recognized in earnings immediately.  Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

A contract designated as a cash flow hedge of an anticipated transaction that is probable of not occurring is immediately recognized in earnings.

Interest Rate Derivative Instruments

We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain consolidated debt agreements.  This strategy is a component in controlling our cost of capital associated with such borrowings.

The following table summarizes our interest rate derivative instruments outstanding at December 31, 2009, all of which were designated as hedging instruments under the FASB’s derivative and hedging guidance:

 
Number and Type of
  
Notional
  
Period of
Rate
Accounting
Hedged Transaction
Derivative Employed
  
Amount
  
Hedge
Swap
Treatment
Parent Company:
              
   Variable-interest rate borrowings
2 floating-to-fixed swaps
   $ 250.0  
9/07 to 8/11
0.3% to 4.8%
Cash flow hedge
Enterprise Products Partners:
                
   Senior Notes C
1 fixed-to-floating swap
   $ 100.0  
1/04 to 2/13
6.4% to 2.8%
Fair value hedge
   Senior Notes G
3 fixed-to-floating swaps
   $ 300.0  
10/04 to 10/14
5.6% to 1.5%
Fair value hedge
Senior Notes P
7 fixed-to-floating swaps
   $ 400.0  
6/09 to 8/12
4.6% to 2.7%
Fair value hedge
Duncan Energy Partners:
                
   Variable-interest rate borrowings
3 floating-to-fixed swaps
   $ 175.0  
9/07 to 9/10
0.3% to 4.6%
Cash flow hedge

In August 2009, two of the Parent Company’s floating-to-fixed interest rate swaps associated with its variable-interest rate borrowings expired.  Such swaps had a notional amount of $250.0 million.

Changes in the fair value of the interest rate swaps and the related hedged items were recorded on the balance sheet with the offset recorded as interest expense.  Cash flow hedges fix the interest rate paid on floating rate debt with the difference between the floating rate and fixed rate being recorded as an increase or decrease to interest expense.  This combined activity resulted in an increase of interest expense of $16.2 million and $6.4 million for the years ended December 31, 2009 and 2008, respectively.

At times, we may use treasury lock derivative instruments to hedge the underlying U.S. treasury rates related to forecasted issuances of debt.  As cash flow hedges, gains or losses on these instruments are recorded in OCI and amortized into earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.  During 2008, we terminated treasury locks with a combined notional amount of $1.2 billion and recognized an aggregate loss of $43.9 million in OCI related to these terminations.

During the year ended December 31, 2009, we entered into four forward starting interest rate swaps to hedge the underlying benchmark interest payments related to the forecasted issuances of debt.

 
Number and Type of
  
Notional
  
Period of
  
Average Rate
  
Accounting
Hedged Transaction
Derivative Employed
  
Amount
  
Hedge
  
Locked
  
Treatment
   Future debt offering
1 forward starting swap
   $ 50.0  
6/10 to 6/20
   3.3%  
Cash flow hedge
   Future debt offering
3 forward starting swaps
   $ 250.0  
2/11 to 2/21
   3.6%  
Cash flow hedge

Forward starting interest rate swaps are used to hedge the underlying benchmark interest payments related to the forecasted issuances of debt.  The fair market value of the forward starting swaps was $21.0


million at December 31, 2009.  During January and February 2010, we entered into five additional forward starting swaps with a notional amount of $50.0 million each.  The period hedged by these five forward starting swaps is February 2012 through February 2022.

Commodity Derivative Instruments

The prices of natural gas, NGLs, crude oil, refined products and certain petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control.  In order to manage the price risk associated with certain exposures, we enter into commodity derivative instruments such as forwards, basis swaps, futures and options contracts.  The following table summarizes our commodity derivative instruments outstanding at December 31, 2009:

 
Volume (1)
Accounting
Derivative Purpose
Current
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:
      
Enterprise Products Partners:
      
Natural gas processing:
      
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)
 17.8 Bcf
n/a
Cash flow hedge
Forecasted NGL sales (4)
2.4 MMBbls
n/a
Cash flow hedge
Octane enhancement:
      
Forecasted purchases of NGLs
2.0 MMBbls
n/a
Cash flow hedge
NGLs inventory management
0.1 MMBbls
n/a
Cash flow hedge
Forecasted sales of octane enhancement products
3.4 MMBbls
0.4 MMBbls
Cash flow hedge
Natural gas marketing:
      
Natural gas storage inventory management activities
3.5 Bcf
n/a
Fair value hedge
NGL marketing:
      
Forecasted purchases of NGLs and related hydrocarbon products
7.5 MMBbls
n/a
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products
8.0 MMBbls
n/a
Cash flow hedge
       
Derivatives not designated as hedging instruments:
      
Enterprise Products Partners:
      
Natural gas risk management activities (5) (6)
359.2 Bcf
33.9 Bcf
Mark-to-market
NGL risk management activities (6)
0.4 MMBbls
n/a
Mark-to-market
Crude oil risk management activities (6)
3.5 MMBbls
n/a
Mark-to-market
Duncan Energy Partners:
      
Natural gas risk management activities (6)
2.2 Bcf
n/a
Mark-to-market
(1)   Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)   The maximum term for derivatives included in the long-term column is December 2012.
(3)   PTR represents the British thermal unit equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages.  See the discussion below for the primary objective of this strategy.
(4)   Excludes 5.4 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements under the FASB’s derivative and hedging guidance.  The combination of these volumes with the 2.4 MMBbls reflected as derivatives in the table above results in a total of 7.8 MMBbls of hedged forecasted NGL sales volumes, which corresponds to the 17.8 Bcf of forecasted natural gas purchase volumes for PTR.
(5)   Current and long-term volumes include approximately 109.5 and 12.6 billion cubic feet (“Bcf”), respectively, of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount.
(6)   Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Certain of our derivative instruments do not meet hedge accounting requirements; therefore, they are accounted for using mark-to-market accounting.

Our three predominant hedging strategies are hedging natural gas processing margins, hedging anticipated future sales of NGLs, refined products and crude oil associated with volumes held in inventory


and hedging the fair value of natural gas in inventory.  The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with the gas processing activities. We achieve this by using physical and financial instruments to lock in the prices of natural gas purchases used for PTR and NGL sales.  This program consists of (i) the forward sale of a portion of our expected equity NGL production at fixed prices through December 2010, achieved through the use of forward physical sales and commodity derivative instruments and (ii) the purchase of commodity derivative instruments with a notional amount determined by the amount of natural gas expected to be consumed as PTR in the production of such equity NGL production.  The objective of our NGL, refined products and crude oil sales hedging program is to hedge anticipated future sales of inventory by locking in the sales price through the use of forward physical sales and commodity derivative instruments.  The objective of our natural gas inventory hedging program is to hedge the fair value of natural gas currently held in inventory by locking in the sales price of the inventory through the use of commodity derivative instruments.

Foreign Currency Derivative Instruments

We are exposed to a nominal amount of foreign currency exchange risk in connection with our NGL and natural gas marketing activities in Canada.  As a result, we could be adversely affected by fluctuations in currency rates between the U.S. dollar and Canadian dollar.  In order to manage this risk, we may enter into foreign exchange purchase contracts to lock in the exchange rate.  Prior to 2009, these derivative instruments were accounted for using mark-to-market accounting.  Beginning with the first quarter of 2009, the long-term transactions (more than two months) are accounted for as cash flow hedges.  Shorter term transactions are accounted for using mark-to-market accounting.

In 2008 and 2009 we were exposed to foreign currency exchange risk in connection with a term loan denominated in Japanese yen (see Note 12).  We entered into this loan agreement in November 2008 and the loan matured in March 2009.  The derivative instrument used to hedge this risk was accounted for as a cash flow hedge and was settled upon repayment of the loan.

At December 31, 2009, we had foreign currency derivative instruments outstanding with a notional amount of $4.1 million Canadian dollars.  The fair market value of these instruments was an asset of $0.2 million at December 31, 2009.

Credit-Risk Related Contingent Features in Derivative Instruments

                A limited number of our commodity derivative instruments include provisions related to credit ratings and/or adequate assurance clauses.  A credit rating provision provides for a counterparty to demand immediate full or partial payment to cover a net liability position upon the loss of a stipulated credit rating.  An adequate assurance clause provides for a counterparty to demand immediate full or partial payment to cover a net liability position should reasonable grounds for insecurity arise with respect to contractual performance by either party.  At December 31, 2009, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $7.7 million, approximately $6.1 million of which was subject to a credit rating contingent feature.  If our credit ratings were downgraded to Ba2/BB, approximately $1.1 million would be payable as a margin deposit to the counterparties, and if our credit ratings were downgraded to Ba3/BB- or below, approximately $6.1 million would be payable as a margin deposit to the counterparties.  Currently, no margin is required to be deposited.  The potential for derivatives with contingent features to enter a net liability position may change in the future as positions and prices fluctuate. 










Tabular Presentation of Fair Value Amounts, and Gains and Losses on
   Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:
 
 
Asset Derivatives
  
Liability Derivatives
  
 
December 31, 2009
  
December 31, 2008
  
December 31, 2009
  
December 31, 2008
  
 
Balance Sheet
  
Fair
  
Balance Sheet
  
Fair
  
Balance Sheet
  
Fair
  
Balance Sheet
  
Fair
  
 
Location
  
Value
  
Location
  
Value
  
Location
  
Value
  
Location
  
Value
  
   
Derivatives designated as hedging instruments
  
Interest rate derivatives
Derivative assets
   $ 32.7  
Derivative assets
   $ 7.8  
Derivative liabilities
   $ 18.6  
Derivative liabilities
   $ 19.2  
Interest rate derivatives
Other assets
     31.8  
Other assets
     38.9  
Other liabilities
     6.7  
Other liabilities
     17.1  
Total interest rate derivatives
       64.5         46.7         25.3         36.3  
Commodity derivatives
Derivative assets
     52.0  
Derivative assets
     150.6  
Derivative liabilities
     62.6  
Derivative liabilities
     253.5  
Commodity derivatives
Other assets
     0.5  
Other assets
     --  
Other liabilities
     1.8  
Other liabilities
     0.2  
Total commodity derivatives (1)
       52.5         150.6         64.4         253.7  
Foreign currency derivatives (2)
Derivative assets
     0.2  
Derivative assets
     9.3  
Derivative liabilities
     --  
Derivative liabilities
     --  
Total derivatives designated
                                        
as hedging instruments
     $ 117.2       $ 206.6       $ 89.7       $ 290.0  
                                         
Derivatives not designated as hedging instruments
  
Commodity derivatives
Derivative assets
   $ 28.9  
Derivative assets
   $ 50.9  
Derivative liabilities
   $ 24.9  
Derivative liabilities
   $ 43.4  
Commodity derivatives
Other assets
     2.0  
Other assets
     --  
Other liabilities
     2.7  
Other liabilities
     --  
Total commodity derivatives
       30.9         50.9         27.6         43.4  
Foreign currency derivatives
Derivative assets
     --  
Derivative assets
     --  
Derivative liabilities
     --  
Derivative liabilities
     0.1  
Total derivatives not designated
                                        
as hedging instruments
     $ 30.9       $ 50.9       $ 27.6       $ 43.5  
                                         
(1)   Represents commodity derivative transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.
(2)   Relates to the hedging of our exposure to fluctuations in the foreign currency exchange rate related to our Canadian NGL marketing subsidiary.
  

The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the periods indicated:

 Derivatives in Fair Value
    
Gain (Loss) Recognized in
  
Hedging Relationships
Location
  
Income on Derivative
  
     
For Year Ended December 31,
  
     
2009
    
2008
  
Interest rate
Interest expense
   $ (8.8 )   $ 31.2  
Commodity
Revenue
     1.8       --  
   Total
     $ (7.0 )   $ 31.2  

 Derivatives in Fair Value
    
Gain (Loss) Recognized in
  
Hedging Relationships
Location
  
Income on Hedged Item
  
     
For Year Ended December 31,
  
     
2009
    
2008
  
Interest rate
Interest expense
   $ 3.2     $ (31.2 )
Commodity
Revenue
     (1.3 )     --  
   Total
     $ 1.9     $ (31.2 )







The following tables present the effect of our derivative instruments designated as cash flow hedges on our Statements of Consolidated Operations for the periods indicated:

   
Change in Value Recognized
  
Derivatives in Cash Flow
  
in OCI on Derivative
  
Hedging Relationships
  
(Effective Portion)
  
   
For Year Ended December 31,
  
   
2009
    
2008
  
Interest rate derivatives
   $ 12.5     $ (73.0 )
Commodity derivatives – Revenue
     (34.8 )     (34.8 )
Commodity derivatives – Operating costs and expenses
     (144.8 )     (135.4 )
Foreign currency derivatives
     (10.2 )     9.3  
   Total
   $ (177.3 )   $ (233.9 )

     
Amount of Loss
  
Derivatives in Cash Flow
    
Reclassified from AOCI
  
Hedging Relationships
Location
  
into Income (Effective Portion)
  
     
For Year Ended December 31,
  
     
2009
    
2008
  
Interest rate derivatives
Interest expense
   $ (26.4 )   $ (5.5 )
Commodity derivatives
Revenue
     (61.0 )     (56.7 )
Commodity derivatives
Operating costs and expenses
     (233.2 )     (39.6 )
   Total
     $ (320.6 )   $ (101.8 )

     
Amount of Gain/(Loss)
  
Derivatives in Cash Flow
    
Recognized in Income on
  
Hedging Relationships
Location
  
Ineffective Portion of Derivative
  
     
For Year Ended December 31,
  
     
2009
    
2008
  
Interest rate derivatives
Interest expense
   $ 1.4     $ (2.7 )
Commodity derivatives
Revenue
     0.2       --  
Commodity derivatives
Operating costs and expenses
     (0.1 )     (1.7 )
Foreign currency derivatives
       --       (0.1 )
   Total
     $ 1.5     $ (4.5 )

Over the next twelve months, we expect to reclassify $21.3 million of AOCI attributable to interest rate derivative instruments into earnings as an increase to interest expense.  Likewise, we expect to reclassify $0.8 million of AOCI attributable to commodity derivative instruments into earnings, $0.2 million as an increase in operating costs and expenses and $1.0 million as an increase in revenues.

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the periods indicated:

Derivatives Not Designated as
    
Gain/(Loss) Recognized in
  
Hedging Instruments
Location
  
Income on Derivative
  
     
For Year Ended December 31,
  
     
2009
    
2008
  
Commodity derivatives
Revenue
   $ 40.7     $ 39.3  
Commodity derivatives
Operating costs and expenses
     --       (7.6 )
Foreign currency derivatives
Other expense
     (0.1 )     (0.1 )
   Total
     $ 40.6     $ 31.6  

Fair Value Measurements

Fair value is defined 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, including 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.

A three-tier hierarchy has been established 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 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 with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange).  Our Level 1 fair values primarily consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.

§  
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, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and 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).  Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over the counter.  The fair values of these derivatives are based on observable price quotes for similar products and locations.  The value of our interest rate derivatives are valued by using appropriate financial models with the implied forward London  Interbank Offered Rate (“LIBOR”) yield curve for the same period as the future interest swap settlements.

§  
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.  Our Level 3 fair values largely consist of ethane, normal butane and natural gasoline-based contracts with a range of two to 12 months in term.  We rely on price quotes from reputable brokers in the marketplace who publish price quotes on certain products.  Whenever possible, we compare these prices to other reputable brokers for the same product in the same market.  These prices, combined with our forward transactions, are used in our model to determine the fair value of such instruments.



The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at the dates indicated.  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, in addition to their placement within the fair value hierarchy levels.

   
At December 31, 2009
  
   
Level 1
    
Level 2
    
Level 3
    
Total
  
Financial assets:
                        
Interest rate derivative instruments
   $ --     $ 64.5     $ --     $ 64.5  
Commodity derivative instruments
     14.6       34.4       34.4       83.4  
Foreign currency derivative instruments
     --       0.2       --       0.2  
Total
   $ 14.6     $ 99.1     $ 34.4     $ 148.1  
                                 
Financial liabilities:
                                
Interest rate derivative instruments
   $ --     $ 25.3     $ --     $ 25.3  
Commodity derivative instruments
     17.1       46.2       28.7       92.0  
Total
   $ 17.1     $ 71.5     $ 28.7     $ 117.3  

   
At December 31, 2008
  
   
Level 1
    
Level 2
    
Level 3
    
Total
  
Financial assets:
                        
Interest rate derivative instruments
   $ --     $ 46.7     $ --     $ 46.7  
Commodity derivative instruments
     4.0       164.7       32.8       201.5  
Foreign currency derivative instruments
     --       9.3       --       9.3  
Total
   $ 4.0     $ 220.7     $ 32.8     $ 257.5  
                                 
Financial liabilities:
                                
Interest rate derivative instruments
   $ --     $ 36.3     $ --     $ 36.3  
Commodity derivative instruments
     7.1       289.6       0.4       297.1  
Foreign currency derivative instruments
     --       0.1       --       0.1  
Total
   $ 7.1     $ 326.0     $ 0.4     $ 333.5  

The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities for the periods presented:

   
For Year Ended December 31,
  
   
2009
    
2008
  
Balance, January 1
   $ 32.4     $ (5.0 )
Total gains (losses) included in:
                
Net income (1)
     27.0       (34.6 )
Other comprehensive income (loss)
     (21.8 )     37.2  
Purchases, issuances, settlements
     (26.8 )     34.8  
Transfer out of Level 3
     (5.1 )     --  
Balance, December 31
   $ 5.7     $ 32.4  
                 
(1)   There were unrealized losses of $5.2 million and gains of $0.2 million included in these amounts for the years ended December 31, 2009 and 2008, respectively.
  










Nonfinancial Assets and Liabilities

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment).  The following table presents the estimated fair value of certain assets carried on our Consolidated Balance Sheet by caption for which a nonrecurring change in fair value has been recorded during the year ended December 31, 2009:
 
   
Level 3
    
Impairment
Charges
  
Property, plant and equipment (see Note 8)
   $ 29.6     $ 29.4  
Intangible assets (see Note 11)
     0.6       0.6  
Goodwill (see Note 11)
     --       1.3  
Other current assets
     1.2       2.2  
  Total
   $ 31.4     $ 33.5  

Using appropriate valuation techniques, we adjusted the carrying value of certain assets to $31.4 million and recorded non-cash impairment charges of $33.5 million during 2009. These charges are reflected in operating costs and expenses for the year ended December 31, 2009 and have been allocated to property, plant and equipment, intangible assets, goodwill and other current assets.  During 2009, impairments primarily resulted from (i) reduced levels of throughput volumes at certain river terminals and the indefinite suspension of three new proposed river terminals, (ii) reduced throughput levels at a natural gas processing plant, (iii) the cancellation of a compressor station project and (iv) the determination that a storage cavern and certain marine barges were obsolete.  Our fair value estimates were based primarily on an evaluation of the future cash flows associated with each asset.


Note 7.  Inventories

Our inventory amounts were as follows at the dates indicated:

   
December 31,
  
   
2009
    
2008
  
   Working inventory (1)
   $ 466.4     $ 188.1  
   Forward sales inventory (2)
     245.5       216.9  
      Total inventory
   $ 711.9     $ 405.0  
                 
(1)   Working inventory is comprised of inventories of natural gas, NGLs, crude oil, refined products, lubrication oils and certain petrochemical products that are either available-for-sale or used in the provision for services.
(2)   Forward sales inventory consists of identified natural gas, NGL, refined product and crude oil volumes dedicated to the fulfillment of forward sales contracts. In general, the increase in volumes dedicated to forward physical sales contracts improves the overall utilization and profitability of our fee-based assets. The cash invested in forward sales NGL inventories is expected to be recovered within the next twelve months as physical delivery from inventory occurs.
  

In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties, see Note 4), these volumes are valued at market-based prices during the month in which they are acquired.

Due to fluctuating commodity prices, we recognize LCM adjustments when the carrying value of our inventories exceeds their net realizable value.  These non-cash charges are a component of cost of sales in the period they are recognized and generally affect our segment operating results in the following manner:

§  
Write-downs of NGL inventories are recorded as an expense related to our NGL marketing activities within our NGL Pipelines & Services business segment;



§  
Write-downs of natural gas inventories are recorded as an expense related to our natural gas pipeline operations within our Onshore Natural Gas Pipelines & Services business segment;

§  
Write-downs of crude oil inventories are recorded as an expense related to our crude oil operations within our Onshore Crude Oil Pipelines & Services business segment; and

§  
Write-downs of petrochemical, refined products and related inventories are recorded as an expense related to our petrochemical and refined products marketing activities or octane additive production business, as applicable, within our Petrochemical & Refined Products Services business segment.

To the extent our commodity hedging strategies address inventory-related risks and are successful, these inventory valuation adjustments are mitigated or offset.  See Note 6 for a description of our commodity hedging activities.

The following table summarizes our cost of sales and LCM adjustment amounts for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Cost of sales (1)
   $ 20,921.8     $ 31,204.8     $ 23,494.0  
LCM adjustments
     6.3       63.0       14.1  
(1)   Cost of sales is included in operating costs and expenses, as presented on our Statements of Consolidated Operations. The fluctuation in this amount year-to-year is primarily due to changes in energy commodity prices associated with our marketing activities.
  


Note 8.  Property, Plant and Equipment

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

   
Estimated
        
   
Useful Life
    
December 31,
  
   
in Years
    
2009
    
2008
  
Plants and pipelines (1)
   3-45 (5)     $ 17,681.9     $ 15,444.7  
Underground and other storage facilities (2)
   5-40 (6)       1,280.5       1,203.9  
Platforms and facilities (3)
   20-31       637.6       634.8  
Transportation equipment (4)
   3-10       60.1       50.9  
Marine vessels
   20-30       559.4       453.0  
Land
             82.9       76.5  
Construction in progress
             1,207.2       2,015.4  
    Total
             21,509.6       19,879.2  
Less accumulated depreciation
             3,820.4       3,146.4  
    Property, plant and equipment, net
           $ 17,689.2     $ 16,732.8  
                         
(1)   Plants and pipelines include processing plants; NGL, petrochemical, crude 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; above ground 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 and related equipment, 5-45 years; terminal facilities, 10-35 years; delivery facilities, 20-40 years; office furniture and equipment, 3-20 years; buildings, 20-40 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, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
  



In August 2008, our wholly owned subsidiaries, together with Oiltanking Holding Americas, Inc. (“Oiltanking”) formed the Texas Offshore Port System partnership (“TOPS”).  Effective April 16, 2009, our wholly owned subsidiaries dissociated from TOPS.  As a result, operating costs and expenses and net income for the year ended December 31, 2009 include a non-cash charge of $68.4 million.  This loss represents the forfeiture of our cumulative investment in TOPS through the date of dissociation and reflects our capital contributions to TOPS for construction in progress amounts.  

TOPS was a consolidated subsidiary of ours prior to the dissociation.  The effect of deconsolidation was to remove the accounts of TOPS, including Oiltanking’s noncontrolling interest of $33.4 million, from our books and records, after reflecting the $68.4 million aggregate write-off of the investment.  See Note 18 for information regarding expense amounts recognized during 2009 in connection with a settlement agreement involving TOPS.

We recorded $21.0 million, $4.3 million and $4.1 million of non-cash impairment charges within our Petrochemical & Refined Products Services segment, Onshore Natural Gas Pipelines & Services segment and NGL Pipelines & Services segment, respectively, related to plant, property and equipment during the year ended December 31, 2009.  See Note 6 for additional information regarding impairment charges.

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

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Depreciation expense (1)
   $ 678.1     $ 595.9     $ 515.7  
Capitalized interest (2)
     53.1       90.7       86.5  
(1)   Depreciation expense is a component of costs and expenses as presented in our 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 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 year ended December 31, 2008 decreased by approximately $20.0 million.   Of this amount, $19.0 million was attributed to noncontrolling interest.  The impact of this change on our earnings per unit was immaterial.

Asset Retirement Obligations

We have recorded AROs related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations.  In general, our AROs primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities.  In addition, our AROs may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.







The following table presents information regarding our AROs since December 31, 2007:

ARO liability balance, December 31, 2007
   $ 42.2  
   Liabilities incurred
     1.1  
   Liabilities settled
     (8.2 )
   Revisions in estimated cash flows
     4.7  
   Accretion expense
     2.4  
ARO liability balance, December 31, 2008
     42.2  
   Liabilities incurred
     0.5  
   Liabilities settled
     (17.1 )
   Revisions in estimated cash flows
     26.1  
   Accretion expense
     3.1  
ARO liability balance, December 31, 2009
   $ 54.8  

The increase in our ARO liability balance during 2009 primarily reflects revised estimates of the cost to comply with regulatory abandonment obligations associated with our offshore facilities in the Gulf of Mexico.  We incurred $14.6 million of costs through December 31, 2009 as a result of ARO settlement activities associated with certain pipeline laterals and a platform located in the Gulf of Mexico.

Property, plant and equipment at December 31, 2009 and 2008 includes $26.7 million and $11.7 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.  The following table presents forecasted accretion expense associated with our AROs for the years presented:

2010
    
2011
    
2012
    
2013
    
2014
  
$ 3.8     $ 3.7     $ 4.0     $ 4.3     $ 4.7  

Certain of our unconsolidated affiliates have AROs recorded at December 31, 2009 and 2008 relating to contractual agreements and regulatory requirements.  These amounts are immaterial to our financial statements.






 











Note 9.  Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting.  We group our investments in unconsolidated affiliates according to the business segment to which they relate (see Note 14 for a general discussion of our business segments).  The following table shows our investments in unconsolidated affiliates by business segment at the dates indicated:

   
Ownership
        
   
Percentage at
        
   
December 31,
    
December 31,
  
   
2009
    
2009
    
2008
  
NGL Pipelines & Services:
                  
Venice Energy Service Company, L.L.C.
   13.1%     $ 32.6     $ 37.7  
K/D/S Promix, L.L.C.
   50%       48.9       46.4  
Baton Rouge Fractionators LLC
   32.2%       22.2       24.2  
Skelly-Belvieu Pipeline Company, L.L.C.
   49%       37.9       36.0  
Onshore Natural Gas Pipelines & Services:
                        
Evangeline (1)
   49.5%       5.6       4.5  
White River Hub, LLC
   50%       26.4       21.4  
Onshore Crude Oil Pipelines & Services:
                        
Seaway Crude Pipeline Company
   50%       178.5       186.2  
Offshore Pipelines & Services:
                        
Poseidon Oil Pipeline, L.L.C.
   36%       61.7       60.2  
Cameron Highway Oil Pipeline Company (“Cameron Highway”)
   50%       239.6       250.9  
Deepwater Gateway, L.L.C.
   50%       101.8       104.8  
Neptune Pipeline Company, L.L.C.
   25.7%       53.8       52.7  
Nemo Gas Gathering Company, LLC (“Nemo”)
   33.9 %       --       0.4  
Petrochemical & Refined Products Services:
                        
Baton Rouge Propylene Concentrator, LLC
   30%       11.1       12.6  
Centennial Pipeline LLC (“Centennial”)
   50%       66.7       69.7  
Other (2)
  
Varies
       3.8       4.2  
Other Investments:
                        
Energy Transfer Equity
   17.5%       1,513.5       1,587.1  
LE GP
   40.6%       12.1       11.7  
Total
           $ 2,416.2     $ 2,510.7  
                         
(1)   Evangeline refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.
(2)   Other unconsolidated affiliates include a 50% interest in a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest in a company that provides logistics communications solutions between petroleum pipelines and their customers.
  

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 unconsolidated affiliates.  The following table summarizes the unamortized excess cost amounts by business segment at the dates indicated:

   
December 31,
  
   
2009
    
2008
  
             
NGL Pipelines & Services
   $ 27.1     $ 28.0  
Onshore Crude Oil Pipelines & Services
     20.4       21.1  
Offshore Pipelines & Service
     17.3       18.6  
Petrochemical & Refined Products Services
     4.0       7.9  
Other Investments (1)
     1,573.0       1,609.6  
Total
   $ 1,641.8     $ 1,685.2  
                 
(1)   The Parent Company’s initial investment in Energy Transfer Equity and LE GP exceeded its share of the historical cost of the underlying net assets of such investees by $1.67 billion. At December 31, 2009, this basis differential decreased to $1.57 billion (after taking into account related amortization amounts) and consisted of the following: $514.2 million attributed to fixed assets; $513.5 million attributed to the IDRs (an indefinite-life intangible asset) held by Energy Transfer Equity in the cash flows of ETP; $209.5 million attributed to amortizable intangible assets and $335.8 million attributed to equity method goodwill.
  



We amortize such excess cost amounts as a reduction in equity earnings in a manner similar to depreciation.  The following table presents our amortization of such excess cost amounts by business segment for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
                   
NGL Pipelines & Services
   $ 0.9     $ 0.5     $ 0.6  
Onshore Crude Oil Pipelines & Services
     0.7       0.7       0.7  
Offshore Pipelines & Service
     1.3       1.3       1.3  
Petrochemical & Refined Products Services
     3.9       4.3       5.3  
Other Investments
     36.6       34.3       26.7  
Total
   $ 43.4     $ 41.1     $ 34.6  

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

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
NGL Pipelines & Services
   $ 11.3     $ 1.4     $ 7.1  
Onshore Natural Gas Pipelines & Services
     4.9       1.6       0.2  
Onshore Crude Oil Pipelines & Services
     9.3       11.7       2.6  
Offshore Pipelines & Services
     36.9       33.7       12.6  
Petrochemical & Refined Products Services
     (11.2 )     (13.5 )     (12.0 )
Other Investments
     41.1       31.3       3.1  
Total
   $ 92.3     $ 66.2     $ 13.6  

NGL Pipelines & Services

At December 31, 2009, our investees included in our NGL Pipelines & Services segment own: (i) a natural gas processing facility and related assets located in south Louisiana, (ii) an NGL fractionation facility and related storage and pipeline assets located in south Louisiana, (iii) an NGL fractionation facility located in south Louisiana and (iv) a 572-mile pipeline that transports mixed NGLs to markets in southeast Texas.

During 2007, we sold an investment for approximately $156.0 million in cash and recognized a gain of $59.6 million, which is included in “Other, net” in our Statement of Consolidated Operations for the year ended December 31, 2007.  The sale was required by the U.S. Federal Trade Commission in connection with ending its investigation into the acquisition of TEPPCO GP by privately held affiliates of EPCO in February 2005.

Onshore Natural Gas Pipelines & Services

At December 31, 2009, our investees included in our Onshore Natural Gas Pipelines & Services segment own: (i) a natural gas pipeline located in south Louisiana and (ii) a natural gas hub located in northwest Colorado that commenced operations in December 2008.

Onshore Crude Oil Pipelines & Services

At December 31, 2009, our investee included in our Onshore Crude Oil Pipelines & Services segment owns a pipeline that transports crude oil from a marine terminal located in Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal located in Texas City, Texas, to refineries in the Texas City and Houston, Texas areas.

Offshore Pipelines & Services

At December 31, 2009, our investees included in our Offshore Pipelines & Services segment own:  (i) a crude oil pipeline that gathers production from the outer continental shelf and deepwater areas of the


Gulf of Mexico for delivery to onshore locations in south Louisiana, (ii) a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas, (iii) a crude oil and natural gas platform that processes production from the Marco Polo, K2, K2 North and Genghis Khan fields located in the South Green Canyon area of the Gulf of Mexico and (iv) natural gas pipeline systems located in the Gulf of Mexico.

During 2007, Cameron Highway repaid two series of notes aggregating $415.0 million using cash contributions from its partners.  We funded our 50% share of the capital contributions using borrowings under EPO’s Multi-Year Revolving Credit Facility.  Cameron Highway incurred a $14.1 million make-whole premium in connection with the repayment of its Series A notes.

Also during 2007, we evaluated our equity method investment in Nemo for impairment due to a decrease in throughput volumes primarily due to underperformance of certain fields and natural depletion.  As a result of this evaluation, we recorded a $7.0 million non-cash impairment charge that is a component of “Equity in income of unconsolidated affiliates” on our Consolidated Statement of Operations for the year ended December 31, 2007.

Petrochemical & Refined Products Services

At December 31, 2009, the investees included in our Petrochemical & Refined Products Services segment own: (i) a propylene fractionation facility located in south Louisiana, (ii) a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and (iii) an interstate refined products pipeline extending from the upper Texas Gulf Coast to central Illinois that effectively loops our refined products pipeline system providing incremental transportation capacity into Mid-continent markets.

Other Investments

This segment reflects the Parent Company’s non-controlling ownership interests in Energy Transfer Equity and its general partner, LE GP.  In May 2007, the Parent Company paid $1.65 billion to acquire 38,976,090 common units of Energy Transfer Equity and approximately 34.9% of the membership interests of LE GP.  On January 22, 2009, the Parent Company acquired an additional 5.7% membership interest in LE GP for $0.8 million, which increased our total ownership in LE GP to 40.6%.

The business purpose of LE GP is to manage the affairs and operations of Energy Transfer Equity.  LE GP has no separate business activities outside of those conducted by Energy Transfer Equity.  LE GP owns a 0.31% general partner interest in Energy Transfer Equity and has no IDRs in the quarterly cash distributions of Energy Transfer Equity.

Energy Transfer Equity currently has no separate operating activities apart from those of ETP.  Energy Transfer Equity’s principal sources of distributable cash flow are its investments in the limited and general partner interests of ETP as follows:

§  
Direct ownership of 62,500,797 ETP limited partner units representing approximately 35% of the total outstanding ETP units.

§  
Indirect ownership of the general partner interest of ETP (representing a 1.9% interest as of December 31, 2009) and all associated IDRs held by ETP’s general partner, of which Energy Transfer Equity owns 100% of the membership interests.

ETP is a publicly traded partnership owning and operating a diversified portfolio of midstream energy assets. ETP has pipeline operations in Arizona, Colorado, Louisiana, New Mexico and Utah, and owns the largest intrastate pipeline system in Texas.  ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, natural gas treating and processing assets and three natural gas storage facilities located in Texas.  ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.


Summarized Combined Financial Information of Unconsolidated Affiliates

The consolidated balance sheet and results of operations information for the last two years for Energy Transfer Equity is summarized below:

   
At December 31,
  
   
2009
    
2008
  
BALANCE SHEET DATA:
            
Current assets
   $ 1,268.0     $ 1,181.0  
Property, plant and equipment, net
     9,064.5       8,702.5  
Other assets
     1,828.0       1,186.4  
Total assets
   $ 12,160.5     $ 11,069.9  
                 
Current liabilities
   $ 889.7     $ 1,208.9  
Other liabilities
     8,050.5       7,521.7  
Combined equity
     3,220.3       2,339.3  
Total liabilities and combined equity
   $ 12,160.5     $ 11,069.9  
                 
   
For Year Ended December 31,
  
    2009     2008  
INCOME STATEMENT DATA:
                
Revenues
   $ 5,417.3     $ 9,293.4  
Operating income
     1,110.4       1,098.9  
Net income (1)
     442.5       375.0  
(1)   Net income for Energy Transfer Equity represents net income attributable to the partners of Energy Transfer Equity.
  

Energy Transfer Equity’s income statement data for the year ended December 31, 2007 is excluded from the table above due to Energy Transfer Equity changing its fiscal year end from August 31 to December 31 in November 2007.  Energy Transfer Equity did not recast its consolidated financial data for prior fiscal periods; however, it did complete a four month transition period that began on September 1, 2007 and ended December 31, 2007.  For the four months ended December 31, 2007, Energy Transfer Equity reported revenues of $2.35 billion, operating income of $316.7 million and net income attributable to Energy Transfer Equity of $92.7 million.  For the year ended August 31, 2007, Energy Transfer Equity reported revenues of $6.79 billion, operating income of $809.3 million and net income attributable to Energy Transfer Equity of $319.4 million.

Equity earnings from our investment in Energy Transfer Equity for the year ended December 31, 2009 were $77.7 million, before $36.6 million of amortization of excess cost amounts.  Equity earnings from this investment for the year ended December 31, 2008 were $65.6 million, before $34.3 million of amortization of excess cost amounts.


















The combined balance sheet information for the last two years and results of operations data for the last three years for the remainder of our unconsolidated affiliates are summarized below:

   
At December 31,
        
   
2009
    
2008
        
BALANCE SHEET DATA:
                  
Current assets
   $ 201.0     $ 240.8        
Property, plant and equipment, net
     1,997.2       2,053.3        
Other assets
     36.4       23.1        
Total assets
   $ 2,234.6     $ 2,317.2        
                       
Current liabilities
   $ 118.6     $ 165.9        
Other liabilities
     255.4       282.8        
Combined equity
     1,860.6       1,868.5        
Total liabilities and combined equity
   $ 2,234.6     $ 2,317.2        
       
   
For Year Ended December 31,
  
    2009     2008     2007  
INCOME STATEMENT DATA:
                        
Revenues
   $ 738.1     $ 961.7     $ 794.1  
Operating income
     169.2       154.3       173.4  
Net income
     155.9       136.1       110.5  


Note 10.  Business Combinations

The following table presents our cash used for business combinations by segment for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
NGL Pipelines & Services
   $ 33.3     $ 77.0     $ 0.4  
Onshore Natural Gas Pipelines & Services
     0.8       125.2       35.5  
Petrochemical & Refined Products Services
     73.2       351.3       --  
         Total cash used for business combinations
   $ 107.3     $ 553.5     $ 35.9  

The following table depicts the fair value allocation of assets acquired and liabilities assumed for our business combinations for the periods indicated:
 
   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Assets acquired in business combination:
                  
Current assets
   $ 1.4     $ 6.6     $ --  
Property, plant and equipment, net
     115.9       549.6       44.5  
Intangible assets
     0.3       92.5       (8.5 )
Other assets
     (0.3 )     0.4       --  
Total assets acquired
     117.3       649.1       36.0  
Liabilities assumed in business combination:
                        
Current liabilities
     0.3       (3.2 )     --  
Long-term debt
     --       (2.6 )     --  
Other long-term liabilities
     --       (109.5 )     (1.2 )
Total liabilities assumed
     0.3       (115.3 )     (1.2 )
Total assets acquired plus liabilities assumed
     117.6       533.8       34.8  
Noncontrolling interest acquired
     10.3       --       --  
Fair value of 4,854,899 TEPPCO units
     --       186.6       --  
Total cash used for business combinations
     107.3       553.5       35.9  
Goodwill (1)
   $ --     $ 206.3     $ 1.1  
                         
(1)   See Note 11 for additional information regarding goodwill.
  


On a pro forma consolidated basis, our revenues, costs and expenses, operating income, net income attributable to Enterprise GP Holdings L.P. and earnings per unit amounts would not have differed materially from those we actually reported for 2009, 2008 and 2007 due to the immaterial nature of our business combination transactions for those respective periods.

2009 Transactions

Our business combinations during 2009 primarily consisted of:

§  
the acquisition of certain rail and truck terminal facilities located in Mont Belvieu, Texas from Martin Midstream Partners LP for $23.7 million in cash;

§  
the acquisition of tow boats and tank barges primarily based in Miami, Florida, with additional assets located in Mobile, Alabama and Houston, Texas from TransMontaigne Product Services Inc. for $50.0 million in cash; and

§  
the acquisition of a majority interest in the Rio Grande Pipeline Company (“Rio Grande”) purchased from HEP Navajo Southern L.P. for $32.8 million in cash.  Rio Grande owns an NGL pipeline system in Texas.

2008 Transactions

Great Divide Gathering System Acquisition.  In December 2008, one of our subsidiaries, Enterprise Gas Processing, LLC, purchased a 100% membership interest in Great Divide Gathering, LLC (“Great Divide”) for cash consideration of $125.2 million.  Great Divide was wholly owned by EnCana Oil & Gas (“EnCana”).

The assets of Great Divide consist of a 32-mile natural gas gathering system, the Great Divide Gathering System, located in the Piceance Basin of northwest Colorado.  The Great Divide Gathering System extends from the southern portion of the Piceance Basin, including production from EnCana’s Mamm Creek field, to a pipeline interconnection with our Piceance Basin Gathering System.  Volumes of natural gas originating on the Great Divide Gathering System are transported through our Piceance Creek Gathering System to our 1.7 Bcf/d Meeker natural gas treating and processing complex.  A significant portion of these volumes are produced by EnCana and are dedicated to the Great Divide and Piceance Creek Gathering Systems for the life of the associated lease holdings.
 
Cenac and Horizon Acquisitions.  In February 2008, TEPPCO entered the marine transportation business for refined products, crude oil and condensate through the purchase of assets from Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. (collectively “Cenac”).  The aggregate value of total consideration TEPPCO paid or issued to complete this business combination was $444.7 million, which consisted of $258.1 million in cash and 4,854,899 newly issued TEPPCO units.  Additionally, TEPPCO assumed approximately $63.2 million of Cenac’s debt in the transaction.  TEPPCO acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements.  This business serves refineries and storage terminals along the Mississippi, Illinois and Ohio rivers and the Intracoastal Waterway between Texas and Florida.  These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast.  TEPPCO used a short-term credit facility to finance the cash portion of the acquisition price and to repay the $63.2 million of debt assumed in this transaction.

Also in February 2008, TEPPCO purchased related marine assets from Horizon Maritime, L.L.C. (“Horizon”), a privately held Houston-based company and an affiliate of Cenac, for $80.8 million in cash.  In this transaction, TEPPCO acquired seven tow boats, 17 tank barges, rights to two tow boats under construction and the economic benefit of certain related commercial agreements.  In April 2008, TEPPCO paid an additional $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and in June 2008, TEPPCO paid an additional $3.8 million upon delivery of the second tow boat.  These vessels transport asphalt, heavy fuel oil and other heated oil products to storage


facilities and refineries along the Mississippi, Illinois and Ohio Rivers and the Intracoastal Waterway.  TEPPCO used a short-term credit facility to finance this acquisition.

The results of operations related to these assets are included in our Statements of Consolidated Operations beginning at the date of acquisition.

Other Transactions.  Other business combinations during 2008 primarily consisted of the acquisition of a natural gas gathering system located in the Piceance Basin of northwestern Colorado and additional interests in three consolidated NGL pipeline systems located along the U.S. Gulf Coast and southeastern United States.

2007 Transactions

Our expenditures for business combinations during the year ended December 31, 2007 primarily relate to the acquisition of a business with natural gas pipelines located in southeast Texas.


Note 11.  Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by segment at the dates indicated:
 
   
December 31, 2009
    
December 31, 2008
  
   
Gross
    
Accum.
    
Carrying
    
Gross
    
Accum.
    
Carrying
  
   
Value
    
Amort.
    
Value
    
Value
    
Amort.
    
Value
  
NGL Pipelines & Services: (1)
                                    
Customer relationship intangibles
   $ 237.4     $ (86.5 )   $ 150.9     $ 237.4     $ (68.7 )   $ 168.7  
Contract-based intangibles
     321.4       (156.7 )     164.7       320.3       (137.6 )     182.7  
    Segment total
     558.8       (243.2 )     315.6       557.7       (206.3 )     351.4  
Onshore Natural Gas Pipelines & Services:
                                                
Customer relationship intangibles (2)
     372.0       (124.3 )     247.7       372.0       (103.2 )     268.8  
Contract-based intangibles
     565.3       (285.8 )     279.5       565.3       (249.7 )     315.6  
    Segment total
     937.3       (410.1 )     527.2       937.3       (352.9 )     584.4  
Onshore Crude Oil Pipelines & Services:
                                                
Contract-based intangibles
     10.0       (3.5 )     6.5       10.0       (3.1 )     6.9  
    Segment total
     10.0       (3.5 )     6.5       10.0       (3.1 )     6.9  
Offshore Pipelines & Services:
                                                
Customer relationship intangibles
     205.8       (105.3 )     100.5       205.8       (90.7 )     115.1  
Contract-based intangibles
     1.2       (0.2 )     1.0       1.2       (0.1 )     1.1  
    Segment total
     207.0       (105.5 )     101.5       207.0       (90.8 )     116.2  
Petrochemical & Refined Products Services: (3)
                                                
Customer relationship intangibles
     104.6       (18.8 )     85.8       104.9       (13.8 )     91.1  
Contract-based intangibles
     42.1       (13.9 )     28.2       41.1       (8.2 )     32.9  
    Segment total
     146.7       (32.7 )     114.0       146.0       (22.0 )     124.0  
    Total all segments
   $ 1,859.8     $ (795.0 )   $ 1,064.8     $ 1,858.0     $ (675.1 )   $ 1,182.9  
                                                 
(1)   In 2008, we acquired $6.0 million of certain permits related to our Mont Belvieu complex and had $12.7 million of purchase price allocation adjustments related to San Felipe customer relationships from a 2007 business combination.
(2)   In 2008, we acquired $9.8 million of customer relationships due to the Great Divide business combination.
(3)   Amount includes a non-cash impairment charge of $0.6 million in 2009 related to certain intangible assets, see Note 6 for additional information.
  








 
F-47
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

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

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
NGL Pipelines & Services
   $ 36.9     $ 40.7     $ 38.2  
Onshore Natural Gas Pipelines & Services
     57.2       61.7       64.4  
Onshore Crude Oil Pipelines & Services
     0.4       0.5       0.5  
Offshore Pipelines & Services
     14.7       16.9       19.3  
Petrochemical & Refined Products Services
     10.7       10.2       2.8  
Total all segments
   $ 119.9     $ 130.0     $ 125.2  

The following table presents forecasted amortization expense associated with existing intangible assets for the years presented:

2010
    
2011
    
2012
    
2013
    
2014
  
$ 112.2     $ 105.0     $ 89.4     $ 82.4     $ 78.1  

In general, our intangible assets fall within two categories – customer relationship and contract-based intangible assets.  The values assigned to such intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate.

Customer relationship intangible assets.  Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations and asset purchases whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us.  Customer relationships may arise from contractual arrangements (such as supplier contracts and service contracts) and through means other than contracts, such as through regular contact by sales or service representatives.

At December 31, 2009, the carrying value of our customer relationship intangible assets was $584.9 million.  The following information summarizes the significant components of this category of intangible assets:

§  
San Juan Gathering System customer relationships – We acquired these customer relationships in connection with the GulfTerra Merger, which was completed on September 30, 2004.  At December 31, 2009, the carrying value of this group of intangible assets was $220.8 million.  These intangible assets are being amortized to earnings over their estimated economic life of 35 years through 2039.  Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying natural gas resource bases are expected to be consumed or otherwise used.
 
§  
Offshore Pipeline & Platform customer relationships – We acquired these customer relationships in connection with the GulfTerra Merger.  At December 31, 2009, the carrying value of this group of intangible assets was $100.5 million.  These intangible assets are being amortized to earnings over their estimated economic lives, which range from 18 to 33 years (i.e., through 2022 to 2037).  Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying crude oil and natural gas resource bases are expected to be consumed or otherwise used.
 
§  
Encinal natural gas processing customer relationship – We acquired this customer relationship in connection with our Encinal acquisition in 2006.  At December 31, 2009, the carrying value of this intangible asset was $89.3 million.  This intangible asset is being amortized to earnings over its estimated economic life of 20 years through 2026.  Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefit of the underlying natural gas resource bases are expected to be consumed or otherwise used.


Contract-based intangible assets.  Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations or asset purchases.  At December 31, 2009, the carrying value of our contract-based intangible assets was $479.9 million.  The following information summarizes the significant components of this category of intangible assets:

§  
Jonah Gas Gathering Company (“Jonah”) natural gas gathering agreements – These intangible assets represent the value attributed to certain of Jonah’s natural gas gathering contracts that were originally acquired by TEPPCO in 2001.  At December 31, 2009, the carrying value of this group of intangible assets was $125.0 million.  These intangible assets are being amortized to earnings using a units-of-production method based on throughput volumes on the Jonah system, which is estimated to extend through 2041.

§  
Val Verde natural gas gathering agreements – These intangible assets represent the value attributed to certain natural gas gathering agreements associated with our Val Verde Gathering System that was originally acquired by TEPPCO in 2002.  At December 31, 2009, the carrying value of these intangible assets was $98.4 million.  These intangible assets are being amortized to earnings using a units-of-production method based on throughput volumes on the Val Verde Gathering System, which is estimated to extend through 2032.

§  
Shell Processing Agreement – This margin-band/keepwhole processing agreement grants us the right to process Shell Oil Company’s (or its assignee’s) current and future natural gas production within the state and federal waters of the Gulf of Mexico.  We acquired the Shell Processing Agreement in connection with our 1999 purchase of certain of Shell’s midstream energy assets located along the U.S. Gulf Coast.  At December 31, 2009, the carrying value of this intangible asset was $105.9 million.  This intangible asset is being amortized to earnings on a straight-line basis over its estimated economic life of 20 years through 2019.

§  
Mississippi natural gas storage contracts – These intangible assets represent the value assigned by us to certain natural gas storage contracts associated with our Petal and Hattiesburg, Mississippi storage facilities.  These facilities were acquired in connection with the GulfTerra Merger.  At December 31, 2009, the carrying value of these intangible assets was $55.4 million.  These intangible assets are being amortized to earnings on a straight-line basis over the remainder of their respective contract terms, which range from eight to 18 years (i.e. 2012 through 2022).

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction.  Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year.  The following table presents the changes in the carrying amount of goodwill for the periods presented:

         
Onshore
    
Onshore
          
Petrochemical
        
   
NGL
    
Natural Gas
    
Crude Oil
    
Offshore
    
& Refined
        
   
Pipelines
    
Pipelines
    
Pipelines
    
Pipelines
    
Products
    
Consolidated
  
   
& Services
    
& Services
    
& Services
    
& Services
    
Services
    
Totals
  
                                     
Balance at January 1, 2007
   $ 224.8     $ 284.9     $ 303.0     $ 82.1     $ 917.3     $ 1,812.1  
Goodwill related to acquisitions
     1.2       --       --       --       --       1.2  
Balance at December 31, 2007
     226.0       284.9       303.0       82.1       917.3       1,813.3  
Goodwill related to acquisitions
     115.2       --       --       --       91.1       206.3  
Balance at December 31, 2008
     341.2       284.9       303.0       82.1       1,008.4       2,019.6  
Impairment charges (1)
     --       --       --       --       (1.3 )     (1.3 )
Balance at December 31, 2009 (2)
   $ 341.2     $ 284.9     $ 303.0     $ 82.1     $ 1,007.1     $ 2,018.3  
                                                 
(1)   See Note 6 for additional information regarding impairment charges recorded during year ended December 31, 2009.
(2)   The total carrying amount of goodwill at December 31, 2009 is reflected net of $1.3 million of accumulated impairment charges.
  



   Our goodwill impairment testing involves the determination of a reporting unit’s fair value, which is predicated based on our assumptions regarding the future economic prospects of the reporting unit.  Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins and transportation volumes; (ii) long-term growth rates for cash flows beyond the discrete forecast period; and (iii) appropriate discount rates.  Based on our most recent goodwill impairment testing, each reporting unit’s fair value was substantially in excess (a minimum of 10%) of its carrying value. 

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

   
December 31,
  
   
2009
    
2008
  
NGL Pipelines & Services
            
Acquisition of ownership interests in TEPPCO
   $ 72.2     $ 72.2  
GulfTerra Merger
     23.8       23.8  
Acquisition of Encinal
     95.3       95.3  
Acquisition of interest in Dixie
     80.3       80.3  
Acquisition of Great Divide
     44.9       44.9  
Acquisition of Indian Springs natural gas processing business
     13.2       13.2  
Other
     11.5       11.5  
Onshore Natural Gas Pipelines & Services
                
GulfTerra Merger
     279.9       279.9  
Other
     5.0       5.0  
Onshore Crude Oil Pipeline & Services
                
Acquisition of ownership interests in TEPPCO
     288.8       288.8  
Acquisition of crude oil pipeline and services business
     14.2       14.2  
Offshore Pipelines & Services
                
GulfTerra Merger
     82.1       82.1  
Petrochemical & Refined Products Services
                
Acquisition of ownership interests in TEPPCO
     842.3       842.3  
Acquisition of marine services businesses
     90.4       90.4  
Acquisition of Mont Belvieu propylene fractionation business
     73.7       73.7  
Other (1)
     0.7       2.0  
Total
   $ 2,018.3     $ 2,019.6  
                 
(1)   Includes a non-cash impairment charge of $1.3 million, see Note 6 for additional information.
  

Goodwill attributable to the acquisition of ownership interests in TEPPCO.  As a result of our ownership of 100% of the limited and general partner interests of TEPPCO following the recently completed TEPPCO Merger, we applied push down accounting to the $1.2 billion of goodwill recorded by affiliates of EPCO (which are under common control with us) when they acquired 100% of the membership interests of TEPPCO GP and 4,400,000 TEPPCO limited partner units from a third-party in February 2005.  The $1.2 billion in push down goodwill represents the excess of the purchase price paid by such affiliates to acquire ownership interests in TEPPCO in February 2005 over the respective fair value of assets acquired and liabilities assumed in the February 2005 transaction.  Management attributes the $1.2 billion of goodwill to the future economic benefits we may realize from our ownership of TEPPCO, including anticipated commercial synergies and cost savings.

TEPPCO owns and operates an extensive network of assets that facilitate the movement, marketing, gathering and storage services of various commodities and energy-related products.  TEPPCO’s pipeline network is comprised of approximately 12,500 miles of pipelines that gather and transport refined products, crude oil, natural gas and NGLs, including one of the largest common carrier pipelines for refined products in the United States.  TEPPCO also owns a marine services business that transports refined products, crude oil, asphalt, condensate, heavy fuel oil and other heated oil products via tow boats and tank barges.  In addition, TEPPCO owns interests in the Seaway and Centennial pipeline systems.

Goodwill attributable to GulfTerra Merger.  Goodwill recorded in connection with the GulfTerra Merger can be attributed to our belief (at the time the merger was consummated) that the combined


partnerships would benefit from the strategic location of each partnership’s assets and the industry relationships that each possessed.  In addition, we expected that various operating synergies could develop (such as reduced general and administrative costs and interest savings) that would result in improved financial results for the merged entity.  Based on miles of pipelines, GulfTerra was one of the largest natural gas gathering and transportation companies in the United States, serving producers in the central and western Gulf of Mexico and onshore in Texas and New Mexico.  These regions offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure.

Acquisition of Encinal.  Management attributes goodwill recorded in connection with the Encinal acquisition to potential future benefits we may realize from our other south Texas processing and NGL businesses as a result of acquiring the Encinal business.  Specifically, our acquisition of the long-term dedication rights associated with the Encinal business is expected to add value to our south Texas processing facilities and related NGL businesses due to increased volumes.  The Encinal goodwill is recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.

Acquisition of Dixie and Great Divide.  In 2008, we recorded goodwill in connection with our acquisition of the remaining third-party interest in Dixie and with the acquisition of Great Divide.  The remaining ownership interests in Dixie were acquired from Amoco Pipeline Holding Company in August 2008.  Management attributes the goodwill to future earnings growth on the Dixie Pipeline.  Specifically, a 100% ownership interest in the Dixie Pipeline will increase our flexibility to pursue future opportunities.  Great Divide was acquired from EnCana in December 2008.  The Great Divide goodwill is attributable to management’s expectations of future economics benefits derived from incremental natural gas processing margins and other downstream activities.

The Dixie and Great Divide goodwill amounts are recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.

Acquisition of Cenac and Horizon.  Also in 2008, we recorded goodwill in connection with our acquisition of marine services businesses, which are recorded as a part of the Petrochemical & Refined Products Services business segment due to management’s belief of potential future economic benefits we expect to realize as a result of acquiring these assets.

Other goodwill amounts.  The remainder of our goodwill amounts are associated with prior acquisitions, principally that of our crude oil pipeline and services business originally purchased by TEPPCO in 2001, our purchase of a propylene fractionation business in February 2002 and our acquisition of indirect ownership interests in the Indian Springs natural gas gathering and processing business in January 2005.

















Note 12.  Debt Obligations

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

   
December 31,
  
   
2009
    
2008
  
Parent Company debt obligations:
            
EPE Revolver, variable-rate, due September 2012
   $ 123.5     $ 102.0  
$125.0 million Term Loan A, variable-rate, due September 2012
     125.0       125.0  
$850.0 Term Loan B, variable-rate, due November 2014 (1)
     833.0       850.0  
EPO senior debt obligations:
                
Multi-Year Revolving Credit Facility, variable-rate, due November 2012
     195.5       800.0  
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 (1)
     54.0       54.0  
Petal GO Zone Bonds, variable-rate, due August 2037
     57.5       57.5  
Yen Term Loan, 4.93% fixed-rate, due March 2009
     --       217.6  
Senior Notes B, 7.50% fixed-rate, due February 2011
     450.0       450.0  
Senior Notes C, 6.375% fixed-rate, due February 2013
     350.0       350.0  
Senior Notes D, 6.875% fixed-rate, due March 2033
     500.0       500.0  
Senior Notes F, 4.625% fixed-rate, due October 2009
     --       500.0  
Senior Notes G, 5.60% fixed-rate, due October 2014
     650.0       650.0  
Senior Notes H, 6.65% fixed-rate, due October 2034
     350.0       350.0  
Senior Notes I, 5.00% fixed-rate, due March 2015
     250.0       250.0  
Senior Notes J, 5.75% fixed-rate, due March 2035
     250.0       250.0  
Senior Notes K, 4.95% fixed-rate, due June 2010 (1)
     500.0       500.0  
Senior Notes L, 6.30% fixed-rate, due September 2017
     800.0       800.0  
Senior Notes M, 5.65% fixed-rate, due April 2013
     400.0       400.0  
Senior Notes N, 6.50% fixed-rate, due January 2019
     700.0       700.0  
Senior Notes O, 9.75% fixed-rate, due January 2014
     500.0       500.0  
Senior Notes P, 4.60% fixed-rate, due August 2012
     500.0       --  
Senior Notes Q, 5.25% fixed-rate, due January 2020
     500.0       --  
Senior Notes R, 6.125% fixed-rate, due October 2039
     600.0       --  
Senior Notes S, 7.625% fixed-rate, due February 2012 (2)
     490.5       --  
Senior Notes T, 6.125% fixed-rate, due February 2013 (2)
     182.5       --  
Senior Notes U, 5.90% fixed-rate, due April 2013 (2)
     237.6       --  
Senior Notes V, 6.65% fixed-rate, due April 2018 (2)
     349.7       --  
Senior Notes W, 7.55% fixed-rate, due April 2038 (2)
     399.6       --  
TEPPCO senior debt obligations:
                
TEPPCO Revolving Credit Facility, variable-rate, due December 2012
     --       516.7  
TEPPCO Senior Notes (2)
     40.1       1,700.0  
Duncan Energy Partners’ debt obligations:
                
DEP Revolving Credit Facility, variable-rate, due February 2011
     175.0       202.0  
DEP Term Loan, variable-rate, due December 2011
     282.3       282.3  
Total principal amount of senior debt obligations
     10,845.8       11,107.1  
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066
     550.0       550.0  
EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068
     682.7       682.7  
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 (2)
     285.8       --  
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067 (2)
     14.2       300.0  
          Total principal amount of senior and junior debt obligations
     12,378.5       12,639.8  
Other, non-principal amounts:
                
Change in fair value of debt-related derivative instruments (see Note 6)
     44.4       51.9  
Unamortized discounts, net of premiums
     (18.7 )     (12.6 )
Unamortized deferred net gains related to terminated interest rate swaps (see Note 6)
     23.7       35.8  
Total other, non-principal amounts
     49.4       75.1  
Total long-term debt
   $ 12,427.9     $ 12,714.9  
                 
(1)   Long-term and current maturities of debt reflect the classification of such obligations at December 31, 2009. With respect to the $8.5 million due under Term Loan B, the Parent Company has the ability to use available credit capacity under the EPE Revolver to fund repayment of this amount. In addition, EPO has the ability to use available borrowing capacity under its Multi-Year Revolving Credit Facility to fund the repayments of the Pascagoula MBFC Loan and Senior Notes K.
(2)   Substantially all of TEPPCO debt obligations were exchanged for a corresponding series of new EPO notes in October 2009 in connection with the TEPPCO Merger.
  



Letters of Credit

At December 31, 2009, EPO had outstanding a $50.0 million letter of credit related to its commodity derivative instruments and a $58.3 million letter of credit related to its Petal GO Zone Bonds.  These letter of credit facilities do not reduce the amount available for borrowing under EPO’s credit facilities.

Subsidiary Guarantor Relationships

Enterprise Products Partners acts as guarantor of the consolidated debt obligations of EPO with the exception of the DEP Revolving Credit Facility and the DEP Term Loan Agreement.  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.  Additionally, TEPPCO’s remaining debt obligations are non-recourse to Enterprise Products Partners.

Parent Company’s Debt Obligations

The Parent Company consolidates the debt obligations of Enterprise Products Partners; however, the Parent Company does not have the obligation to make interest or debt payments with respect to such consolidated debt obligations.

EPE Interim Credit Facility.  In May 2007, the Parent Company executed a $1.9 billion interim credit facility (the “EPE Interim Credit Facility”) in connection with its acquisition of equity interests in Energy Transfer Equity and LE GP.  The EPE Interim Credit Facility provided for a $200.0 million revolving credit facility and $1.7 billion of term loans.  In August 2007, the Parent Company refinanced the $1.2 billion then outstanding under the EPE Interim Credit Facility using proceeds from its EPE August 2007 Credit Agreement.

EPE August 2007 Credit Agreement.  The $1.2 billion EPE August 2007 Credit Agreement provided for a $200.0 million revolving credit facility (the “EPE Revolver”), a $125.0 million term loan (“Term Loan A”) and an $850.0 million term loan (the “Term Loan A-2”).  The EPE Revolver replaced the $200.0 million revolver associated with the EPE Interim Credit Facility and Term Loan A and Term Loan A-2 refinanced amounts then outstanding under the term loans associated with the EPE Interim Credit Facility.  Amounts borrowed under the EPE Revolver and Term Loan A mature in September 2012.  Amounts borrowed under Term Loan A-2 were refinanced in November 2007 with proceeds from a term loan (Term Loan B – described below) due November 2014.

Borrowings under the EPE August 2007 Credit Agreement are secured by the Parent Company’s ownership of (i) 20,242,179 common units of Enterprise Products Partners, (ii) 100% of the membership interests in EPGP and (iii) 38,976,090 common units of Energy Transfer Equity.

The EPE Revolver may be used by the Parent Company to fund working capital and other capital requirements and for general partnership purposes.  The EPE Revolver offers secured ABR loans (“ABR Loans”) and Eurodollar loans (“Eurodollar Loans”) each having different interest requirements.

ABR Loans bear interest at an alternative base rate (the “Alternative Base Rate”) plus an applicable rate (the “Applicable Rate”).  The Alternative Base Rate is a rate per annum equal to the greater of:  (i) the annual interest rate publicly announced by Citibank, N.A. as its base rate in effect at its principal office in New York, New York (the “Prime Rate”) in effect on such day and (ii) the federal funds effective rate in effect on such day plus 0.50%.  The Applicable Rate for ABR Loans will be increased by an applicable margin ranging from 0% to 1.0% per annum.  The Eurodollar Loans bear interest at a “LIBOR rate” (as defined in the August 2007 Credit Agreement) plus the Applicable Rate.  The Applicable Rate for Eurodollar Loans will be increased by an applicable margin ranging from 1.00% to 2.50% per annum.

All borrowings outstanding under Term Loan A will, at the Parent Company’s option, be made and maintained as ABR Loans or Eurodollar Loans, or a combination thereof.  Any amount repaid under


the Term Loan A may not be reborrowed.

  In November 2007, the Parent Company executed a seven-year, $850 million senior secured term loan (“Term Loan B”) in the institutional leveraged loan market.  Proceeds from the Term Loan B were used to permanently refinance borrowings outstanding under the partnership’s $850 million Term Loan A-2.  The Term Loan B generally bears interest at LIBOR plus 2.25% and is scheduled to mature in November 2014.  The Term Loan B is callable by the partnership at par.

The EPE August 2007 Credit Agreement contains various covenants related to the Parent Company’s ability to incur certain indebtedness, grant certain liens, make fundamental structural changes, make distributions following an event of default and enter into certain restricted agreements.  The credit agreement also requires the Parent Company to satisfy certain quarterly financial covenants.

EPO’s Debt Obligations

Multi-Year Revolving Credit Facility.  EPO has in place a $1.75 billion unsecured revolving credit facility, including the issuance of letters of credit (“Multi-Year Revolving Credit Facility”), which matures in November 2012.  This credit facility has a term-out option that allows for EPO on the maturity date to convert the principal balance of all revolving loans then outstanding into a non-revolving one-year term loan.  The credit facility allows EPO to request unlimited one-year extensions of the maturity date, subject to lender approval.  The total amount of the bank commitments may be increased, without the consent of the lenders, by an amount not exceeding $500.0 million by adding one or more lenders to the facility and/or requesting that the commitments of existing lenders be increased.

As defined by the credit agreement, variable interest rates charged under this facility bear interest at a Eurodollar rate plus an applicable margin.  In addition, EPO is required to pay a quarterly facility fee on each lender’s commitment irrespective of commitment usage.  The applicable margins will be increased by 0.1% per annum for each day that the total outstanding loans and letter of credit obligations under the facility exceeds 50% of the total lender commitments.  Also, if EPO exercises its term-out option at the maturity date, the applicable margin will increase by 0.125% per annum and, if immediately prior to such election, the total amount of outstanding loans and letter of credit obligations under the facility exceeds 50% of the total lender commitments, the applicable margin with respect to the term loan will increase by an additional 0.1% per annum.

The Multi-Year Revolving Credit Facility contains certain financial and other customary affirmative and negative covenants.  The credit agreement also restricts EPO’s ability to pay cash distributions to Enterprise Products Partners if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid.

EPO’s borrowings under this agreement are unsecured general obligations that are non-recourse to EPGP.  Enterprise Products Partners has guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.

Pascagoula MBFC Loan.  This loan, from the Mississippi Business Finance Corporation (“MBFC”), matured on March 1, 2010 and was repaid.
 
Petal GO Zone Bonds.  In August 2007, Petal Gas Storage, L.L.C. (“Petal”), a wholly owned subsidiary of EPO, borrowed $57.5 million from the MBFC pursuant to a loan agreement and promissory note between Petal and the MBFC.  The promissory note between Petal and MBFC is guaranteed by EPO and supported by a letter of credit issued by a bank that expires in August 2014.  On the same date, the MBFC issued $57.5 million in Gulf Opportunity Zone Tax-Exempt (“GO Zone”) bonds to various third parties.  The promissory note and the GO Zone bonds have identical terms including floating interest rates and maturities of 30 years. 

Petal MBFC Loan.  In August 2007, Petal entered into a loan agreement and a promissory note with the MBFC under which Petal may borrow up to $29.5 million.  On the same date, the MBFC issued


taxable bonds to EPO in the maximum amount of $29.5 million.  At December 31, 2009, there was $8.9 million outstanding under the loan and the bonds.  The promissory note and the taxable bonds have identical terms.  The loan and bonds and the related interest expense and income amounts are netted in preparing our consolidated financial statements.

Japanese Yen Term Loan.  In November 2008, EPO executed the Yen Term Loan in the amount of approximately 20.7 billion yen (approximately $217.6 million U.S. Dollar equivalent on the closing date).  EPO entered into foreign exchange currency swaps that effectively converted the loan into a U.S. Dollar loan with a fixed interest rate of approximately 4.93%.  The Yen Term Loan matured on March 30, 2009.  Additionally, EPO executed a forward purchase exchange (yen principal and interest due) at an exchange rate of 94.515 to eliminate foreign exchange risk, resulting in a payment of US$221.6 million on March 30, 2009.

364-Day Revolving Credit Facility.   From November 2008 through June 2009, EPO had a $375.0 million standby credit facility.  The facility was never utilized and was terminated in June 2009 under its terms as a result of issuing senior notes.

Senior Notes.  EPO’s senior fixed-rate notes are unsecured obligations of EPO and rank equally with its existing and future unsecured and unsubordinated indebtedness.  They are senior to any future subordinated indebtedness.  EPO’s borrowings under these notes are non-recourse to EPGP.  Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee.  Enterprise Products Partners’ guarantee of such notes is non-recourse to EPGP.  EPO’s senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict EPO’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

In June 2009, EPO issued $500.0 million in principal amount of 3-year senior unsecured notes (Senior Notes P) at 99.95% of their principal amount.  In October 2009, EPO issued: (i) $500.0 million in principal amount of 10-year unsecured notes (Senior Notes Q) at 99.355% of their principal amount and (ii) $600.0 million in principal amount of 30-year unsecured notes (Senior Notes R) at 99.386% of their principal amount.  Net proceeds from the issuance of these senior notes were used (i) to repay amounts borrowed under a $200.0 million term loan that EPO entered into during April 2009, (ii) to repay $500.0 million in aggregate principal amount of Senior Notes F that matured in October 2009, (iii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and (iv) for general partnership purposes.

In connection with the TEPPCO Merger, EPO offered to exchange all of TEPPCO’s outstanding senior notes for a corresponding series of new EPO senior notes.  The exchanges were completed on October 27, 2009 as follows:

TEPPCO
Notes
Exchanged
Corresponding
Series of New
EPO Notes
  
Aggregate
Principal
Amount
    
Principal
Amount
Exchanged
    
Principal
Amount
Remaining
  
TEPPCO Senior Notes, 7.625% fixed-rate, due February 2012
Senior Notes S, 7.625%
fixed-rate, due February 2012
   $ 500.0     $ 490.5     $ 9.5  
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013
Senior Notes T, 6.125%
fixed-rate, due February 2013
     200.0       182.5       17.5  
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013
Senior Notes U, 5.90%
fixed-rate, due April 2013
     250.0       237.6       12.4  
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018
Senior Notes V, 6.65%
fixed-rate, due April 2018
     350.0       349.7       0.3  
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038
Senior Notes W, 7.55%
fixed-rate, due April 2038
     400.0       399.6       0.4  
      $ 1,700.0     $ 1,659.9     $ 40.1  

Junior Subordinated Notes.  EPO’s payment obligations under its junior notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement).  Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and


subordinated guarantee.  The indenture agreement governing these notes allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions.  During any period in which interest payments are deferred and subject to certain exceptions, neither Enterprise Products Partners nor EPO can declare or make any distributions to any of its respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or are subordinate to the junior notes.  Each series of our subordinated junior notes are ranked equally with each other.  Generally, each series of junior subordinated notes are not redeemable by EPO without payment of a make-whole premium while the notes bear interest at a fixed annual rate.

In connection with the issuance of each series of junior subordinated notes, EPO entered into separate Replacement Capital Covenants in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed for the benefit of such debt holders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities.

In connection with the TEPPCO Merger, EPO offered to exchange TEPPCO’s outstanding junior subordinated notes for a corresponding series of new EPO junior subordinated notes.  The exchange was completed on October 27, 2009:

TEPPCO
Notes
Exchanged
Corresponding
Series of New
EPO Notes
  
Aggregate
Principal
Amount
    
Principal
Amount
Exchanged
    
Principal
Amount
Remaining
  
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067
   $ 300.0     $ 285.8     $ 14.2  

The following table summarizes the interest rate terms of our junior subordinated notes:

   
Variable Annual
 
Fixed Annual
Interest Rate
Series
Interest Rate
Thereafter
Junior Subordinated Notes A
8.375% through August 2016 (1)
3-month LIBOR rate + 3.708%  (4)
Junior Subordinated Notes B
7.034%  through January 2018 (2)
Greater of:  (i) 3-month LIBOR rate + 2.68%  or (ii) 7.034%  (5)
Junior Subordinated Notes C
7.00%  through June 2017 (3)
3-month LIBOR rate + 2.778%  (6)
     
(1)   Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007.
(2)   Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008.
(3)   Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009.
(4)   Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016.
(5)   Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018.
(6)   Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017.

TEPPCO’s Debt Obligations

TEPPCO Revolving Credit Facility.  Upon consummation of the TEPPCO Merger, EPO repaid and terminated all of the outstanding indebtedness under the TEPPCO Revolving Credit Facility.

TEPPCO Senior Notes.  As previously discussed, on October 27, 2009, $1.66 billion of the TEPPCO Senior Notes were exchanged for an equal amount of new EPO Senior Notes.  In addition to the debt exchange, substantially all of the restrictive covenants and reporting requirements associated with the remaining TEPPCO Senior Notes were eliminated through amendments that became effective on October 26, 2009.

TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. (collectively, the “Subsidiary Guarantors”) acted as guarantors of TEPPCO’s outstanding senior notes through November 2009.  The subsidiary guarantees were terminated in November 2009.


TEPPCO Junior Subordinated Notes.  As discussed above, on October 27, 2009, $285.8 million of the TEPPCO Junior Subordinated Notes were exchanged for an equal amount of new EPO Junior Subordinated Notes.  In addition to the debt exchange, substantially all of the restrictive covenants and reporting requirements associated with the remaining TEPPCO Junior Subordinated Notes were eliminated through amendments that became effective on October 26, 2009.

The Subsidiary Guarantors also acted as guarantors, on a junior subordinated basis, of TEPPCO’s outstanding junior subordinated notes through November 2009.  These subsidiary guarantees were terminated in November 2009.

The terms and provisions of the TEPPCO’s Junior Subordinated Notes are similar to each series of EPO’s junior subordinated notes.  For example, they: (i) are general unsecured subordinated obligations, (ii) allow interest payments to be deferred for multiple periods of up to ten consecutive years and (iii) are subordinated in right of payment to all existing and future senior indebtedness.  The maturity date, the interest rate and the interest payment due dates are the identical to EPO’s Junior Subordinated Notes C as discussed above.

In connection with the issuance of the TEPPCO Junior Subordinated Notes, TEPPCO and its Subsidiary Guarantors entered into a Replacement Capital Covenant in favor of the covered debt holders (as defined in the underlying documents) pursuant to which TEPPCO agreed for the benefit of such debt holders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities.  The Replacement Capital Covenant is not a term of the governing indenture or the junior subordinated notes.
 
Duncan Energy Partners’ Debt Obligations

Enterprise Products Partners consolidates the debt of Duncan Energy Partners with that of its own; however, Enterprise Products Partners does not have the obligation to make interest payments or debt payments with respect to the debt of Duncan Energy Partners.

DEP Revolving Credit Facility.  Duncan Energy Partners has in place a $300 million unsecured revolving credit facility, all of which may be used for letters of credit, with a $30.0 million sublimit for Swingline loans.  This credit facility will be used by Duncan Energy Partners in the future to fund working capital and other capital requirements and for general partnership purposes.  Duncan Energy Partners may make up to two requests for one-year extensions of the maturity date, which is February 2011 (subject to certain restrictions).  The revolving credit facility is available to pay distributions to its partners, fund working capital, make acquisitions and provide payment for general purposes.  Duncan Energy Partners can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150.0 million, by adding to the facility one or more new lenders and/or requesting that the commitments of existing lenders be increased.

This revolving credit facility offers the following unsecured loans, each having different interest requirements: (i) a Eurodollar rate, plus the applicable Eurodollar margin (as defined in the credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal to the higher of (a) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii) Swingline loans bear interest at a rate per annum equal to LIBOR plus an applicable LIBOR margin.

The Duncan Energy Partners’ credit facility contains certain financial and other customary affirmative and negative covenants.  Also, if an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity date of amounts borrowed under the credit agreement and exercise other rights and remedies.

DEP Term Loan.  In April 2008, Duncan Energy Partners entered into a standby term loan agreement consisting of commitments for up to a $300.0 million senior unsecured term loan.  Subsequently, commitments under this agreement decreased to $282.3 million due to bankruptcy of one of


the lenders.  Duncan Energy Partners borrowed the full amount of $282.3 million on December 8, 2008 in connection with the acquisition of equity interests in midstream energy businesses.

Duncan Energy Partners may prepay loans under the term loan agreement at any time, subject to prior notice in accordance with the credit agreement.  Loans may also be payable earlier in connection with an event of default.

Loans under the term loan agreement bear interest of the type specified in the applicable borrowing request, and consist of either Alternate Base Rate loans or Eurodollar loans.  The term loan agreement contains certain financial and other customary affirmative and negative covenants.

Dixie Revolving Credit Facility

Dixie’s debt obligation consisted of a senior, unsecured revolving credit facility having a borrowing capacity of $28.0 million.  This credit facility was terminated in January 2009.

Canadian Debt Obligation

In May 2007, Canadian Enterprise Gas Products, Ltd., a wholly owned subsidiary of EPO, entered into a $30.0 million Canadian revolving credit facility with The Bank of Nova Scotia.  The credit facility, which includes the issuance of letters of credit, matures in October 2011.  Letters of credit outstanding under this facility reduce the amount available for borrowings.  The credit facility contains customary covenants and events of default.  The obligations under the credit facility are guaranteed by EPO.  As of December 31, 2009, there were no debt obligations outstanding under this credit facility.

Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2009.

Information Regarding Variable Interest Rates Paid

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt obligations during the year ended December 31, 2009:

 
Range of
Weighted-Average
 
Interest Rates
Interest Rate
 
Paid
Paid
EPE Revolver
1.23% to 3.25%
1.63%
EPE Term Loan A
1.23% to 3.20%
1.63%
EPE Term Loan B
2.48% to 6.77%
3.00%
EPO Multi-Year Revolving Credit Facility
0.73% to 3.25%
0.95%
TEPPCO Revolving Credit Facility
0.75% to 3.25%
0.88%
DEP Revolving Credit Facility
0.81% to 2.74%
1.48%
DEP Term Loan
0.93% to 2.93%
1.15%
Petal GO Zone Bonds
0.21% to 2.75%
0.60%












Consolidated Debt Maturity Table

The following table presents contractually scheduled maturities of our consolidated debt obligations for the next five years, and in total thereafter.

         
Scheduled Maturities of Debt
  
                                       
After
  
   
Total
    
2010 (1)
    
2011
    
2012
    
2013
    
2014
    
2014
  
Revolving Credit Facilities
   $ 494.0     $ --     $ 175.0     $ 319.0     $ --     $ --     $ --  
Senior Notes
     9,000.0       500.0       450.0       1,000.0       1,200.0       1,150.0       4,700.0  
Term Loans
     1,240.3       8.5       290.8       133.5       8.5       799.0       --  
Junior Subordinated Notes
     1,532.7       --       --       --       --       --       1,532.7  
Other
     111.5       54.0       --       --       --       --       57.5  
   Total
   $ 12,378.5     $ 562.5     $ 915.8     $ 1,452.5     $ 1,208.5     $ 1,949.0     $ 6,290.2  
                                                         
(1)   Long-term and current maturities of debt reflect the classification of such obligations on our Consolidated Balance Sheet at December 31, 2009 after taking into consideration EPO’s ability to use available borrowing capacity under its Multi-Year Revolving Credit Facility and the Parent Company’s ability to use available borrowing capacity under the EPE Revolver.
  

Debt Obligations of Unconsolidated Affiliates

We have three unconsolidated affiliates with long-term debt obligations.  The following table shows (i) the ownership interest in each entity at December 31, 2009, (ii) total debt of each unconsolidated affiliate at December 31, 2009 (on a 100% basis to the unconsolidated affiliate) and (iii) the corresponding scheduled maturities of such debt.

               
Scheduled Maturities of Debt
  
   
Ownership
                                        
After
  
   
Interest
    
Total
    
2010
    
2011
    
2012
    
2013
    
2014
    
2014
  
Poseidon
   36%     $ 92.0     $ --     $ 92.0     $ --     $ --     $ --     $ --  
Evangeline
   49.5%       10.7       3.2       7.5       --       --       --       --  
Centennial
   50%       120.0       9.1       9.0       8.9       8.6       8.6       75.8  
   Total
           $ 222.7     $ 12.3     $ 108.5     $ 8.9     $ 8.6     $ 8.6     $ 75.8  

The credit agreements of these unconsolidated affiliates include customary covenants, including financial covenants.  These businesses were in compliance with such financial covenants at December 31, 2009.  The credit agreements of these unconsolidated affiliates restrict their ability to pay cash dividends or distributions if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend or distribution is scheduled to be paid.

The following information summarizes the significant terms of the debt obligations of these unconsolidated affiliates at December 31, 2009:

Poseidon.  At December 31, 2009, Poseidon’s debt obligations consisted of $92.0 million outstanding under its $150.0 million variable-rate revolving credit facility.  Amounts borrowed under this facility mature in May 2011 and are secured by substantially all of Poseidon’s assets.  The weighted-average variable interest rates charged on this debt at December 31, 2009 and 2008 were 1.88% and 4.31%, respectively.

Evangeline.  At December 31, 2009, Evangeline’s debt obligations consisted of: (i) $3.2 million in principal amount of 9.90% fixed-rate Series B senior secured notes due December 2010 and (ii) a $7.5 million subordinated note payable due in 2011.  The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract and by a debt service reserve requirement.

Evangeline incurred the subordinated note payable as a result of its acquisition of a contract-based intangible asset in the early 1990s.  This note is subject to a subordination agreement which prevents the


repayment of principal and accrued interest on the subordinated note until such time as the Series B noteholders are either fully cash secured through debt service accounts or have been completely repaid.
 
Variable-rate interest accrues on the subordinated note at LIBOR plus 0.5%.  The weighted-average variable interest rates charged on this note at December 31, 2009 and 2008 were 1.59% and 3.62%, respectively.  Accrued interest payable related to the subordinated note was $10.2 million and $9.8 million at December 31, 2009 and 2008, respectively.

Centennial.  At December 31, 2009, Centennial’s debt obligations consisted of $120.0 million borrowed under a master shelf loan agreement through two private placements, with interest rates ranging from 7.99% to 8.09%.  Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial’s assets and severally guaranteed by Centennial’s owners.

We and our joint venture partner in Centennial have each guaranteed one-half of Centennial’s debt obligations.  If Centennial were to default on its debt obligations, the estimated payment obligation would be $60.0 million based on amounts outstanding at December 31, 2009.  We recognized a liability of $8.4 million for our share of the Centennial debt guaranty at December 31, 2009.


Note 13.  Equity and Distributions

Our Units represent limited partner interests, which give the holders thereof the right to participate in cash distributions and to exercise the other rights or privileges available to them under our First Amended and Restated Agreement of Limited Partnership (as amended from time to time, the “Partnership Agreement”).

In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and limited partners.  The capital account provisions of the Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to GAAP-based equity amounts presented in our consolidated financial statements.  Earnings and cash distributions are allocated to holders of our Units in accordance with their respective percentage interests.

Registration Statement

The Parent Company has a universal shelf registration statement on file with the SEC that allows it to issue an unlimited amount of debt and equity securities for general partnership purposes.  As of December 31, 2009, the Parent Company had not issued any securities under its registration statement.

Class B and C Units

In May 2007, we issued an aggregate of 14,173,304 Class B Units and 16,000,000 Class C Units to private company affiliates of EPCO in connection with their contribution of 4,400,000 common units representing limited partner interest of TEPPCO and 100% of the general partner interest of TEPPCO GP.

On July 12, 2007, all of the outstanding 14,173,304 Class B Units were converted into Units on a one-to-one basis.  On February 1, 2009, all of the outstanding 16,000,000 Class C Units were converted to Units on a one-to-one basis.  For financial accounting purposes, the Class C Units were not allocated any portion of net income until their conversion into Units.  In addition, the Class C Units were non-participating in current or undistributed earnings prior to conversion.  The Units into which the Class C Units were converted were eligible to receive cash distributions beginning with the distribution paid in May 2009.

Prior to February 1, 2009, the Class C Units (i) entitled the holder to the allocation of taxable income, gain, loss, deduction and credit to the same extent as such tax amounts were allocated to the holder if the Class C Units were converted and outstanding Units and (ii)  were non-voting, except that, the Class C Units were entitled to vote as a separate class on any matter that adversely affected the rights or


preferences of the Class C Units in relation to other classes of partnership interests (including as a result of a merger or consolidation) or as required by law.  The approval of a majority of the Class C Units was required to approve any matter for which the holders of the Class C Units were entitled to vote as a separate class.

Private Placement of Parent Company Units

On July 17, 2007, the Parent Company completed a private placement of 20,134,220 Units to third-party investors at $37.25 per Unit.  The net proceeds of this private placement, after giving effect to placement agent fees, were approximately $739.0 million.  The net proceeds were used to repay certain principal amounts outstanding under the EPE Interim Credit Facility and related accrued interest.  Effective October 5, 2007, these Units were registered for resale.

Unit History

The following table summarizes changes in our outstanding Units since December 31, 2006:

         
Class B
    
Class C
  
   
Units
    
Units
    
Units
  
Balance, December 31, 2006
     88,884,116       14,173,304       16,000,000  
Conversion of Class B Units to Units in July 2007
     14,173,304       (14,173,304 )     --  
Units issued in connection private placement in July 2007
     20,134,220       --       --  
Balance, December 31, 2007 and 2008
     123,191,640       --       16,000,000  
Conversion of Class C Units to Units in February 2009
     16,000,000       --       (16,000,000 )
Balance, December 31, 2009
     139,191,640       --       --  

Summary of Changes in Limited Partners’ Equity

The following table details the changes in limited partners’ equity since December 31, 2006:

         
Class B
    
Class C
        
   
Units
    
Units
    
Units
    
Total
  
Balance, December 31, 2006
   $ 681.0     $ 357.1     $ 380.7     $ 1,418.8  
Net income
     75.6       33.4       --       109.0  
Operating lease expenses paid by EPCO
     0.1       --       --       0.1  
Cash distributions paid to partners
     (159.0 )     --       --       (159.0 )
Distributions to former owners
     --       (29.8 )     --       (29.8 )
Conversion of Class B Units to Units
     360.7       (360.7 )     --       --  
Net cash proceeds from issuance of Units
     739.4       --       --       739.4  
Amortization of equity awards
     0.6       --       --       0.6  
Balance, December 31, 2007
     1,698.4       --       380.7       2,079.1  
Net income
     164.0       --       --       164.0  
Operating lease expenses paid by EPCO
     0.1       --       --       0.1  
Cash distributions paid to partners
     (213.1 )     --       --       (213.1 )
Amortization of equity awards
     1.1       --       --       1.1  
Balance, December 31, 2008
     1,650.5       --       380.7       2,031.2  
Net income
     204.1       --       --       204.1  
Cash distributions paid to partners
     (266.7 )     --       --       (266.7 )
Conversion of Class C Units to Units
     380.7       --       (380.7 )     --  
Amortization of equity awards
     3.8       --       --       3.8  
Balance, December 31, 2009
   $ 1,972.4     $ --     $ --     $ 1,972.4  

Distributions to Partners

The Parent Company’s cash distribution policy is consistent with the terms of its Partnership Agreement, which requires it to distribute its available cash (as defined in our Partnership Agreement) to its partners no later than 50 days after the end of each fiscal quarter.  The quarterly cash distributions are not cumulative.


The following table presents the Parent Company’s declared quarterly cash distribution rates per Unit since the first quarter of 2008 and the related record and distribution payment dates.  The quarterly cash distribution rates per Unit correspond to the fiscal quarters indicated.  Actual cash distributions are paid within 50 days after the end of such fiscal quarter.

   
Cash Distribution History
   
Distribution
  
Record
Payment
   
per Unit
  
Date
Date
2008
          
1st Quarter
   $ 0.425  
Apr. 30, 2008
May 8, 2008
2nd Quarter
   $ 0.440  
Jul. 31, 2008
Aug. 8, 2008
3rd Quarter
   $ 0.455  
Oct. 31, 2008
Nov. 13, 2008
4th Quarter
   $ 0.470  
Jan. 30, 2009
Feb. 10, 2009
2009
            
1st Quarter
   $ 0.485  
Apr. 30, 2009
May 11, 2009
2nd Quarter
   $ 0.500  
Jul. 31, 2009
Aug. 10, 2009
3rd Quarter
   $ 0.515  
Oct. 30, 2009
Nov. 6, 2009
4th Quarter
   $ 0.530  
Jan. 29, 2010
Feb. 5, 2010

Accumulated Other Comprehensive Loss

AOCI primarily includes the effective portion of the gain or loss on derivative instruments designated and qualified as a cash flow hedge, foreign currency adjustments and minimum pension liability adjustments.  Amounts accumulated in OCI from cash flow hedges are reclassified into earnings in the same period(s) in which the hedged forecasted transactions (such as a forecasted forward sale of NGLs) affect earnings.  If it becomes probable that the forecasted transaction will not occur, the net gain or loss in AOCI must be immediately reclassified.

The following table presents the components of AOCI at the dates indicated:

   
At December 31,
  
   
2009
    
2008
  
Commodity derivative instruments (1)
   $ 0.5     $ (114.1 )
Interest rate derivative instruments (1)
     (27.6 )     (66.5 )
Foreign currency derivative instruments (1)
     0.4       10.6  
Foreign currency translation adjustment (2)
     0.8       (1.3 )
Pension and postretirement benefit plans
     (0.8 )     (0.8 )
Proportionate share of other comprehensive loss of
                
unconsolidated affiliates, primarily Energy Transfer Equity
     (11.2 )     (13.7 )
    Subtotal
     (37.9 )     (185.8 )
         Amount attributable to noncontrolling interest
     4.6       132.6  
    Total AOCI in partners’ equity
   $ (33.3 )   $ (53.2 )
                 
(1)   See Note 6 for additional information regarding these components of AOCI.
(2)   Relates to transactions of Enterprise Products Partners’ Canadian NGL marketing subsidiary.
  

Noncontrolling Interest

Prior to the completion of the TEPPCO Merger, effective October 26, 2009, we accounted for the former owners’ interest in TEPPCO and TEPPCO GP as noncontrolling interest.  Under this method of presentation, all pre-merger revenues and expenses of TEPPCO and TEPPCO GP are included in net income, and the former owners’ share of the income of TEPPCO and TEPPCO GP is allocated to net income attributable to noncontrolling interest.  In addition, the former owners’ share of the net assets of TEPPCO and TEPPCO GP are presented as noncontrolling interest, a component of equity, on our Consolidated Balance Sheets.





The following table presents the components of noncontrolling interest as presented on our Consolidated Balance Sheets at the dates indicated:

   
 At December 31,
  
   
2009
    
2008
  
Limited partners of Enterprise Products Partners:
            
     Third-party owners of Enterprise Products Partners (1)
   $ 7,001.6     $ 5,010.6  
     Related party owners of Enterprise Products Partners (2)
     1,003.6       347.7  
Limited partners of Duncan Energy Partners:
                
     Third-party owners of Duncan Energy Partners (1)
     414.3       281.1  
     Related party owners of Duncan Energy Partners (2)
     1.7       --  
Former owners of TEPPCO (3)
     --       2,126.5  
Joint venture partners (4)
     117.4       148.1  
AOCI attributable to noncontrolling interest
     (4.6 )     (132.6 )
         Total noncontrolling interest on consolidated balance sheets
   $ 8,534.0     $ 7,781.4  
                 
(1)   Consists of non-affiliate public unitholders of Enterprise Products Partners and Duncan Energy Partners. The increase in noncontrolling interest between periods for these entities is primarily due to equity offerings.
(2)   Consists of unitholders of Enterprise Products Partners and Duncan Energy Partners that are related party affiliates of the Parent Company. This group is primarily comprised of EPCO and certain of its private company consolidated subsidiaries.
(3)   Represents former ownership interests in TEPPCO and TEPPCO GP (see Note 1 “Basis of Presentation”). This amount excludes AOCI attributable to former owners of TEPPCO.
(4)   Represents third-party ownership interests in joint ventures that we consolidate, including Seminole, Tri-States Pipeline L.L.C., Independence Hub LLC and Wilprise Pipeline Company LLC. The balance at December 31, 2008 included $35.6 million related to Oiltanking’s ownership interest in TOPS, from which our subsidiaries dissociated in April 2009 (see Note 8).
  

The following table presents the components of net income attributable to noncontrolling interest as presented on our Statements of Consolidated Operations for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Limited partners of Enterprise Products Partners (1)
   $ 825.5     $ 786.5     $ 404.8  
Limited partners of Duncan Energy Partners (1)
     31.3       17.3       13.8  
Former owners of TEPPCO (2)
     53.0       153.3       217.6  
Joint venture partners
     26.4       24.0       16.8  
        Total
   $ 936.2     $ 981.1     $ 653.0  
                         
(1)   Represents the allocation of Enterprise Products Partners’ and Duncan Energy Partners’ earnings to their respective unitholders, other than the Parent Company.
(2)   Represents the allocation of earnings to the former owners of TEPPCO.
  

The following table presents cash distributions paid to and cash contributions received from noncontrolling interests as presented on our Statements of Consolidated Cash Flows for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Cash distributions paid to noncontrolling interests:
                  
   Limited partners of Enterprise Products Partners
   $ 1,038.1     $ 865.7     $ 807.5  
   Limited partners of Duncan Energy Partners
     33.7       24.8       15.8  
   Limited partners of TEPPCO
     218.4       260.5       234.0  
   Joint venture partners
     31.9       31.1       16.6  
         Total cash distributions paid to noncontrolling interests
   $ 1,322.1     $ 1,182.1     $ 1,073.9  
Cash contributions from noncontrolling interests:
                        
   Limited partners of Enterprise Products Partners
   $ 875.4     $ 135.0     $ 68.0  
   Limited partners of Duncan Energy Partners
     137.4       --       290.5  
   Limited partners of TEPPCO
     3.5       275.8       1.7  
   Joint venture partners
     (2.1 )     35.6       12.5  
         Total cash contributions received from noncontrolling interests
   $ 1,014.2     $ 446.4     $ 372.7  



Distributions paid to the limited partners of Enterprise Products Partners, Duncan Energy Partners and former owners of TEPPCO primarily represent the quarterly cash distributions paid by these entities to their unitholders, excluding those paid to the Parent Company.
 
        Contributions received from limited partners of Enterprise Products Partners, Duncan Energy Partners and TEPPCO primarily represent net cash proceeds each entity received from common unit offerings and distribution reinvestment plans, excluding those received from the Parent Company.  During 2009, Enterprise Products Partners issued an aggregate of 36,950,014 of its common units, which generated net cash proceeds of approximately $911.0 million.  Additionally, during 2009 Duncan Energy Partners issued an aggregate 8,943,400 of its common units, which generated net cash proceeds of approximately $137.4 million.  During 2007, Duncan Energy Partners received approximately $291.0 million of net cash proceeds in connection with its initial public offering.  During 2008, TEPPCO sold 9,200,000 of its units in an underwritten equity offering, which generated net cash proceeds of $257.0 million.


Note 14.  Business Segments

We have six reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Onshore Crude Oil Pipelines & Services, Offshore Pipelines & Services, Petrochemical & Refined Products Services and Other Investments.  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 our 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 operating income before: (i) depreciation, amortization and accretion expense; (ii) non-cash consolidated asset impairment charges; (iii) operating lease expenses for which we do not have the payment obligation; (iv) gains and losses from asset sales and related transactions; and (v) general and administrative costs.  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 intercompany transactions.  In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation.  Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, the cumulative effect of changes in accounting principles and extraordinary charges.  Gross operating margin is presented on a 100% basis before the allocation of earnings to noncontrolling interests.

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

We include equity in income of 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 standalone basis.  Many of these businesses perform supporting or complementary roles to our other business operations.


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, refined products 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, refined products 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.  Additionally, our use of the Centennial pipeline, which loops the refined products pipeline system between Beaumont, Texas and southern Illinois, permits effective supply of product to points south of Illinois as well as incremental product supply capacity to mid-continent markets downstream of southern Illinois.  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.

Substantially all of our consolidated revenues are 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, refined products and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas, Louisiana, and onshore in Colorado; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); (iii) the Midwestern and northeastern United States; and (iv) certain regions of the central and western United States, including the Rocky Mountains.  Our marketing activities are headquartered in Houston, Texas and Oklahoma City, Oklahoma and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.

Segment assets consist of property, plant and equipment, investments in unconsolidated affiliates, intangible assets and goodwill.  The carrying values of such amounts are assigned to each segment based on each asset’s or investment’s principal operations and contribution to the gross operating margin of that particular segment.  Since construction-in-progress amounts (which are a component of property, plant and equipment) generally do not contribute to segment gross operating margin, such amounts 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 Enterprise Products Partners with those of our own.  As a result, our consolidated gross operating margin amounts include 100% of the gross operating margin amounts of Enterprise Products Partners.

















The following table shows our measurement of total segment gross operating margin for the periods indicated:

     
For Year Ended December 31,
  
     
2009
    
2008
    
2007
  
Revenues
   $ 25,510.9     $ 35,469.6     $ 26,713.8  
Less:
Operating costs and expenses
     (23,565.8 )     (33,618.9 )     (25,402.1 )
Add:
Equity in income of unconsolidated affiliates
     92.3       66.2       13.6  
 
Depreciation, amortization and accretion in operating costs and expenses (1)
     809.3       725.4       647.9  
 
Impairment charges in operating costs and expenses
     33.5       --       --  
 
Operating lease expenses paid by EPCO
     0.7       2.0       2.1  
 
Gain from asset sales and related transactions in operating
costs and expenses (2)
     --       (4.0 )     (7.8 )
Total segment gross operating margin
   $ 2,880.9     $ 2,640.3     $ 1,967.5  
                         
(1)   Amount is a component of “Depreciation, amortization and accretion” as presented on the Statements of Consolidated Cash Flows.
(2)   Amount is a component of “Gain from asset sales and related transactions” as presented on the Statements of Consolidated Cash Flows.
  

The following table shows a reconciliation of our total segment gross operating margin to operating income and income before provision for income taxes for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Total segment gross operating margin
   $ 2,880.9     $ 2,640.3     $ 1,967.5  
Adjustments to reconcile total segment gross operating margin
                        
to operating income:
                        
Depreciation, amortization and accretion in operating costs and expenses
     (809.3 )     (725.4 )     (647.9 )
Impairment charges in operating costs and expenses
     (33.5 )     --       --  
    Operating lease expenses paid by EPCO
     (0.7 )     (2.0 )     (2.1 )
    Gain from asset sales and related transactions in operating
costs and expenses
     --       4.0       7.8  
   General and administrative costs
     (182.8 )     (144.8 )     (131.9 )
Operating income
     1,854.6       1,772.1       1,193.4  
   Other expense, net
     (689.0 )     (596.0 )     (415.6 )
Income before provision for income taxes
   $ 1,165.6     $ 1,176.1     $ 777.8  































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

   
Reportable Segments
              
         
Onshore
    
Onshore
          
Petrochemical
                    
   
NGL
   Natural Gas   
Crude Oil
    
Offshore
    
& Refined
          
Adjustments
        
   
Pipelines
    
Pipelines
    
Pipelines
    
Pipelines
    
Products
    
Other
    
and
    
Consolidated
  
   
& Services
    
& Services
    
& Services
    
& Services
    
Services
    
Investments
    
Eliminations
    
Totals
  
Revenues from third parties:
                                                
     Year ended December 31, 2009
   $ 11,928.3     $ 2,938.7     $ 7,191.2     $ 332.9     $ 2,520.8     $ --     $ --     $ 24,911.9  
     Year ended December 31, 2008
     14,715.8       3,407.2       12,763.8       260.3       3,307.1       --       --       34,454.2  
     Year ended December 31, 2007
     12,149.2       2,044.0       9,103.7       222.6       2,609.1       --       --       26,128.6  
Revenues from related parties:
                                                                
     Year ended December 31, 2009
     380.7       211.2       (0.2 )     7.0       0.3       --       --       599.0  
     Year ended December 31, 2008
     598.0       409.2       --       8.1       0.1       --       --       1,015.4  
     Year ended December 31, 2007
     301.5       281.9       0.1       1.2       0.5       --       --       585.2  
Intersegment and intrasegment revenues:
                                                                
     Year ended December 31, 2009
     6,865.5       515.3       47.6       1.3       612.3       --       (8,042.0 )     --  
     Year ended December 31, 2008
     8,091.7       881.6       75.1       1.4       663.3       --       (9,713.1 )     --  
     Year ended December 31, 2007
     5,436.3       205.5       48.6       2.0       522.6       --       (6,215.0 )     --  
Total revenues:
                                                                
     Year ended December 31, 2009
     19,174.5       3,665.2       7,238.6       341.2       3,133.4       --       (8,042.0 )     25,510.9  
     Year ended December 31, 2008
     23,405.5       4,698.0       12,838.9       269.8       3,970.5       --       (9,713.1 )     35,469.6  
     Year ended December 31, 2007
     17,887.0       2,531.4       9,152.4       225.8       3,132.2       --       (6,215.0 )     26,713.8  
Equity in income of unconsolidated affiliates:
                                                                
     Year ended December 31, 2009
     11.3       4.9       9.3       36.9       (11.2 )     41.1       --       92.3  
     Year ended December 31, 2008
     1.4       1.6       11.7       33.7       (13.5 )     31.3       --       66.2  
     Year ended December 31, 2007
     7.1       0.2       2.6       12.6       (12.0 )     3.1       --       13.6  
Gross operating margin:
                                                                
     Year ended December 31, 2009
     1,628.7       501.5       164.4       180.5       364.7       41.1       --       2,880.9  
     Year ended December 31, 2008
     1,325.0       589.9       132.2       187.0       374.9       31.3       --       2,640.3  
     Year ended December 31, 2007
     848.0       493.2       109.6       171.6       342.0       3.1       --       1,967.5  
Segment assets:
                                                                
     At December 31, 2009
     7,191.2       6,918.7       865.3       2,121.4       3,359.0       1,525.6       1,207.3       23,188.5  
     At December 31, 2008
     6,459.3       6,118.8       883.0       2,061.8       3,308.9       1,598.8       2,015.4       22,446.0  
     At December 31, 2007
     5,488.5       5,502.3       858.8       2,152.3       2,631.9       1,653.4       1,588.3       19,875.5  
Property, plant and equipment, net (see Note 8):
                                                                
     At December 31, 2009
     6,392.8       6,074.6       377.3       1,480.9       2,156.3       --       1,207.3       17,689.2  
     At December 31, 2008
     5,622.4       5,223.6       386.9       1,394.5       2,090.0       --       2,015.4       16,732.8  
     At December 31, 2007
     4,770.4       4,577.4       363.7       1,452.6       1,556.7       --       1,588.3       14,309.1  
Investments in unconsolidated affiliates (see Note 9):                                                           
     At December 31, 2009
     141.6       32.0       178.5       456.9       81.6       1,525.6       --       2,416.2  
     At December 31, 2008
     144.3       25.9       186.2       469.0       86.5       1,598.8       --       2,510.7  
     At December 31, 2007
     117.0       3.5       184.8       484.6       95.7       1,653.4       --       2,539.0  
Intangible assets, net (see Note 11):
                                                                
     At December 31, 2009
     315.6       527.2       6.5       101.5       114.0       --       --       1,064.8  
     At December 31, 2008
     351.4       584.4       6.9       116.2       124.0       --       --       1,182.9  
     At December 31, 2007
     375.1       636.5       7.3       133.0       62.2       --       --       1,214.1  
Goodwill (see Note 11):
                                                                
     At December 31, 2009
     341.2       284.9       303.0       82.1       1,007.1       --       --       2,018.3  
     At December 31, 2008
     341.2       284.9       303.0       82.1       1,008.4       --       --       2,019.6  
     At December 31, 2007
     226.0       284.9       303.0       82.1       917.3       --       --       1,813.3  

Our consolidated revenues are derived from a wide customer base.  During 2009, our largest non-affiliated customer based on revenues was Shell Oil Company and its affiliates, which accounted for 9.8% of our revenues.  During 2008 and 2007, our largest non-affiliated customer based on revenues was Valero Energy Corporation and its affiliates, which accounted for 11.2% and 8.9%, respectively, of our revenues.

 
The following table provides additional information regarding our consolidated revenues (net of adjustments and eliminations) and expenses for the periods indicated:
 
   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
NGL Pipelines & Services:
                  
 Sales of NGLs
   $ 11,598.9     $ 14,573.5     $ 11,701.3  
 Sales of other petroleum and related products
     1.8       2.4       3.0  
 Midstream services
     708.3       737.9       746.4  
       Total
     12,309.0       15,313.8       12,450.7  
Onshore Natural Gas Pipelines & Services:
                        
 Sales of natural gas
     2,410.5       3,083.1       1,676.7  
 Midstream services
     739.4       733.3       649.2  
       Total
     3,149.9       3,816.4       2,325.9  
Onshore Crude Oil Pipelines & Services:
                        
 Sales of crude oil
     7,110.6       12,696.2       9,048.5  
 Midstream services
     80.4       67.6       55.3  
       Total
     7,191.0       12,763.8       9,103.8  
Offshore Pipelines & Services:
                        
 Sales of natural gas
     1.2       2.8       3.2  
 Sales of crude oil
     5.3       11.1       12.1  
 Midstream services
     333.4       254.5       208.5  
   Total
     339.9       268.4       223.8  
Petrochemical & Refined Products Services:
                        
 Sales of other petroleum and related products
     1,991.8       2,757.6       2,207.2  
 Midstream services
     529.3       549.6       402.4  
       Total
     2,521.1       3,307.2       2,609.6  
Total consolidated revenues
   $ 25,510.9     $ 35,469.6     $ 26,713.8  
                         
Consolidated costs and expenses
                        
   Operating costs and expenses:
                        
Cost of sales for our marketing activities
   $ 18,656.7     $ 28,250.2     $ 21,142.5  
Depreciation, amortization and accretion
     809.3       725.4       647.9  
Gain on sale of assets and related transactions
     --       (4.0 )     (7.8 )
Non-cash impairment charges
     33.5       --       --  
Other operating costs and expenses
     4,066.3       4,647.3       3,619.5  
   General and administrative costs
     182.8       144.8       131.9  
Total consolidated costs and expenses
   $ 23,748.6     $ 33,763.7     $ 25,534.0  















 
Note 15.  Related Party Transactions

The following table summarizes our related party transactions for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Revenues – related parties:
                  
EPCO and affiliates
   $ --     $ --     $ 0.2  
Energy Transfer Equity and subsidiaries
     423.1       618.5       294.5  
Unconsolidated affiliates
     175.9       396.9       290.5  
   Total revenue – related parties
   $ 599.0     $ 1,015.4     $ 585.2  
Costs and expenses – related parties:
                        
EPCO and affiliates
   $ 592.5     $ 555.4     $ 470.7  
Energy Transfer Equity and subsidiaries
     443.8       192.2       35.2  
Cenac and affiliates
     40.9       48.3       --  
Unconsolidated affiliates
     38.2       56.1       41.0  
   Total costs and expenses – related parties
   $ 1,115.4     $ 852.0     $ 546.9  
Other expense – related parties:
                        
EPCO and affiliates
   $ 4.1     $ 0.3     $ 0.2  

The following table summarizes our related party receivable and payable amounts at the dates indicated:

   
December 31,
  
   
2009
    
2008
  
Accounts receivable - related parties:
            
EPCO and affiliates
   $ --     $ 0.2  
Energy Transfer Equity and subsidiaries
     28.2       35.0  
Other
     10.2       --  
Total accounts receivable – related parties
   $ 38.4     $ 35.2  
                 
Accounts payable - related parties:
                
EPCO and affiliates
   $ 27.8     $ 14.1  
Energy Transfer Equity and subsidiaries
     33.4       0.1  
Other
     9.6       3.4  
Total accounts payable – related parties
   $ 70.8     $ 17.6  

           We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Relationship with EPCO and Affiliates

We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not a part of our consolidated group of companies:

§  
EPCO and its privately held affiliates;

§  
EPE Holdings, our sole general partner; and

§  
the Employee Partnerships (see Note 5).


EPCO is a privately held company controlled by Dan L. Duncan, who is also a Director and Chairman of EPE Holdings and EPGP.  At December 31, 2009, EPCO and its affiliates beneficially owned interests in the following entities:
 
   
Percentage of
 
Number of Units
Outstanding Units
Enterprise Products Partners (1) (2)
191,363,613
31.3%
Parent Company (3)
108,503,133
78.0%
(1)   Includes 4,520,431 Class B units and 21,167,783 common units owned by the Parent Company.
(2)   The Parent Company owns 100% of Enterprise Products Partners’ general partner, EPGP.
(3)   An affiliate of EPCO owns 100% of our general partner.
 
The principal business activity of EPE Holdings and EPGP is to act as the sole managing partner of the Parent Company and Enterprise Products Partners, respectively.  The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.

The Parent Company, EPE Holdings, Enterprise Products Partners and EPGP are separate legal entities apart from each other and apart from EPCO and their respective other affiliates, with assets and liabilities that are separate from those of EPCO and their respective other affiliates.  EPCO and its privately held subsidiaries depend on the cash distributions they receive from the Parent Company, Enterprise Products Partners and other investments to fund their other operations and to meet their debt obligations.  The following table presents cash distributions received by EPCO and its privately held affiliates from the Parent Company and Enterprise Products Partners for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Enterprise Products Partners
   $ 314.5     $ 281.1     $ 263.4  
Parent Company
     205.2       158.7       125.5  
Total distributions
   $ 519.7     $ 439.8     $ 388.9  

Substantially all of the ownership interests in Enterprise Products Partners that are owned or controlled by the Parent Company are pledged as security under its credit facility.  In addition, substantially all of the ownership interests in the Parent Company and Enterprise Products Partners that are owned or controlled by EPCO and its affiliates, other than those interests owned by the Parent Company, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of a privately held affiliate of EPCO.  This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including the Parent Company and Enterprise Products Partners.

We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products.  We also lease office space in various buildings from affiliates of EPCO.  The rental rates in these lease agreements approximate market rates.

EPCO ASA

We have no employees.  All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA or by other service providers.  The Parent Company, Enterprise Products Partners, Duncan Energy Partners and their respective general partners are parties to the ASA.  The significant terms of the ASA are as follows:

§  
EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices).  EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.

§  
We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO).  In addition, we have agreed to pay all


sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.

§  
EPCO will allow us to participate as a named insured in its overall insurance program, with the associated premiums and other costs being allocated to us.

Under the ASA, EPCO subleases to Enterprise Products Partners (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to Enterprise Products Partners its purchase option under such leases (the “retained leases”).  EPCO remains liable for the actual cash lease payments associated with these agreements.  Enterprise Products Partners records the full value of these payments made by EPCO on its behalf as a non-cash related party operating lease expense, with the offset to equity accounted for as a general contribution to its partnership.

Our operating costs and expenses include amounts paid to EPCO for the costs it incurs to operate our facilities, including compensation of employees.  We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets.  Likewise, our general and administrative costs include amounts paid to EPCO for administrative services, including compensation of employees.  In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs).  The following table presents a breakout of costs and expenses related to the ASA and other EPCO transactions for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Operating costs and expenses
   $ 495.3     $ 463.2     $ 387.7  
General and administrative expenses
     97.2       92.2       83.0  
Total costs and expenses
   $ 592.5     $ 555.4     $ 470.7  

Since the vast majority of such expenses are charged to us on an actual basis (i.e. no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a standalone basis.  With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.

The ASA also addresses potential conflicts that may arise among the Parent Company (including EPE Holdings), Enterprise Products Partners (including EPGP), Duncan Energy Partners (including DEP GP), and the EPCO Group with respect to business opportunities (as defined within the ASA) with third parties.  The EPCO Group includes EPCO and its other affiliates, but excludes the Parent Company, Enterprise Products Partners, Duncan Energy Partners and their respective general partners.

The ASA was amended on January 30, 2009 to provide for the cash reimbursement by the Parent Company and Enterprise Products Partners to EPCO of distributions of cash or securities, if any, made by EPCO Unit to its Class B limited partners.  The ASA amendment also extended the term under which EPCO provides services to the partnership entities from December 2010 to December 2013 and made other updating and conforming changes.

Relationships with Unconsolidated Affiliates

Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations.  Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here.  
 
The following information summarizes significant related party transactions with our current unconsolidated affiliates:

§  
We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility.  Revenues from Evangeline were $155.5 million, $362.9 million and $268.0 million for the years ended December 31, 2009, 2008 and 2007, respectively.

§  
We pay Promix for the transportation, storage and fractionation of NGLs.  In addition, we sell natural gas to Promix for its plant fuel requirements.  Revenues from Promix were $11.0 million, $24.5 million and $17.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.  Expenses with Promix were $26.0 million, $38.7 million and $30.4 million for the years ended December 31, 2009, 2008 and 2007, respectively.

§  
For the years ended December 31, 2008 and 2007, we paid $1.7 million and $3.8 million, respectively, to Centennial in connection with a pipeline capacity lease.  In addition, we paid $6.7 million, $6.6 million and $5.3 million to Centennial for the years ended December 31, 2009, 2008 and 2007 for other pipeline transportation services, respectively.

§  
For the years ended December 31, 2009, 2008 and 2007, we paid Seaway $3.4 million, $6.0 million and $4.7 million, respectively, for transportation and tank rentals in connection with our crude oil marketing activities.

§  
We perform management services for certain of our unconsolidated affiliates.  We charged such affiliates $10.7 million, $11.2 million and $11.0 million for the years ended December 31, 2009, 2008 and 2007, respectively.

§  
Enterprise Products Partners has a long-term sales contract with a subsidiary of ETP.  In addition, Enterprise Products Partners and another subsidiary of ETP transport natural gas on each other’s systems and share operating expenses on certain pipelines.  A subsidiary of ETP also sells natural gas to Enterprise Products Partners.  See previous table for related party revenue and expense amounts recorded by Enterprise Products Partners in connection with Energy Transfer Equity.

Relationship with Duncan Energy Partners

Duncan Energy Partners was formed in September 2006 and did not acquire any assets prior to February 5, 2007, which was the date it completed its initial public offering and acquired controlling interests in five midstream energy businesses from EPO in a drop down transaction.  On December 8, 2008, through a second drop down transaction, Duncan Energy Partners acquired controlling interests in three additional midstream energy businesses from EPO.  The business purpose of Duncan Energy Partners is to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO and other affiliates under common control.  Duncan Energy Partners is engaged in (i) the gathering, transportation and storage of natural gas; (ii) NGL transportation and fractionation; (iii) the storage of NGL and petrochemical products; (iv) the transportation of petrochemical products and (v) the marketing of NGLs and natural gas.

At December 31, 2009, Duncan Energy Partners is owned 99.3% by its limited partners and 0.7% by its general partner, DEP GP, which is a wholly owned subsidiary of EPO.  DEP GP is responsible for managing the business and operations of Duncan Energy Partners.  DEP Operating Partnership L.P., a wholly owned subsidiary of Duncan Energy Partners, conducts substantially all of Duncan Energy Partners’ business.  At December 31, 2009, EPO owned 58.6% of Duncan Energy Partners’ limited partner interests and 100% of its general partner.  Due to Enterprise Products Partners’ control of Duncan Energy Partners, its financial statements are consolidated with those of Enterprise Products Partners and Enterprise Products Partners’ transactions with Duncan Energy Partners are eliminated in consolidation.


 
F-72
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

Relationship with Cenac

In connection with our marine services acquisition in February 2008, Cenac and affiliates became a related party of ours.  We entered into a transitional operating agreement with Cenac in which our fleet of tow boats and tank barges (which were primarily acquired from Cenac) continued to be operated by employees of Cenac for a period of up to two years following the acquisition.  Under this agreement, we paid Cenac a monthly operating fee and reimbursed Cenac for personnel salaries and related employee benefit expenses, certain repairs and maintenance expenses and insurance premiums on the equipment.  Effective August 1, 2009, the transitional operating agreement was terminated.  Personnel providing services pursuant to the agreement became employees of EPCO and will continue to provide services under the ASA.  Concurrently with the termination of the transitional operating agreement, we entered into a two-year consulting agreement with Mr. Cenac and Cenac Marine Services, L.L.C. under which Mr. Cenac has agreed to supervise the day-to-day operations of our marine services business and, at our request, provide related management and transitional services.


Note 16.  Provision for Income Taxes

Our provision for income taxes relates primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes.  In addition, with the amendment of the Texas Margin Tax, we have become a taxable entity in the state of Texas.  Our federal and state income tax provision is summarized below:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Current:
                  
Federal
   $ 7.9     $ 4.9     $ 4.7  
State
     11.9       23.9       5.1  
Foreign
     1.0       0.4       0.1  
Total current
     20.8       29.2       9.9  
Deferred:
                        
Federal
     4.8       0.8       2.8  
State
     (0.3 )     1.0       3.1  
Total deferred
     4.5       1.8       5.9  
Total provision for income taxes
   $ 25.3     $ 31.0     $ 15.8  

A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Pre Tax Net Book Income (“NBI”)
   $ 1,165.6     $ 1,176.1     $ 777.8  
                         
Texas Margin Tax
   $ 10.1     $ 23.9     $ 7.7  
State income taxes (net of federal benefit)
     1.3       0.5       0.3  
Federal income taxes computed by applying the federal
                        
        statutory rate to NBI of corporate entities
     8.3       6.3       5.3  
Valuation allowance
     (1.7 )     (1.4 )     2.4  
Expiration of tax net operating loss
     1.7       --       --  
Other permanent differences
     5.6       1.7       0.1  
Provision for income taxes
   $ 25.3     $ 31.0     $ 15.8  
Effective income tax rate
     2.2 %     2.6 %     2.0 %














 
F-73
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Significant components of deferred tax assets and deferred tax liabilities as of December 31, 2009 and 2008 are as follows:

   
At December 31,
  
   
2009
    
2008
  
Deferred tax assets:
            
 Net operating loss carryovers (1)
   $ 24.6     $ 26.3  
 Property, plant and equipment
     --       0.8  
 Employee benefit plans
     2.8       2.6  
 Deferred revenue
     1.1       1.0  
 Reserve for legal fees and damages
     --       0.3  
 Equity investment in partnerships
     1.0       0.6  
 AROs
     0.1       0.1  
 Accruals
     1.3       0.9  
  Total deferred tax assets
     30.9       32.6  
     Valuation allowance (2)
     2.2       3.9  
    Net deferred tax assets
     28.7       28.7  
Deferred tax liabilities:
                
    Property, plant and equipment
     97.4       92.9  
    Other
     --       0.1  
  Total deferred tax liabilities
     97.4       93.0  
          Total net deferred tax liabilities
   $ (68.7 )   $ (64.3 )
                 
Current portion of total net deferred tax assets
   $ 1.9     $ 1.4  
Long-term portion of total net deferred tax liabilities
   $ (70.6 )   $ (65.7 )
                 
(1)   These losses expire in various years between 2010 and 2028 and are subject to limitations on their utilization.
(2)   We record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that is more likely than not to be realized.
  
 
On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax.  In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including previously non-taxable entities such as limited liability companies, limited partnerships and limited liability partnerships.  The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.

Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.  Due to the enactment of the Texas Margin Tax, we recorded a net deferred tax asset of $0.3 million and a liability of $1.0 million during the years ended December 31, 2009 and 2008, respectively.  The offsetting net benefit of $0.3 million and net charge of $1.0 million is shown on our Statements of Consolidated Operations for the years ended December 31, 2009 and 2008, respectively, as a component of “Provision for income taxes.”


Note 17.  Earnings Per Unit

Basic and diluted earnings per unit is computed by dividing net income or loss allocated to limited partners by the weighted-average number of Units outstanding during a period, including Class B Units (see below).  The amount of net income allocated to limited partners is derived by subtracting, from net income or loss, our general partner’s share of such net income or loss.

As consideration for the contribution of 4,400,000 common units of TEPPCO and the 100% membership interest in TEPPCO GP (including associated TEPPCO IDRs) in May 2007, the Parent Company issued 14,173,304 Class B Units and 16,000,000 Class C Units to private company affiliates of EPCO that are under common control with the Parent Company.  As a result of this common control

 
F-74
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


relationship, the Class B Units, which were distribution bearing, were treated as outstanding securities for purposes of calculating our basic and diluted earnings per Unit.  On July 12, 2007, all of the outstanding 14,173,304 Class B Units were converted to Units on a one-to-one basis.  On February 1, 2009, all of the outstanding 16,000,000 Class C Units were converted to Units on a one-to-one basis.  The Class C Units were non-participating in current or undistributed earnings prior to conversion.  The Units into which the Class C Units were converted were eligible to receive cash distributions beginning with the distribution paid in May 2009.  See Note 13 for additional information regarding the Class B and C Units.

The following table shows the allocation of net income to our general partner for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Net income
   $ 204.1     $ 164.0     $ 109.0  
Multiplied by general partner ownership interest
     0.01 %     0.01 %     0.01 %
General partner interest in net income
   $ *     $ *     $ *  

The following table shows the calculation of our limited partners’ interest in net income and basic and diluted earnings per Unit.

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
BASIC AND DILUTED EARNINGS PER UNIT
                  
   Numerator:
                  
Net income before general partner interest
   $ 204.1     $ 164.0     $ 109.0  
General partner interest in net income
     *       *       *  
Limited partners' interest in net income
   $ 204.1     $ 164.0     $ 109.0  
   Denominator:
                        
Units
     137.8       123.2       104.9  
Class B Units
     --       --       7.5  
Total
     137.8       123.2       112.4  
   Basic and diluted earnings per Unit:
                        
Net income before general partner interest
   $ 1.48     $ 1.33     $ 0.97  
General partner interest in net income
     *       *       *  
Limited partners’ interest in net income
   $ 1.48     $ 1.33     $ 0.97  
                         
*  Amount is negligible
                        


Note 18.  Commitments and Contingencies

Litigation

On occasion, we or our unconsolidated affiliates are named as defendants in litigation and legal proceedings relating to our normal business activities, including regulatory and environmental matters.  Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.  We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.

We evaluate our ongoing litigation based upon a combination of litigation and settlement alternatives.  These reviews are updated as the facts and combinations of the cases develop or change.  Assessing and predicting the outcome of these matters involves substantial uncertainties.  In the event that the assumptions we used to evaluate these matters change in future periods or new information becomes

 
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available, we may be required to record a liability for an adverse outcome.  In an effort to mitigate potential adverse consequences of litigation, we could also seek to settle legal proceedings brought against us.  We have not recorded any significant reserves for any litigation in our financial statements.

Parent Company Matters.  In February 2008, Joel A. Gerber, a purported unitholder of the Parent Company, filed a derivative complaint on behalf of the Parent Company in the Court of Chancery of the State of Delaware.  The complaint names as defendants EPE Holdings, the Board of Directors of EPE Holdings, EPCO, and Dan L. Duncan and certain of his affiliates.  The Parent Company is named as a nominal defendant. The complaint alleges that the defendants, in breach of their fiduciary duties to the Parent Company and its unitholders, caused the Parent Company to purchase in May 2007 the TEPPCO GP membership interests and TEPPCO units from Mr. Duncan’s affiliates at an unfair price.  The complaint also alleges that Charles E. McMahen, Edwin E. Smith and Thurmon Andress, constituting the three members of EPE Holdings’ ACG Committee, cannot be considered independent because of their relationships with Mr. Duncan.  The complaint seeks relief (i) awarding damages for profits allegedly obtained by the defendants as a result of the alleged wrongdoings in the complaint and (ii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts.  Management believes this lawsuit is without merit and intends to vigorously defend against it.  See Note 15 for information regarding our relationship with Mr. Duncan and his affiliates.

Enterprise Products Partners’ Matters.  On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of the State of Delaware (the “Delaware Court”), in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and Enterprise Product Partners or their affiliates.  Mr. Brinckerhoff filed an amended complaint on July 12, 2007.  The amended complaint names as defendants (i) TEPPCO, certain of its current and former directors, and certain of its affiliates, (ii) Enterprise Products Partners and certain of its affiliates, (iii) EPCO and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into specified transactions that were unfair to TEPPCO or otherwise unfairly favored Enterprise Products Partners or its affiliates over TEPPCO.  These transactions are alleged to include: (i) the joint venture to further expand the Jonah system entered into by TEPPCO and Enterprise Products Partners in August 2006 (the plaintiff alleges that TEPPCO did not receive fair value for allowing Enterprise Products Partners to participate in the joint venture); (ii) the sale by TEPPCO of its Pioneer natural gas processing plant and certain gas processing rights to Enterprise Products Partners in March 2006 (the plaintiff alleges that the purchase price paid by Enterprise Products Partners did not provide fair value to TEPPCO) and (iii) certain amendments to TEPPCO’s partnership agreement, including a reduction in the maximum tier of TEPPCO’s incentive distribution rights in exchange for TEPPCO units.  The amended complaint seeks (i) rescission of the amendments to TEPPCO’s partnership agreement, (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended complaint and (iii) an award to plaintiff of the costs of the action, including fees and expenses of his attorneys and experts.  By its Opinion and Order dated November 25, 2008, the Delaware Court dismissed Mr. Brinckerhoff’s individual and putative class action claims with respect to the amendments to TEPPCO’s partnership agreement.  We refer to this action and the remaining claims in this action as the “Derivative Action.”

On April 29, 2009, Peter Brinckerhoff and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of TEPPCO, filed separate complaints in the Delaware Court as putative class actions on behalf of other unitholders of TEPPCO, concerning the TEPPCO Merger.  On May 11, 2009, these actions were consolidated under the caption Texas Eastern Products Pipeline Company, LLC Merger Litigation, C.A. No. 4548-VCL (“Merger Action”).  The complaints name as defendants Enterprise Products Partners, EPGP, TEPPCO GP, the directors of TEPPCO GP, EPCO and Dan L. Duncan.

The Merger Action complaints allege, among other things, that the terms of the merger (as proposed as of the time the Merger Action complaints were filed) are grossly unfair to TEPPCO’s unitholders and that the TEPPCO Merger is an attempt to extinguish the Derivative Action without consideration.  The complaints further allege that the process through which the Special Committee of the

 
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ACG Committee of TEPPCO GP was appointed to consider the TEPPCO Merger is contrary to the spirit and intent of TEPPCO’s partnership agreement and constitutes a breach of the implied covenant of fair dealing.

The complaints seek relief (i) enjoining the defendants and all persons acting in concert with them from pursuing the TEPPCO Merger, (ii) rescinding the TEPPCO Merger to the extent it is consummated, or awarding rescissory damages in respect thereof, (iii) directing the defendants to account for all damages suffered or to be suffered by the plaintiffs and the purported class as a result of the defendants’ alleged wrongful conduct, and (iv) awarding plaintiffs’ costs of the actions, including fees and expenses of their attorneys and experts.

On August 5, 2009, the parties entered into a Stipulation and Agreement of Compromise, Settlement and Release (the “Settlement Agreement”).  Pursuant to the Settlement Agreement, the board of directors of TEPPCO GP recommended to TEPPCO’s unitholders that they approve the adoption of the merger agreement and took all necessary steps to seek unitholder approval for the merger.

The Delaware Court approved the Settlement Agreement on January 15, 2010, dismissing with prejudice the Merger Action and the Derivative Action.

Additionally, on June 29 and 30, 2009, respectively, M. Lee Arnold and Sharon Olesky, purported unitholders of TEPPCO, filed separate complaints in the District Courts of Harris County, Texas, as putative class actions on behalf of other unitholders of TEPPCO, concerning the TEPPCO Merger (the “Texas Actions”).  The complaints name as defendants Enterprise Products Partners, TEPPCO, TEPPCO GP, EPGP, EPCO, Dan L. Duncan, Jerry Thompson, and the board of directors of TEPPCO GP.  The allegations in the complaints are similar to the complaints filed in Delaware on April 29, 2009 and seek similar relief.  The named plaintiffs in the two Texas Actions (the “Texas Plaintiffs/Objectors”) also appeared in the Delaware proceedings as objectors to the settlement of those cases which were then awaiting court approval.  On October 7, 2009, the Texas Plaintiffs/Objectors and the parties to the Settlement Agreement entered into a Stipulation to Withdraw Objection (the “Stipulation”).  In accordance with the Stipulation, and upon the receipt of Final Court Approval (as defined in the Settlement Agreement), the Texas Plaintiffs/Objectors agreed to dismiss the Texas Actions with prejudice. As of March 1, 2010, the Texas Actions have been dismissed with prejudice pursuant to the Settlement Agreement.

In February 2007, EPO received a letter from the Environment and Natural Resources Division of the U.S. Department of Justice related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third-party, Magellan Ammonia Pipeline, L.P. (“Magellan”), and a previous release of ammonia on September 27, 2004 from the same pipeline.  EPO was the operator of this pipeline until July 1, 2008.  This matter was settled in September 2009, and Magellan has agreed to pay all assessed penalties.

The Attorney General of Colorado on behalf of the Colorado Department of Public Health and Environment (“CDPHE”) filed suit against Enterprise Products Partners and others on April 15, 2008 in connection with the construction of a pipeline near Parachute, Colorado.  The State sought a temporary restraining order and an injunction to halt construction activities since it alleged that the defendants failed to install measures to minimize damage to the environment and to follow requirements for the pipeline’s storm water permit and appropriate storm water plan.  Enterprise Products Partners has entered into a settlement agreement with the State that dismisses the suit and assesses a fine of approximately $0.2 million.

The CDPHE, through its Air Pollution Control Division, has proposed a Compliance Order on Consent with Enterprise Gas Processing, L.L.C for alleged violations of the Colorado Air Pollution and Prevention and Control Act (“Colorado Act”) with respect to operations of the Meeker Gas Processing Plant.  The Compliance Order proposes an administrative fine of approximately $0.3 million and would require the Meeker Gas Processing Plant to be operated in compliance with the Colorado Act.  We have entered into discussions regarding the terms of the Compliance Order.

 
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In January 2009, the State of New Mexico filed suit in District Court in Santa Fe County, New Mexico, under the New Mexico Air Quality Control Act.  The lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon Oil Corp. (“Marathon”) as operator of the Indian Basin natural gas processing facility located in Eddy County, New Mexico.  We own a 42.4% undivided interest in the assets comprising the Indian Basin facility.  The State alleges violations of its air laws.  Marathon agreed to a Consent Decree with the State which was approved by the District Court on December 21, 2009.  Under the Decree, Marathon paid the State approximately $0.6 million, agreed to $4.5 million of additional environmental projects in New Mexico and agreed to two projects for “corrective measures” at the facility.   We are in discussions with Marathon regarding the responsibility for these payments.  We believe that any potential payment we make will not have a material impact on our consolidated financial position, results of operations or cash flows.

In connection with our dissociation from TOPS (see Note 8), Oiltanking filed an original petition against Enterprise Offshore Port System, LLC, EPO, TEPPCO O/S Port System, LLC, TEPPCO and TEPPCO GP in the District Court of Harris County, Texas, 61st Judicial District (Cause No. 2009-31367), asserting, among other things, that the dissociation was wrongful and in breach of the TOPS partnership agreement, citing provisions of the agreement that, if applicable, would continue to obligate us and TEPPCO to make capital contributions to fund the project and impose liabilities on us and TEPPCO.  On September 17, 2009, Enterprise Products Partners and TEPPCO entered into a settlement agreement with certain affiliates of Oiltanking and TOPS that resolved all disputes between the parties related to the business and affairs of the TOPS project (including the litigation described above).  We recognized approximately $66.9 million of expense during 2009 in connection with this settlement.  This charge is classified within our Offshore Pipelines & Services business segment.

Energy Transfer Equity Matters.  In July 2007, ETP announced that it was under investigation by the FERC with respect to (i) whether ETP engaged in manipulation or improper trading activities in the Houston Ship Channel market around the time of the hurricanes in the fall of 2005 and other prior periods in order to benefit financially from commodity derivative instrument positions and from certain index-priced physical gas purchases in the Houston Ship Channel market and (ii) whether ETP manipulated daily prices at the Waha and Permian hubs in west Texas on two dates.  Certain third-party lawsuits were also filed in connection with these matters.

In September 2009, ETP announced that the FERC approved a settlement agreement related to these allegations.  The settlement agreement provides that ETP make a $5.0 million payment to the federal government and the FERC will dismiss all claims against ETP.  Separate from the payment to the federal government, ETP also is required to establish a $25.0 million fund for the purpose of settling related third-party claims against ETP.  This fund amount will be paid into a specific account held by a financial institution selected by mutual agreement of ETP and the FERC.  An administrative law judge appointed by the FERC will determine the validity of any third-party claim against this fund.  Any party who receives money from this fund will be required to waive all claims against ETP related to this matter.  Management of ETP believes that the application of this fund will resolve the existing litigation related to this matter, although, in the event that all plaintiffs in the existing litigation do not participate in this fund, these non-participating plaintiffs will be entitled to continue their litigation claims through the judiciary system.

Pursuant to the settlement agreement, the FERC made no findings of fact or conclusions of law.  In addition, the settlement agreement specifies that ETP does not admit or concede to the FERC or any third-party any actual or potential fault, wrongdoing or liability in connection with its alleged conduct related to the FERC claims.

The FERC’s actions against ETP also included allegations related to its Oasis pipeline, which is an intrastate pipeline that transports natural gas between the Waha and Katy hubs in Texas.  The allegations related to the Oasis pipeline included claims that the pipeline violated Natural Gas Policy Act regulations from January 2004 through June 2006 by granting undue preference to ETP’s affiliates.  In March 2009, ETP entered into a separate settlement agreement with the FERC related to these allegations.  The Oasis settlement agreement did not require ETP to make any payments to the federal government or any other parties.

 
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Regulatory Matters

Certain recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to climate change.  On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program intended to reduce the emissions of greenhouse gases in the United States and would require most sources of greenhouse gas emissions to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases.  The U.S. Senate has also begun work on its own legislation for controlling and reducing emissions of greenhouse gases in the United States.  In addition, on December 7, 2009, the U.S. Environmental Protection Agency (“EPA”) announced its finding that emissions of greenhouse gases presented an endangerment to human health and the environment.  These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  Although it may take the EPA several years to adopt and impose regulations limiting emissions of greenhouse gases, any such regulation could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.  Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases would likely require us to incur increased operating costs, and may have an adverse effect on our business, financial position, demand for our operations, results of operations and cash flows.

Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2009.  A description of each type of contractual obligation follows:

   
Payment or Settlement due by Period
  
Contractual Obligations
  
Total
    
2010
    
2011
    
2012
    
2013
    
2014
    
Thereafter
  
Scheduled maturities of long-term debt
   $ 12,378.5     $ 562.5     $ 915.8     $ 1,452.5     $ 1,208.5     $ 1,949.0     $ 6,290.2  
Estimated cash interest payments
   $ 12,520.3     $ 706.4     $ 653.7     $ 599.4     $ 527.1     $ 458.5     $ 9,575.2  
Operating lease obligations
   $ 343.9     $ 37.6     $ 35.3     $ 32.7     $ 27.3     $ 21.5     $ 189.5  
Purchase obligations:
                                                        
Product purchase commitments:
                                                        
Estimated payment obligations:
                                                        
Natural gas
   $ 5,697.6     $ 1,308.9     $ 685.5     $ 696.3     $ 487.5     $ 471.8     $ 2,047.6  
NGLs
   $ 2,943.0     $ 997.0     $ 339.3     $ 329.8     $ 329.7     $ 329.7     $ 617.5  
Crude oil
   $ 237.3     $ 237.3     $ --     $ --     $ --     $ --     $ --  
Petrochemicals & refined products
   $ 2,642.2     $ 1,486.6     $ 586.0     $ 238.5     $ 113.9     $ 72.4     $ 144.8  
Other
   $ 114.1     $ 21.2     $ 12.2     $ 11.9     $ 11.8     $ 11.0     $ 46.0  
Underlying major volume commitments:
                                                        
Natural gas (in BBtus) (1)
     969,180       221,530       114,304       116,146       83,854       81,154       352,192  
NGLs (in MBbls) (2)
     49,300       19,048       5,337       5,159       5,158       5,158       9,440  
Crude oil (in MBbls) (2)
     2,985       2,985       --       --       --       --       --  
Petrochemicals & refined products (in MBbls)
     35,034       19,523       7,856       3,266       1,509       960       1,920  
Service payment commitments
   $ 575.6     $ 72.0     $ 57.0     $ 56.7     $ 55.1     $ 55.0     $ 279.8  
Capital expenditure commitments
   $ 497.5     $ 497.5     $ --     $ --     $ --     $ --     $ --  
(1)   Volume is measured in billion British thermal units (“BBtus”).
(2)   Volume is measured in thousands of barrels (“MBbls”).
  

Scheduled Maturities of Long-Term Debt.  We have long-term and short-term payment obligations under debt agreements.  Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the periods indicated.  See Note 12 for additional information regarding our consolidated debt obligations.

Operating Lease Obligations.  We lease certain property, plant and equipment under noncancelable and cancelable operating leases.  Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year.

 
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Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with affiliates of EPCO and (iii) land held pursuant to right-of-way agreements.  In general, our material lease agreements have current terms that range from 14 to 20 years.  The agreements for leased office space with affiliates of EPCO and underground NGL storage caverns we lease from a third party include renewal options that could extend these contracts for up to an additional 20 years.  The remainder of our material lease agreements do not provide for additional renewal terms.
 
Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit.  Contingent rental payments are expensed as incurred.  We are generally required to perform routine maintenance on the underlying leased assets.  In addition, certain leases give us the option to make leasehold improvements.  Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred.  We did not make any significant leasehold improvements during the years ended December 31, 2009, 2008 or 2007.

The operating lease commitments shown in the preceding table exclude the non-cash, related party expense associated with retained leases contributed to us by EPCO in 1998.  EPCO remains liable for the actual cash lease payments associated with these agreements, which it accounts for as operating leases.  At December 31, 2009, the retained leases were for approximately 100 railcars.  EPCO’s minimum future rental payments under these leases are $0.7 million for each of the years 2010 through 2015 and $0.3 million for 2016.  We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to equity accounted for as a general contribution to our partnership.

The retained lease agreements contain lessee purchase options, which are at prices that approximate fair value of the underlying leased assets.  EPCO has assigned these purchase options to us.   We exercised our election under the retained leases to purchase a cogeneration unit in December 2008 for $2.3 million.  Should we decide to exercise the purchase option associated with the remaining agreement, we would pay the original lessor $3.1 million in June 2016.

Lease and rental expense included in costs and expenses was $60.7 million, $56.8 million and $61.4 million during the years ended December 31, 2009, 2008 and 2007, respectively.

Purchase Obligations.  We define a purchase obligation as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.  We have classified our unconditional purchase obligations into the following categories:

§  
We have long and short-term product purchase obligations for natural gas, NGLs, crude oil, refined products and certain petrochemicals with third-party suppliers.  The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes.  The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods indicated.  Our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2009 applied to all future volume commitments.  Actual future payment obligations may vary depending on prices at the time of delivery.  At December 31, 2009, we do not have any significant product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.

§  
We have long and short-term commitments to pay third-party providers for services.  Our contractual service payment commitments primarily represent our obligations under firm pipeline transportation contracts on pipelines owned by third parties.  Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment.  The preceding table shows our estimated future payment obligations under these service contracts.

 
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§  
We have short-term payment obligations relating to our capital projects and those of our unconsolidated affiliates.  These commitments represent unconditional payment obligations to vendors for services rendered or products purchased.  The preceding table presents our share of such commitments for the periods indicated.

Commitments Under Equity Compensation Plans of EPCO

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us.  See Note 5 for additional information regarding our accounting for equity awards.

Other Claims

As part of our normal business activities with joint venture partners, customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements.  As of December 31, 2009, claims against us totaled approximately $21.1 million.  These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated.  However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote.  Accordingly, accruals for loss contingencies related to these matters that might result from the resolution of such disputes have not been reflected in our consolidated financial statements.

Other Commitments

We transport and store natural gas, NGLs and petrochemicals for third parties under various processing, storage, transportation and similar agreements. These volumes are either accrued as product payables, in transit for delivery to our customers or held at our storage facilities for redelivery to  customers.  Under terms of our storage agreements, we are generally required to redeliver volumes to the owner on demand.  At December 31, 2009, NGL and petrochemical products aggregating 29.8 million barrels were due to be redelivered to their owners along with 17,112 BBtus of natural gas.  See Note 2 for more information regarding accrued product payables.

Centennial Guarantees

We have certain guarantee obligations in connection with our ownership interest in Centennial.  We have guaranteed one-half of Centennial’s debt obligations, which obligates us to an estimated payment of $60.0 million in the event of a default by Centennial.  At December 31, 2009, we had a liability of $8.4 million representing the estimated fair value of our share of the Centennial debt guaranty.  See Note 12 for information regarding Centennial’s debt obligations.

In lieu of Centennial procuring insurance to satisfy third-party liabilities arising from a catastrophic event, we and Centennial’s other joint venture partner have entered a limited cash call agreement.  We are obligated to contribute up to a maximum of $50.0 million (in proportion to our ownership interest in Centennial) in the event of a catastrophic event.  At December 31, 2009, we had a liability of $3.6 million representing the estimated fair value of our cash call guaranty.  Cash contributions to Centennial under the limited cash call agreement may be covered by our insurance depending on the nature of the catastrophic event.


Note 19.  Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, refined products and certain

 
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petrochemicals.  We also market natural gas, NGLs, crude oil and other hydrocarbon products.  As such, our financial position, results of operations and cash flows may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products (e.g., natural gas processing margins are influenced by the ratio of natural gas prices to crude oil prices).  The prices of hydrocarbon products are subject to fluctuation in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of hydrocarbon products gathered, transported, processed, fractionated or stored at our facilities.  A material decrease in natural gas or crude oil production or crude oil refining, for reasons such as depressed commodity prices or a decrease in exploration and development activities, could result in a decline in the volume of natural gas, NGLs, refined products and crude oil handled by our facilities.

A reduction in demand for natural gas, crude oil, NGL and other hydrocarbon products by the petrochemical, refining or heating industries, whether because of: (i) general economic conditions, (ii) reduced demand by consumers for the end products made using such products, (iii) increased competition from other products due to pricing differences, (iv) adverse weather conditions, (v) government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could adversely affect our financial position, results of operations and cash flows.

Credit Risk Due to Industry Concentrations

A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries.  This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions.  We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.  See Note 14 for information regarding our largest customers.

Counterparty Risk with Respect to Derivative Instruments

In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis.  Generally, we do not require collateral nor do we anticipate nonperformance by our counterparties.

Insurance-Related Risks

We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other coverages, the scope and amounts of which are customary and sufficient for the nature and extent of our operations.  While we believe EPCO maintains adequate insurance coverage on our behalf, insurance will not cover every type of damage or interruption that might occur.  If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position, results of operations and cash flows.  In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for our repair costs or lost income.  Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to our partners and, accordingly, adversely affect the market price of our common units.

EPCO’s deductible for onshore physical damage from windstorms is currently $25.0 million per storm.  EPCO’s onshore program currently provides $150.0 million per occurrence for named windstorm events.  With respect to offshore assets, the windstorm deductible is $75.0 million per storm.  EPCO’s offshore program currently provides $100.0 million in the aggregate.  For non-windstorm events, EPCO’s deductible for both onshore and offshore physical damage is $5.0 million per occurrence.  For certain of our major offshore assets, our producer customers have agreed to provide a specified level of physical

 
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damage insurance for named windstorms.  For example, the producers associated with our Independence Hub and Marco Polo platforms have agreed to cover windstorm generated physical damage costs up to $250.0 million for each platform.

Business interruption coverage in connection with a windstorm event remains in place for onshore assets, but was eliminated for offshore assets.  Onshore assets covered by business interruption insurance must be out-of-service in excess of 60 days before any losses from business interruption will be covered.  Furthermore, pursuant to the current policy, we will now absorb 50% of the first $50.0 million of any loss in excess of deductible amounts for our onshore assets.

The following table summarizes proceeds we received from weather-related business interruption and property damage insurance claims during the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Business interruption proceeds:
                  
Hurricanes Katrina and Rita in 2005
   $ --     $ 1.1     $ 33.9  
Hurricanes Gustav and Ike in 2008
     33.2       --       --  
Other
     --       --       1.4  
   Total proceeds
     33.2       1.1       35.3  
Property damage proceeds:
                        
Hurricanes Katrina and Rita in 2005
     38.6       12.1       103.7  
Hurricanes Gustav and Ike in 2008
     15.1       --       --  
Other
     0.7       --       1.5  
   Total proceeds
     54.4       12.1       105.2  
      Total
   $ 87.6     $ 13.2     $ 140.5  

At December 31, 2009, we have $37.6 million of estimated property damage claims outstanding related to these storms that we believe are probable of collection through 2010.  To the extent we estimate the dollar value of such damages, please be aware that a change in our estimates may occur as additional information becomes available.


























 
F-83
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 20.  Supplemental Cash Flow Information

The following table provides information regarding: (i) the net effect of changes in our operating assets and liabilities; (ii) cash payments for interest and (iii) cash payments for federal and state income taxes for the periods indicated.

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Decrease (increase) in:
                  
Accounts and notes receivable – trade
   $ (1,069.1 )   $ 1,333.9     $ (1,176.4 )
Accounts receivable – related party
     7.2       0.2       (0.2 )
Inventories
     (317.4 )     14.9       (34.8 )
Prepaid and other current assets
     71.1       (26.3 )     32.7  
Other assets
     15.0       (12.0 )     (2.2 )
Increase (decrease) in:
                        
Accounts payable – trade
     (44.4 )     (7.2 )     42.6  
Accounts payable – related party
     44.9       3.4       (4.7 )
Accrued product payables
     1,553.0       (1,720.4 )     1,398.8  
Accrued expenses
     42.4       4.6       126.5  
Accrued interest
     28.2       13.9       56.6  
Other current liabilities
     (97.6 )     (26.7 )     20.3  
Other liabilities
     16.8       7.1       (1.6 )
Net effect of changes in operating accounts
   $ 250.1     $ (414.6 )   $ 457.6  
                         
Cash payments for interest, net of $53.1, $90.7 and
                        
$86.5 capitalized in 2009, 2008 and 2007, respectively
   $ 699.9     $ 643.0     $ 340.5  
                         
Cash payments for federal and state income taxes
   $ 29.5     $ 6.8     $ 5.8  

We incurred liabilities for construction in progress that had not been paid at December 31, 2009, 2008 and 2007 of $182.6 million, $108.0 million and $98.0 million, respectively.  Such amounts are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows.

Third parties may be obligated to reimburse us for all or a portion of expenditures on certain of our capital projects.  The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins.  These amounts are included under the caption “Contributions in aid of construction costs” on the Statements of Consolidated Cash Flows.


Note 21.  Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the years ended December 31, 2009 and 2008:

   
First
    
Second
    
Third
    
Fourth
  
   
Quarter
    
Quarter
    
Quarter
    
Quarter
  
For the Year Ended December 31, 2009:
                        
Revenues
   $ 4,886.9     $ 5,434.3     $ 6,789.4     $ 8,400.3  
Operating income
     498.2       377.8       353.4       625.2  
Net income
     317.7       204.0       174.9       443.7  
  Net income attributable to Enterprise GP Holdings L.P.
     62.9       39.1       25.3       76.8  
Net income per Unit:
                                
Basic and diluted
   $ 0.47     $ 0.28     $ 0.18     $ 0.55  
For the Year Ended December 31, 2008:
                                
Revenues
   $ 8,506.3     $ 10,538.6     $ 10,499.2     $ 5,925.5  
Operating income
     479.5       468.7       410.0       413.9  
Net income
     327.9       316.8       249.6       250.8  
  Net income attributable to Enterprise GP Holdings L.P.
     46.6       49.4       42.0       26.0  
Net income per Unit:
                                
Basic and diluted
   $ 0.38     $ 0.40     $ 0.34     $ 0.21  


 
F-84
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 22.  Supplemental Parent Company Financial Information

In order to fully understand the financial position and results of operations of the Parent Company, we are providing the condensed standalone financial information of Enterprise GP Holdings L.P. apart from that of our consolidated Partnership financial information.

The Parent Company has no operations apart from its investing activities and indirectly overseeing the management of the entities controlled by it.  At December 31, 2009, the Parent Company had investments in Enterprise Products Partners, Energy Transfer Equity and their respective general partners.  The Parent Company controls Enterprise Products Partners through its ownership of EPGP.  The Parent Company owns noncontrolling partnership and membership interests in Energy Transfer Equity and LE GP, respectively.  At December 31, 2008, the Parent Company had investments in Enterprise Products Partners, TEPPCO, Energy Transfer Equity and their respective general partners.  On October 26, 2009, the TEPPCO Merger was completed and TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners.

The Parent Company’s primary cash requirements are for general and administrative costs, debt service requirements and distributions to its partners.  The principal sources of cash flow for the Parent Company are the distributions it receives from its investments in Enterprise Products Partners, Energy Transfer Equity and their respective general partners.  The amount of cash distributions the Parent Company is able to pay its unitholders may fluctuate based on the level of distributions it receives from its investments.  For example, if EPO is not able to satisfy certain financial covenants in accordance with its credit agreements, Enterprise Products Partners would be restricted from making quarterly cash distributions to its partners, which includes the Parent Company.

Factors such as capital contributions, debt service requirements, general and administrative costs, reserves for future distributions and other cash reserves established by the Board of EPE Holdings may affect the distributions the Parent Company makes to its unitholders.  The Parent Company’s credit facility contains covenants requiring it to maintain certain financial ratios.  Also, the Parent Company is prohibited from making any distribution to its unitholders if such distribution would cause an event of default or otherwise violate a covenant under its credit facility.

The Parent Company’s assets and liabilities are not available to satisfy the debts and other obligations of Enterprise Products Partners, Energy Transfer Equity or their respective general partners.  Conversely, the assets and liabilities of these entities are not available to satisfy the debts and obligations of the Parent Company.

Enterprise Products Partners and EPGP

At December 31, 2009, the Parent Company owned 21,167,783 common units of Enterprise Products Partners and 100% of the membership interests of EPGP, which is entitled to 2% of the cash distributions paid by Enterprise Products Partners as well as the IDRs of Enterprise Products Partners.

EPGP’s percentage interest in Enterprise Products Partners’ quarterly cash distributions is increased through its ownership of the associated IDRs, after certain specified target levels of distribution rates are met by Enterprise Products Partners. EPGP’s quarterly general partner and associated incentive distribution thresholds are as follows:

§  
2% of quarterly cash distributions up to $0.253 per unit paid by Enterprise Products Partners;

§  
15% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit paid by Enterprise Products Partners; and

§  
25% of quarterly cash distributions that exceed $0.3085 per unit paid by Enterprise Products Partners.

 
F-85
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The following table summarizes the distributions received by EPGP from Enterprise Products Partners for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
From 2% general partner interest
   $ 21.8     $ 18.2     $ 16.9  
From IDRs
     161.3       125.9       107.4  
Total
   $ 183.1     $ 144.1     $ 124.3  

Energy Transfer Equity and LE GP

 On May 7, 2007, the Parent Company acquired 38,976,090 common units of Energy Transfer Equity and approximately 34.9% of the membership interests in LE GP for $1.65 billion in cash.  On January 22, 2009, the Parent Company acquired an additional 5.7% membership interest in LE GP for $0.8 million, which increased our total ownership in LE GP to 40.6%.

LE GP owns a 0.31% general partner interest in Energy Transfer Equity, which general partner interest has no associated IDRs in the quarterly cash distributions of Energy Transfer Equity.  The business purpose of LE GP is to manage the affairs and operations of Energy Transfer Equity.  LE GP has no separate business activities outside of those conducted by Energy Transfer Equity.

Energy Transfer Equity is a publicly traded Delaware limited partnership formed in 2002 that completed its initial public offering in February 2006.  Energy Transfer Equity’s only cash generating assets are its investments in limited and general partner interests of ETP as follows:

§  
Direct ownership of 62,500,797 ETP limited partner units, representing approximately 35% of ETP’s total outstanding common units at December 31, 2009.

§  
Indirect ownership of the general partner interest of ETP (representing a 1.9% interest as of December 31, 2009) and all associated IDRs held by ETP’s general partner, of which Energy Transfer Equity owns 100% of the membership interests.  Currently, the quarterly general partner and associated IDR thresholds of ETP’s general partner are based on the ETP general partner percentage interest, plus the following with respect to the IDRs:

§  
13% of quarterly cash distributions from $0.275 per unit up to $0.3175 per unit paid by ETP;

§  
23% of quarterly cash distributions from $0.3175 per unit up to $0.4125 per unit paid by ETP; and

§  
48% of quarterly cash distributions that exceed $0.4125 per unit paid by ETP.

The following table summarizes the cash distributions received by Energy Transfer Equity from ETP for the periods indicated:

   
For Year Ended December 31,
    
Four Months Ended December 31,
    
Year Ended
August 31,
  
   
2009
    
2008
    
2007 (1)
    
2007 (1)
  
Limited partners interests
   $ 223.4     $ 221.9     $ 70.3     $ 199.2  
General partner interest
     19.5       17.3       5.1       13.7  
IDRs
     350.5       298.6       85.8       222.4  
   Total distributions received
   $ 593.4     $ 537.8     $ 161.2     $ 435.3  
                                 
(1)   In November 2007, Energy Transfer Equity changed its fiscal year end from August 31 to December 31. Energy Transfer Equity did not recast its consolidated financial data for prior fiscal periods; however, it did complete a four month transition period that began on September 1, 2007 and ended December 31, 2007.
  


 
F-86
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


TEPPCO and TEPPCO GP

Private company affiliates of EPCO contributed equity interests in TEPPCO and TEPPCO GP to the Parent Company in May 2007.  As a result of such contributions, the Parent Company owned 4,400,000 common units of TEPPCO and 100% of the membership interests of TEPPCO GP, which was entitled to 2% of the cash distributions of TEPPCO as well as the IDRs of TEPPCO.  On October 26, 2009, the TEPPCO Merger was completed and TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners.  As a result, the Parent Company’s ownership interests in the TEPPCO units were converted to 5,456,000 common units of Enterprise Products Partners.  In addition, the Parent Company’s membership interests in TEPPCO GP were exchanged for (i) 1,331,681 common units of Enterprise Products Partners and (ii) EPGP (on behalf of the Parent Company as a wholly owned subsidiary of the Parent Company) was credited in its Enterprise Products Partners’ capital account an amount to maintain its 2% general partner interest in Enterprise Products Partners.  For additional information regarding the TEPPCO Merger, see Note 1 “Basis of Presentation.”

Condensed Parent Company Cash Flow Information

The following table presents the Parent Company’s cash flow information for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Operating activities:
                  
Net income
   $ 204.1     $ 164.0     $ 109.0  
Adjustments to reconcile net income to net cash
                        
    flows provided by operating activities:
                        
   Amortization
     2.1       1.3       9.7  
   Equity income
     (259.8 )     (238.8 )     (187.6 )
   Cash distributions from investees
     355.4       313.5       237.6  
   Net effect of changes in operating  accounts
     (3.2 )     (5.3 )     15.9  
         Net cash flows provided by operating activities
     298.6       234.7       184.6  
Investing activities:
                        
Investments (1)
     (38.3 )     (7.7 )     (1,650.8 )
         Cash used in investing activities
     (38.3 )     (7.7 )     (1,650.8 )
Financing activities:
                        
Borrowings under debt agreements
     117.6       67.6       3,787.0  
Repayments of debt
     (113.1 )     (80.6 )     (2,852.0 )
Debt issuance costs
     --       (0.1 )     (18.6 )
Cash distributions paid by Parent Company
     (266.7 )     (213.1 )     (159.0 )
Proceeds from issuance of Parent Company’s Units, net
     --       --       739.4  
Cash distributions paid by former owners of TEPPCO interests
     --       --       (29.8 )
Contribution from partners
     --       --       0.1  
        Cash provided by (used in) financing activities
     (262.2 )     (226.2 )     1,467.1  
Net change in cash and cash equivalents
     (1.9 )     0.8       0.9  
Cash and cash equivalents, January 1
     2.5       1.7       0.8  
Cash and cash equivalents, December 31
   $ 0.6     $ 2.5     $ 1.7  
                         
(1)   The amount for 2007 includes the $1.65 billion paid to acquire interests in Energy Transfer Equity and LE GP in May 2007.
  






 
F-87
ENTERPRISE GP HOLDINGS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The following table details the components of cash distributions received from investees and cash distributions paid by the Parent Company for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Cash distributions from investees: (1)
                  
   Investment in Enterprise Products Partners and EPGP:
                  
      From common units of Enterprise Products Partners
   $ 33.5     $ 27.5     $ 25.8  
      From 2% general partner interest in Enterprise Products Partners
     21.8       18.2       16.9  
      From general partner IDRs in distributions of
                        
          Enterprise Products Partners
     161.3       123.9       104.7  
   Investment in TEPPCO and TEPPCO GP:
                        
      From 4,400,000 common units of TEPPCO
     9.6       12.5       12.1  
      From 2% general partner interest in TEPPCO
     4.7       5.6       5.0  
      From general partner IDRs in distributions of  TEPPCO
     41.8       49.3       43.2  
  Investment in Energy Transfer Equity and LE GP: (2)
                        
      From 38,976,090 common units of Energy Transfer Equity
     82.0       76.0       29.7  
      From member interest in LE GP
     0.7       0.5       0.2  
          Total cash distributions received
   $ 355.4     $ 313.5     $ 237.6  
                         
Distributions by the Parent Company:
                        
    EPCO and affiliates
   $ 205.7     $ 158.9     $ 125.9  
    Public
     61.0       54.2       33.1  
    General partner interest
     *       *       *  
          Total distributions by the Parent Company
   $ 266.7     $ 213.1     $ 159.0  
                         
Distributions paid to affiliates of EPCO that were the former
    owners of the TEPPCO and TEPPCO GP interests contributed
    to the Parent Company in May 2007 (3)
   $ --     $ --     $ 29.8  
                         
         *    Amount is negligible.
(1)   Represents cash distributions received during each reporting period.
(2)   The Parent Company received its first cash distribution from Energy Transfer Equity and LE GP in July 2007.
(3)   Represents cash distributions paid to affiliates of EPCO that were former owners of these partnership and membership interests prior to the contribution of such interests to the Parent Company in May 2007.
  


 









Condensed Parent Company Balance Sheet Information

The following table presents the Parent Company’s balance sheet information at the dates indicated:

   
December 31,
  
   
2009
    
2008
  
ASSETS
            
Current assets
   $ 2.7     $ 4.6  
Investments:
                
   Enterprise Products Partners and EPGP
     1,522.8       829.2  
   TEPPCO and TEPPCO GP (1)
     --       708.5  
   Energy Transfer Equity and LE GP
     1,525.6       1,564.0  
      Total investments
     3,048.4       3,101.7  
Other assets
     6.4       8.2  
      Total assets
   $ 3,057.5     $ 3,114.5  
                 
LIABILITIES AND PARTNERS’ EQUITY
                
Current liabilities
   $ 17.9     $ 23.2  
Long-term debt (see Note 12)
     1,081.5       1,077.0  
Other long-term liabilities
     4.5       13.2  
Partners’ equity
     1,953.6       2,001.1  
      Total liabilities and partners’ equity
   $ 3,057.5     $ 3,114.5  
                 
(1)   On October 26, 2009, the TEPPCO Merger was completed and TEPPCO and TEPPCO GP became wholly owned subsidiaries of Enterprise Products Partners.
  

Condensed Parent Company Income Information

The following table presents the Parent Company’s income information for the periods indicated:

   
For Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Equity income:
                  
   Enterprise Products Partners and EPGP
   $ 205.2     $ 167.8     $ 128.5  
   TEPPCO and TEPPCO GP
     13.5       39.7       56.0  
   Energy Transfer Equity and LE GP
     41.1       31.3       3.1  
      Total equity income
     259.8       238.8       187.6  
General and administrative costs
     10.3       7.3       4.3  
Operating income
     249.5       231.5       183.3  
Other income (expense):
                        
Interest expense
     (45.4 )     (67.5 )     (74.5 )
Interest income
     --       --       0.2  
      Total
     (45.4 )     (67.5 )     (74.3 )
Net income
   $ 204.1     $ 164.0     $ 109.0  


Note 23.  Subsequent Event

Enterprise Products Partners Issues $343.1 Million of Common Units

In January 2010, Enterprise Products Partners issued 10,925,000 common units (including an over-allotment of 1,425,000 common units) to the public at an offering price of $32.42 per unit.  Enterprise Products Partners used the net cash proceeds of $343.1 million to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility, which may be reborrowed to fund capital expenditures and other growth projects, and for general partnership purposes.

 
F-89