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TEPPCO Partners, L.P. 10-Q 2008
tppform10q_093008.htm
 
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________
FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934>
 
For the quarterly period ended September 30, 2008

 
OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934>
 
For the transition period from _____ to _____.


Commission File No. 1-10403
____________________
TEPPCO Partners, L.P.
(Exact name of Registrant as specified in its charter)

Delaware
76-0291058
(State of Other Jurisdiction of
(I.R.S. Employer Identification Number)
Incorporation or Organization)
 

1100 Louisiana Street, Suite 1600
Houston, Texas 77002
(Address of principal executive offices, including zip code)

(713) 381-3636
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes  þ  No o

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.  Limited Partner Units outstanding as of November 3, 2008:  104,524,501

 
 

 
 
TEPPCO PARTNERS, L.P.
 
 
TABLE OF CONTENTS
 
 
 
Page No.
PART I.  FINANCIAL INFORMATION
 
   
Item 1.  Financial Statements
 
Unaudited Condensed Consolidated Balance Sheets
1
   
Unaudited Condensed Statements of Consolidated Income
2
   
Unaudited Condensed Statements of Comprehensive Income
3
   
Unaudited Condensed Statements of Consolidated Cash Flows
4
   
Unaudited Condensed Statements of Consolidated Partners’ Capital
5
   
Notes to Unaudited Condensed Consolidated Financial Statements
6
 
Note 1.  Partnership Organization and Basis of Presentation
6
 
Note 2.  General Accounting Policies and Related Matters
7
 
Note 3.  Accounting for Unit-Based Awards
11
 
Note 4.  Employee Benefit Plans
15
 
Note 5.  Financial Instruments
16
 
Note 6.  Inventories
20
 
Note 7.  Property, Plant and Equipment
20
 
Note 8.  Investments in Unconsolidated Affiliates
22
 
Note 9.  Acquisitions and Dispositions
25
 
Note 10.  Intangible Assets and Goodwill
30
 
Note 11.  Debt Obligations
32
 
Note 12.  Partners’ Capital and Distributions
36
 
Note 13.  Business Segments
39
 
Note 14.  Related Party Transactions
43
 
Note 15.  Earnings per Unit
46
 
Note 16.  Commitments and Contingencies
48
 
Note 17.  Supplemental Cash Flow Information
52
 
Note 18.  Supplemental Condensed Consolidating Financial Information
53
   
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
58
   
Cautionary Note Regarding Forward-Looking Statements
59
   
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
86
   
Item 4.  Controls and Procedures
88
   
PART II.  OTHER INFORMATION
 
   
Item 1.  Legal Proceedings
89
   
Item 1A.  Risk Factors
89
   
Item 5.  Other Information 
91
   
Item 6.  Exhibits
91
   
Signatures
94
   
i
 
 

 
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
TEPPCO PARTNERS,  L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
 

   
September 30,
   
December 31,
 
   
2008
   
2007
 
ASSETS
 
Current assets:
           
  Cash and cash equivalents
  $ 55     $ 23  
  Accounts receivable, trade (net of allowance for doubtful accounts of
               
$1,525 and $125)  
    1,715,504       1,381,871  
  Accounts receivable, related parties                                                                                         
    6,410       6,525  
  Inventories                                                                                         
    170,290       80,299  
  Other                                                                                         
    78,541       47,271  
     Total current assets                                                                                         
    1,970,800       1,515,989  
Property, plant and equipment, at cost (net of accumulated
               
  depreciation of $651,936 and $582,225)                                                                                         
    2,372,694       1,793,634  
Equity investments                                                                                         
    1,191,377       1,146,995  
Intangible assets                                                                                         
    214,370       164,681  
Goodwill                                                                                         
    106,404       15,506  
Other assets                                                                                         
    129,980       113,252  
     Total assets                                                                                         
  $ 5,985,625     $ 4,750,057  
LIABILITIES AND PARTNERS’ CAPITAL
 
Current liabilities:
               
  Senior notes                                                                                         
  $ --     $ 353,976  
  Accounts payable and accrued liabilities                                                                                         
    1,809,746       1,413,447  
  Accounts payable, related parties                                                                                         
    38,940       38,980  
  Accrued interest                                                                                         
    49,327       35,491  
  Other accrued taxes                                                                                         
    29,970       20,483  
  Other                                                                                         
    50,608       84,848  
     Total current liabilities                                                                                         
    1,978,591       1,947,225  
Long-term debt:
               
  Senior notes                                                                                         
    1,714,463       721,545  
  Junior subordinated notes                                                                                         
    299,565       299,538  
  Other long-term debt                                                                                         
    324,717       490,000  
         Total long-term debt                                                                                         
    2,338,745       1,511,083  
Other liabilities and deferred credits                                                                                         
    30,138       27,122  
Commitments and contingencies
               
Partners’ capital:
               
  Limited partners’ interests:
               
     Limited partner units (104,367,201 and 89,849,132 units outstanding)
    1,788,146       1,394,812  
     Restricted limited partner units (157,300 and 62,400 units outstanding)
    1,059       338  
  General partner’s interest                                                                                         
    (100,709 )     (87,966 )
  Accumulated other comprehensive loss                                                                                         
    (50,345 )     (42,557 )
     Total partners’ capital                                                                                         
    1,638,151       1,264,627  
     Total liabilities and partners’ capital                                                                                         
  $ 5,985,625     $ 4,750,057  
 
See Notes to Unaudited Condensed Consolidated Financial Statements.
 

 
1

 
TEPPCO PARTNERS,  L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Dollars in thousands, except per Unit amounts)
 

   
For the Three Months Ended
   
For the Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2008
   
2007
   
2008
   
2007
 
Operating revenues:
                       
Sales of petroleum products
  $ 4,025,641     $ 2,455,695     $ 10,676,786     $ 6,238,927  
Transportation – Refined products
    42,203       48,123       123,602       126,976  
Transportation – LPGs
    16,335       16,735       68,589       69,535  
Transportation – Crude oil
    15,759       12,332       48,491       32,702  
Transportation – NGLs
    12,560       12,023       38,218       34,062  
Transportation – Marine
    46,018       --       119,584       --  
Gathering – Natural gas
    14,620       15,429       42,822       46,289  
Other
    32,608       20,320       76,603       60,031  
Total operating revenues
    4,205,744       2,580,657       11,194,695       6,608,522  
                                 
Costs and expenses:
                               
Purchases of petroleum products
    3,989,484       2,426,692       10,571,817       6,141,630  
    Operating expense      80,868        45,375        201,210        134,458  
Operating fuel and power
    25,954       15,060       76,401       45,163  
General and administrative
    10,846       7,396       30,620       24,158  
Depreciation and amortization
    32,071       26,486       92,234       77,735  
Taxes – other than income taxes
    6,662       4,931       19,759       15,149  
Gains on sales of assets
    (1 )     (2 )     (1 )     (18,653 )
Total costs and expenses
    4,145,884       2,525,938       10,992,040       6,419,640  
                                 
Operating income
    59,860       54,719       202,655       188,882  
                                 
Other income (expense):
                               
Interest expense – net
    (34,301 )     (26,901 )     (105,906 )     (71,897 )
Gain on sale of ownership interest in Mont
   Belvieu Storage Partners, L.P.
    --       (20 )     --       59,628  
Equity earnings
    22,133       19,059       63,212       54,856  
Interest income
    289       454       880       1,241  
Other income – net
    106       306       905       1,085  
                                 
Income before provision for income taxes
    48,087       47,617       161,746       233,795  
                                 
Provision for income taxes
    1,056       (14 )     2,894       213  
                                 
Net income
  $ 47,031     $ 47,631     $ 158,852     $ 233,582  
                                 
Net Income Allocation:
                               
Limited Partner’s interest in net income
  $ 39,007     $ 39,656     $ 132,111     $ 195,106  
General Partner interest in net income
    8,024       7,975       26,741       38,476  
     Total net income allocated
  $ 47,031     $ 47,631     $ 158,852     $ 233,582  
Basic and diluted net income per Limited Partner Unit
  $ 0.40     $ 0.44     $ 1.39     $ 2.17  
Weighted average Limited Partner Units outstanding
    97,316       89,868       95,145       89,835  
                                 
See Notes to Unaudited Condensed Consolidated Financial Statements.
 
2

 
TEPPCO PARTNERS,  L.P.

UNAUDITED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
 
 
   
For the Three Months Ended
   
For the Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2008
   
2007
   
2008
   
2007
 
                         
Net income
  $ 47,031     $ 47,631     $ 158,852     $ 233,582  
Other comprehensive income (loss):
                               
    Cash flow hedges:
                               
        Change in fair values of interest rate cash flow
          hedges and treasury locks
    (27 )     (2,528 )     (23,254 )     (1,016 )
        Changes in fair values of crude oil cash flow
          hedges
    23,370       (3,216 )     15,466       (3,369 )
            Total cash flow hedges
    23,343       (5,744 )     (7,788 )     (4,385 )
           Total other comprehensive income (loss)
    23,343       (5,744 )     (7,788 )     (4,385 )
Comprehensive income
  $ 70,374     $ 41,887     $ 151,064     $ 229,197  

See Notes to Unaudited Condensed Consolidated Financial Statements.



 
3

 
TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
 (Dollars in thousands, except per Unit amounts)

   
For the Nine Months Ended
 
   
September 30,
 
   
2008
   
2007
 
Operating activities:
           
Net income  
  $ 158,852     $ 233,582  
Adjustments to reconcile net income to cash provided by operating activities:
               
Deferred income taxes  
    5       (656 )
Depreciation and amortization
    92,234       77,735  
Amortization of deferred compensation 
    1,257       514  
Amortization in interest expense
    1,461       (2,369 )
Earnings in equity investments 
    (63,212 )     (54,856 )
Distributions from equity investments 
    119,017       96,967  
Gains on sales of assets
    --       (18,653 )
Gain on sale of ownership interest in Mont Belvieu Storage Partners, L.P.
    --       (59,628 )
Loss on early extinguishment of debt
    8,689       --  
Net effect of changes in operating accounts
    (23,434 )     (53,450 )
   Net cash provided by operating activities 
    294,869       219,186  
Investing activities:
               
Proceeds from sales of assets 
    --       27,771  
Proceeds from sale of ownership interest 
    --       137,326  
Purchase of assets 
    --       (12,733 )
Increase in restricted cash  
    --       (2,877 )
Cash used for business combinations
    (351,866 )     --  
Investment in Centennial Pipeline LLC  
    --       (11,081 )
Investment in Jonah Gas Gathering Company 
    (94,875 )     (127,775 )
Investment in Texas Offshore Port System   
    (8 )     --  
Acquisition of intangible assets 
    (317 )     (2,500 )
Cash paid for linefill on assets owned  
    (11,530 )     (26,613 )
Capital expenditures  
    (215,162 )     (164,161 )
          Net cash used in investing activities 
    (673,758 )     (182,643 )
Financing activities:
               
Proceeds from term credit facility
    1,000,000       --  
Repayments on term credit facility 
    (1,000,000 )     --  
Proceeds from revolving credit facility 
    1,852,567       805,250  
Repayments on revolving credit facility
    (2,017,850 )     (918,250 )
Repayment of debt assumed in Cenac acquisition
    (63,157 )     --  
Redemption of 7.51% TE Products Senior Notes 
    (181,571 )     --  
Repayment of 6.45% TE Products Senior Notes
    (180,000 )     --  
Issuance of Limited Partner Units, net 
    271,313       53  
Issuance of senior notes
    996,349       --  
Issuance of Junior Subordinated Notes
    --       299,517  
Debt issuance costs
    (9,857 )     (3,750 )
Settlement of treasury lock agreements
    (52,098 )     1,443  
Payment for termination of interest rate swap
    --       (1,235 )
Distributions paid
    (236,775 )     (219,613 )
         Net cash provided by (used in) financing activities 
    378,921       (36,585 )
Net change in cash and cash equivalents
    32       (42 )
Cash and cash equivalents, January 1 
    23       70  
Cash and cash equivalents, September 30
  $ 55     $ 28  
See Notes to Unaudited Condensed Consolidated Financial Statements.

 
4

 
TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ CAPITAL
(Dollars in thousands, except Unit amounts)


 
   
Outstanding
               
Accumulated
       
   
Limited
   
General
   
Limited
   
Other
       
   
Partner
   
Partner’s
   
Partners’
   
Comprehensive
       
   
Units
   
Interest
   
Interests
   
Loss
   
Total
 
                               
Balance, December 31, 2007  
    89,911,532     $ (87,966 )   $ 1,395,150     $ (42,557 )   $ 1,264,627  
Net income allocation    
    --       26,741       132,111       --       158,852  
Issuance of units in connection with Cenac
      acquisition on February 1, 2008
    4,854,899       --       186,558       --       186,558  
Limited Partner Units issued in connection
      with Distribution Reinvestment Plan
    205,288       --       6,773       --       6,773  
   Units issued in connection with Employee
      Unit Purchase Plan 
    16,502       --       570       --       570  
Issuance of restricted units under 2006
       LTIP 
    94,900       --       --       --       --  
Issuance of Limited Partner Units, net
    9,441,380       --       263,970       --       263,970  
Cash distributions 
    --       (39,484 )     (197,291 )     --       (236,775 )
Non-cash contribution
    --       --       474       --       474  
Amortization of equity awards
    --       --       890       --       890  
Changes in fair values of crude oil cash
   flow hedges 
    --       --       --       15,466       15,466  
Changes in fair values of treasury locks
    --       --       --       (23,254 )     (23,254 )
                                         
Balance, September 30, 2008  
    104,524,501     $ (100,709 )   $ 1,789,205     $ (50,345 )   $ 1,638,151  
                                         

See Notes to Unaudited Condensed Consolidated Financial Statements.

 
5

 
TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 

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

NOTE 1.  PARTNERSHIP ORGANIZATION AND BASIS OF PRESENTATION

Partnership Organization

TEPPCO Partners, L.P. (the “Partnership”), is a publicly traded Delaware limited partnership and our limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”.  As used in this Report, “we,” “us,” “our,” the “Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries.
 
We operate through TE Products Pipeline Company, LLC (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, LLC (“TEPPCO Midstream”), and beginning February 1, 2008, through TEPPCO Marine Services, LLC (“TEPPCO Marine Services”).  Texas Eastern Products Pipeline Company, LLC (the “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us.  We hold a 99.999% limited partner interest in TCTM, 99.999% membership interests in each of TE Products and TEPPCO Midstream and a 100% membership interest in TEPPCO Marine Services.  TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, holds a 0.001% general partner interest in TCTM and a 0.001% managing member interest in each of TE Products and TEPPCO Midstream.
 
Through May 6, 2007, our General Partner was owned by DFI GP Holdings L.P. (“DFIGP”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan.  On May 7, 2007, DFIGP sold all of the membership interests in our General Partner, together with 4,400,000 of our Units, to Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded partnership, also controlled indirectly by Dan L. Duncan. Mr. Duncan and certain of his affiliates, including Enterprise GP Holdings and Dan Duncan LLC, a privately held company controlled by him, control us, our General Partner and Enterprise Products Partners L.P. (“Enterprise Products Partners”) and its affiliates, including Duncan Energy Partners L.P. (“Duncan Energy Partners”).  As of May 7, 2007, Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest.  Enterprise GP Holdings, DFIGP and other entities controlled by Mr. Duncan own 16,950,130 of our Units.  Under an amended and restated administrative services agreement (“ASA”), EPCO performs management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us.
 
Basis of Presentation
 
The accompanying unaudited condensed consolidated financial statements reflect all adjustments that are, in the opinion of our management, of a normal and recurring nature and necessary for a fair statement of our financial position as of September 30, 2008, and the results of our operations and cash flows for the periods presented.  The results of operations for the three months and nine months ended September 30, 2008, are not necessarily indicative of results of our operations for the full year 2008.  The unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).  Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to those rules and regulations.  You should read these interim financial statements in conjunction with our consolidated financial statements and notes thereto presented in the TEPPCO Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2007.  

 
6

 
TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

NOTE 2.  GENERAL ACCOUNTING POLICIES AND RELATED MATTERS

Business Segments

We operate and report in four business segments:
 
§  
pipeline transportation, marketing and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”);
§  
gathering, pipeline transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals (“Upstream Segment”);
§  
gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and pipeline transportation of NGLs (“Midstream Segment”); and
§  
marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges (“Marine Services Segment”).
 
Our reportable segments offer different products and services and are managed separately because each requires different business strategies (see Note 13).
 
Our interstate pipeline transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”).  We refer to refined products, LPGs, petrochemicals, crude oil, lubrication oils and specialty chemicals, NGLs, natural gas, asphalt, heavy fuel oil and other heated oil products in this Report, collectively, as “petroleum products” or “products.”

Consolidation Policy

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

If an investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the 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 are material and remain on our balance sheet (or those of our equity method investments) in inventory or similar accounts.  Our investments in Seaway Crude Pipeline Company (“Seaway”) and Centennial Pipeline LLC (“Centennial”) are accounted for under the equity method of accounting, as we own 50% ownership interests in these entities and have 50% equal management with the other joint venture participants.  Our investment in Texas Offshore Port System is accounted for under the equity method of accounting, as we own a 33% ownership interest in this entity and have equal voting rights with the other joint venture participants.  Our investment in Jonah Gas Gathering Company (“Jonah”) is accounted for under the equity method of accounting, as we have 50% equal management with the other participant, even though we own an approximate 80% economic interest in the partnership.

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


 
7

 
TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

Environmental Expenditures

We accrue for environmental costs that relate to existing conditions caused by past operations, including conditions with assets we have acquired.  Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable.  We monitor the balance of accrued undiscounted environmental liabilities on a regular basis.  We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made.  Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods.  Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations.  None of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable.  Expenditures to mitigate or prevent future environmental contamination are capitalized.

At September 30, 2008 and December 31, 2007, our accrued liabilities for environmental remediation projects totaled $7.1 million and $4.0 million, respectively.  These amounts were derived from a range of reasonable estimates based upon studies and site surveys.  Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.

Estimates
 
The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Although we believe these estimates are reasonable, actual results could differ from those estimates.
 
Recent Accounting Developments

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

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

 
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only affects disclosure requirements; therefore, our adoption of this statement effective January 1, 2009 will not impact our financial position, results of operations or cash flows.

In March 2008, the Emerging Issues Task Force (“EITF”), reached consensus on EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships. This guidance prescribes the manner in which a master limited partnership (“MLP”) should allocate and present earnings per unit using the two-class method set forth in SFAS No. 128, Earnings per Share.  Under the two-class method, current period earnings are allocated to the general partner (including any embedded incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement.  EITF 07-4 is effective for us on January 1, 2009.  We do not believe that EITF 07-4 will have a material impact on our earnings per unit computations and disclosures.

In June 2008, FASB Staff Position (“FSP”) No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, was issued.  FSP EITF 03-6-1 clarifies that unvested share-based payment awards constitute participating securities, if such awards include nonforfeitable rights to dividends or dividend equivalents.  Consequently, awards that are deemed to be participating securities must be allocated earnings in the computation of earnings per share under the two-class method.  FSP EITF 03-6-1 is effective for us on January 1, 2009.  We do not believe that FSP EITF 03-6-1 will have a material impact on our earnings per unit computations and disclosures.

In February 2008, FSP SFAS No, 157-2, Effective Date of FASB Statement No. 157, was issued.  FSP 157-2 defers the effective date of SFAS 157, Fair Value Measurements, to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  As allowed under FSP 157-2, we have not applied the provisions of SFAS 157 to our nonfinancial assets and liabilities measured at fair value, which include certain assets and liabilities acquired in business combinations.  On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities.  See Note 5 for these fair value disclosures.  We do not expect any immediate impact from adoption of the remaining portions of SFAS 157 on January 1, 2009.
 
        In light of current market conditions, the FASB has issued additional clarifying guidance regarding the implementation of SFAS 157, particularly with respect to financial assets that do not trade in active markets such as investments in joint ventures.   This clarifying guidance did not result in a change in our accounting, reporting or impairment testing for such investments. We continue to monitor developments at the FASB and SEC for new matters and guidance that may affect our valuation processes.
 
In April 2008, the FASB issued FSP No. 142-3, Determination of the Useful Life of Intangible Assets (“FSP 142-3”), which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful lives of recognized intangible assets under SFAS No. 142, Goodwill and Other Intangible Assets.  This change is intended to improve consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of such assets under SFAS 141(R) and other accounting guidance.  The requirement for determining useful lives must be applied prospectively to intangible assets acquired after January 1, 2009 and the disclosure requirements must be applied prospectively to all intangible assets recognized as of, and subsequent to, January 1, 2009.  We will adopt the provisions of FSP 142-3 on January 1, 2009.

Revenue Recognition

Our Downstream Segment revenues are earned from pipeline transportation, marketing and storage of refined products and LPGs, intrastate pipeline transportation of petrochemicals, sale of product inventory and other ancillary services.  Transportation revenues are recognized as products are delivered to customers.  Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Refined products terminaling revenues are recognized as products are out-loaded.  From time to time, we buy and sell products to balance our inventory for operational needs, and the revenues from the sale of product inventory are recognized when the products are sold.  Our refined products marketing activities generate revenues by purchasing refined products from our throughput partner and establishing a margin by selling refined products for physical delivery
 

 
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through spot and contract sales.  These marketing activities are conducted at our Aberdeen and Boligee truck racks to independent wholesalers and retailers of refined products.  Spot purchases and sales are generally contracted to occur on the same day.
 
Our Upstream Segment revenues are earned from gathering, pipeline transporting, marketing and storing crude oil, and distributing lubrication oils and specialty chemicals principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region.  Revenues are also generated from trade documentation and terminaling services, primarily at Cushing, Oklahoma, and Midland, Texas.  Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, LLC (“TCO”), which typically occurs upon our receipt of the product.  Revenues related to trade documentation and terminaling services are recognized as services are completed.
 
Except for crude oil purchased from time to time as inventory required for operations, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received.  As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation.  Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations.  However, commodity price risks cannot be completely hedged.
 
Our Midstream Segment revenues are earned from the gathering of natural gas, pipeline transportation of NGLs and fractionation of NGLs.  Gathering revenues are recognized as natural gas is received from the customer.  Transportation revenues are recognized as NGLs are delivered.  Through March 31, 2008, fractionation revenues were recognized ratably over the contract year as products were delivered.  Beginning April 1, 2008, based upon contract terms, fractionation revenues are recognized based upon the volume of NGLs fractionated at a fixed rate per gallon.  We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances.  Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.

Our Marine Services Segment revenues are earned from 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.  We also provide offshore well-testing and other offshore services.  Our transportation services are generally provided under term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from within designated operating areas at set day rates or a set fee per cargo movement.  Most of the inland term contracts have one-year terms with the remainder having terms of up to two years.  Substantially all of the inland contracts have renewal options, which are exercisable subject to agreement on rates applicable to the option terms.  Most of the offshore service and transportation contracts have up to one-year terms with renewal options, which are exercisable subject to agreement on rates applicable to the option terms, or are spot contracts.  A spot contract is an agreement with a customer to move cargo within designated operating areas for a rate negotiated at the time the cargo movement takes place.  We do not assume ownership of the products we transport in this segment.  As is typical for inland and offshore affreightment contracts, the term contracts establish set day rates but do not include revenue or volume guarantees.  Most of the contracts include escalation provisions to recover specific increased operating costs such as incremental increases in labor.  The costs of fuel and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts.






 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

NOTE 3.  ACCOUNTING FOR UNIT-BASED AWARDS

The following table summarizes compensation expense by plan for the three months and nine months ended September 30, 2008 and 2007:
 
   
For the Three Months Ended
September 30,
   
For the Nine Months Ended
September 30,
 
   
2008
   
2007
   
2008
   
2007
 
Phantom Unit Plans: (1) (2)
                       
  1999 Phantom Unit Retention Plan
  $ (91 )   $ (51 )   $ (40 )   $ 731  
  2000 Long Term Incentive Plan
    39       (25 )     (135 )     277  
  2005 Phantom Unit Plan
    (32 )     (112 )     74       429  
EPCO, Inc. 2006 TPP Long-Term Incentive Plan:
                               
  Unit options
    48       27       111       39  
  Restricted units (3)
    284       135       671       199  
  Unit appreciation rights (“UARs”) (1) (2)
    (1 )     20       3       44  
  Phantom units (1)
    --       3       8       7  
TEPPCO Unit L.P.
    30       --       30       --  
Compensation expense allocated under ASA (4)
    490       357       1,201       710  
      Total compensation expense
  $ 767     $ 354     $ 1,923     $ 2,436  
                                 
___________________________________

(1)  
These awards are accounted for as liability awards under the provisions of SFAS No. 123(R), Share-Based Payment (“SFAS 123(R)”).  Accruals for plan award payouts are based on the Unit price.
(2)  
The decrease in compensation expense for the three months ended September 30, 2007 and the three months and nine months ended September 30, 2008, is primarily due to a decrease in the Unit price at September 30, 2007 and September 30, 2008, respectively, as compared to the Unit price at June 30, 2007, June 30, 2008 and December 31, 2007, respectively.
(3)  
As used in the context of the EPCO, Inc. 2006 TPP Long-Term Incentive Plan, the term “restricted unit” represents a time-vested unit under SFAS 123(R).  Such awards are non-vested until the required service period expires.
(4)  
Represents compensation expense under equity awards under other EPCO compensation plans allocated to us from EPCO under the ASA in connection with shared service employees working on our behalf.

1999 Plan

The Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 Plan”) provides for the issuance of phantom unit awards as incentives to key employees.  In April 2008, 13,000 phantom units vested resulting in a cash payment of $0.4 million.  A total of 18,600 phantom units were outstanding under the 1999 Plan at September 30, 2008.  These awards cliff vest as follows: 13,000 in April 2009 and 5,600 in January 2010.  At September 30, 2008 and December 31, 2007, we had accrued liability balances of $0.5 million and $1.0 million, respectively, for compensation related to the 1999 Plan.
 
2000 LTIP

The Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) provides key employees incentives to achieve improvements in our financial performance.  On December 31, 2007, 8,400 phantom units vested and $0.5 million was paid out to participants in the first quarter of 2008.  At September 30, 2008, a total of 11,300 phantom units were outstanding under the 2000 LTIP that cliff vest on December 31, 2008 and will be paid out to participants in 2009.  At September 30, 2008 and December 31, 2007, we had accrued liability balances of $0.3 million and $0.9 million, respectively, related to the 2000 LTIP.


 
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2005 Phantom Unit Plan

The Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 Phantom Unit Plan”) provides key employees incentives to achieve improvements in our financial performance.  On December 31, 2007, 36,200 phantom units vested and $1.6 million was paid out to participants in the first quarter of 2008.  At September 30, 2008, a total of 36,600 phantom units were outstanding under the 2005 Phantom Unit Plan that cliff vest on December 31, 2008 and will be paid out to participants in 2009.  At September 30, 2008 and December 31, 2007, we had accrued liability balances of $0.8 million and $2.6 million, respectively, for compensation related to the 2005 Phantom Unit Plan.
 
2006 LTIP
 
The EPCO, Inc. 2006 TPP Long-Term Incentive Plan (“2006 LTIP”) provides for awards of our Units and other rights to our non-employee directors and to certain employees of EPCO and its affiliates providing services to us.  Awards granted under the 2006 LTIP may be in the form of restricted units, phantom units, unit options, UARs and distribution equivalent rights.  Subject to adjustment as provided in the 2006 LTIP, awards with respect to up to an aggregate of 5,000,000 Units may be granted under the 2006 LTIP.  We reimburse EPCO for the costs allocable to 2006 LTIP awards made to employees who work in our business.   The 2006 LTIP is effective until December 8, 2016 or, if earlier, the time which all available Units under the 2006 LTIP have been delivered to participants or the time of termination of the 2006 LTIP by EPCO or the Audit, Conflicts and Governance Committee of the Board of Directors of our General Partner (“ACG Committee”).  In May 2008, we granted 200,000 unit options and 95,900 restricted units to certain employees providing services directly to us and 29,429 UARs to a non-executive member of the board of directors in connection with his election to the board.  After giving effect to outstanding unit options and restricted units at September 30, 2008, and the forfeiture of restricted units through September 30, 2008, a total of 4,487,700 additional Units could be issued under the 2006 LTIP in the future.

Unit Options

The information in the following table presents unit option activity under the 2006 LTIP for the periods indicated:
               
Weighted-
 
         
Weighted-
   
Average
 
         
Average
   
Remaining
 
   
Number
   
Strike Price
   
Contractual
 
   
of Units
   
(dollars/Unit)
   
Term (in years)
 
Unit Options:
                 
Outstanding at December 31, 2007 (1)
    155,000     $ 45.35       --  
Granted during 2008 (2)                                                    
    200,000       35.86       --  
Outstanding at September 30, 2008
    355,000     $ 40.00       4.82  
  Options exercisable at:
                       
      September 30, 2008                                                        
    --     $ --       --  
___________________________________

(1)  
During 2008, previous unit option grants were amended.  The expiration dates of the 2007 awards were modified from May 22, 2017 to December 31, 2012.
(2)  
The total grant date fair value of these awards was $0.3 million based on the following assumptions:  (i) expected life of the option of 4.7 years; (ii) risk-free interest rate of 3.3%; (iii) expected distribution yield on Units of 7.9%; (iv) estimated forfeiture rate of 17%; and (v) expected Unit price volatility on Units of 18.7%.

At September 30, 2008, total unrecognized compensation cost related to nonvested unit options granted under the 2006 LTIP was an estimated $0.6 million.  We expect to recognize this cost over a weighted-average period of 3.2 years.

 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

  Restricted Units

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

         
Weighted-
 
         
Average Grant
 
   
Number
   
Date Fair Value
 
   
of Units
   
per Unit (1)
 
Restricted Units at December 31, 2007
    62,400        
Granted during 2008 (2)                                                   
    95,900     $ 32.97  
Forfeited during 2008                                                   
    (1,000 )     35.86  
Restricted Units at September 30, 2008
    157,300          
____________________________

(1)  
Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued.
(2)  
Aggregate grant date fair value of restricted unit awards issued during the nine months ended September 30, 2008 was $2.8 million based on grant date market prices of our Units ranging from $34.63 to $35.86 per Unit and an estimated forfeiture rate of 17%.

None of our restricted units vested during the nine months ended September 30, 2008.  At September 30, 2008, total unrecognized compensation cost related to restricted units was $4.1 million, and these costs are expected to be recognized over a weighted-average period of 3.05 years.

Phantom Units

At September 30, 2008, a total of 1,647 phantom units were outstanding, which have been awarded under the 2006 LTIP to non-executive members of the board of directors.  Each phantom unit will pay out in cash on April 30, 2011 or, if earlier, the date the director is no longer serving on the board of directors, whether by voluntarily resignation or otherwise.  Each participant is also entitled to cash distributions equal to the product of the number of phantom units granted to the participant and the per Unit cash distribution that we paid to our unitholders.  Phantom unit awards to non-executive directors are accounted for similar to SFAS 123(R) liability awards.

UARs

At September 30, 2008, a total of 431,377 UARs were outstanding, which have been awarded under the 2006 LTIP to non-executive members of the board of directors and to certain employees providing services directly to us.

Non-Executive Members of the Board of Directors.  On June 20, 2008, 29,429 UARs were awarded under the 2006 LTIP at an exercise price of $33.98 per Unit to a non-executive member of the board of directors in connection with his election to the board.  At September 30, 2008, a total of 95,654 UARs, awarded to non-executive members of the board of directors under the 2006 LTIP, were outstanding at a weighted average exercise price of $41.82 per Unit.  The UARs will be subject to five year cliff vesting and will vest earlier if the director dies or is removed from, or not re-elected or appointed to, the board of directors for reasons other than his voluntary resignation or unwillingness to serve.  When the UARs become payable, the director will receive a payment in cash equal to the fair market value of the Units subject to the UARs on the payment date over the fair market value of the Units subject to the UARs on the date of grant.  UARs awarded to non-executive directors are accounted for similar to SFAS 123(R) liability awards.

 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

Employees.  At September 30, 2008, a total of 335,723 UARs, awarded under the 2006 LTIP to certain employees providing services directly to us, were outstanding at an exercise price of $45.35 per Unit.  The UARs are subject to five year cliff vesting and are subject to forfeiture.  When the UARs become payable, the awards will be redeemed in cash (or, in the sole discretion of the ACG Committee, Units or a combination of cash and Units) equal to the fair market value of the Units subject to the UARs on the payment date over the fair market value of the Units subject to the UARs on the date of grant.  In addition, for each calendar quarter from the grant date until the UARs become payable, each holder will receive a cash payment equal to the product of (i) the per Unit cash distribution paid to our unitholders during such calendar quarter less the quarterly distribution amount in effect at the time of grant multiplied by (ii) the number of Units subject to the UAR.  UARs awarded to employees are accounted for as liability awards under SFAS 123(R) since the current intent is to settle the awards in cash.

Employee Partnership

On September 4, 2008, EPCO formed a Delaware limited partnership, TEPPCO Unit L.P. (“TEPPCO Unit”), for which it serves as the general partner, to serve as an incentive arrangement for certain employees of EPCO providing services to us.  EPCO Holdings, Inc. (“EPCO Holdings”), an affiliate of EPCO, contributed approximately $7.0 million to TEPPCO Unit as a capital contribution with respect to its interest and was admitted as the Class A limited partner of TEPPCO Unit.  TEPPCO Unit purchased 241,380 Units directly from us in an unregistered transaction at the public offering price concurrently with the closing of our September 2008 equity offering (see Note 12).  Certain EPCO employees who perform services for us, including the executive officers named in the Executive Compensation section of our most recent Annual Report on Form 10-K, were issued Class B limited partner interests and admitted as Class B limited partners of TEPPCO Unit without any capital contribution.  The Class B limited partner interests, which entitle the holder to participate in the appreciation in value of our Units, are equity-based compensatory awards designed to incentivize officers and employees of EPCO who perform services for us to enhance the long-term value of our Units.

The Class B limited partner interests in TEPPCO Unit that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to September 4, 2013, with the customary exceptions for death, disability or certain retirements.  The risk of forfeiture associated with the Class B limited partner interests in TEPPCO Unit will also lapse upon certain change of control events.

Unless otherwise agreed to by EPCO, and a majority in interest of the Class B limited partners of TEPPCO Unit, TEPPCO Unit will terminate at the earlier of September 4, 2013 (five years from the date of TEPPCO Unit’s agreement of limited partnership) or a change in control of us, our General Partner or EPCO.  Summarized below are certain material terms regarding quarterly cash distributions by TEPPCO Unit to its partners:

§  
Distributions of cash flow Each quarter, 100% of the cash distributions received by TEPPCO Unit from us in that quarter will be distributed to the Class A limited partner until the Class A limited partner has received an amount equal to the Class A preferred return (as defined below), and any excess distributions received by TEPPCO Unit in that quarter will be distributed to the Class B limited partners.  The Class A preferred return equals the Class A capital base (as defined below) multiplied by a floating rate determined by EPCO, in its sole discretion, that will be no less than 4.5% and no greater than 5.725% per annum.  The Class A limited partner’s capital base equals the amount of any other contributions of cash or cash equivalents made by the Class A limited partner to TEPPCO Unit, plus any unpaid Class A preferred return from prior periods, less any distributions made by TEPPCO Unit of proceeds from the sale of Units owned by TEPPCO Unit (as described below).

§  
Liquidating Distributions Upon liquidation of TEPPCO Unit, Units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, plus any accrued

 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

  
Class A preferred return for the quarter in which liquidation occurs.  Any remaining Units will be distributed to the Class B limited partners.

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

Compensation expense attributable to these awards was based on the estimated grant date fair value of each award.  A portion of the fair value of these equity awards are allocated to us under the ASA as a non-cash expense. We will not reimburse EPCO, TEPPCO Unit or any of their affiliates or partners, through the ASA or otherwise, for any expenses related to TEPPCO Unit, including the $7.0 million contribution to TEPPCO Unit or the purchase of the unregistered Units by TEPPCO Unit.  The grant date fair value of the Class B limited partnership interests in TEPPCO Unit was $2.1 million.  This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards of five years, (ii) risk-free interest rate of 2.87%, (iii) an expected distribution yield on our Units of 7.28%, and (iv) an expected Unit price volatility for our Units of 16.42%.  At September 30, 2008, there was an estimated $1.7 million of unrecognized compensation cost related to TEPPCO Unit.  We will recognize our share of these costs in accordance with the ASA over a weighted average period of 4.93 years.


NOTE 4.  EMPLOYEE BENEFIT PLANS

Retirement Plan

The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan.  The benefit formula for all eligible employees was a cash balance formula.  Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits.  The pay credits were based on a participant’s salary, age and service.  We used a December 31 measurement date for this plan.

Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date.  Effective June 1, 2005, EPCO adopted the TEPPCO RCBP for the benefit of its employees providing services to us.  Effective December 31, 2005, all plan benefits accrued were frozen, participants received no additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service.  The TEPPCO RCBP plan was terminated effective December 31, 2005, and plan participants had the option to receive their benefits either through a lump sum payment in 2006 or through an annuity.  In April 2006, we received a determination letter from the Internal Revenue Service (“IRS”) providing IRS approval of the plan termination.  For those plan participants who elected to receive an annuity, we purchased an annuity contract from an insurance company in which the plan participants own the annuity, absolving us of any future obligation to the participants.

As of December 31, 2007, all benefit obligations to plan participants have been settled.  During the first quarter of 2008, the remaining balance of the TEPPCO RCBP was transferred to an EPCO benefit plan.

EPCO maintains defined contribution plans for the benefit of employees providing services to us, and we reimburse EPCO for the cost of maintaining these plans in accordance with the ASA (see Note 14 for additional information related to the costs and expenses allocated to us for employee benefits).


 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

NOTE 5.  FINANCIAL INSTRUMENTS

We are exposed to financial market risks, including changes in commodity prices and interest rates.  We do not have foreign exchange risks.  We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions.  In general, the type of risks we attempt to hedge are those related to fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices.

Interest Rate Risk Hedging Program
 
Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements.  From time to time we utilize interest rate swaps and similar arrangements to manage a portion of our interest rate exposure, which allows us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

  Fair Value Hedges – Interest Rate Swaps

In January 2006, we entered into interest rate swap agreements with a total notional value of $200.0 million to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility.  Under the swap agreements, we paid a fixed rate of interest ranging from 4.67% to 4.695% and received a floating rate based on the three-month U.S. Dollar LIBOR rate.  At December 31, 2007, the fair value of these interest rate swaps was an asset of $0.3 million.  These interest rate swaps expired in January 2008.
 
In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. This swap agreement, designated as a fair value hedge, had a notional value of $210.0 million and was set to mature in January 2028 to match the principal and maturity of the TE Products Senior Notes.  During the three months and nine months ended September 30, 2007, we recognized reductions in interest expense of $0.1 million and $0.7 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.  In September 2007, we terminated this swap agreement, resulting in a loss of $1.2 million.  This loss was deferred as an adjustment to the carrying value of the 7.51% Senior Notes, and approximately $0.2 million of the loss was amortized to interest expense in 2007, with the remaining $1.0 million recognized in interest expense in January 2008 at the time the 7.51% Senior Notes were redeemed (see Note 11).
 
During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012.  The swap agreements had a combined notional value of $500.0 million and were set to mature in 2012 to match the principal and maturity of the underlying debt.  These swap agreements were terminated in 2002 resulting in deferred gains of $44.9 million, which are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the 7.625% Senior Notes.  At September 30, 2008 and December 31, 2007, the unamortized balance of the deferred gains was $19.4 million and $23.2 million, respectively.  In the event of early extinguishment of the 7.625% Senior Notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.
 
Cash Flow Hedges – Treasury Locks
 
At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to anticipated debt incurrence.  Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.  Each of our treasury
 

 
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lock transactions was designated as a cash flow hedge under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted.
 
In October 2006 and February 2007, we entered into treasury lock agreements, accounted for as cash flow hedges, which extended through June 2007 for a notional value totaling $300.0 million.  In May 2007, these treasury locks were terminated concurrent with the issuance of junior subordinated notes (see Note 11). The termination of the treasury locks resulted in gains of $1.4 million, and these gains were recorded in accumulated other comprehensive income.  These gains are being amortized using the effective interest method as reductions to future interest expense over the term of the forecasted fixed rate interest payments, which is ten years.  Over the next twelve months, we expect to reclassify $0.1 million of accumulated other comprehensive income that was generated by these treasury locks as a reduction to interest expense.  In the event of early extinguishment of the junior subordinated notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.
 
           In 2007, we entered into treasury locks, accounted for as cash flow hedges, which extended through January 31, 2008 for a notional value totaling $600.0 million.  At December 31, 2007, the fair value of the treasury locks was a liability of $25.3 million.  In January 2008, these treasury locks were extended through April 30, 2008.  In March 2008, these treasury locks were settled concurrently with the issuance of senior notes (see Note 11).  The settlement of the treasury locks resulted in losses of $52.1 million, and these losses were recorded in accumulated other comprehensive income.  We recognized approximately $3.6 million of this loss in interest expense as a result of interest payments hedged under the treasury locks not occurring as forecasted.  The remaining losses are being amortized using the effective interest method as increases to future interest expense over the terms of the forecasted interest payments, which range from five to ten years.  Over the next twelve months, we expect to reclassify $5.7 million of accumulated other comprehensive loss that was generated by these treasury locks as an increase to interest expense.  In the event of early extinguishment of these senior notes, any remaining unamortized losses would be recognized in the statement of consolidated income at the time of extinguishment.
 
Commodity Risk Hedging Program
 
We seek to maintain a position that is substantially balanced between crude oil purchases and related sales and future delivery obligations.  As part of our crude oil marketing business, we enter into financial instruments such as swaps and other hedging instruments.  The purpose of such hedging activity is to either balance our inventory position or to lock in a profit margin.

At September 30, 2008 and December 31, 2007, we had a limited number of commodity financial instruments that were accounted for as cash flow hedges.  The majority of these contracts will expire during 2008, with the remainder expiring during 2009, and any amounts remaining in accumulated other comprehensive income will be recorded in net income upon the contract expiration.  Gains and losses on these financial instruments are offset against corresponding gains or losses of the hedged item and are deferred through other comprehensive income, thus minimizing exposure to cash flow risk.  No ineffectiveness was recognized as of September 30, 2008.  In addition, we had some commodity financial instruments that did not qualify for hedge accounting.  These financial instruments had a minimal impact on our earnings.  The fair values of the open positions at September 30, 2008 and December 31, 2007 were liabilities of $2.8 million and $18.9 million, respectively.

Adoption of SFAS 157 – Fair Value Measurements

On January 1, 2008, we adopted the provisions of SFAS No. 157, Fair Value Measurements, that apply to financial assets and liabilities.  We will adopt the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009.  SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
 

 
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Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability.  These assumptions include estimates of risk.  Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates.   These inputs may be either readily observable, corroborated by market data, or generally unobservable.  In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible.  Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.
 
SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values.  The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.  The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:
 
§  
Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date.  Active markets are defined as those in which transactions for identical assets or liabilities occur in sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYSE or New York Mercantile Exchange).  Level 1 primarily consists of financial assets and liabilities such as exchange-traded financial instruments, publicly-traded equity securities and U.S. government treasury securities.
 
§  
Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date.  Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies.  Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors for stocks, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are validated by inputs other than quoted prices (e.g., interest rates and yield curves at commonly quoted intervals).  Level 2 includes non-exchange-traded instruments such as over-the-counter forward contracts, options, and repurchase agreements.
 
§  
Level 3 fair values are based on unobservable inputs.  Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk).  Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally-developed data.  The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort.  Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value.  Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs.
 
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities measured on a recurring basis at September 30, 2008.  These financial assets and liabilities are classified in their
 

 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.  At September 30, 2008, we had no Level 1 financial assets and liabilities.
 
   
Level 2
   
Level 3
   
Total
 
                   
Financial assets:
                 
Commodity financial instruments                                                         
  $ 24,339     $ 1,597     $ 25,936  
    Total                                                         
  $ 24,339     $ 1,597     $ 25,936  
                         
Financial liabilities:
                       
Commodity financial instruments                                                         
  $ 28,694     $ 58     $ 28,752  
    Total                                                         
  $ 28,694     $ 58     $ 28,752  
Net financial assets, Level 3                                                           
          $ 1,539          

The determination of fair values above associated with our commodity financial instrument portfolios are developed using available market information and appropriate valuation techniques in accordance with SFAS 157.
 
The following table sets forth a reconciliation of changes in the fair value of our net financial assets and liabilities classified as Level 3 in the fair value hierarchy:
 
   
Net
 
   
Commodity
 
   
Financial
 
   
Instruments
 
       
Balance, January 1, 2008                                                                                           
  $ (394 )
Total gains included in net income (1)                                                                                       
    418  
Balance, March 31, 2008                                                                                           
  $ 24  
Total losses included in net income (1)                                                                                       
    (66 )
Balance, June 30, 2008                                                                                           
  $ (42 )
Total gains included in net income (1)                                                                                       
    1,581  
Ending balance, September 30, 2008                                                                                           
  $ 1,539  
         
_________
 
(1)  
Total commodity financial instrument gains, recognized in revenues and included in net income on our statements of consolidated income, were $1.6 million and $1.9 million for the three months and nine months ended September 30, 2008, respectively.












 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

NOTE 6.  INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market.  The major components of inventories were as follows:
   
September 30,
   
December 31,
 
   
2008
   
2007
 
Crude oil (1)                                                                                 
  $ 135,684     $ 44,542  
Refined products and LPGs (2)                                                                                 
    13,209       18,616  
Lubrication oils and specialty chemicals                                                                                 
    11,631       9,160  
Materials and supplies                                                                                 
    8,104       7,178  
NGLs                                                                                 
    1,662       803  
          Total                                                                                 
  $ 170,290     $ 80,299  
_________________________________

(1)  
At September 30, 2008 and December 31, 2007, $117.7 million and $16.5 million, respectively, of our crude oil inventory was subject to forward sales contracts.
(2)  
Refined products and LPGs inventory is managed on a combined basis.

 
Due to fluctuating commodity prices, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value.  These non-cash charges are a component of costs and expenses in the period they are recognized.  For the three months ended September 30, 2008 and for the nine months ended September 30, 2008 and 2007, we recognized LCM adjustments of approximately $9.3 million, $9.4 million and $0.6 million, respectively.  For the three months ended September 30, 2007, we had no LCM adjustments.
 

NOTE 7.    PROPERTY, PLANT AND EQUIPMENT

Major categories of property, plant and equipment at September 30, 2008 and December 31, 2007, were as follows:
 
   
Estimated
             
   
Useful Life
   
September 30,
   
December 31,
 
   
In Years
   
2008
   
2007
 
Plants and pipelines (1)
   
5-40(4)
    $ 1,872,107     $ 1,810,195  
Underground and other storage facilities (2)
   
5-40(5)
      286,212       254,677  
Transportation equipment (3)
   
5-10
      10,245       7,780  
Marine vessels
   
20-30
      445,341       --  
Land and right of way
            141,547       117,628  
Construction work in progress 
            269,178       185,579  
Total property, plant and equipment
          $ 3,024,630     $ 2,375,859  
Less accumulated depreciation                                                                    
            651,936       582,225  
Property, plant and equipment, net                                                                
          $ 2,372,694     $ 1,793,634  
______________________________________________

(1)  
Plants and pipelines include refined products, LPGs, 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; storage tanks; and other related assets.
(3)  
Transportation equipment includes vehicles and similar assets used in our operations.

 
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(4)  
The estimated useful lives of major components of this category are as follows:  pipelines, 20-40 years (with some equipment at 5 years); terminal facilities, 10-40 years; office furniture and equipment, 5-10 years; buildings 20-40 years; and laboratory and shop equipment, 5-40 years.
(5)  
The estimated useful lives of major components of this category are as follows:  underground storage facilities, 20-40 years (with some components at 5 years) and storage tanks, 20-30 years.

The following table summarizes our depreciation expense and capitalized interest amounts for the three months and nine months ended September 30, 2008 and 2007:

   
For the Three Months Ended
September 30,
   
For the Nine Months Ended
September 30,
 
   
2008
   
2007
   
2008
   
2007
 
                         
Depreciation expense (1)
  $ 24,414     $ 20,542     $ 70,261     $ 59,914  
Capitalized interest (2)
    4,292       2,010       14,177       8,813  
________________________________________________________
 
(1)  
Depreciation expense is a component of depreciation and amortization expense as presented in our statements of consolidated income.
(2)  
Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.
 
Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of a tangible long-lived asset that results from its acquisition, construction, development or normal operation or a combination of these factors.  We have conditional AROs related to the retirement of the Val Verde Gas Gathering Company, L.P. (“Val Verde”) natural gas gathering system and to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination.  At September 30, 2008, we have a $1.4 million liability, which represents the fair values of these conditional AROs.  We assigned probabilities for settlement dates and settlement methods for use in an expected present value measurement of fair value and recorded conditional AROs.

The following table presents information regarding our AROs:

ARO liability balance, December 31, 2007                                                                                        
  $ 1,346  
  Liabilities incurred                                                                                        
    --  
  Liabilities settled                                                                                        
    --  
  Accretion expense                                                                                        
    95  
ARO liability balance, September 30, 2008                                                                                        
  $ 1,441  

Property, plant and equipment at September 30, 2008, includes $0.5 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

 

 
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 

NOTE 8.  INVESTMENTS IN UNCONSOLIDATED AFFILIATES

We own interests in related businesses that are accounted for using the equity method of accounting.  These investments are identified below by reporting business segment (see Note 13 for a general discussion of our business segments).  The following table presents our investments in unconsolidated affiliates as of September 30, 2008 and December 31, 2007:
 
   
Ownership Percentage at
     
   
September 30,
2008
 
September 30,
2008
   
December 31,
2007
 
                 
Downstream Segment:
               
Centennial                                                                       
   
50.0%
  $ 73,616     $ 78,962  
Other                                                                       
   
25.0%
    369       362  
Upstream Segment:
                     
Seaway                                                                       
   
50.0%
    193,819       188,650  
Texas Offshore Port System                                                                       
   
33.3%
    2,354       --  
Midstream Segment:
                     
Jonah                                                                       
   
80.64%
    921,219       879,021  
          Total                                                                            
        $ 1,191,377     $ 1,146,995  
 
 
The following table summarizes equity earnings by business segment for the three months and nine months ended September 30, 2008 and 2007:
 
   
For the Three Months Ended
September 30,
   
For the Nine Months Ended
September 30,
 
   
2008
   
2007
   
2008
   
2007
 
                         
Equity earnings (losses):
                       
Downstream Segment
  $ (2,349 )   $ (3,064 )   $ (10,066 )   $ (8,430 )
Upstream Segment
    2,748       1,073       9,925       4,310