**UNITED STATES**

**SECURITIES AND EXCHANGECOMMISSION**

**Washington,D.C. 20549**

** **

----

** **

**FORM 10-Q**

**x****QUARTERLY REPORT PURSUANT TOSECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**

**Forthe quarterly period ended September 30, 2006**

**OR**

**o****TRANSITION REPORT PURSUANT TOSECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**

**CommissionFile No. 1-10403**

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**TEPPCO Partners, L.P.**

(Exact name ofRegistrant as specified in its charter)

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

 

**1100Louisiana Street, Suite 1300**

**Houston,Texas 77002**

(Address ofprincipal executive offices, including zip code)

**(713)381-3636**

(Registrant’stelephone number, including area code)

Indicateby check mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.

Yes x  No o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer.  See definition of“accelerated filer and large accelerated filer” in Rule 12b-2 of the ExchangeAct.  (Check one):Large accelerated filer x     Accelerated Filer o     Non-accelerated Filer o

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theExchange Act).Yes o  No x

Indicate thenumber 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 6, 2006:   75,713,554

 

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**TEPPCO PARTNERS, L.P.**

**TABLE OF CONTENTS**
| **PART I. FINANCIAL  INFORMATION**                                                                                                   |                                                                                        |
|--------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------|
| ** **                                                                                                                           |                                                                                        |
| Item  1.                                                                                                                             | Financial  Statements                                                                       |   |
| ** **                                                                                                                           |                                                                                        |
| Consolidated  Balance Sheets as of September 30, 2006 (unaudited) and December 31, 2005  (unaudited)                                 |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Consolidated  Statements of Income for the three months and nine months ended September 30,  2006 and 2005 (unaudited)               |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Consolidated Statements  of Cash Flows for the nine months ended September 30, 2006 and 2005  (unaudited)                            |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Consolidated  Statement of Partners’ Capital for the nine months ended September 30, 2006  (unaudited)                          |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Consolidated  Statements of Comprehensive Income for the three months and nine months ended  September 30, 2006 and 2005 (unaudited) |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Notes to the Consolidated Financial Statements  (unaudited)                                                                          |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Item 2.                                                                                                                              | Management’s Discussion and Analysis of Financial  Condition and Results of Operations |   |
|                                                                                                                                 |                                                                                        |
| Cautionary Note Regarding Forward-Looking Statements                                                                                 |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Item 3.                                                                                                                              | Quantitative and Qualitative Disclosures About Market  Risk                                 |   |
|                                                                                                                                 |                                                                                        |
| Item 4.                                                                                                                              | Controls and Procedures                                                                     |   |
|                                                                                                                                 |                                                                                        |
| **PART  II. OTHER INFORMATION**                                                                                                      |                                                                                        |
|                                                                                                                                 |                                                                                        |
| Item  1.                                                                                                                             | Legal  Proceedings                                                                          |   |
|                                                                                                                                 |                                                                                        |   |
| Item 1A.                                                                                                                             | Risk Factors                                                                                |   |
|                                                                                                                                 |                                                                                        |   |
| Item 6.                                                                                                                              | Exhibits                                                                                    |   |
|                                                                                                                                 |                                                                                        |
| Signatures                                                                                                                           |                                                                                        |

 

i

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**PART I. FINANCIAL INFORMATION**

**Item 1. Financial Statements**

**TEPPCOPARTNERS, L.P.**

**CONSOLIDATEDBALANCE SHEETS**

**(Unaudited)**

**(inthousands)**
| ** **                                                                                                           | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                                                                                           | ** ** | **2006**               | ** ** | **2005**              | ** ** |
|                                                                                                                 |       |                   |       |                  |       |
| **ASSETS**                                                                                                           |       |                   |       |                  |       |
| Current assets:                                                                                                      |       |                   |       |                  |       |
| Cash and cash  equivalents                                                                                           |       | $                      | 90         |                  | $          | 119 |   |
| Accounts  receivable, trade (net of allowance for doubtful accounts of $100 and $250)                                |       | 789,494                |       | 803,373               |       |
| Accounts  receivable, related parties                                                                                |       | 2,364                  |       | 5,207                 |       |
| Inventories                                                                                                          |       | 26,951                 |       | 29,069                |       |
| Other                                                                                                                |       | 49,510                 |       | 61,361                |       |
| Total current  assets                                                                                                |       | 868,409                |       | 899,129               |       |
| Property, plant and  equipment, at cost (net of accumulated depreciation and amortization of  $491,665 and $474,332) |       | 1,607,832              |       | 1,960,068             |       |
| Equity investments                                                                                                   |       | 1,016,131              |       | 359,656               |       |
| Intangible assets                                                                                                    |       | 189,588                |       | 376,908               |       |
| Goodwill                                                                                                             |       | 14,167                 |       | 16,944                |       |
| Other assets                                                                                                         |       | 71,858                 |       | 67,833                |       |
| Total assets                                                                                                         |       | $                      | 3,767,985  |                  | $          | 3,680,538 |   |
|                                                                                                                 |       |                   |       |                  |       |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                                           |       |                   |       |                  |       |
| ** **                                                                                                           | ** ** | ** **             | ** ** | ** **            | ** ** |
| Current liabilities:                                                                                                 |       |                   |       |                  |       |
| Accounts payable  and accrued liabilities                                                                            |       | $                      | 824,389    |                  | $          | 800,033 |   |
| Accounts  payable, related parties                                                                                   |       | 45,620                 |       | 11,836                |       |
| Accrued interest                                                                                                     |       | 15,969                 |       | 32,840                |       |
| Other accrued  taxes                                                                                                 |       | 17,067                 |       | 16,532                |       |
| Other                                                                                                                |       | 35,092                 |       | 75,970                |       |
| Total current  liabilities                                                                                           |       | 938,137                |       | 937,211               |       |
| Senior notes                                                                                                         |       | 1,113,075              |       | 1,119,121             |       |
| Other long-term debt                                                                                                 |       | 359,000                |       | 405,900               |       |
| Deferred tax liability                                                                                               |       | 657                    |       | —                |       |
| Other liabilities and  deferred credits                                                                              |       | 21,717                 |       | 16,936                |       |
| Commitments and  contingencies                                                                                       |       |                   |       |                  |       |
| Partners’ capital:                                                                                              |       |                   |       |                  |       |
| Accumulated  other comprehensive (loss) income                                                                       |       | (339                   | )          | 11                    |       |
| General  partner’s interest                                                                                     |       | (79,331                | )          | (61,487               | )          |
| Limited  partners’ interests                                                                                    |       | 1,415,069              |       | 1,262,846             |       |
| Total partners’  capital                                                                                        |       | 1,335,399              |       | 1,201,370             |       |
| Total liabilities and  partners’ capital                                                                        |       | $                      | 3,767,985  |                  | $          | 3,680,538 |   |

 

See accompanyingNotes to Unaudited Consolidated Financial Statements.

1

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**TEPPCOPARTNERS, L.P.**

**CONSOLIDATEDSTATEMENTS OF INCOME**

**(Unaudited)**

**(inthousands, except per Unit amounts)**
| ** **                                | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|-------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                                | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Operating  revenues:                      |       |                             |       |                            |       |   |   |   |   |
| Sales of petroleum products               |       | $                                | 2,446,671  |                            | $          | 2,367,830 |   | $ | 7,130,283 |   | $ | 5,714,199 |   |
| Transportation – Refined products    |       | 42,067                           |       | 38,240                          |       | 113,309 |   | 111,039 |   |
| Transportation – LPGs                |       | 16,877                           |       | 16,519                          |       | 59,652 |   | 63,220 |   |
| Transportation – Crude oil           |       | 9,567                            |       | 10,001                          |       | 29,034 |   | 28,215 |   |
| Transportation – NGLs                |       | 10,971                           |       | 11,829                          |       | 32,362 |   | 33,435 |   |
| Gathering – Natural gas              |       | 25,022                           |       | 38,833                          |       | 107,856 |   | 112,349 |   |
| Other                                     |       | 18,870                           |       | 16,875                          |       | 58,970 |   | 48,846 |   |
| Total operating revenues                  |       | 2,570,045                        |       | 2,500,127                       |       | 7,531,466 |   | 6,111,303 |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Costs and  expenses:                      |       |                             |       |                            |       |   |   |   |   |
| Purchases of petroleum products           |       | 2,417,636                        |       | 2,349,919                       |       | 7,043,432 |   | 5,662,899 |   |
| Operating expense                         |       | 49,237                           |       | 49,079                          |       | 151,015 |   | 135,475 |   |
| Operating fuel and power                  |       | 15,478                           |       | 12,538                          |       | 42,762 |   | 35,154 |   |
| General and administrative                |       | 6,994                            |       | 8,517                           |       | 25,353 |   | 21,822 |   |
| Depreciation and amortization             |       | 26,250                           |       | 30,807                          |       | 83,683 |   | 82,556 |   |
| Taxes – other than income taxes      |       | 2,625                            |       | 5,920                           |       | 13,984 |   | 15,567 |   |
| Gains on sales of assets                  |       | (14                              | )          | (31                             | )          | (1,410 | ) | (597 | ) |
| Total costs and expenses                  |       | 2,518,206                        |       | 2,456,749                       |       | 7,358,819 |   | 5,952,876 |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Operating income                          |       | 51,839                           |       | 43,378                          |       | 172,647 |   | 158,427 |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Interest expense  – net              |       | (23,181                          | )          | (19,726                         | )          | (63,522 | ) | (60,640 | ) |
| Equity earnings                           |       | 11,567                           |       | 4,747                           |       | 15,230 |   | 16,592 |   |
| Other income –  net                  |       | 1,063                            |       | 484                             |       | 2,416 |   | 885 |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Income before deferred income tax expense |       | 41,288                           |       | 28,883                          |       | 126,771 |   | 115,264 |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Deferred income  tax expense              |       | 143                              |       | —                          |       | 657 |   | — |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Income from continuing operations         |       | 41,145                           |       | 28,883                          |       | 126,114 |   | 115,264 |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Income from  discontinued operations      |       | —                           |       | 692                             |       | 1,497 |   | 2,662 |   |
| Gain on sale of  discontinued operations  |       | —                           |       | —                          |       | 17,872 |   | — |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Discontinued operations                   |       | —                           |       | 692                             |       | 19,369 |   | 2,662 |   |
|                                      |       |                             |       |                            |       |   |   |   |   |
| Net income                                |       | $                                | 41,145     |                            | $          | 29,575 |   | $ | 145,483 |   | $ | 117,926 |   |

 

2

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| ** **                                               | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|----------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                               | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                                               | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Net Income Allocation:                                   |       |                             |       |                            |       |   |   |   |   |
| Limited Partner  Unitholders:                            |       |                             |       |                            |       |   |   |   |   |
| Income from continuing operations                        |       | $                                | 29,047     |                            | $          | 20,426 |   | $ | 89,035 |   | $ | 81,527 |   |
| Income from discontinued operations                      |       | —                           |       | 489                             |       | 13,674 |   | 1,883 |   |
| Total Limited Partner Unitholders net income  allocation |       | 29,047                           |       | 20,915                          |       | 102,709 |   | 83,410 |   |
|                                                     |       |                             |       |                            |       |   |   |   |   |
| General Partner:                                         |       |                             |       |                            |       |   |   |   |   |
| Income from continuing operations                        |       | 12,098                           |       | 8,457                           |       | 37,079 |   | 33,737 |   |
| Income from discontinued operations                      |       | —                           |       | 203                             |       | 5,695 |   | 779 |   |
| Total General Partner net income allocation              |       | 12,098                           |       | 8,660                           |       | 42,774 |   | 34,516 |   |
| Total net income allocated                               |       | $                                | 41,145     |                            | $          | 29,575 |   | $ | 145,483 |   | $ | 117,926 |   |
|                                                     |       |                             |       |                            |       |   |   |   |   |
| Basic and  diluted net income per Limited Partner Unit:  |       |                             |       |                            |       |   |   |   |   |
| Continuing operations                                    |       | $                                | 0.39       |                            | $          | 0.29 |   | $ | 1.24 |   | $ | 1.22 |   |
| Discontinued operations                                  |       | —                           |       | 0.01                            |       | 0.19 |   | 0.03 |   |
| Basic and diluted net income per Limited Partner  Unit   |       | $                                | 0.39       |                            | $          | 0.30 |   | $ | 1.43 |   | $ | 1.25 |   |
|                                                     |       |                             |       |                            |       |   |   |   |   |
| Weighted average  Limited Partner Units outstanding      |       | 75,360                           |       | 69,964                          |       | 71,782 |   | 66,533 |   |

 

See accompanyingNotes to Unaudited Consolidated Financial Statements.

3

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**TEPPCO PARTNERS, L.P.**

** **

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**

**(Unaudited)**

**(in thousands)**

 
| ** **                                                                                | ** ** | **Nine Months Ended** | ** ** |
|-------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                                                | ** ** | **September 30,**          | ** ** |
| ** **                                                                                | ** ** | **2006**                        | ** ** | **2005** | ** ** |
| Cash flows from  operating activities:                                                    |       |                            |       |   |   |
| Net income                                                                                |       | $                               | 145,483    |   | $ | 117,926 |   |
| Adjustments to reconcile net income to cash provided  by continuing operating activities: |       |                            |       |   |   |
| Income from discontinued operations                                                       |       | (19,369                         | )          | (2,662 | ) |
| Deferred income tax expense                                                               |       | 657                             |       | — |   |
| Depreciation and amortization                                                             |       | 83,683                          |       | 82,556 |   |
| Earnings in equity investments                                                            |       | (15,230                         | )          | (16,592 | ) |
| Distributions from equity investments                                                     |       | 26,546                          |       | 28,178 |   |
| Gains on sales of assets                                                                  |       | (1,410                          | )          | (597 | ) |
| Non-cash portion of interest expense                                                      |       | 1,241                           |       | 1,214 |   |
| Increase in accounts receivable, trade                                                    |       | (3,995                          | )          | (296,340 | ) |
| Decrease in accounts receivable, related parties                                          |       | 1,309                           |       | 6,523 |   |
| Decrease (increase) in inventories                                                        |       | 103                             |       | (111,083 | ) |
| Decrease (increase) in other current assets                                               |       | 5,877                           |       | (21,002 | ) |
| Increase in accounts payable and accrued expenses                                         |       | 2,159                           |       | 283,167 |   |
| Increase (decrease) in accounts payable, related  parties                                 |       | 14,919                          |       | (14,796 | ) |
| Other                                                                                     |       | (10,960                         | )          | (10,530 | ) |
| Net cash provided by continuing operating activities                                      |       | 231,013                         |       | 45,962 |   |
| Net cash provided by discontinued operations                                              |       | 1,521                           |       | 3,110 |   |
| Net cash provided by operating activities                                                 |       | 232,534                         |       | 49,072 |   |
|                                                                                      |       |                            |       |   |   |
| Cash flows from  investing activities:                                                    |       |                            |       |   |   |
| Proceeds from the sales of assets                                                         |       | 39,750                          |       | 510 |   |
| Purchase of assets                                                                        |       | (10,975                         | )          | (112,231 | ) |
| Investment in Centennial Pipeline LLC                                                     |       | (2,500                          | )          | — |   |
| Investment in Mont Belvieu Storage Partners, L.P.                                         |       | (4,168                          | )          | (2,635 | ) |
| Investment in Jonah Gas Gathering Company                                                 |       | (65,342                         | )          | — |   |
| Cash paid for linefill on assets owned                                                    |       | (5,640                          | )          | (5,124 | ) |
| Capital expenditures                                                                      |       | (125,684                        | )          | (148,063 | ) |
| Net cash used in investing activities                                                     |       | (174,559                        | )          | (267,543 | ) |
|                                                                                      |       |                            |       |   |   |
| Cash flows from  financing activities:                                                    |       |                            |       |   |   |
| Proceeds from revolving credit facility                                                   |       | 509,750                         |       | 549,657 |   |
| Repayments on revolving credit facility                                                   |       | (556,650                        | )          | (442,157 | ) |
| Issuance of Limited Partner Units, net                                                    |       | 195,072                         |       | 278,830 |   |
| Distributions paid                                                                        |       | (206,176                        | )          | (184,209 | ) |
| Net cash provided by (used in) financing activities                                       |       | (58,004                         | )          | 202,121 |   |
|                                                                                      |       |                            |       |   |   |
| Net decrease in  cash and cash equivalents                                                |       | (29                             | )          | (16,350 | ) |
|                                                                                      |       |                            |       |   |   |
| Cash and cash  equivalents at beginning of period                                         |       | 119                             |       | 16,422 |   |
| Cash and cash equivalents  at end of period                                               |       | $                               | 90         |   | $ | 72 |   |

 

4

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| ** **                                                                                                   | ** ** | **Nine Months Ended** | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                                                                   | ** ** | **September 30,**          | ** ** |
| ** **                                                                                                   | ** ** | **2006**                        | ** ** | **2005** | ** ** |
| **Non-cash  investing activities:**                                                                          |       |                            |       |   |   |
| Net assets transferred to Mont Belvieu Storage  Partners, L.P.                                               |       | $                               | —     |   | $ | 1,429 |   |
| Net assets transferred to Jonah Gas Gathering  Company                                                       |       | $                               | 572,609    |   | $ | — |   |
| Payable to Enterprise Gas Processing, LLC for  spending for Phase V expansion of Jonah Gas Gathering Company |       | $                               | 18,943     |   | $ | — |   |
| ** **                                                                                                   | ** ** | ** **                      | ** ** | ** ** | ** ** |
| **Supplemental  disclosure of cash flows:**                                                                  |       |                            |       |   |   |
| Cash paid for  interest (net of amounts capitalized)                                                         |       | $                               | 84,402     |   | $ | 78,504 |   |

See accompanying Notes toUnaudited Consolidated Financial Statements.

5

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**TEPPCOPARTNERS, L.P.**

**CONSOLIDATEDSTATEMENT OF PARTNERS’ CAPITAL**

**(Unaudited)**

**(inthousands, except Unit amounts)**
| ** **                                                | ** ** | **Outstanding** | ** ** | ** **         | ** ** | ** **         | ** ** | **Accumulated**        | ** ** | ** ** | ** ** |
|-----------------------------------------------------------|------------|-----------------|------------|--------------------|------------|--------------------|------------|------------------------|------------|------------|------------|
| ** **                                                | ** ** | **Limited**     | ** ** | **General**        | ** ** | **Limited**        | ** ** | **Other**              | ** ** | ** ** | ** ** |
| ** **                                                | ** ** | **Partner**     | ** ** | **Partner’s** | ** ** | **Partners’** | ** ** | **Comprehensive**      | ** ** | ** ** | ** ** |
| ** **                                                | ** ** | **Units**       | ** ** | **Interest**       | ** ** | **Interests**      | ** ** | **Income (Loss)** | ** ** | **Total**  | ** ** |
|                                                      |       |            |       |               |       |               |       |                   |       |       |       |
| Partners’  capital at December 31, 2005              |       | 69,963,554      |       | $                  | (61,487    | )                  | $          | 1,262,846              |       | $          | 11         |   | $ | 1,201,370 |   |
| Issuance of Limited Partner Units, net                    |       | 5,750,000       |       | —             |       | 195,072            |       | —                 |       | 195,072    |       |
| Net income allocation                                     |       | —          |       | 42,774             |       | 102,709            |       | —                 |       | 145,483    |       |
| Cash distributions                                        |       | —          |       | (60,618            | )          | (145,558           | )          | —                 |       | (206,176   | )          |
| Changes in fair values of interest rate cash flow  hedges |       | —          |       | —             |       | —             |       | (584                   | )          | (584       | )          |
| Changes in fair values of crude oil cash flow hedges      |       | —          |       | —             |       | —             |       | 234                    |       | 234        |       |
|                                                      |       |            |       |               |       |               |       |                   |       |       |       |
| Partners’ capital at  September 30, 2006             |       | 75,713,554      |       | $                  | (79,331    | )                  | $          | 1,415,069              |       | $          | (339       | ) | $ | 1,335,399 |   |

 

See accompanyingNotes to Unaudited Consolidated Financial Statements.

6

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**TEPPCOPARTNERS, L.P.**

**CONSOLIDATEDSTATEMENTS OF COMPREHENSIVE INCOME**

**(Unaudited)**

**(inthousands)**
| ** **                                                | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-----------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| Net income                                                |       | $                                                    | 41,145     |                                                | $          | 29,575 |   | $ | 145,483 |   | $ | 117,926 |   |
|                                                      |       |                                                 |       |                                                |       |   |   |   |   |
| Changes in fair  values of interest rate cash flow hedges |       | (584                                                 | )          | —                                              |       | (584 | ) | — |   |
| Changes in fair  values of crude oil cash flow hedges     |       | 507                                                  |       | 35                                                  |       | 234 |   | 35 |   |
|                                                      |       |                                                 |       |                                                |       |   |   |   |   |
| Comprehensive  income                                     |       | $                                                    | 41,068     |                                                | $          | 29,610 |   | $ | 145,133 |   | $ | 117,961 |   |

 

See accompanying Notes toUnaudited Consolidated Financial Statements.

7

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**TEPPCOPARTNERS, L.P.**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS**

**(Unaudited)**

**NOTE1.  ORGANIZATION AND BASIS OFPRESENTATION**

TEPPCO Partners, L.P. (the “Partnership”), a Delawarelimited partnership, is a master limited partnership formed in March 1990.  We operate through TE Products PipelineCompany, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCOMidstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to asthe “Operating Partnerships.”  TexasEastern Products Pipeline Company, LLC (the “Company” or “General Partner”), aDelaware limited liability company, serves as our general partner and owns a 2%general partner interest in us.  

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.

Through February 23, 2005, the General Partner was anindirect wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), ajoint venture between Duke Energy Corporation (“Duke Energy”) andConocoPhillips.  Duke Energy held aninterest of approximately 70% in DEFS, and ConocoPhillips held the remaininginterest of approximately 30%.  OnFebruary 24, 2005, the General Partner was acquired by DFI GP Holdings L.P.(formerly Enterprise GP Holdings L.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”),a privately held company controlled by Dan L. Duncan, for approximately $1.1billion.  Mr. Duncan and his affiliates,including EPCO and Dan Duncan LLC, privately held companies controlled by him,control us, the General Partner and Enterprise Products Partners L.P. (“Enterprise”).  As a result of the transaction, DFI owns andcontrols the 2% general partner interest in us and has the right to receive theincentive distribution rights associated with the general partnerinterest.  In conjunction with an amendedand restated administrative services agreement (“ASA”), EPCO performs allmanagement, administrative and operating functions required for us, and wereimburse EPCO for all direct and indirect expenses that have been incurred inmanaging us.  As a result of the sale ofour General Partner, DEFS and Duke Energy continued to provide someadministrative services for us for a period of up to one year after the sale,at which time, we or EPCO assumed these services.  Prior to the sale of our General Partner,DEFS also managed and operated certain of our TEPPCO Midstream assets for usunder contractual agreements.  We assumedthe operations of these assets from DEFS, and certain DEFS employees becameemployees of EPCO effective June 1, 2005. 

In connection with our formation, the Company received2,500,000 Deferred Participation Interests (“DPIs”).  Effective April 1, 1994, the DPIs wereconverted to Limited Partner Units, but they have not been listed for tradingon the New York Stock Exchange.  TheseLimited Partner Units were assigned to Duke Energy when ownership of theCompany was transferred from Duke Energy to DEFS in 2000.  On February 24, 2005, DFI entered into an LPUnit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000Limited Partner Units for $104.0 million. As of September 30, 2006, none of these Limited Partner Units had beensold by DFI.  

The accompanying unaudited consolidated financialstatements reflect all adjustments that are, in the opinion of our management,of a normal and recurring nature and necessary for a fair statement of ourfinancial position as of September 30, 2006, and the results of our operationsand cash flows for the periods presented. The results of operations for the three months and nine months endedSeptember 30, 2006, are not necessarily indicative of results of our operationsfor the full year 2006.  You should readthese interim financial statements in conjunction with our consolidatedfinancial statements and notes thereto presented in our Current Report on Form8-K filed on June 16, 2006, which recast certain information from our AnnualReport on Form 10-K for the year ended December 31, 2005, as discontinuedoperations. We have reclassified certain amounts from prior periods to conformto the current presentation.  EffectiveAugust 1, 2006, we have deconsolidated Jonah Gas Gathering Company (“Jonah”)due to the formation of a joint venture with an affiliate of Enterprise.  Jonah has been subsequently accounted for asan equity method investment (see Note 8).

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**Business Segments**

We operate and report in three business segments:transportation and storage of refined products, liquefied petroleum gases (“LPGs”)and petrochemicals (“Downstream Segment”); gathering, transportation, marketingand storage of crude oil and distribution of lubrication oils and specialtychemicals (“Upstream Segment”); and gathering of natural gas, fractionation ofnatural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”).  Our reportable segments offer differentproducts and services and are managed separately because each requiresdifferent business strategies.

Our interstate transportation operations, includingrates charged to customers, are subject to regulations prescribed by theFederal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, NGLs andnatural gas in this Report, collectively, as “petroleum products” or “products.”

**NetIncome Per Unit**

Basic net income per Limited Partner Unit (“Unit” or “Units”)is computed by dividing net income, after deduction of the General Partner’sinterest, by the weighted average number of Units outstanding (a total of 75.4million Units and 70.0 million Units for the three months ended September 30,2006 and 2005, respectively, and a total of 71.8 million Units and 66.5 millionUnits for the nine months ended September 30, 2006 and 2005, respectively). TheGeneral Partner’s percentage interest in our net income is based on itspercentage of cash distributions from Available Cash for each period (see Note10).  The General Partner was allocated$12.1 million (representing 29.4%) and $8.7 million (representing 29.27%) ofour net income for the three months ended September 30, 2006 and 2005,respectively, and $42.8 million (representing 29.4%) and $34.5 million(representing 29.27%) of our net income for the nine months ended September 30,2006 and 2005, respectively.  The GeneralPartner’s percentage interest in our net income increases as cash distributionspaid per Unit increase, in accordance with the Partnership Agreement.  

Diluted net income per Unit equaled basic net incomeper Unit for each of the three-month and nine-month periods ended September 30,2006 and 2005, as there were no dilutive instruments outstanding.  

**DeferredIncome Tax Expense – Texas Margin Tax**

In May 2006, the State of Texas enacted a new businesstax (the “Texas Margin Tax”) that replaces its existing franchise tax.  In general, legal entities that do businessin Texas are subject to the Texas Margin Tax. Limited partnerships, limited liability companies, corporations, limitedliability partnerships and joint ventures are examples of the types of entitiesthat are subject to the Texas Margin Tax. As a result of the change in tax law, our tax status in the state ofTexas changed from nontaxable to taxable. The Texas Margin Tax is considered an income tax for purposes of adjustmentsto deferred tax liability, as the tax is determined by applying a tax rate to abase that considers both revenues and expenses. Our deferred income tax expense for state taxes relates only to TexasMargin Tax obligations.  The Texas MarginTax becomes effective for franchise tax reports due on or after January 1,2008.  The Texas Margin Tax due in 2008will be based on revenues earned during the 2007 fiscal year.    

The Texas Margin Tax is assessed at 1% ofTexas-sourced taxable margin measured by the ratio of gross receipts frombusiness done in Texas to gross receipts from business done everywhere.  The taxable margin is computed as the lesserof (i) 70% of total revenue or (ii) total revenues less (a) cost of goods soldor (b) compensation.  The deferred taxliability shown on our consolidated balance sheet reflects the net tax effectof temporary differences related to items such as property, plant andequipment; therefore, the deferred tax liability is classified as noncurrent.  The Texas Margin Tax is calculated, paid andfiled at an affiliated unitary group level. Generally, an affiliated group is made up of one or more entities inwhich a controlling interest of at least 80% is 

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owned by a common owner or owners. Generally, abusiness is unitary if it is characterized by a sharing or exchange of valuebetween members of the group, and a synergy and mutual benefit all of themembers of the group achieved by working together.  We have calculated and recorded an estimateddeferred tax liability of approximately $0.7 million associated with the TexasMargin Tax.  The non-cash offsettingcharge is shown on our unaudited consolidated statements of income as deferredincome tax expense for the nine months ended September 30, 2006.

Since the Texas Margin Tax is determined by applying atax rate to a base that considers both revenues and expenses, it hascharacteristics of an income tax. Accordingly, we determined the Texas Margin Tax should be accounted foras an income tax in accordance with the provisions of Statement of FinancialAccounting Standards (“SFAS”) No. 109, *Accounting for IncomeTaxes*.   

**AssetRetirement Obligations**

During the second and third quarters of 2006, werecorded $0.3 million and $0.3 million of expense, respectively, included indepreciation and amortization expense, related to conditional asset retirementobligations.  Additionally, we haverecorded a $1.2 million liability, which represents the fair values ofconditional asset retirement obligations related to structural restoration workto be completed on leased office space that is required upon our anticipatedoffice lease termination and related to the retirement of certain of our naturalgas gathering systems.  These conditionalasset retirement obligations were not previously recorded, due to theindeterminate range of settlement dates and settlement methods, during theimplementation of SFAS No. 143, *Accounting for AssetRetirement Obligations*, and Financial Accounting Standards Board (“FASB”)Interpretation No. 47, *Accounting for ConditionalAsset Retirement Obligations, an interpretation of FASB Statement No. 143*,which we adopted on January 1, 2003 and December 31, 2005, respectively.  During the second and third quarters of 2006,we assigned probabilities for settlement dates and settlement methods for usein an expected present value measurement of fair value and recorded assetretirement obligations.  

**NewAccounting Pronouncements**

In December 2004, the FASB issued SFAS No. 123(R)(revised 2004), *Share-Based Payment*.  SFAS 123(R) is a revision of SFAS No. 123, *Accounting for Stock-Based Compensation*,as amended by SFAS No. 148,*Accounting forStock-Based Compensation – Transition and Disclosure* and supersedesAccounting Principles Board (“APB”) Opinion No. 25, *Accounting for Stock Issued to Employees*.  SFAS 123(R) requires that the cost resultingfrom all share-based payment transactions be recognized in the financialstatements at fair value.  In April 2005,both the FASB and the Securities and Exchange Commission (“SEC”) decided todelay the effective date for public companies to implement SFAS 123(R).  SFAS 123(R) became effective for publiccompanies for annual periods beginning after June 15, 2005.  Accordingly, we adopted SFAS 123(R) in thefirst quarter of 2006.  We adopted SFAS123(R) under the modified prospective transition method.  We have determined that our 1999 and 2005Phantom Unit Plans are liability awards under the provisions of thisstatement.  No additional compensationexpense has been recorded in connection with the adoption of SFAS 123(R) as wehave historically recorded the associated liabilities at fair value.  The adoption of SFAS 123(R) did not have amaterial effect on our financial position, results of operations or cash flows.

In June 2005, the Emerging Issues Task Force (“EITF”)reached consensus in EITF 04-5, *Determining Whether aGeneral Partner, or the General Partners as a Group, Controls a LimitedPartnership or Similar Entity When the Limited Partners Have Certain Rights*,to provide guidance on how general partners in a limited partnership shoulddetermine whether they control a limited partnership and therefore shouldconsolidate it.  The EITF agreed that thepresumption of general partner control would be overcome only when the limitedpartners have either of two types of rights. The first type, referred to as “kick-outrights,” is the right to dissolve or liquidate the partnership or otherwiseremove the general partner without cause. The second type, referred to as “participating 

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rights,” is the right to effectively participate insignificant decisions made in the ordinary course of the partnership’sbusiness. The kick-out rights and the participating rights must be substantivein order to overcome the presumption of general partner control. The consensusis effective for general partners of all new limited partnerships formed andfor existing limited partnerships for which the partnership agreements aremodified subsequent to the date of FASB ratification (June 29, 2005).  For existing limited partnerships that havenot been modified, the guidance in EITF 04-5 is effective no later than thebeginning of the first reporting period in fiscal years beginning afterDecember 15, 2005.  Although this EITFdid not directly impact us, it did impact our General Partner.  Our General Partner adopted this EITF onJanuary 1, 2006.  The adoption of EITF04-5 resulted in the consolidation of our results of operations and balancesheet into its consolidated financial statements.  

In May 2005, the FASB issued SFAS No. 154, *Accounting Changes and Error Corrections*.  SFAS 154 establishes new standards onaccounting for changes in accounting principles.  All such changes must be accounted for byretrospective application to the financial statements of prior periods unlessit is impracticable to do so.  SFAS 154completely replaces APB Opinion No. 20, *Accounting Changes*,and SFAS No. 3, *Reporting Accounting Changes in InterimPeriods*.  However, it carriesforward the guidance in those pronouncements with respect to accounting forchanges in estimates, changes in the reporting entity and the correction oferrors.  SFAS 154 is effective foraccounting changes and error corrections made in fiscal years beginning afterDecember 15, 2005, with early adoption permitted for changes and correctionsmade in years beginning after June 1, 2005. The application of SFAS 154 doesnot affect the transition provisions of any existing pronouncements, includingthose that are in the transition phase as of the effective date of SFAS154.  The adoption of SFAS 154 did nothave a material effect on our financial position, results of operations or cashflows.

In September 2005, the EITF reached consensus in EITF04-13, *Accounting for Purchases and Sales of Inventorywith the Same Counterparty*, to define when a purchase and a sale ofinventory with the same party that operates in the same line of business shouldbe considered a single nonmonetary transaction subject to APB Opinion No. 29, *Accounting for Nonmonetary Transactions*.  Two or more inventory transactions with thesame party should be combined if they are entered into in contemplation of oneanother.  The EITF also requires entitiesto account for exchanges of inventory in the same line of business at fairvalue or recorded amounts based on inventory classification.  The guidance in EITF 04-13 is effective fornew inventory arrangements entered into in reporting periods beginning afterMarch 15, 2006.  We adopted EITF 04-13 onApril 1, 2006, which resulted in crude oil inventory purchases and sales underbuy/sell transactions, which were previously recorded as gross purchases andsales, to be treated as inventory exchanges in our consolidated statements ofincome.  EITF 04-13 reduced grossrevenues and purchases, but did not have a material effect on our financialposition, results of operations or cash flows. The treatment of buy/sell transactions under EITF 04-13 reduced therelative amount of revenues and purchases of petroleum products on ourconsolidated statement of income by approximately $774.4 million each for theperiod from April 1, 2006 through September 30, 2006 ($460.7 million for thethree months ended September 30, 2006). The revenues and purchases of petroleum products associated withbuy/sell transactions that are reported on a gross basis in our consolidatedstatements of income for the three months and nine months ended September 30,2005, and for the period from January 1, 2006 through March 31, 2006, areapproximately $494.7 million, $898.0 million and $275.4 million, respectively.

In February 2006, the FASB issued SFAS No. 155, **Accounting forCertain Hybrid Financial Instruments,**which amends SFASNo. 133, **Accounting for Derivative Instruments and HedgingActivities** and SFAS No. 140, **Accounting for Transfers and Servicingof Financial Assets and Extinguishments of Liabilities**.  SFAS 155 improves the financial reporting ofcertain hybrid financial instruments and simplifies the accounting for theseinstruments. SFAS 155 permits fair value remeasurement for any hybrid financialinstrument that contains an embedded derivative that otherwise would requirebifurcation, clarifies which interest-only and principal-only strips are notsubject to the requirements of SFAS 133, establishes a requirement to evaluateinterests in securitized financial assets to identify interests that arefreestanding derivatives or that are hybrid financial instruments that containan 

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embedded derivative requiring bifurcation, clarifiesthat concentrations of credit risk in the form of subordination are notembedded derivatives, and amends SFAS 140 to eliminate the prohibition on aqualifying special-purpose entity from holding a derivative financialinstrument that pertains to a beneficial interest other than another derivativefinancial instrument. SFAS 155 is effective for all financial instrumentsacquired, issued, or subject to a remeasurement event occurring after thefiscal year that begins after September 15, 2006 (January 1, 2007). At September 30, 2006, we did not have any hybrid financial securitiesoutstanding and, as such, we do not believe that adoption of SFAS 155 will havea material effect on our financial position, results of operations or cashflows, unless such hybrid securities are issued by us prior to SFAS 155 becomingeffective.  

In June 2006, the EITF reached consensus in EITF 06-3,*How Taxes Collected from Customers and Remitted toGovernmental Authorities Should Be Presented in the Income Statement (That Is,Gross versus Net Presentation)*. The accounting guidance permits companies to elect to present on eithera gross or net basis sales and other taxes that are imposed on and concurrentwith individual revenue-producing transactions between a seller and acustomer.  The gross basis includes thetaxes in revenues and costs; the net basis excludes the taxes from revenues.The accounting guidance does not apply to tax systems that are based on grossreceipts or total revenues.  EITF 06-3requires companies to disclose their policy for presenting the taxes and discloseany amounts presented on a gross basis if those amounts are significant.  The guidance in EITF 06-3 is effectiveJanuary 1, 2007.  As a matter of policy,we report such taxes on a net basis.  Webelieve that adoption of EITF 06-3 will not have a material effect on ourfinancial position, results of operations or cash flows.

InJune 2006, the FASB issued FASB Interpretation No. 48, *Accountingfor Uncertainty in Income Taxes*, an Interpretation of SFAS 109,*Accounting for Income Taxes* (“FIN 48”).  FIN 48 provides that the tax effects of anuncertain tax position should be recognized in a company’s financial statementsif the position taken by the entity is more likely than not sustainable if itwere to be examined by an appropriate taxing authority, based on technicalmerit.  After determining if a taxposition meets such criteria, the amount of benefit to be recognized should bethe largest amount of benefit that has more than a 50% chance of being realizedupon settlement.  The provisions of FIN48 are effective for fiscal years beginning after December 15, 2006, and we arerequired to adopt FIN 48 as of January 1, 2007. We are currently assessing the impact, if any, that the adoption of FIN48 will have on our financial position, results of operations or cash flows.

**InSeptember 2006, the FASB issued SFAS No. 157, *Fair ValueMeasurements*.  SFAS 157defines fair value, establishes a framework for measuring fair value ingenerally accepted accounting principles and expands disclosures about fairvalue measurements.  SFAS 157 appliesonly to fair-value measurements that are already required or permitted by otheraccounting standards and is expected to increase the consistency of thosemeasurements.  SFAS 157 emphasizes thatfair value is a market-based measurement that should be determined based on theassumptions that market participants would use in pricing an asset orliability. Companies will be required to disclose the extent to which fairvalue is used to measure assets and liabilities, the inputs used to develop themeasurements, and the effect of certain of the measurements on earnings (orchanges in net assets) for the period. SFAS 157 is effective for fiscal yearsbeginning after December 15, 2007, and we are required to adopt SFAS 157 as ofJanuary 1, 2008.  We are currentlyassessing the impact that the adoption of SFAS 157 will have on our financialposition, results of operations and cash flows.**

**In September 2006, the SEC issued Staff Accounting BulletinNo. 108, *Considering the Effects of Prior Year Misstatementswhen Quantifying Misstatements in Current Year Financial Statements*(“SAB 108”).  SAB 108 addresses how theeffects of prior-year uncorrected misstatements should be considered whenquantifying misstatements in current-year financial statements.  The SAB requires registrants to quantifymisstatements using both balance-sheet and income-statement approaches and toevaluate whether either approach results in quantifying an error that ismaterial in light of relevant quantitative and qualitative factors.  When the effect of initial adoption isdetermined to be material, SAB 108 allows registrants to record that effect asa cumulative-effect adjustment to**

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**beginning-of-yearretained earnings.  The requirements areeffective for annual financial statements covering the first fiscal year endingafter November 15, 2006.  Additionally,the nature and amount of each individual error being corrected through thecumulative-effect adjustment, when and how each error arose, and the fact thatthe errors had previously been considered immaterial is required to bedisclosed.  We are required to adopt SAB108 for our current fiscal year ending December 31, 2006.  We do not expect the adoption of SAB 108 tohave a material effect on our financial position, results of operations or cashflows.**

**NOTE2. GOODWILL AND OTHER INTANGIBLE ASSETS**

**Goodwill**

Goodwill represents the excess of purchase price overfair value of net assets acquired and is presented on the consolidated balancesheets net of accumulated amortization. We account for goodwill under SFAS No. 142, *Goodwill andOther Intangible Assets,*which was issued by the FASB in July2001.  SFAS 142 prohibits amortization ofgoodwill, but instead requires testing for impairment at least annually. Wetest goodwill for impairment annually at December 31.

To perform an impairment test of goodwill, we haveidentified our reporting units and have determined the carrying value of eachreporting unit by assigning the assets and liabilities, including the existinggoodwill, to those reporting units.  Wethen determine the fair value of each reporting unit and compare it to thecarrying value of the reporting unit.  Wewill continue to compare the fair value of each reporting unit to its carryingvalue on an annual basis to determine if an impairment loss has occurred.  There have been no goodwill impairment lossesrecorded since the adoption of SFAS 142. 

The following tablepresents the carrying amount of goodwill at September 30, 2006 and December 31,2005, by business segment (in thousands):
|                        | ** ** | **Downstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Upstream  Segment** | ** ** | **Segments  Total** | ** ** |
|------------------------|------------|-------------------------|------------|------------------------|------------|-----------------------|------------|---------------------|------------|
| Goodwill:              |       |                    |       |                   |       |                  |       |                |       |
| September 30, 2006 (1) |       | $                       | —     |                   | $          | —                |       | $                   | 14,167     |   | $ | 14,167 |   |
| December 31,  2005     |       | —                  |       | 2,777                  |       | 14,167                |       | 16,944              |       |
|                        |            |                         |            |                        |            |                       |            |                     |            |  |  |  |  |

 

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**(1)**   Effective August 1, 2006, with the formation of a joint venture withEnterprise, Jonah was deconsolidated and has been subsequently accounted for asan equity investment (see Note 8). 

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**Other Intangible Assets**

The following tablereflects the components of intangible assets, including excess investments,being amortized at September 30, 2006, and December 31, 2005 (in thousands):
| ** **                                  | ** ** | **September 30, 2006** | ** ** | **December 31, 2005** | ** ** |
|---------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                  | ** ** | **Gross Carrying  Amount**  | ** ** | **Accumulated  Amortization**   | ** ** | **Gross Carrying  Amount** | ** ** | **Accumulated  Amortization** | ** ** |
| Intangible  assets:                         |       |                             |       |                            |       |   |   |   |   |
| Gathering and transportation agreements (1) |       | $                                | 241,537    |                            | $          | (81,683 | ) | $ | 464,337 |   | $ | (118,921 | ) |
| Fractionation agreement                     |       | 38,000                           |       | (16,150                         | )          | 38,000 |   | (14,725 | ) |
| Other                                       |       | 10,336                           |       | (2,452                          | )          | 10,226 |   | (2,009 | ) |
| Subtotal                                    |       | 289,873                          |       | (100,285                        | )          | 512,563 |   | (135,655 | ) |
|                                        |       |                             |       |                            |       |   |   |   |   |
| Excess  investments:                        |       |                             |       |                            |       |   |   |   |   |
| Centennial Pipeline LLC                     |       | 33,390                           |       | (15,678                         | )          | 33,390 |   | (12,947 | ) |
| Seaway Crude Pipeline Company               |       | 27,100                           |       | (4,282                          | )          | 27,100 |   | (3,764 | ) |
| Subtotal                                    |       | 60,490                           |       | (19,960                         | )          | 60,490 |   | (16,711 | ) |
|                                        |       |                             |       |                            |       |   |   |   |   |
| Total intangible  assets                    |       | $                                | 350,363    |                            | $          | (120,245 | ) | $ | 573,053 |   | $ | (152,366 | ) |

 

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**(1)**   Effective August 1, 2006, with the formation of ajoint venture with Enterprise, Jonah was deconsolidated and has beensubsequently accounted for as an equity investment (see Note 8).

SFAS 142 requires thatintangible assets with finite useful lives be amortized over their respectiveestimated useful lives.  If an intangibleasset has a finite useful life, but the precise length of that life is notknown, that intangible asset shall be amortized over the best estimate of itsuseful life.  At a minimum, we willassess the useful lives and residual values of all intangible assets on anannual basis to determine if adjustments are required.  Amortization expense on intangible assets was$6.7 million and $8.2 million for the three months ended September 30, 2006 and2005, respectively, and $22.7 million and $22.3 million for the nine monthsended September 30, 2006 and 2005, respectively.  Amortization expense on excess investmentsincluded in equity earnings was $1.2 million and $1.3 million for the threemonths ended September 30, 2006 and 2005, respectively, and $3.2 million and$3.8 million for the nine months ended September 30, 2006 and 2005,respectively.

The values assigned to our intangible assets fornatural gas gathering contracts on Val Verde Gas Gathering Company, L.P.’ssystem (“Val Verde”) are amortized on a unit-of-production basis, based uponthe actual throughput of the systems compared to the expected total throughputfor the lives of the contracts.  On aquarterly basis, we may obtain limited production forecasts and updatedthroughput estimates from some of the producers on the system, and as a result,we evaluate the remaining expected useful lives of the contract assets based onthe best available information.  Duringthe quarter ended September 30, 2006, we received updated limited productionestimates from some of the producers on the Val Verde system, which reduced thefuture production forecast.  We revised theunits-of-production calculation for Val Verde, which increased amortizationexpense by approximately $0.2 million per month.  Further revisions to these estimates mayoccur as additional production information is made available to us.

The values assigned to our fractionation agreement andother intangible assets are generally amortized on a straight-line basis.  Our fractionation agreement is beingamortized over its contract period of 20 years. The amortization periods for our other intangible assets, which includenon-compete and other agreements, range from 3 

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years to 15 years. The value of $8.7 million assigned to our crude supply andtransportation intangible customer contracts is being amortized on aunit-of-production basis. 

The value assigned to our excess investment inCentennial Pipeline LLC was created upon its formation.  Approximately $30.0 million is related to acontract and is being amortized on a unit-of-production basis based upon thevolumes transported under the contract compared to the guaranteed totalthroughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is beingamortized on a straight-line basis over the life of the pipeline, which is 35 years.  The value assigned to our excess investmentin Seaway Crude Pipeline Company was created upon acquisition of our 50%ownership interest in 2000.  We areamortizing the $27.1 million excess investment on a straight-line basis over a39-year life related primarily to the life of the pipeline.  

The following table sets forth the estimatedamortization expense of intangible assets and the estimated amortizationexpense allocated to equity earnings for the years ending December 31 (inthousands):
|      | ** ** | **Intangible Assets (1)** | ** ** | **Excess Investments** | ** ** |
|------|------------|-------------------------------------|------------|-----------------------------|------------|
| 2006 |       | $                                   | 28,916     |                        | $          | 4,691 |   |
| 2007 |       | 22,707                              |       | 5,113                       |       |
| 2008 |       | 19,965                              |       | 5,438                       |       |
| 2009 |       | 17,485                              |       | 6,878                       |       |
| 2010 |       | 15,509                              |       | 7,042                       |       |
|      |            |                                     |            |                             |            |  |  |

 

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(1)   Excludes estimated amortization expense of Jonah’s intangible assets asa result of its deconsolidation effective August 1, 2006.

**NOTE3.  INTEREST RATE SWAPS**

In October 2001, TE Products entered into an interestrate swap agreement to hedge its exposure to changes in the fair value of itsfixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as afair value hedge.  The swap agreement hasa notional amount of $210.0 million and matures in January 2028 to match theprincipal and maturity of the TE Products Senior Notes.  Under the swap agreement, TE Products pays afloating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus aspread of 147 basis points, and receives a fixed rate of interest of7.51%.  During the nine months endedSeptember 30, 2006 and 2005, we recognized reductions in interest expense of$1.5 million and $4.6 million, respectively, related to the difference betweenthe fixed rate and the floating rate of interest on the interest rateswap.  During the quarters endedSeptember 30, 2006 and 2005, we reviewed the hedge effectiveness of thisinterest rate swap and noted that no gain or loss from ineffectiveness wasrequired to be recognized.   The fairvalues of this interest rate swap were losses of approximately $3.9 million and$0.9 million at September 30, 2006, and December 31, 2005, respectively.  

During 2002, we entered into interest rate swapagreements, designated as fair value hedges, to hedge our exposure to changesin the fair value of our fixed rate 7.625% Senior Notes due 2012.  The swap agreements had a combined notionalamount of $500.0 million and matured in 2012 to match the principal andmaturity of the Senior Notes.  Under theswap agreements, we paid a floating rate of interest based on a U.S. DollarLIBOR rate, plus a spread, and received a fixed rate of interest of7.625%.  These swap agreements were laterterminated in 2002 resulting in gains of $44.9 million.  The gains realized from the swap terminationshave been deferred as adjustments to the carrying value of the Senior Notes andare being amortized using the effective interest method as reductions to futureinterest expense over the remaining term of the Senior Notes.  At September 30, 2006, the unamortizedbalance of the deferred gains was $29.1 million.  In the event of early extinguishment of theSenior Notes, any 

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remaining unamortized gains would be recognized in theconsolidated statement of income at the time of extinguishment.

During May 2005, we executed a treasury rate lockagreement for a notional amount of $200.0 million to hedge our exposure toincreases in the treasury rate that was to be used to establish the fixedinterest rate for a debt offering that was proposed to occur in the secondquarter of 2005.  During June 2005, theproposed debt offering was cancelled, and the treasury lock was terminated witha realized loss of $2.0 million.  Therealized loss was recorded as a component of interest expense in theconsolidated statements of income in June 2005.

On January 20, 2006, we entered intointerest rate swap agreements with a total notional amount of $200.0 million tohedge our exposure to increases in the benchmark interest rate underlying ourvariable rate revolving credit facility. These interest rate swaps mature in January 2008.  Under the swap agreements, we pay a fixedrate of interest ranging from 4.67% to 4.695% and receive a floating rate basedon a three-month U.S. Dollar LIBOR rate. In the third quarter of 2006, these swaps were designated as cash flowhedges.  Forthe period from January 20,2006 through the date these swaps were designated as cash flow hedges, changesin the fair value of the swaps wererecognized in earnings, which resulted in a $2.2million reduction to interest expense.  While these interest rate swaps remainin effect, future changes in the fair value of the cash flow hedges, to theextent the swaps are effective, will be recognized in othercomprehensive income until the hedged interest costs are recognized inearnings.  At September 30, 2006, thefair value of these interest rate swaps was $1.5 million.   

**NOTE4. PROPERTY, PLANT AND EQUIPMENT**

We evaluate impairment oflong-lived assets in accordance with SFAS No. 144, *Accountingfor the Impairment or Disposal of Long-Lived Assets*.  Long-lived assets are reviewed for impairmentwhenever events or changes in circumstances indicate that the carrying amountof an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used ismeasured by a comparison of the carrying amount of the asset to future net cashflows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to berecognized is measured by the amount by which the carrying amount of the assetsexceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carryingamount or fair value less costs to sell.

During the third quarterof 2005, our Upstream Segment was notified by a connecting carrier that theflow of the carrier’s pipeline system would be reversed, which would directlyimpact the viability of one of our pipeline systems.  This system, located in East Texas, consistsof approximately 45 miles of pipeline, six tanks of various sizes and otherequipment and asset costs.  As a resultof changes to the connecting carrier, we performed an impairment test of thesystem and recorded a $1.8 million non-cash impairment charge, or $0.03 perUnit, included in depreciation and amortization expense in our consolidatedstatements of income, for the excess carrying value over the fair value of thesystem.

During the third quarterof 2005, we completed an evaluation of a crude oil system included in ourUpstream Segment.  The system, located inOklahoma, consists of approximately six miles of pipelines, tanks and otherequipment and asset costs.  The usage ofthe system has declined in recent months as a result of shifting crude oilproduction into areas not supported by the system, and as such, it has becomemore economical to transport barrels by truck to our other pipelinesystems.  As a result, we performed animpairment test on the system and recorded a $0.8 million non-cash impairmentcharge, included in depreciation and amortization expense in our consolidatedstatements of income, for the excess carrying value over the fair value of thesystem.  

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In September 2005, ourTodhunter facility, near Middletown, Ohio, experienced a propane release andfire at a dehydration unit within the storage facility.  The facility is included in our DownstreamSegment.  The dehydration unit wasdestroyed due to the propane release and fire, and as a result, we wrote offthe remaining book value of the asset of $0.8 million to depreciation andamortization expense during the third quarter of 2005.

**NOTE5.  ACQUISITIONS**

**Mexia Pipeline**

On March 31, 2005, we purchased crude oil pipelineassets for $7.1 million from BP Pipelines (North America) Inc. (“BP”).  The assets include approximately 158 miles ofpipeline, which extend from Mexia, Texas, to the Houston, Texas, area and twostations in south Houston with connections to a BP pipeline that originates insouth Houston.  We funded the purchasethrough borrowings under our revolving credit facility, and we allocated thepurchase price to property, plant and equipment.  We have integrated these assets into ourSouth Texas pipeline system, which is included in our Upstream Segment.

**Storage and Terminaling Assets**

On April 1, 2005, we purchased crude oil storage andterminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P.for $35.4 million.  The assets consist ofeight storage tanks with 945,000 barrels of storage capacity, receipt anddelivery manifolds, interconnections to several pipelines, crude oil inventoryand approximately 70 acres of land.  Wefunded the purchase through borrowings under our revolving credit facility, andwe allocated the purchase price to property, plant and equipment andinventory.  

**Refined Products Terminal andTruck Rack**

On July 12, 2005, we purchased a refined products terminal and two-baytruck loading rack in North Little Rock, Arkansas, for $6.8 million from ExxonMobil Corporation.  The assets includethree storage tanks and a two-bay truck loading rack.  We funded the purchase through borrowingsunder our revolving credit facility, and we allocated the purchase price toproperty, plant and equipment and inventory. The terminal serves the central Arkansas refined products market andcomplements our existing Downstream Segment infrastructure in North LittleRock, Arkansas.

**GencoAssets**

On July 15, 2005, we acquired from Texas Genco LLC (“Genco”)all of its interests in certain companies that own a 90-mile pipeline systemand 5.5 million barrels of storage capacity for $62.1 million.  We funded the purchase through borrowingsunder our revolving credit facility.  Weallocated the purchase price to property, plant and equipment, and we accountedfor the acquisition of these assets under the purchase method ofaccounting.  This acquisition was made aspart of an expansion of our refined products origin capabilities in the Houston,Texas, and Texas City, Texas, areas.  Theassets of the purchased companies are being integrated into our DownstreamSegment origin infrastructure in Texas City and Baytown, Texas.  The integration and other system enhancementsshould be in service by the first quarter of 2007, at an estimated cost of$45.0 million.  See Note 17 regarding thesale of certain of these assets to Enterprise.      

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**Terminal Assets**

On July 14, 2006, we purchased assets from New York LPGas Storage, Inc. for $10.0 million.  Theassets consist of two active caverns, one active brine pond, a four bay truckrack, seven above ground storage tanks, and a twelve-spot railcar rack locatedeast of our Watkins Glen, New York facility. We funded the purchase through borrowings under our revolving creditfacility.  We allocated the purchaseprice, net of liabilities assumed, primarily to property, plant and equipmentand inventory.

**NOTE 6.  DISPOSITIONS AND DISCONTINUED OPERATIONS**

**Pioneer Plant**

On March 31, 2006, we sold our ownership interest inthe Pioneer silica gel natural gas processing plant located near Opal, Wyoming,together with Jonah’s rights to process natural gas originating from the Jonahand Pinedale fields, located in southwest Wyoming, to an affiliate ofEnterprise for $38.0 million in cash. The Pioneer plant was not an integral part of our Midstream Segmentoperations, and natural gas processing is not a core business.  We have no continuing involvement in theoperations or results of this plant. This transaction was reviewed and recommended for approval by the Auditand Conflicts Committee of the Board of Directors of our General Partner and afairness opinion was rendered by an independent third-party.  The sales proceeds were used to fund organicgrowth projects, retire debt and for other general partnership purposes.  The carrying value of the Pioneer plant atMarch 31, 2006, prior to the sale, was $19.7 million.  Costs associated with the completion of thetransaction were approximately $0.4 million. 

Condensed statements of income for the Pioneer plant,which is classified as discontinued operations, for the three months and ninemonths ended September 30, 2006 and 2005, are presented below (inthousands):    
| ** **                            | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|---------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                            | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                            | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                  |       |                             |       |                            |       |   |   |   |   |
| Sales of  petroleum products          |       | $                                | —     |                            | $          | 2,880 |   | $ | 3,828 |   | $ | 7,337 |   |
| Other                                 |       | —                           |       | 789                             |       | 932 |   | 2,141 |   |
| Total operating revenues              |       | —                           |       | 3,669                           |       | 4,760 |   | 9,478 |   |
| Purchases of  petroleum products      |       | —                           |       | 2,585                           |       | 3,000 |   | 5,761 |   |
| Operating  expense                    |       | —                           |       | 205                             |       | 182 |   | 501 |   |
| Depreciation and  amortization        |       | —                           |       | 153                             |       | 51 |   | 459 |   |
| Taxes – other  than income taxes |       | —                           |       | 34                              |       | 30 |   | 95 |   |
| Total costs and expenses              |       | —                           |       | 2,977                           |       | 3,263 |   | 6,816 |   |
| Income from  discontinued operations  |       | $                                | —     |                            | $          | 692 |   | $ | 1,497 |   | $ | 2,662 |   |

 

Assets of the discontinued operations consisted of thefollowing at December 31, 2005 (in thousands):
|                                     | ** ** | **December 31,  2005** | ** ** |
|-------------------------------------|------------|-----------------------------|------------|
| Inventories                         |       | $                           | 7          |   |
| Property, plant  and equipment, net |       | 19,812                      |       |
| Assets of discontinued  operations  |       | $                           | 19,819     |   |

 

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Cash flows from discontinued operations for the ninemonths ended September 30, 2006 and 2005, are presented below (in thousands):
|                                         | ** ** | **Nine Months Ended** | ** ** |
|-----------------------------------------|------------|---------------------------------|------------|
| ** **                              | ** ** | **September 30,**          | ** ** |
| ** **                              | ** ** | **2006**                        | ** ** | **2005** | ** ** |
| Cash flows from  operating activities:  |       |                            |       |   |   |
| Net income                              |       | $                               | 19,369     |   | $ | 2,662 |   |
| Depreciation and amortization           |       | 51                              |       | 459 |   |
| Gain on sale of Pioneer plant           |       | (17,872                         | )          | — |   |
| Increase in inventories                 |       | (27                             | )          | (11 | ) |
|                                    |       |                            |       |   |   |
| Cash flow from  discontinued operations |       | $                               | 1,521      |   | 3,110 |   |
|                                         |            |                                 |            |  |  |  |  |

 

**NOTE7.  INVENTORIES**

Inventories are valued atthe lower of cost (based on weighted average cost method) or market.  The costs of inventories did not exceedmarket values at September 30, 2006, and December 31, 2005.  The major components of inventories were asfollows (in thousands):
|                                           | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|-------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| Crude oil (1)                             |       | $                            | 3,754      |                        | $          | 3,021 |   |
| Refined products  and LPGs (2)            |       | 8,361                        |       | 11,864                      |       |
| Lubrication oils  and specialty chemicals |       | 7,281                        |       | 5,740                       |       |
| Materials and  supplies                   |       | 7,423                        |       | 8,203                       |       |
| Other                                     |       | 132                          |       | 241                         |       |
| Total                                     |       | $                            | 26,951     |                        | $          | 29,069 |   |

 

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**(1)**   At September 30, 2006, substantially all of our crudeoil inventory was subject to forward sales contracts.

**(2)**   Refined products and LPGs inventory is managed on acombined basis.  

**NOTE 8.  EQUITYINVESTMENTS**

**Seaway**

Through one of our indirect wholly owned subsidiaries,we own a 50% ownership interest in Seaway Crude Pipeline Company (“Seaway”).  The remaining 50% interest is owned byConocoPhillips.  We operate the Seawayassets.  Seaway owns a pipeline thatcarries mostly imported crude oil from a marine terminal at Freeport, Texas, toCushing, Oklahoma, and from a marine terminal at Texas City, Texas, torefineries in the Texas City and Houston, Texas, areas.  The Seaway Crude Pipeline Company PartnershipAgreement provides for varying participation ratios throughout the life ofSeaway.  From June 2002 through December31, 2005, we received 60% of revenue and expense of Seaway.  For 2006, we are allocated 60% of revenue andexpense for the period January 1, 2006, through May 12, 2006, and 40% for theperiod May 13, 2006, through December 31, 2006. Our share of revenue and expense of Seaway is 47% for 2006.  Thereafter, we will receive 40% of revenueand expense of Seaway.  During the ninemonths ended September 30, 2006 and 2005, we received distributions from Seawayof $15.3 million and 

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$17.5 million, respectively.  During the nine months ended September 30,2006 and 2005, we did not invest any funds in Seaway.

**Centennial**

TE Products owns a 50% ownership interest in CentennialPipeline LLC (“Centennial”), and Marathon Petroleum Company LLC (“Marathon”)owns the remaining 50% interest. Centennial owns an interstate refinedpetroleum products pipeline extending from the upper Texas Gulf Coast tocentral Illinois.  During the nine monthsended September 30, 2006, TE Products contributed $2.5 million toCentennial.  During the nine months endedSeptember 30, 2005, TE Products did not invest any funds in Centennial.  TE Products has received no cashdistributions from Centennial since its formation.

**MBStorage**

TE Products owns a 50% ownership interest in MontBelvieu Storage Partners, L.P. (“MB Storage”), and Louis Dreyfus EnergyServices L.P. (“Louis Dreyfus”) owns the remaining 50% interest.  MB Storage owns storage capacity at the MontBelvieu fractionation and storage complex and a short haul transportationshuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coastenergy marketplace. MB Storage is a service-oriented, fee-based venture servingthe fractionation, refining and petrochemical industries with substantialcapacity and flexibility for the transportation, terminaling and storage ofNGLs, LPGs and refined products.  MBStorage has no commodity trading activity. TE Products operates the facilities for MB Storage.  See Note 14 regarding the expecteddivestiture of MB Storage.

For the years ended December 31, 2006 and 2005, TEProducts receives the first $1.7 million per quarter (or $6.78 million on anannual basis) of MB Storage’s income before depreciation expense, as defined inthe Agreement of Limited Partnership of MB Storage.  TE Products’ share of MB Storage’s earningsmay be adjusted annually by the partners of MB Storage.  Any amount of MB Storage’s annual incomebefore depreciation expense in excess of $6.78 million is allocated evenlybetween TE Products and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MBStorage is allocated between TE Products and Louis Dreyfus based on the netbook value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storagesubsequent to formation is allocated evenly between TE Products and LouisDreyfus.  For the nine months endedSeptember 30, 2006 and 2005, TE Products’ sharing ratios in the earnings of MBStorage were approximately 63.8% and 64.3%, respectively.  During the nine months ended September 30,2006, TE Products received distributions from MB Storage of $11.2 million andcontributed $4.2 million to MB Storage. During the nine months ended September 30, 2005, TE Products receiveddistributions of $10.7 million from MB Storage and contributed $4.0 million toMB Storage, which included a combination of non-cash asset transfers of $1.4million and cash contributions of $2.6 million. 

**SummarizedFinancial Information for Seaway, Centennial and MB Storage**

We use the equity method of accounting to account forour investments in Seaway, Centennial and MB Storage.  Summarized combined financial information forSeaway, Centennial and MB Storage for the nine months ended September 30, 2006and 2005, is presented below (in thousands):  
|            | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------|------------|-----------------------------------------------------|------------|
| ** ** | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
| Revenues   |       | $                                                   | 122,742    |   | $ | 123,224 |   |
| Net income |       | 26,030                                              |       | 39,896 |   |
|            |            |                                                     |            |  |  |  |  |

 

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Summarized combined balance sheet information forSeaway, Centennial and MB Storage as of September 30, 2006, and December 31,2005, is presented below (in thousands):
|                         | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|-------------------------|------------|------------------------------|------------|-----------------------------|------------|
| Current assets          |       | $                            | 62,269     |                        | $          | 60,082 |   |
| Noncurrent  assets      |       | 619,904                      |       | 630,212                     |       |
| Current  liabilities    |       | 24,502                       |       | 32,242                      |       |
| Long-term debt          |       | 150,000                      |       | 150,000                     |       |
| Noncurrent  liabilities |       | 21,341                       |       | 13,626                      |       |
| Partners’ capital  |       | 486,330                      |       | 494,426                     |       |
|                         |            |                              |            |                             |            |  |  |

 

## **Jonah**

OnAugust 1, 2006, Enterprise, through its affiliate, Enterprise Gas Processing,LLC, became our joint venture partner by acquiring an interest in Jonah, thepartnership through which we owned the Jonah system.  Prior to entering into the Jonah jointventure, Enterprise had managed the construction of the Phase V expansion andfunded the initial costs under a letter of intent we entered into in February2006.  In connection with the jointventure arrangement, we and Enterprise intend to continue the Phase Vexpansion, which is expected to increase the system capacity of the Jonahsystem from 1.5 billion cubic feet (“Bcf”) per day to approximately 2.4 Bcf perday and to significantly reduce system operating pressures, which isanticipated to lead to increased production rates and ultimate reserverecoveries.  The first portion of theexpansion, which is expected to increase the system gathering capacity toapproximately 2.0 Bcf per day, is scheduled to be completed in the firstquarter of 2007 at an estimated cost of approximately $295.0 million.  The second portion of the expansion isexpected to cost approximately $170.0 million and be completed by the end of2007.  We expect to reimburse Enterprisefor approximately 50% of these costs.    

Enterprisewill continue to manage the Phase V construction project.  We are entitled to all distributions from thejoint venture until specified milestones are achieved, at which pointEnterprise will be entitled to receive approximately 50% of the incrementalcash flow from portions of the system placed in service as part of the expansion.  From August 1, 2006, we and Enterpriseequally share the costs of the Phase V expansion.  In the third quarter of 2006, we reimbursedEnterprise $65.0 million for 50% of the Phase V cost incurred by it throughAugust 1, 2006 (including its cost of capital of $1.3 million).  At September 30, 2006, we had a payable toEnterprise for costs incurred through September 30, 2006, of $18.9million.  After subsequent milestones areachieved, we and Enterprise will share distributions based on a formula thattakes into account the capital contributions of the parties, includingexpenditures by us prior to the expansion. Based on this formula in the partnership agreement, we expect to own aninterest in Jonah of approximately 80%, with Enterprise owning the remaining20% and serving as operator, with further costs being allocated based on suchownership interests.  The joint ventureis governed by a management committee comprised of two representatives approvedby Enterprise and two representatives approved by us, each with equal votingpower.  This transaction was reviewed andrecommended for approval by the Audit and Conflicts Committee of the Board ofDirectors of our General Partner.

EffectiveAugust 1, 2006, with the formation of the joint venture, Jonah was deconsolidated,and we began using the equity method of accounting to account for ourinvestment in Jonah.  Under the equitymethod, we record the costs of our investment within the “Equity Investments”line on our consolidated balance sheet, and as changes in the net assets ofJonah occur (for example, earnings, contributions and distributions), we willrecognize our proportional share of that change in the “Equity Investments”account.    

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Summarized financial information for Jonah for theperiod August 1, 2006 through September 30, 2006, is presented below (inthousands):   
| Revenues   |   | $      | 30,101 |   |
|------------|--------|--------|--------|--------|
| Net income |   | 11,563 |   |

 

Summarized balance sheet information for Jonah as ofSeptember 30, 2006, is presented below (in thousands):
| Current assets          |   | $       | 39,202 |   |
|-------------------------|--------|---------|--------|--------|
| Noncurrent  assets      |   | 725,953 |   |
| Current  liabilities    |   | 15,425  |   |
| Noncurrent  liabilities |   | 186     |   |
| Partners’ capital  |   | 749,544 |   |

 

**NOTE9.  DEBT**

## **Senior Notes**

On January 27, 1998, TE Products completed theissuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and$210.0 million principal amount of 7.51% Senior Notes due 2028 (collectivelythe “TE Products Senior Notes”).  The6.45% TE Products Senior Notes were issued at a discount of $0.3 million andare being accreted to their face value over the term of the notes.  The 6.45% TE Products Senior Notes due 2008may not be redeemed prior to their maturity on January 15, 2008.  The 7.51% TE Products Senior Notes due 2028,issued at par, may be redeemed at any time after January 15, 2008, at theoption of TE Products, in whole or in part, at the following redemption prices(expressed in percentages of the principal amount) during the twelve monthsbeginning January 15 of the years indicated:
|          | ** ** | **Redemption** | ** ** |
|----------|------------|----------------|------------|
| **Year** | ** ** | **Price**      | ** ** |
|     |       |           |       |
| 2008     |       | 103.755        | %          |
| 2009     |       | 103.380        | %          |
| 2010     |       | 103.004        | %          |
| 2011     |       | 102.629        | %          |
| 2012     |       | 102.253        | %          |
| 2013     |       | 101.878        | %          |
| 2014     |       | 101.502        | %          |
| 2015     |       | 101.127        | %          |
| 2016     |       | 100.751        | %          |
| 2017     |       | 100.376        | %          |

 

and thereafter at 100% of the principal amount,together in each case with accrued interest at the redemption date.   

The TE Products Senior Notes do not have sinking fundrequirements.  Interest on the TEProducts Senior Notes is payable semiannually in arrears on January 15 and July15 of each year.  The TE Products SeniorNotes are unsecured obligations of TE Products and rank pari passu with allother unsecured and unsubordinated indebtedness of TE Products.  The indenture governing the TE ProductsSenior Notes contains covenants, including, but not limited to, covenantslimiting the creation of liens securing indebtedness and sale and leasebacktransactions.  However, the indenturedoes not limit our ability to incur additional indebtedness.  As of September 30, 2006, TE Products was incompliance with the covenants of the TE Products Senior Notes. 

On February 20, 2002, we completed the issuance of$500.0 million principal amount of 7.625% Senior Notes due 2012.  The 7.625% Senior Notes were issued at adiscount of $2.2 million and are being accreted to their face value over theterm of the notes.  The Senior Notes maybe redeemed at any time at our option with the payment 

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of accrued interest and a make-whole premiumdetermined by discounting remaining interest and principal payments using adiscount rate equal to the rate of the United States Treasury securities ofcomparable remaining maturity plus 35 basis points.  The indenture governing our 7.625% SeniorNotes contains covenants, including, but not limited to, covenants limiting thecreation of liens securing indebtedness and sale and leasebacktransactions.  However, the indenturedoes not limit our ability to incur additional indebtedness.  As of September 30, 2006, we were incompliance with the covenants of these Senior Notes.  

On January 30, 2003, we completed the issuance of$200.0 million principal amount of 6.125% Senior Notes due 2013.  The 6.125% Senior Notes were issued at adiscount of $1.4 million and are being accreted to their face value over theterm of the notes.  The Senior Notes maybe redeemed at any time at our option with the payment of accrued interest anda make-whole premium determined by discounting remaining interest and principalpayments using a discount rate equal to the rate of the United States Treasurysecurities of comparable remaining maturity plus 35 basis points.  The indenture governing our 6.125% SeniorNotes contains covenants, including, but not limited to, covenants limiting thecreation of liens securing indebtedness and sale and leaseback transactions.  However, the indenture does not limit ourability to incur additional indebtedness. As of September 30, 2006, we were in compliance with the covenants ofthese Senior Notes.   

The following table summarizes the estimated fairvalues of the Senior Notes as of September 30, 2006, and December 31, 2005 (inmillions):
|                                                   | ** ** | ** **      | ** ** | **Fair Value**          | ** ** |
|---------------------------------------------------|------------|-----------------|------------|------------------------------|------------|
| ** **                                        | ** ** | **Face  Value** | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
| 6.45% TE Products Senior Notes, due January 2008  |       | $               | 180.0      |                         | $          | 182.2 |   | $ | 183.7 |   |
| 7.625% Senior  Notes, due February 2012           |       | 500.0           |       | 536.1                        |       | 552.0 |   |
| 6.125% Senior  Notes, due February 2013           |       | 200.0           |       | 200.7                        |       | 205.6 |   |
| 7.51% TE Products  Senior Notes, due January 2028 |       | 210.0           |       | 222.6                        |       | 224.1 |   |
|                                                   |            |                 |            |                              |            |  |  |  |  |  |

 

We have entered into interest rate swap agreements tohedge our exposure to changes in the fair value on a portion of the SeniorNotes discussed above (see Note 3).

## **Revolving Credit Facility**

We have in place a $700.0 million unsecured revolvingcredit facility, including the issuance of letters of credit (“Revolving CreditFacility”), which matures on December 13, 2011. Commitments under the credit facility may be increased up to a maximumof $850.0 million upon our request, subject to lender approval and thesatisfaction of certain other conditions. The interest rate is based, at our option, on either the lender’s baserate plus a spread, or LIBOR plus a spread in effect at the time of theborrowings.  Financial covenants in theRevolving Credit Facility require that we maintain a ratio of ConsolidatedFunded Debt to Pro Forma EBITDA (as defined and calculated in the facility) ofless than 4.75 to 1.00 (subject to adjustment for specified acquisitions) and aratio of EBITDA to Interest Expense (as defined and calculated in the facility)of at least 3.00 to 1.00, in each case with respect to specified twelve monthperiods.  Other restrictive covenants inthe Revolving Credit Facility limit our ability to, among other things, incuradditional indebtedness, make distributions in excess of Available Cash (seeNote 10), incur liens, engage in specified transactions with affiliates andcomplete mergers, acquisitions and sales of assets.    

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On July 31, 2006, we amended our Revolving CreditFacility.  The primary revisions were asfollows:

·      The maturity date of thecredit facility was extended from December 13, 2010 to December 13, 2011.  Also under the terms of the amendment, we mayrequest up to two one-year extensions of the maturity date.  These extensions, if requested, will becomeeffective subject to lender approval and satisfaction of certain otherconditions.

·      The amendment releases Jonahas a guarantor of the Revolving Credit Facility and restricts the amount ofoutstanding debt of the Jonah joint venture to debt owing to the owners of itspartnership interests and other third-party debt in the principal aggregateamount of $50.0 million. 

·      The amendment modifies thefinancial covenants to, among other things, allow us to include in thecalculation of our Consolidated EBITDA (as defined in the Revolving CreditFacility) pro forma adjustments for material capital projects.

·      The amendmentallows for the issuance of Hybrid Securities (as defined in the RevolvingCredit Facility) of up to 15% of our Consolidated Total Capitalization (asdefined in the Revolving Credit Facility). 

At September 30, 2006, $359.0 million was outstandingunder the Revolving Credit Facility at a weighted average interest rate of6.02%.  At September 30, 2006, we were incompliance with the covenants of this credit facility.   

The following table summarizes the principal amountsoutstanding under all of our debt instruments as of September 30, 2006, andDecember 31, 2005 (in thousands):
|                                                                    | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|--------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| Revolving Credit  Facility, due December 2011                      |       | $                            | 359,000    |                        | $          | 405,900 |   |
| 6.45% TE  Products Senior Notes, due January 2008                  |       | 179,960                      |       | 179,937                     |       |
| 7.625% Senior  Notes, due February 2012                            |       | 498,825                      |       | 498,659                     |       |
| 6.125% Senior  Notes, due February 2013                            |       | 199,095                      |       | 198,988                     |       |
| 7.51% TE  Products Senior Notes, due January 2028                  |       | 210,000                      |       | 210,000                     |       |
|                                                               |       |                         |       |                        |       |
| Total borrowings                                                   |       | 1,446,880                    |       | 1,493,484                   |       |
| Adjustment to  carrying value associated with hedges of fair value |       | 25,195                       |       | 31,537                      |       |
|                                                               |       |                         |       |                        |       |
| Total Debt Instruments                                             |       | $                            | 1,472,075  |                        | $          | 1,525,021 |   |

 

**Letter of Credit**

At September 30, 2006, we had outstanding a $10.1million standby letter of credit in connection with crude oil purchased duringthe third quarter of 2006.  The payablerelated to these purchases of crude oil is expected to be paid during thefourth quarter of 2006.

**NOTE 10.  PARTNERS’ CAPITAL AND DISTRIBUTIONS**

## **Equity Offering**

## In July 2006,we issued and sold in an underwritten public offering 5.0 million Units at aprice to the public of $35.50 per Unit. The proceeds from the offering, net of underwriting discount, totaledapproximately $170.4 

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## million. On July 12, 2006, 750,000 additional Units were sold upon exercise ofthe underwriters’ over-allotment option granted in connection with theoffering.  Proceeds from theover-allotment sale, net of underwriting discount, totaled $25.6 million.  The net proceeds from the offering and theover-allotment were used to reduce indebtedness under our Revolving CreditFacility.

## **Quarterly Distributions of Available Cash**

We make quarterly cash distributions of all of ouravailable cash, generally defined in our Partnership Agreement as consolidatedcash receipts less consolidated cash disbursements and cash reservesestablished by the General Partner in its reasonable discretion (“AvailableCash”).  Pursuant to the PartnershipAgreement, the General Partner receives incremental incentive cashdistributions when unitholders’ cash distributions exceed certain targetthresholds as follows:
|                                                                               | ** ** | ** **      | ** ** | **General** | ** ** |
|-------------------------------------------------------------------------------|------------|-----------------|------------|-------------|------------|
| ** **                                                                    | ** ** | **Unitholders** | ** ** | **Partner** | ** ** |
| Quarterly Cash  Distribution per Unit:                                        |       |            |       |        |       |
| Up to Minimum Quarterly Distribution ($0.275 per  Unit)                       |       | 98              | %          | 2           | %          |
| First Target – $0.276 per Unit up to $0.325 per Unit                     |       | 85              | %          | 15          | %          |
| Second Target – $0.326 per Unit up to $0.45 per Unit                     |       | 75              | %          | 25          | %          |
| Over Second  Target – Cash distributions greater than $0.45 per Unit (1) |       | 50              | %          | 50          | %          |

 

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(1)   See “– EPCO Proposal” below for a discussionof the proposed elimination of the 50%/50% distribution tier in exchange forthe issuance of additional Units to the General Partner.

The following table reflects the allocation of totaldistributions paid during the nine months ended September 30, 2006 and 2005 (inthousands, except per Unit amounts):
|                                         | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-----------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                              | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
| Limited Partner  Units                  |       | $                                                   | 145,558    |   | $ | 130,694 |   |
| General Partner  Ownership Interest     |       | 2,971                                               |       | 2,667 |   |
| General Partner  Incentive              |       | 57,647                                              |       | 50,848 |   |
| Total Cash Distributions Paid           |       | $                                                   | 206,176    |   | $ | 184,209 |   |
| Total Cash  Distributions Paid Per Unit |       | $                                                   | 2.025      |   | $ | 2.00 |   |

 

On November 7, 2006, wepaid a cash distribution of $0.675 per Unit for the quarter ended September 30,2006.  The third quarter 2006 cashdistribution totaled $72.4 million.

**General Partner’s Interest**

As of September 30, 2006, and December 31, 2005, wehad deficit balances of $79.3 million and $61.5 million, respectively, in ourGeneral Partner’s equity account.  Thesenegative balances do not represent assets to us and do not representobligations of the General Partner to contribute cash or other property tous.  The General Partner’s equity accountgenerally consists of its cumulative share of our net income less cashdistributions made to it plus capital contributions that it has made to us (seeour Consolidated Statement of Partners’ Capital for a detail of the GeneralPartner’s equity account).  For the ninemonths ended September 30, 2006, the General Partner was allocated $42.8million (representing 29.4%) of our net income and received $60.6 million incash distributions.

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Capital Accounts, as defined under our PartnershipAgreement, are maintained for our General Partner and our limited partners.  The Capital Account provisions of ourPartnership Agreement incorporate principles established for U.S. federalincome tax purposes and are not comparable to the equity accounts reflectedunder accounting principles generally accepted in the United States in ourfinancial statements.  Under ourPartnership Agreement, the General Partner is required to make additionalcapital contributions to us upon the issuance of any additional Units ifnecessary to maintain a Capital Account balance equal to 1.999999% of the totalCapital Accounts of all partners.  AtSeptember 30, 2006, and December 31, 2005, the General Partner’s CapitalAccount balance substantially exceeded this requirement.

Net income is allocated between the General Partnerand the limited partners in the same proportion as aggregate cash distributionsmade to the General Partner and the limited partners during the period.  This is generally consistent with the mannerof allocating net income under our Partnership Agreement.  Net income determined under our PartnershipAgreement, however, incorporates principles established for U.S. federal incometax purposes and is not comparable to net income reflected under accountingprinciples generally accepted in the United States in our financial statements.

Cash distributions that we make during a period mayexceed our net income for the period.  Wemake quarterly cash distributions of all of our Available Cash, generallydefined as consolidated cash receipts less consolidated cash disbursements andcash reserves established by the General Partner in its reasonablediscretion.  Cash distributions in excessof net income allocations and capital contributions during the year endedDecember 31, 2005, and the nine months ended September 30, 2006, resulted in deficitsin the General Partner’s equity account at December 31, 2005, and September 30,2006.  Future cash distributions thatexceed net income will result in an increase in the deficit balance in theGeneral Partner’s equity account. 

According to the Partnership Agreement, in the eventof our dissolution, after satisfying our liabilities, our remaining assetswould be divided among our limited partners and our General Partner generallyin the same proportion as Available Cash but calculated on a cumulative basisover the life of the Partnership.  If adeficit balance still remains in the General Partner’s equity account after allallocations are made between the partners, the General Partner would not berequired to make whole any such deficit.

**EPCOProposal**

On April 20, 2006,EPCO submitted a proposal to the Audit and Conflicts Committee of our GeneralPartner’s Board of Directors to reduce the General Partner’s maximum percentageinterest in our quarterly distributions from 50% to 25% with respect to thatportion of our quarterly cash distribution to partners that exceeds $0.325 perUnit.  In exchange for the agreement toreduce its maximum percentage interest in our quarterly distributions, ourGeneral Partner would receive a number of newly-issued Units that, based on thedistribution rate and the number of Units outstanding at the time of issuance,would result in our General Partner receiving cash distributions from thenewly-issued Units and from its reduced maximum percentage interest in ourquarterly distributions that would approximately equal the cash distributionsour General Partner would have received from its maximum percentage interest inour quarterly distributions without reduction. Based on our distribution rate and outstanding Units as of the date ofthe filing of this Report, the number of newly-issued Units issued to theGeneral Partner would be approximately 14.1 million.  On September 11, 2006, we filed with theSecurities and Exchange Commission a definitive proxy statement that outlinesthe EPCO proposal to be voted upon at a special meeting of our unitholders andother changes to our Partnership Agreement that are part of the EPCO proposal,all of which are conditioned upon one another. The proxy statement also contains separate proposals for the adoption ofan employee Unit purchase plan and a long term incentive plan.  The special meeting was convened on October26, 2006, and adjourned, without voting on the proposals, to November 30, 2006by the General Partner for lack of a quorum.    

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**NOTE 11.RELATED PARTY TRANSACTIONS**

**EPCO andAffiliates and Duke Energy, DEFS and Affiliates**

We do not have any employees.  We are managed by the Company, which prior toFebruary 23, 2005, was an indirect wholly owned subsidiary of DEFS.  According to our Partnership Agreement, theCompany was entitled to reimbursement of all direct and indirect expensesrelated to our business activities.  As aresult of the change in ownership of the General Partner on February 24, 2005,all of our management, administrative and operating functions are performed byemployees of EPCO, pursuant to the ASA. We reimburse EPCO for the allocated costs of its employees who performoperating, management and other administrative functions for us (see Note 1).**             **

The following tablesummarizes the related party transactions with EPCO and affiliates and DEFS andaffiliates for the three months and nine months ended September 30, 2006 and2005 (in millions):
| ** **                                        | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|---------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                        | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                                        | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Revenues from EPCO and  affiliates: (1)           |       |                             |       |                            |       |   |   |   |   |
| Sales of  petroleum products                      |       | $                                | 1.0        |                            | $          | — |   | $ | 3.1 |   | $ | — |   |
| Transportation –  NGLs                       |       | 2.8                              |       | 2.3                             |       | 7.4 |   | 5.2 |   |
| Transportation –  LPGs                       |       | 0.5                              |       | 1.1                             |       | 2.8 |   | 2.7 |   |
| Other operating  revenues                         |       | 0.4                              |       | —                          |       | 0.6 |   | — |   |
|                                              |       |                             |       |                            |       |   |   |   |   |
| Costs and Expenses from  EPCO and affiliates: (1) |       |                             |       |                            |       |   |   |   |   |
| Payroll,  administrative and other (2)            |       | 27.9                             |       | 29.1                            |       | 90.2 |   | 37.9 |   |
| Purchases of  petroleum products                  |       | 14.0                             |       | —                          |       | 30.5 |   | — |   |
|                                              |       |                             |       |                            |       |   |   |   |   |
| Revenues from DEFS and  affiliates: (3)           |       |                             |       |                            |       |   |   |   |   |
| Sales of  petroleum products                      |       | —                           |       | —                          |       | — |   | 4.3 |   |
| Transportation –  NGLs                       |       | —                           |       | —                          |       | — |   | 2.8 |   |
| Gathering –  Natural gas – Jonah        |       | —                           |       | —                          |       | — |   | 0.5 |   |
| Transportation –  LPGs                       |       | —                           |       | —                          |       | — |   | 0.7 |   |
| Other operating  revenues                         |       | —                           |       | —                          |       | — |   | 2.4 |   |
|                                              |       |                             |       |                            |       |   |   |   |   |
| Costs and Expenses from  DEFS and affiliates: (3) |       |                             |       |                            |       |   |   |   |   |
| Payroll,  administrative and other (4) (5)        |       | —                           |       | —                          |       | — |   | 16.2 |   |
| Purchases of petroleum  products                  |       | —                           |       | —                          |       | — |   | 38.5 |   |
|                                                   |            |                                  |            |                                 |            |  |  |  |  |  |  |  |  |

 

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(1)   Operating revenues earned and expensesincurred from activities with EPCO and its affiliates are considered relatedparty transactions beginning February 24, 2005, as a result of the change inownership of the General Partner.

(2)   Substantially all of these costs were relatedto payroll, payroll related expenses and administrative expenses, includingreimbursements related to employee benefits and employee benefit plans,incurred in managing us and our subsidiaries in accordance with the ASA.

(3)   Operating revenues earned and expensesincurred from activities with DEFS and its affiliates are considered relatedparty transactions prior to February 23, 2005, at which time a change inownership of the General Partner occurred.

(4)   Includes operating costs and expenses relatedto DEFS managing and operating the Jonah and Val Verde systems and theChaparral NGL pipeline on our behalf under contractual agreements establishedat the time of acquisition of each asset. In connection with the change in ownership of our General Partner, we orEPCO have assumed these activities.

(5)   Substantially all of these costs were relatedto payroll, payroll related expenses and administrative expenses incurred inmanaging us and our subsidiaries.

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At September 30, 2006 and December 31, 2005, we hadreceivables from EPCO and affiliates of $1.6 million and $4.3 million,respectively, related to sales and transportation services provided to EPCO andaffiliates.  At September 30, 2006 andDecember 31, 2005, we had payables to EPCO and affiliates of $41.6 million and$9.8 million, respectively, related to direct payroll, payroll related costsand other operational related costs attributable to our operations under theASA.

Beginning February 24, 2005, the majority of ourinsurance coverage, including property, liability, business interruption, autoand directors and officers’ liability insurance, was obtained throughEPCO.  We incurred insurance expenserelated to premiums paid by EPCO of $3.6 million and $2.4 million for the threemonths ended September 30, 2006 and 2005, respectively.  We incurred insurance expense related topremiums paid by EPCO of $10.8 million (including $0.1 million in financecharges) and $4.5 million for the nine months ended September 30, 2006 and2005, respectively.  At September 30,2006 and December 31, 2005, we had insurance reimbursement receivables due fromEPCO of $1.8 million and $1.3 million, respectively.

On March 31, 2006, we sold our ownership interest inthe Jonah Pioneer silica gel natural gas processing plant located near Opal,Wyoming, together with Jonah’s rights to process natural gas originating fromthe Jonah and Pinedale fields, located in southwest Wyoming to an affiliate ofEnterprise for $38.0 million.  Werecognized a gain of approximately $17.9 million on the sale of this asset (seeNote 6).

On October 6, 2006, we sold certain idled crude oilpipeline assets and refined products pipeline assets in the Houston, Texasarea, with a carrying value of approximately $5.6 million, to an affiliate ofEnterprise for approximately $11.7 million (see Note 17).  We also anticipate selling additional refinedproducts pipeline assets in the Houston, Texas area to an affiliate ofEnterprise in the fourth quarter of 2006 for approximately $8.0 million, whichat September 30, 2006, have a carrying value of approximately $2.5million.  These transactions werereviewed and recommended for approval by the Audit and Conflicts Committee ofthe Board of Directors of our General Partner.

*Jonah Joint Venture*

OnAugust 1, 2006, Enterprise (through an affiliate) became our joint venturepartner by acquiring an interest in Jonah, the partnership through which weowned the Jonah system.  In the thirdquarter of 2006, we reimbursed Enterprise $65.0 million for 50% of the Phase Vcost incurred by it through August 1, 2006 (including its cost of capital of$1.3 million).  At September 30, 2006, wehad a payable to Enterprise for costs incurred through September 30, 2006, of$18.9 million (see Note 8 for further discussion on the Jonah joint venture).

In conjunction with theformation of the joint venture, we have agreed to indemnify Enterprise from anyand all losses, claims, demands, suits, liability, costs and expenses arisingout of or related to breaches of our representations, warranties, or covenantsrelated to the formation of the Jonah joint venture, Jonah’s ownership oroperation of the Jonah system prior to the effective date of the joint venture,and any environmental activity, or violation of or liability underenvironmental laws arising from or related to the condition of the Jonah systemprior to the effective date of the joint venture.  In general, a claim for indemnificationcannot be filed until the losses suffered by Enterprise exceed $1.0 million,and the maximum potential amount of future payments under the indemnity islimited to $100.0 million.  However, ifcertain representations or warranties are breached, the maximum potentialamount of future payments under the indemnity is capped at $207.6 million.  All indemnity payments are net of insurancerecoveries that Enterprise may receive from third-party insurers. We carry insurancecoverage that may 

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offset anypayments required under the indemnity. We do not expect that these indemnities will have a material adverseeffect on our financial position, results of operations or cash flows.

**NOTE12.  EMPLOYEE BENEFIT PLANS**

## **Retirement Plans**

The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”)was a non-contributory, trustee-administered pension plan.  In addition, the TEPPCO Supplemental BenefitPlan (“TEPPCO SBP”) was a non-contributory, nonqualified, defined benefitretirement plan, in which certain executive officers participated.  The TEPPCO SBP was established to restorebenefit reductions caused by the maximum benefit limitations that apply toqualified plans.  The benefit formula forall eligible employees was a cash balance formula.  Under a cash balance formula, a planparticipant accumulated a retirement benefit based upon pay credits and currentinterest credits.  The pay credits werebased on a participant’s salary, age and service.  We used a December 31 measurement date forthese plans.

On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBPwere amended.  Effective May 31, 2005,participation in the TEPPCO RCBP was frozen, and no new participants wereeligible to be covered by the plan after that date.  Effective June 1, 2005, EPCO adopted theTEPPCO RCBP and the TEPPCO SBP for the benefit of its employees providingservices to us.  Effective December 31,2005, all plan benefits accrued were frozen, participants received no additionalpay credits after that date, and all plan participants were 100% vestedregardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, andplan participants have the option to receive their benefits either through alump sum payment in 2006 or through an annuity. In April 2006, we received a determination letter from the IRS providingIRS approval of the plan termination. For those plan participants who elect to receive an annuity, we willpurchase an annuity contract from an insurance company in which the planparticipant owns the annuity, absolving us of any future obligation to theparticipant.  Participants in the TEPPCOSBP received pay credits through November 30, 2005, and received lump sumbenefit payments in December 2005.  Boththe RCBP and SBP benefit payments are discussed below.

In June 2005, we recorded a curtailment charge of $0.1million in accordance with SFAS No. 88, *Employers’ Accounting forSettlements and Curtailments of Defined Benefit Pension Plans and forTermination Benefits*, as a result of the TEPPCO RCBP and TEPPCO SBPamendments.  As of May 31, 2005, thefollowing assumptions were changed for purposes of determining the net periodicbenefit costs for the remainder of 2005: the discount rate, the long-term rateof return on plan assets, and the assumed mortality table.  The discount rate was decreased from 5.75% to5.00% to reflect rates of returns on bonds currently available to settle theliability.   The expected long-term rateof return on plan assets was changed from 8% to 2% due to the movement of planfunds from equity investments into short-term money market funds.  The mortality table was changed to reflectoverall improvements in mortality experienced by the general population.  The curtailment charge arose due to theaccelerated recognition of the unrecognized prior service costs.  We recorded additional settlement charges ofapproximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCOSBP.  We expect to record additionalsettlement charges of approximately $4.0 million during the fourth quarter of2006 relating to the TEPPCO RCBP for any existing unrecognized losses upon theplan termination and final distribution of the assets to the plan participants.

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The components of net pension benefits costs for theTEPPCO RCBP and the TEPPCO SBP for the three months and nine months endedSeptember 30, 2006 and 2005, were as follows (in thousands):
|                                                | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                     | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                                     | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Service cost  benefit earned during the period |       | $                                | —     |                            | $          | 1,147 |   | $ | — |   | $ | 3,246 |   |
| Interest cost on  projected benefit obligation |       | 255                              |       | 233                             |       | 762 |   | 701 |   |
| Expected return  on plan assets                |       | (115                             | )          | (76                             | )          | (351 | ) | (595 | ) |
| Amortization of  prior service cost            |       | —                           |       | 1                               |       | — |   | 4 |   |
| Amortization of  actuarial losses              |       | 35                               |       | 37                              |       | 104 |   | 92 |   |
| SFAS 88  curtailment charge                    |       | —                           |       | —                          |       | — |   | 50 |   |
| Net pension  benefits costs                    |       | $                                | 175        |                            | $          | 1,342 |   | $ | 515 |   | $ | 3,498 |   |

 

## **Other Postretirement Benefits**

We provided certain health care and life insurancebenefits for retired employees on a contributory and non-contributory basis (“TEPPCOOPB”).  Employees became eligible forthese benefits if they met certain age and service requirements at retirement,as defined in the plans.  We provided afixed dollar contribution, which did not increase from year to year, towardsretired employee medical costs.  Theretiree paid all health care cost increases due to medical inflation.  We used a December 31 measurement date forthis plan.

In May 2005, benefits provided to employees under theTEPPCO OPB were changed.  Employeeseligible for these benefits received them through December 31, 2005, however,effective December 31, 2005, these benefits were terminated.  As a result of this change in benefits and inaccordance with SFAS No. 106, *Employers’ Accounting forPostretirement Benefits Other Than Pensions*, we recorded acurtailment credit of approximately $1.7 million in our accumulatedpostretirement obligation which reduced our accumulated postretirementobligation to the total of the expected remaining 2005 payments under theTEPPCO OPB.  The employees participatingin this plan at that time were transferred to DEFS, who is expected to providepostretirement benefits to these retirees. We recorded a one-time settlement to DEFS in the third quarter of 2005of $0.4 million for the remaining postretirement benefits.

The components of net postretirement benefits cost forthe TEPPCO OPB for the three months and nine months ended September 30, 2006and 2005, were as follows (in thousands):
|                                                                 | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                                      | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                                                      | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Service cost  benefit earned during the period                  |       | $                                | —     |                            | $          | — |   | $ | — |   | $ | 81 |   |
| Interest cost on  accumulated postretirement benefit obligation |       | —                           |       | —                          |       | — |   | 69 |   |
| Amortization of  prior service cost                             |       | —                           |       | —                          |       | — |   | 53 |   |
| Recognized net  actuarial loss                                  |       | —                           |       | —                          |       | — |   | 4 |   |
| SFAS 106  curtailment credit                                    |       | —                           |       | —                          |       | — |   | (1,676 | ) |
| Net  postretirement benefits costs                              |       | $                                | —     |                            | $          | — |   | $ | — |   | $ | (1,469 | ) |

 

## Effective June1, 2005, the payroll functions performed by DEFS for our General Partner weretransferred from DEFS to EPCO.  For thoseemployees who were receiving certain other postretirement benefits at the timeof the acquisition of our General Partner by DFI, DEFS is expected to continueto provide these benefits to those 

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## employees. Effective June 1, 2005, EPCO began providing certain otherpostretirement benefits to those employees who became eligible for the benefitsafter June 1, 2005, and will charge those benefit related costs to us.  As a result of these changes, we recorded a$1.2 million reduction in our other postretirement obligation in June 2005.

## **Estimated Future Benefit Contributions**

We do not expect to make further contributions to ourretirement plans and other postretirement benefit plans.  However, EPCO maintains a 401(k) plan for thebenefit of employees providing services to us, and we will continue toreimburse EPCO for the cost of maintaining this plan in accordance with theASA.

**NOTE 13.SEGMENT INFORMATION**

We have three reporting segments:

·      Our DownstreamSegment, which is engaged in the transportation and storage of refinedproducts, LPGs and petrochemicals;

·      Our UpstreamSegment, which is engaged in the gathering, transportation, marketing andstorage of crude oil and distribution of lubrication oils and specialtychemicals; and

·      Our MidstreamSegment, which is engaged in the gathering of natural gas, fractionation ofNGLs and transportation of NGLs.

The amounts indicated below as “Partnership and Other”relate primarily to intersegment eliminations and assets that we hold that havenot been allocated to any of our reporting segments.

Our Downstream Segment revenues are earned fromtransportation and storage of refined products and LPGs, intrastatetransportation of petrochemicals, sale of product inventory and other ancillaryservices. The two largest operating expense items of the Downstream Segment arelabor and electric power.  We generallyrealize higher revenues in this segment during the first and fourth quarters ofeach year since these operations are somewhat seasonal. Refined productsvolumes are generally higher during the second and third quarters because ofgreater demand for gasolines during the spring and summer driving seasons. LPGsvolumes are generally higher from November through March due to higher demandfor propane, a major fuel for residential heating.  Our Downstream Segment also includes theresults of operations of the northern portion of the Dean Pipeline, whichtransports refinery grade propylene from Mont Belvieu to Point Comfort,Texas.  Our Downstream Segment alsoincludes our equity investments in MB Storage, which we are required to divest(see Note 14), and in Centennial (see Note 8).

Our Upstream Segment revenues are earned fromgathering, transportation, marketing and storage of crude oil and distributionof lubrication oils and specialty chemicals, principally in Oklahoma, Texas,New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crudeoil along our pipeline systems, or from third party pipeline systems, andarranging the necessary transportation logistics for the ultimate sale ordelivery of the crude oil to local refineries, marketers or other endusers.  Our Upstream Segment alsoincludes our equity investment in Seaway (see Note 8).  Seaway consists of large diameter pipelinesthat transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coastto Cushing, Oklahoma, a crude oil distribution point for the central UnitedStates, and to refineries in the Texas City and Houston areas.

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Our Midstream Segment revenues are earned from thegathering of coal bed methane and conventional natural gas in the San JuanBasin in New Mexico and Colorado, through Val Verde; transportation of NGLsfrom two trunkline NGL pipelines in South Texas, two NGL pipelines in EastTexas and a pipeline system (Chaparral) from West Texas and New Mexico to MontBelvieu; and the fractionation of NGLs in Colorado.  Our Midstream Segment also includes ourequity investment in Jonah (see Note 8). Jonah, which is a joint venture between us and an affiliate ofEnterprise, owns a natural gas gathering system in the Green River Basin insouthwestern Wyoming.  Prior to August 1,2006, when Jonah was wholly-owned by us, operating results for Jonah wereincluded in the consolidated Midstream Segment operating results.  Effective August 1, 2006, we entered into thejoint venture with Enterprise’s affiliate, upon which Jonah was deconsolidated,and its operating results since August 1, 2006, have been accounted for underthe equity method of accounting. Operating results of the Pioneer plant, which we sold to an Enterpriseaffiliate in March 2006, are shown as discontinued operations for the threemonths and nine months ended September 30, 2006 and 2005.

On April 1, 2006, we adopted EITF 04-13, *Accounting for Purchases and Sales of Inventory with the SameCounterparty* (see Note 1), which resulted in crude oil inventorypurchases and sales under buy/sell transactions, which were previously recordedas gross purchases and sales, to be treated as inventory exchanges in ourconsolidated statements of income.  EITF04-13 reduced gross revenues and purchases, but did not have a material effecton our financial position, results of operations or cash flows.  Under the consensus reached in EITF 04-13,buy/sell transactions are reported as non-monetary exchanges and consequentlynot presented on a gross basis in our statements of income.  Implementation of EITF 04-13 reduced revenuesand purchases of petroleum products on our consolidated statements of income byapproximately $774.4 million each for the period from April 1, 2006 throughSeptember 30, 2006 ($460.7 million for the three months ended September 30,2006).  Under the provisions of the consensus,retroactive restatement of buy/sell transactions reported in prior periods wasnot permitted.  The revenues andpurchases of petroleum products associated with buy/sell transactions that arereported on a gross basis in our consolidated statements of income for thethree months and nine months ended September 30, 2005, and for the period fromJanuary 1, 2006 through March 31, 2006, are approximately $494.7 million,$898.0 million and $275.4 million, respectively.

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The table below includesfinancial information by reporting segment for the three months and nine monthsended September 30, 2006 and 2005 (in thousands):
| ** **                                                                         | ** ** | **Three Months Ended September 30, 2006** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Downstream  Segment**                                            | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|                                                                               |       |                                                               |       |   |   |   |   |   |   |   |   |   |   |
| Sales of petroleum  products                                                       |       | $                                                                  | —     |   | $ | 2,441,750 |   | $ | 4,990 |   | $ | 2,446,740 |   | $ | (69 | ) | $ | 2,446,671 |   |
| Operating revenues                                                                 |       | 72,358                                                             |       | 12,176 |   | 38,905 |   | 123,439 |   | (65 | ) | 123,374 |   |
| Purchases of petroleum  products                                                   |       | —                                                             |       | 2,413,391 |   | 4,323 |   | 2,417,714 |   | (78 | ) | 2,417,636 |   |
| Operating expenses,  including power and taxes – other than income taxes      |       | 38,618                                                             |       | 15,930 |   | 12,857 |   | 67,405 |   | (65 | ) | 67,340 |   |
| General and  administrative expenses                                               |       | 3,455                                                              |       | 1,460 |   | 2,079 |   | 6,994 |   | — |   | 6,994 |   |
| Depreciation and  amortization expense                                             |       | 10,713                                                             |       | 3,699 |   | 11,838 |   | 26,250 |   | — |   | 26,250 |   |
| Gains on sales of  assets                                                          |       | (14                                                                | )          | — |   | — |   | (14 | ) | — |   | (14 | ) |
| Operating income                                                                   |       | 19,586                                                             |       | 19,446 |   | 12,798 |   | 51,830 |   | 9 |   | 51,839 |   |
| Equity earnings  (losses)                                                          |       | (2,949                                                             | )          | 2,962 |   | 11,563 |   | 11,576 |   | (9 | ) | 11,567 |   |
| Other income, net                                                                  |       | 289                                                                |       | 344 |   | 430 |   | 1,063 |   | — |   | 1,063 |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                                  | 16,926     |   | $ | 22,752 |   | $ | 24,791 |   | $ | 64,469 |   | $ | — |   | $ | 64,469 |   |

 
| ** **                                                                         | ** ** | **Three Months Ended September 30, 2005** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Downstream  Segment**                                            | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|                                                                               |       |                                                               |       |   |   |   |   |   |   |   |   |   |   |
| Sales of petroleum  products                                                       |       | $                                                                  | —     |   | $ | 2,367,984 |   | $ | — |   | $ | 2,367,984 |   | $ | (154 | ) | $ | 2,367,830 |   |
| Operating revenues                                                                 |       | 66,094                                                             |       | 12,750 |   | 53,641 |   | 132,485 |   | (188 | ) | 132,297 |   |
| Purchases of petroleum  products                                                   |       | —                                                             |       | 2,350,107 |   | — |   | 2,350,107 |   | (188 | ) | 2,349,919 |   |
| Operating expenses,  including power and taxes – other than income taxes      |       | 36,788                                                             |       | 17,200 |   | 13,703 |   | 67,691 |   | (154 | ) | 67,537 |   |
| General and  administrative expenses                                               |       | 4,617                                                              |       | 1,756 |   | 2,144 |   | 8,517 |   | — |   | 8,517 |   |
| Depreciation and  amortization expense                                             |       | 10,098                                                             |       | 6,471 |   | 14,238 |   | 30,807 |   | — |   | 30,807 |   |
| Gains on sales of  assets                                                          |       | (24                                                                | )          | (7 | ) | — |   | (31 | ) | — |   | (31 | ) |
| Operating income                                                                   |       | 14,615                                                             |       | 5,207 |   | 23,556 |   | 43,378 |   | — |   | 43,378 |   |
| Equity earnings  (losses)                                                          |       | (651                                                               | )          | 5,398 |   | — |   | 4,747 |   | — |   | 4,747 |   |
| Other income, net                                                                  |       | 306                                                                |       | 103 |   | 75 |   | 484 |   | — |   | 484 |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                                  | 14,270     |   | $ | 10,708 |   | $ | 23,631 |   | $ | 48,609 |   | $ | — |   | $ | 48,609 |   |

 

33

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| ** **                                                                         | ** ** | **Nine Months Ended September 30, 2006** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Downstream  Segment**                                           | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|                                                                               |       |                                                              |       |   |   |   |   |   |   |   |   |   |   |
| Sales of petroleum  products                                                       |       | $                                                                 | —     |   | $ | 7,116,064 |   | $ | 18,766 |   | $ | 7,134,830 |   | $ | (4,547 | ) | $ | 7,130,283 |   |
| Operating revenues                                                                 |       | 215,758                                                           |       | 36,456 |   | 151,851 |   | 404,065 |   | (2,882 | ) | 401,183 |   |
| Purchases of petroleum  products                                                   |       | —                                                            |       | 7,032,930 |   | 17,272 |   | 7,050,202 |   | (6,770 | ) | 7,043,432 |   |
| Operating expenses,  including power and taxes – other than income taxes      |       | 111,763                                                           |       | 50,892 |   | 45,774 |   | 208,429 |   | (668 | ) | 207,761 |   |
| General and administrative  expenses                                               |       | 13,250                                                            |       | 5,137 |   | 6,966 |   | 25,353 |   | — |   | 25,353 |   |
| Depreciation and  amortization expense                                             |       | 31,143                                                            |       | 10,464 |   | 42,076 |   | 83,683 |   | — |   | 83,683 |   |
| Gains on sales of  assets                                                          |       | (39                                                               | )          | — |   | (1,371 | ) | (1,410 | ) | — |   | (1,410 | ) |
| Operating income                                                                   |       | 59,641                                                            |       | 53,097 |   | 59,900 |   | 172,638 |   | 9 |   | 172,647 |   |
| Equity earnings  (losses)                                                          |       | (6,581                                                            | )          | 10,257 |   | 11,563 |   | 15,239 |   | (9 | ) | 15,230 |   |
| Other income, net                                                                  |       | 1,253                                                             |       | 613 |   | 550 |   | 2,416 |   | — |   | 2,416 |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                                 | 54,313     |   | $ | 63,967 |   | $ | 72,013 |   | $ | 190,293 |   | $ | — |   | $ | 190,293 |   |

 
| ** **                                                                         | ** ** | **Nine Months Ended September 30, 2005** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Downstream  Segment**                                           | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|                                                                               |       |                                                              |       |   |   |   |   |   |   |   |   |   |   |
| Sales of petroleum  products                                                       |       | $                                                                 | —     |   | $ | 5,714,353 |   | $ | — |   | $ | 5,714,353 |   | $ | (154 | ) | $ | 5,714,199 |   |
| Operating revenues                                                                 |       | 207,699                                                           |       | 36,161 |   | 155,481 |   | 399,341 |   | (2,237 | ) | 397,104 |   |
| Purchases of petroleum  products                                                   |       | —                                                            |       | 5,665,136 |   | — |   | 5,665,136 |   | (2,237 | ) | 5,662,899 |   |
| Operating expenses,  including power and taxes – other than income taxes      |       | 104,943                                                           |       | 45,132 |   | 36,275 |   | 186,350 |   | (154 | ) | 186,196 |   |
| General and  administrative expenses                                               |       | 12,328                                                            |       | 4,483 |   | 5,011 |   | 21,822 |   | — |   | 21,822 |   |
| Depreciation and  amortization expense                                             |       | 29,460                                                            |       | 13,623 |   | 39,473 |   | 82,556 |   | — |   | 82,556 |   |
| Gains on sales of  assets                                                          |       | (131                                                              | )          | (59 | ) | (407 | ) | (597 | ) | — |   | (597 | ) |
| Operating income                                                                   |       | 61,099                                                            |       | 22,199 |   | 75,129 |   | 158,427 |   | — |   | 158,427 |   |
| Equity earnings  (losses)                                                          |       | (2,718                                                            | )          | 19,310 |   | — |   | 16,592 |   | — |   | 16,592 |   |
| Other income, net                                                                  |       | 576                                                               |       | 132 |   | 177 |   | 885 |   | — |   | 885 |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                                 | 58,957     |   | $ | 41,641 |   | $ | 75,306 |   | $ | 175,904 |   | $ | — |   | $ | 175,904 |   |

 

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The following tableincludes total assets, capital expenditures, and significant non-cash investingactivities for each segment as of and for the periods ended September 30, 2006,and December 31, 2005 (in thousands):
| ** **                     | ** ** | **Downstream  Segment** | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|--------------------------------|------------|-------------------------|------------|-----------------------|------------|------------------------|------------|---------------------|------------|---------------------------------|------------|------------------|------------|
|                           |       |                    |       |                  |       |                   |       |                |       |                            |       |             |       |
| September 30, 2006:            |       |                    |       |                  |       |                   |       |                |       |                            |       |             |       |
| Total assets                   |       | $                       | 1,081,693  |                  | $          | 1,385,414              |       | $                   | 1,305,690  |                            | $          | 3,772,797        |       | $ | (4,812 | ) | $ | 3,767,985 |   |
| Capital  expenditures          |       | 47,053                  |       | 35,028                |       | 41,624                 |       | 123,705             |       | 1,979                           |       | 125,684          |       |
| Non-cash  investing activities |       | —                  |       | —                |       | 591,552                |       | 591,552             |       | —                          |       | 591,552          |       |
|                           |       |                    |       |                  |       |                   |       |                |       |                            |       |             |       |
| December 31, 2005:             |       |                    |       |                  |       |                   |       |                |       |                            |       |             |       |
| Total assets                   |       | $                       | 1,056,217  |                  | $          | 1,353,492              |       | $                   | 1,280,548  |                            | $          | 3,690,257        |       | $ | (9,719 | ) | $ | 3,680,538 |   |
| Capital  expenditures          |       | 58,609                  |       | 40,954                |       | 119,837                |       | 219,400             |       | 1,153                           |       | 220,553          |       |
| Non-cash investing  activities |       | 1,429                   |       | —                |       | —                 |       | 1,429               |       | —                          |       | 1,429            |       |

 

The following tablereconciles the segment data from the tables above to consolidated net incomefor the three months and nine months ended September 30, 2006 and 2005 (inthousands):
|                                                                                    | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                                                               |       |                                                 |       |                                                |       |   |   |   |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                    | 64,469     |                                                | $          | 48,609 |   | $ | 190,293 |   | $ | 175,904 |   |
| Interest expense  – net                                                       |       | (23,181                                              | )          | (19,726                                             | )          | (63,522 | ) | (60,640 | ) |
| Income before deferred income tax expense                                          |       | 41,288                                               |       | 28,883                                              |       | 126,771 |   | 115,264 |   |
| Deferred income  tax expense                                                       |       | 143                                                  |       | —                                              |       | 657 |   | — |   |
| Income from continuing operations                                                  |       | 41,145                                               |       | 28,883                                              |       | 126,114 |   | 115,264 |   |
| Discontinued  operations                                                           |       | —                                               |       | 692                                                 |       | 19,369 |   | 2,662 |   |
| Net income                                                                         |       | $                                                    | 41,145     |                                                | $          | 29,575 |   | $ | 145,483 |   | $ | 117,926 |   |

 

**NOTE 14.  COMMITMENTS AND CONTINGENCIES**

**Litigation**

In the fall of 1999, the General Partner and TEProducts were named as defendants in a lawsuit in Jackson County CircuitCourt, Jackson County, Indiana, styled *RyanE. McCleery and Marcia S. McCleery, et al. and Michael and Linda Robson, et al.v. Texas Eastern Corporation, et al. * **In the lawsuit, the plaintiffscontend, among other things, that we and other defendants stored and disposedof toxic and hazardous substances and hazardous wastes in a manner that caused thematerials to be released into the air, soil and water.  They furthercontend that the release caused damages to the plaintiffs.  In theircomplaint, the plaintiffs allege strict liability for both personal injury andproperty damage together with gross negligence, continuing nuisance, trespass,criminal mischief and loss of consortium. The plaintiffs are seekingcompensatory, punitive and treble damages.  On March 18, 2005, we enteredinto Release and Settlement Agreements with the McCleery plaintiffs dismissingall of these plaintiffs’ claims on terms that did not have a material adverseeffect on our financial position, results of operations or cash flows. Although we did not settle with all plaintiffs and we therefore remain namedparties in the *Michael and Linda Robson, etal. v. Texas Eastern Corporation, et al*. action, a co-defendant hasagreed, by Cooperative Defense 

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Agreement, to fund the defense and satisfy allfinal judgments which might be rendered with the remaining claims assertedagainst us.  Consequently, we do not believe that the outcome of theseremaining claims will have a material adverse effect on our financial position,results of operations or cash flows.

On December 21, 2001, TE Products was named as adefendant in a lawsuit in the 10th Judicial District, Natchitoches Parish,Louisiana, styled *Rebecca L. Grisham et al. v.  TE Products Pipeline Company, LimitedPartnership*.  In this case,the plaintiffs contend that our pipeline, which crosses the plaintiffs’property, leaked toxic products onto their property and, consequently causeddamages to them.  We have filed an answerto the plaintiffs’ petition denying the allegations, and we are defendingourselves vigorously against the lawsuit. The plaintiffs assert damages attributable to the remediation of theproperty of approximately $1.4 million; however, this case is covered byinsurance, subject to applicable policy limits. We do not believe that the outcome of this lawsuit will have a materialadverse effect on our financial position, results of operations or cash flows.

In 1991, we were named as a defendant in a matterstyled *Jimmy R. Green, et al. v. Cities Service Refinery,et al.*as filed in the 26th Judicial District Court of Bossier Parish,Louisiana.  The plaintiffs in this matterreside or formerly resided on land that was once the site of a refinery ownedby one of our co-defendants.  The formerrefinery is located near our Bossier City facility.  Plaintiffs have claimed personal injuries andproperty damage arising from alleged contamination of the refineryproperty.  The plaintiffs have recentlypursued certification as a class and have significantly increased their demandto approximately $175.0 million.  Thisrevised demand includes amounts for environmental restoration not previouslyclaimed by the plaintiffs.  We have neverowned any interest in the refinery property made the basis of this action, andwe do not believe that we contributed to any alleged contamination of this property.  While we cannot predict the ultimate outcome,we do not believe that the outcome of this lawsuit will have a material adverseeffect on our financial position, results of operations or cash flows.

On September 18, 2006, Peter Brinckerhoff, apurported unitholder of TEPPCO, filed a complaint in the Court of Chancery ofNew Castle County in the State of Delaware, in his individual capacity, as aputative class action on behalf of our other unitholders, and derivatively onour behalf, concerning proposals made to our unitholders in our definitiveproxy statement filed with the SEC on September 11, 2006  (“Proxy Statement”) and other transactionsinvolving us and Enterprise or its affiliates. The complaint names as defendants the General Partner; the Board ofDirectors of the General Partner; the parent companies of the General Partner,including EPCO; Enterprise and certain of its affiliates; and Dan L.Duncan.  We are named as a nominaldefendant.

The complaint alleges, among other things, that certain of thetransactions proposed in the Proxy Statement, including a proposal to reducethe General Partner’s maximum percentage interest in our distributions inexchange for Units (the “Issuance Proposal”), are unfair to our unitholders andconstitute a breach by the defendants of fiduciary duties owed to ourunitholders and that the Proxy Statement fails to provide our unitholders withall material facts necessary for them to make an informed decision whether tovote in favor of or against the proposals. The complaint further alleges that, since Mr. Duncan acquired control ofthe General Partner in 2005, the defendants, in breach of their fiduciaryduties to us and our unitholders, have caused us to enter into certaintransactions with Enterprise or its affiliates that are unfair to us or otherwiseunfairly favored Enterprise or its affiliates over us.  These transactions are alleged to include theJonah joint venture entered into by us and an Enterprise affiliate in August2006, the sale by us to an Enterprise affiliate of the Pioneer plant in March2006 and the impending divestiture of our interest in MB Storage in connectionwith an investigation by the Federal Trade Commission (“FTC”).  As more fully described in the ProxyStatement, the Audit and Conflicts Committee of the Board of Directors of theGeneral Partner recommended the Issuance Proposal for approval by the Board ofDirectors of the General Partner.  Thecomplaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H.Hutchison, constituting the three members of the Audit and Conflicts Committee,cannot be considered independent because of their alleged ownership ofsecurities in Enterprise and its affiliates and their relationships with Mr.Duncan.

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The complaint seeks relief (i) requiring us to issue a proxy statementthat corrects the alleged misstatements and omissions in the Proxy Statement;(ii) enjoining the October 26, 2006 meeting of unitholders provided for in theProxy Statement; (iii) rescinding transactions in the complaint that have beenconsummated or awarding rescissory damages in respect thereof; (iv) awardingdamages for profits and special benefits allegedly obtained by defendants as aresult of the alleged wrongdoings in the complaint; and (v) awarding plaintiffcosts of the action, including fees and expenses of his attorneys and experts.

On September 22, 2006, the plaintiff in the actionfiled a motion to expedite the proceedings, requesting the Court to schedule ahearing on plaintiff’s motion for a preliminary injunction to enjoin thedefendants from proceeding with the October 26, 2006 special meeting ofunitholders.  On September 26, 2006, thedefendants advised the Court that we would provide to our unitholders specifiedsupplemental disclosures, which were included in the Form 8-K and supplementalproxy materials we filed with the SEC on October 5, 2006.  In light of the foregoing, we believe thatthe plaintiff’s motion requesting the Court to schedule a hearing to considerhis motion to enjoin the special meeting is moot.  The special meeting was convened on October26, 2006, and adjourned, without voting on the proposals, to November 30, 2006by the General Partner for lack of a quorum. While we cannot predict the ultimate outcome, we do not believe that theoutcome of this lawsuit will have a material adverse effect on our financialposition, results of operations or cash flows.

In addition to the litigation discussed above, we havebeen, in the ordinary course of business, a defendant in various lawsuits and aparty to various other legal proceedings, some of which are covered in whole orin part by insurance. We believe that the outcome of these lawsuits and otherproceedings will not individually or in the aggregate have a future materialadverse effect on our consolidated financial position, results of operations orcash flows.

**Regulatory Matters**

Our pipelines and otherfacilities are subject to multiple environmental obligations and potentialliabilities under a variety of federal, state and local laws and regulations.These include, without limitation: the Comprehensive Environmental Response,Compensation, and Liability Act; the Resource Conservation and Recovery Act;the Clean Air Act; the Federal Water Pollution Control Act or the Clean WaterAct; the Oil Pollution Act; and analogous state and local laws and regulations.Such laws and regulations affect many aspects of our present and futureoperations, and generally require us to obtain and comply with a wide varietyof environmental registrations, licenses, permits, inspections and other approvals,with respect to air emissions, water quality, wastewater discharges, and solidand hazardous waste management. Failure to comply with these requirements mayexpose us to fines, penalties and/or interruptions in our operations that couldinfluence our results of operations. If an accidental leak, spill or release ofhazardous substances occurs at any facilities that we own, operate or otherwiseuse, or where we send materials for treatment or disposal, we could be heldjointly and severally liable for all resulting liabilities, includinginvestigation, remedial and clean-up costs. Likewise, we could be required toremove or remediate previously disposed wastes or property contamination,including groundwater contamination.  Anyor all of this could materially affect our results of operations and cashflows.

We believe that ouroperations and facilities are in substantial compliance with applicableenvironmental laws and regulations, and that the cost of compliance with suchlaws and regulations will not have a material adverse effect on our results ofoperations or financial position. We cannot ensure, however, that existingenvironmental regulations will not be revised or that new regulations will notbe adopted or become applicable to us. The clear trend in environmentalregulation is to place more restrictions and limitations on activities that maybe perceived to affect the environment, and thus there can be no assurance asto the amount or timing of future expenditures for environmental regulation complianceor remediation, and actual future expenditures may be different from theamounts we currently anticipate. Revised or additional regulations that resultin increased compliance costs or 

37

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additional operating restrictions, particularly ifthose costs are not fully recoverable from our customers, could have a materialadverse effect on our business, financial position, results of operations andcash flows.  At September 30, 2006, andDecember 31, 2005, we have an accrued liability of $1.9 million and $2.4million, respectively, related to sites requiring environmental remediationactivities.

In 1994, the Louisiana Department of EnvironmentalQuality (“LDEQ”) issued a compliance order for environmental contamination atour Arcadia, Louisiana, facility.  In1999, our Arcadia facility and adjacent terminals were directed by theRemediation Services Division of the LDEQ to pursue remediation of thiscontamination.  Effective March 2004, weexecuted an access agreement with an adjacent industrial landowner who islocated upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediationactivities at our Arcadia facility for which it has accepted sharedresponsibility.  At September 30, 2006,we have an accrued liability of $0.1 million for remediation costs at ourArcadia facility.  We do not expect thatthe completion of the remediation program proposed to the LDEQ will have afuture material adverse effect on our financial position, results of operationsor cash flows.

On July 27, 2004, wereceived notice from the United States Department of Justice (“DOJ”) of itsintent to seek a civil penalty against us related to our November 21, 2001,release of approximately 2,575 barrels of jet fuel from our 14-inch diameterpipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, isseeking a civil penalty against us for alleged violations of the Clean WaterAct (“CWA”) arising out of this release, as well as three smaller spills at otherlocations in 2004 and 2005.  We haveagreed with the DOJ on a proposed penalty of $2.865 million, along with ourcommitment to implement additional spill prevention measures, and expect tofinalize the settlement in the fourth quarter of 2006.  We do not expect this settlement to have amaterial adverse effect on our financial position, results of operations orcash flows.

One of the spills encompassed in our currentsettlement discussion with the DOJ involved a 37,450-gallon release from Seawayon May 13, 2005 at Colbert, Oklahoma. This release was remediated under the supervision of the OklahomaCorporation Commission, but resulted in claims by neighboring landowners thathave been settled for approximately $0.7 million.  In addition, the release resulted in aCorrective Action Order by the U.S. Department of Transportation.  Among other requirements of this Order, wewere required to reduce the operating pressure of Seaway by 20% untilcompletion of required corrective actions. The corrective actions were completed and on June 1, 2006, we increasedthe operating pressure of Seaway back to 100%. We have a 50% ownership interest in Seaway, and any settlement should becovered by our insurance.  We do notexpect the completion of our obligations relating to the Colbert release tohave a material adverse effect on our financial position, results of operationsor cash flows.

On September 18, 2005, a propane release and fireoccurred at our Todhunter facility, near Middletown, Ohio.  The incident resulted in the death of one ofour employees; there were no other injuries. Repairs to the impacted facilities have been completed.  On March 17, 2006, we received a citationfrom the Occupational Safety and Health Administration (“OSHA”) arising out ofthis incident, with a penalty of $0.1 million. The settlement of this citation did not have a material adverse effecton our financial position, results of operations or cash flows.

We are also in negotiations with the U.S. Departmentof Transportation with respect to a notice of probable violation that wereceived on April 25, 2005, for alleged violations of pipeline safetyregulations at our Todhunter facility, with a proposed $0.4 million civilpenalty.  We responded on June 30, 2005,by admitting certain of the alleged violations, contesting others andrequesting a reduction in the proposed civil penalty.  We do not expect any settlement, fine orpenalty to have a material adverse effect on our financial position, results ofoperations or cash flows.

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The FERC, pursuant to the Interstate Commerce Act of1887, as amended, regulates the tariff rates for our interstate common carrierpipeline operations.  To be lawful underthat Act, interstate tariff rates, terms and conditions of service must be justand reasonable and not unduly discriminatory, and must be on file withFERC.  In addition, pipelines may notconfer any undue preference upon any shipper. Shippers may protest, and the FERC may investigate, the lawfulness ofnew or changed tariff rates.  The FERCcan suspend those tariff rates for up to seven months and can also requirerefunds of amounts collected pursuant to rates that are ultimately found to beunlawful.  The FERC and interestedparties can also challenge tariff rates that have become final and effective.  Because of the complexity of rate making, thelawfulness of any rate is never assured. The FERC uses prescribed rate methodologies for approving regulatedtariff rates for transporting crude oil and refined products.  These methodologies may limit our ability toset rates based on our actual costs or may delay the use of rates reflectingincreased costs.  Changes in the FERC’sapproved methodology for approving rates could adversely affect us.  Adverse decisions by the FERC in approvingour regulated rates could adversely affect our cash flow.  Challenges to our tariff rates could be filedwith the FERC.

The intrastate liquids pipeline transportation servicewe provide is subject to various state laws and regulations that affect therates we charge and terms and conditions of that service.  Although state regulation typically is lessonerous than FERC regulation, proposed and existing rates subject to stateregulation and the provision of non-discriminatory service are subject tochallenge by complaint.

**Other**

Centennial entered into credit facilities totaling$150.0 million, and as of September 30, 2006, $150.0 million was outstandingunder those credit facilities, of which $140.0 million expires in 2024, and$10.0 million expires in April 2007.  TEProducts and Marathon have each guaranteed one-half of the repayment ofCentennial’s outstanding debt balance (plus interest) under these creditfacilities.  The guarantees arose inorder for Centennial to obtain adequate financing, and the proceeds of the creditfacilities were used to fund construction and conversion costs of its pipelinesystem.  Prior to the expiration of thelong-term credit facility, TE Products could be relinquished fromresponsibility under the guarantee should Centennial meet certain financialtests.  If Centennial defaults on itsoutstanding balance, the estimated maximum potential amount of future paymentsfor TE Products and Marathon is $75.0 million each at September 30, 2006.

TE Products, Marathon and Centennial have entered intoa limited cash call agreement, which allows each member to contribute cash inlieu of Centennial procuring separate insurance in the event of a third-partyliability arising from a catastrophic event. There is an indefinite term for the agreement and each member is tocontribute cash in proportion to its ownership interest, up to a maximum of$50.0 million each.  As a result of thecatastrophic event guarantee, TE Products has recorded a $4.4 millionobligation, which represents the present value of the estimated amount that wewould have to pay under the guarantee. If a catastrophic event were to occur and we were required to contributecash to Centennial, contributions exceeding our deductible might be covered by ourinsurance, depending upon the nature of the catastrophic event.

One of our subsidiaries, TEPPCO Crude Oil, L.P. (“TCO”),has entered into master equipment lease agreements with finance companies forthe use of various equipment.  We haveguaranteed the full and timely payment and performance of TCO’s obligationsunder the agreements.  Generally, eventsof default would trigger our performance under the guarantee.  The maximum potential amount of futurepayments under the guarantee is not estimable, but would include base rentalpayments for both current and future equipment, stipulated loss payments in theevent any equipment is stolen, damaged, or destroyed and any future indemnitypayments.  We carry insurance coveragethat may offset any payments required under the guarantees.

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On February 24, 2005, the General Partner was acquiredfrom DEFS by DFI.  The General Partnerowns a 2% general partner interest in us and is the general partner of thePartnership.  On March 11, 2005, theBureau of Competition of the FTC delivered written notice to DFI’s legaladvisor that it was conducting a non-public investigation to determine whetherDFI’s acquisition of our General Partner may substantially lessen competitionor violate other provisions of federal antitrust laws.  We and our General Partner cooperated fullywith this investigation.

On October 31, 2006, anFTC order and consent agreement ending its investigation became final.  The order requires the divestiture of our 50%interest in MB Storage and certain related assets to one or more FTC-approvedbuyers no later than December 31, 2006 in a manner approved by the FTC andsubject to its final approval.  If we areunable to divest the interest and related assets by that date, the FTC mayappoint a divestiture trustee to oversee their sale to one or more approvedbuyers.  The order contains no minimumprice for the divestiture and requires that we provide the acquirer oracquirers the opportunity to hire employees who spend more than 10% of theirtime working on the divested assets.  Theorder also imposes specified operational, reporting and consent requirements onus including, among other things, in the event that we build a new pipelineconnecting to our mainline at Mont Belvieu, implement new allocation proceduresrelating to the movement of NGLs between storage facilities, our mainline andcustomers, or acquire interests in or operate salt dome storage facilities forNGLs in specified areas.

**NOTE 15. COMPREHENSIVE INCOME**

SFAS No. 130, *Reporting ComprehensiveIncome* requires certain items such as foreign currency translationadjustments, minimum pension liability adjustments and unrealized gains andlosses on certain investments to be reported in a financial statement.  As of and for the nine months ended September30, 2006, the components of accumulated other comprehensive income reflected onour consolidated balance sheets were composed of crude oil hedges and interestrate swaps.  The crude oil hedges maturein December 2006 and December 2007. While the crude oil hedges are in effect, changes in their fair values,to the extent the hedges are effective, are recognized in accumulated othercomprehensive income until they are recognized in net income in futureperiods.  The interest rate swaps maturein January 2008, are related to our variable rate revolving credit facility andare designated as cash flow hedges beginning in the third quarter of 2006.

The accumulated balanceof other comprehensive loss related to our cash flow hedge is as follows (inthousands):
| Balance at December 31, 2005                              |   | $    | 11     |   |
|-----------------------------------------------------------|--------|------|--------|--------|
| Changes in fair values of interest rate cash flow  hedges |   | (584 | )      |
| Changes in fair values of crude oil cash flow hedges      |   | 234  |   |
| Balance at September  30, 2006                            |   | $    | (339   | )      |

 

**NOTE16.  SUPPLEMENTAL CONDENSED CONSOLIDATINGFINANCIAL INFORMATION**

TEProducts Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO MidstreamCompanies, L.P., and Val Verde Gas Gathering Company, L.P., have issued full,unconditional, and joint and several guarantees of our Senior Notes andour Revolving Credit Facility (collectively “the Guaranteed Debt”).  In addition, during the 2005 periodspresented below and extending through July 31, 2006, Jonah Gas GatheringCompany also had provided the same guarantees of our GuaranteedDebt.  Effective August 1, 2006, Enterprise, through itsaffiliate, Enterprise Gas Processing, LLC, became our joint venture partner byacquiring an interest in Jonah Gas Gathering

40

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Company (see Note8).  Jonah Gas Gathering Company was released as a guarantor ofthe Guaranteed Debt, effective upon the formation of the jointventure.

The following supplemental condensed consolidatingfinancial information reflects our separate accounts, the combined accounts ofthe Guarantor Subsidiaries, the combined accounts of our other non-guarantorsubsidiaries, the combined consolidating adjustments and eliminations and ourconsolidated accounts for the dates and periods indicated.  For purposes of the following consolidatinginformation, our investments in our subsidiaries and the Guarantor Subsidiaries’investments in their subsidiaries are accounted for under the equity method ofaccounting.
|                                               | ** ** | **September 30, 2006** | ** ** |
|-----------------------------------------------|------------|----------------------------------|------------|
| ** **                                    | ** ** | **TEPPCO  Partners, L.P.**  | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                    | ** ** | **(in thousands)**          | ** ** |
| Assets                                        |       |                             |       |   |   |   |   |   |   |   |   |
| Current assets                                |       | $                                | 32,286     |   | $ | 56,235 |   | $ | 807,624 |   | $ | (27,736 | ) | $ | 868,409 |   |
| Property, plant and equipment – net      |       | —                           |       | 945,225 |   | 662,607 |   | — |   | 1,607,832 |   |
| Equity investments                            |       | 1,335,767                        |       | 1,149,433 |   | 198,613 |   | (1,667,682 | ) | 1,016,131 |   |
| Intercompany notes receivable                 |       | 1,084,907                        |       | — |   | — |   | (1,084,907 | ) | — |   |
| Intangible assets                             |       | —                           |       | 159,227 |   | 30,361 |   | — |   | 189,588 |   |
| Other assets                                  |       | 5,915                            |       | 21,207 |   | 58,903 |   | — |   | 86,025 |   |
| Total assets                                  |       | $                                | 2,458,875  |   | $ | 2,331,327 |   | $ | 1,758,108 |   | $ | (2,780,325 | ) | $ | 3,767,985 |   |
| Liabilities and  partners’ capital       |       |                             |       |   |   |   |   |   |   |   |   |
| Current liabilities                           |       | $                                | 36,335     |   | $ | 87,120 |   | $ | 844,988 |   | $ | (30,306 | ) | $ | 938,137 |   |
| Long-term debt                                |       | 1,086,017                        |       | 386,058 |   | — |   | — |   | 1,472,075 |   |
| Intercompany notes payable                    |       | —                           |       | 648,663 |   | 436,246 |   | (1,084,909 | ) | — |   |
| Deferred tax liability                        |       | —                           |       | 638 |   | 19 |   | — |   | 657 |   |
| Other long term liabilities                   |       | 1,369                            |       | 18,171 |   | 2,177 |   | — |   | 21,717 |   |
| Total partners’ capital                  |       | 1,335,154                        |       | 1,190,677 |   | 474,678 |   | (1,665,110 | ) | 1,335,399 |   |
| Total  liabilities and partners’ capital |       | $                                | 2,458,875  |   | $ | 2,331,327 |   | $ | 1,758,108 |   | $ | (2,780,325 | ) | $ | 3,767,985 |   |

 

41

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| ** **                                    | ** ** | **December 31, 2005** | ** ** |
|-----------------------------------------------|------------|---------------------------------|------------|
| ** **                                    | ** ** | **TEPPCO  Partners, L.P.** | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                    | ** ** | **(in thousands)**         | ** ** |
| Assets                                        |       |                            |       |   |   |   |   |   |   |   |   |
| Current assets                                |       | $                               | 40,977     |   | $ | 107,692 |   | $ | 789,486 |   | $ | (39,026 | ) | $ | 899,129 |   |
| Property, plant  and equipment – net     |       | —                          |       | 1,335,724 |   | 624,344 |   | — |   | 1,960,068 |   |
| Equity  investments                           |       | 1,201,388                       |       | 461,741 |   | 202,343 |   | (1,505,816 | ) | 359,656 |   |
| Intercompany  notes receivable                |       | 1,134,093                       |       | — |   | — |   | (1,134,093 | ) | — |   |
| Intangible  assets                            |       | —                          |       | 345,005 |   | 31,903 |   | — |   | 376,908 |   |
| Other assets                                  |       | 5,532                           |       | 22,170 |   | 57,075 |   | — |   | 84,777 |   |
| Total assets                                  |       | $                               | 2,381,990  |   | $ | 2,272,332 |   | $ | 1,705,151 |   | $ | (2,678,935 | ) | $ | 3,680,538 |   |
| Liabilities and  partners’ capital       |       |                            |       |   |   |   |   |   |   |   |   |
| Current  liabilities                          |       | $                               | 43,236     |   | $ | 140,743 |   | $ | 793,683 |   | $ | (40,451 | ) | $ | 937,211 |   |
| Long-term debt                                |       | 1,135,973                       |       | 389,048 |   | — |   | — |   | 1,525,021 |   |
| Intercompany  notes payable                   |       | —                          |       | 635,263 |   | 498,832 |   | (1,134,095 | ) | — |   |
| Other long term  liabilities                  |       | 1,422                           |       | 14,564 |   | 950 |   | — |   | 16,936 |   |
| Total partners’  capital                 |       | 1,201,359                       |       | 1,092,714 |   | 411,686 |   | (1,504,389 | ) | 1,201,370 |   |
| Total liabilities and  partners’ capital |       | $                               | 2,381,990  |   | $ | 2,272,332 |   | $ | 1,705,151 |   | $ | (2,678,935 | ) | $ | 3,680,538 |   |

 
| ** **                                 | ** ** | **Three Months Ended September 30, 2006** | ** ** |
|--------------------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                                 | ** ** | **TEPPCO  Partners, L.P.**                                    | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                 | ** ** | **(in thousands)**                                            | ** ** |
| Operating revenues                         |       | $                                                                  | —     |   | $ | 85,938 |   | $ | 2,484,528 |   | $ | (421 | ) | $ | 2,570,045 |   |
| Costs and expenses                         |       | —                                                             |       | 69,040 |   | 2,449,601 |   | (421 | ) | 2,518,220 |   |
| Gains on sales of  assets                  |       | —                                                             |       | (14 | ) | — |   | — |   | (14 | ) |
| Operating income                           |       | —                                                             |       | 16,912 |   | 34,927 |   | — |   | 51,839 |   |
| Interest expense – net                |       | —                                                             |       | (14,586 | ) | (8,595 | ) | — |   | (23,181 | ) |
| Equity earnings                            |       | 41,145                                                             |       | 38,603 |   | 2,962 |   | (71,143 | ) | 11,567 |   |
| Other income – net                    |       | —                                                             |       | 356 |   | 707 |   | — |   | 1,063 |   |
| Income before  deferred income tax expense |       | 41,145                                                             |       | 41,285 |   | 30,001 |   | (71,143 | ) | 41,288 |   |
| Deferred income tax  expense               |       | —                                                             |       | 140 |   | 3 |   | — |   | 143 |   |
| Income from  continuing operations         |       | 41,145                                                             |       | 41,145 |   | 29,998 |   | (71,143 | ) | 41,145 |   |
| Discontinued operations                    |       | —                                                             |       | — |   | — |   | — |   | — |   |
| Net income                                 |       | $                                                                  | 41,145     |   | $ | 41,145 |   | $ | 29,998 |   | $ | (71,143 | ) | $ | 41,145 |   |

 

42

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| ** **                        | ** ** | **Three Months Ended September 30, 2005** | ** ** |
|-----------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                        | ** ** | **TEPPCO  Partners, L.P.**                                    | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                        | ** ** | **(in thousands)**                                            | ** ** |
| Operating  revenues               |       | $                                                                  | —     |   | $ | 104,059 |   | $ | 2,396,410 |   | $ | (342 | ) | $ | 2,500,127 |   |
| Costs and  expenses               |       | —                                                             |       | 74,782 |   | 2,382,340 |   | (342 | ) | 2,456,780 |   |
| Gains on sales  of assets         |       | —                                                             |       | (24 | ) | (7 | ) | — |   | (31 | ) |
| Operating income                  |       | —                                                             |       | 29,301 |   | 14,077 |   | — |   | 43,378 |   |
| Interest expense  – net      |       | —                                                             |       | (12,476 | ) | (7,250 | ) | — |   | (19,726 | ) |
| Equity earnings                   |       | 29,575                                                             |       | 11,723 |   | 5,398 |   | (41,949 | ) | 4,747 |   |
| Other income –  net          |       | —                                                             |       | 335 |   | 149 |   | — |   | 484 |   |
| Income from continuing operations |       | 29,575                                                             |       | 28,883 |   | 12,374 |   | (41,949 | ) | 28,883 |   |
| Discontinued  operations          |       | —                                                             |       | 692 |   | — |   | — |   | 692 |   |
| Net income                        |       | $                                                                  | 29,575     |   | $ | 29,575 |   | $ | 12,374 |   | $ | (41,949 | ) | $ | 29,575 |   |

 
| ** **                                | ** ** | **Nine Months Ended September 30, 2006** | ** ** |
|-------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                | ** ** | **TEPPCO  Partners, L.P.**                                   | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                | ** ** | **(in thousands)**                                           | ** ** |
| Operating  revenues                       |       | $                                                                 | —     |   | $ | 257,078 |   | $ | 7,282,867 |   | $ | (8,479 | ) | $ | 7,531,466 |   |
| Costs and  expenses                       |       | —                                                            |       | 207,291 |   | 7,161,417 |   | (8,479 | ) | 7,360,229 |   |
| Gains on sales  of assets                 |       | —                                                            |       | (1,410 | ) | — |   | — |   | (1,410 | ) |
| Operating income                          |       | —                                                            |       | 51,197 |   | 121,450 |   | — |   | 172,647 |   |
| Interest expense  – net              |       | —                                                            |       | (37,756 | ) | (25,766 | ) | — |   | (63,522 | ) |
| Equity earnings                           |       | 145,483                                                           |       | 130,883 |   | 10,257 |   | (271,393 | ) | 15,230 |   |
| Other income –  net                  |       | —                                                            |       | 1,299 |   | 1,117 |   | — |   | 2,416 |   |
| Income before deferred income tax expense |       | 145,483                                                           |       | 145,623 |   | 107,058 |   | (271,393 | ) | 126,771 |   |
| Deferred income  tax expense              |       | —                                                            |       | 140 |   | 517 |   | — |   | 657 |   |
| Income from continuing operations         |       | 145,483                                                           |       | 145,483 |   | 106,541 |   | (271,393 | ) | 126,114 |   |
| Discontinued  operations                  |       | —                                                            |       | — |   | 19,369 |   | — |   | 19,369 |   |
| Net income                                |       | $                                                                 | 145,483    |   | $ | 145,483 |   | $ | 125,910 |   | $ | (271,393 | ) | $ | 145,483 |   |

 

43

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| ** **                        | ** ** | **Nine Months Ended September 30, 2005** | ** ** |
|-----------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                        | ** ** | **TEPPCO  Partners, L.P.**                                   | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                        | ** ** | **(in thousands)**                                           | ** ** |
| Operating  revenues               |       | $                                                                 | —     |   | $ | 319,832 |   | $ | 5,793,862 |   | $ | (2,391 | ) | $ | 6,111,303 |   |
| Costs and  expenses               |       | —                                                            |       | 207,991 |   | 5,747,873 |   | (2,391 | ) | 5,953,473 |   |
| Gains on sales  of assets         |       | —                                                            |       | (538 | ) | (59 | ) | — |   | (597 | ) |
| Operating income                  |       | —                                                            |       | 112,379 |   | 46,048 |   | — |   | 158,427 |   |
| Interest expense  – net      |       | —                                                            |       | (39,751 | ) | (20,889 | ) | — |   | (60,640 | ) |
| Equity earnings                   |       | 117,926                                                           |       | 41,956 |   | 19,310 |   | (162,600 | ) | 16,592 |   |
| Other income –  net          |       | —                                                            |       | 680 |   | 205 |   | — |   | 885 |   |
| Income from continuing operations |       | 117,926                                                           |       | 115,264 |   | 44,674 |   | (162,600 | ) | 115,264 |   |
| Discontinued  operations          |       | —                                                            |       | 2,662 |   | — |   | — |   | 2,662 |   |
| Net income                        |       | $                                                                 | 117,926    |   | $ | 117,926 |   | $ | 44,674 |   | $ | (162,600 | ) | $ | 117,926 |   |

 
| ** **                                                                                    | ** ** | **Nine Months Ended September 30, 2006** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                                                    | ** ** | **TEPPCO  Partners, L.P.**                                   | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                                                                    | ** ** | **(in thousands)**                                           | ** ** |
| Cash flows from  operating activities                                                         |       |                                                              |       |   |   |   |   |   |   |   |   |
| Net income                                                                                    |       | $                                                                 | 145,483    |   | $ | 145,483 |   | $ | 125,910 |   | $ | (271,393 | ) | $ | 145,483 |   |
| Adjustments to reconcile net income to net cash  provided by continuing operating activities: |       |                                                              |       |   |   |   |   |   |   |   |   |
| Income from discontinued operations                                                           |       | —                                                            |       | — |   | (19,369 | ) | — |   | (19,369 | ) |
| Deferred income tax expense                                                                   |       | —                                                            |       | 140 |   | 517 |   | — |   | 657 |   |
| Depreciation and amortization                                                                 |       | —                                                            |       | 53,236 |   | 30,447 |   | — |   | 83,683 |   |
| Earnings in equity investments, net of distributions                                          |       | 60,693                                                            |       | 10,125 |   | 5,061 |   | (64,563 | ) | 11,316 |   |
| Gains on sales of assets                                                                      |       | —                                                            |       | (1,410 | ) | — |   | — |   | (1,410 | ) |
| Changes in assets and liabilities and other                                                   |       | 51,523                                                            |       | (26,087 | ) | 18,315 |   | (33,098 | ) | 10,653 |   |
| Net cash  provided by continuing operating activities                                         |       | 257,699                                                           |       | 181,487 |   | 160,881 |   | (369,054 | ) | 231,013 |   |
| Cash flows from  discontinued operations                                                      |       | —                                                            |       | — |   | 1,521 |   | — |   | 1,521 |   |
| Net cash  provided by operating activities                                                    |       | 257,699                                                           |       | 181,487 |   | 162,402 |   | (369,054 | ) | 232,534 |   |
|                                                                                          |       |                                                              |       |   |   |   |   |   |   |   |   |
| Cash flows from  investing activities                                                         |       | (195,072                                                          | )          | 34,715 |   | (54,333 | ) | 40,131 |   | (174,559 | ) |
| Cash flows from  financing activities                                                         |       | (58,004                                                           | )          | (216,190 | ) | (108,098 | ) | 324,288 |   | (58,004 | ) |
| Net increase  (decrease) in cash and cash equivalents                                         |       | 4,623                                                             |       | 12 |   | (29 | ) | (4,635 | ) | (29 | ) |
| Cash and cash  equivalents at beginning of period                                             |       | 1,978                                                             |       | — |   | 107 |   | (1,966 | ) | 119 |   |
| Cash and cash  equivalents at end of period                                                   |       | $                                                                 | 6,601      |   | $ | 12 |   | $ | 78 |   | $ | (6,601 | ) | $ | 90 |   |

 

44

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| ** **                                                                                              | ** ** | **Nine Months Ended September 30, 2005** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                                                              | ** ** | **TEPPCO  Partners, L.P.**                                   | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                                                                              | ** ** | **(in thousands)**                                           | ** ** |
| Cash flows from  operating activities                                                                   |       |                                                              |       |   |   |   |   |   |   |   |   |
| Net income                                                                                              |       | $                                                                 | 117,926    |   | $ | 117,926 |   | $ | 44,674 |   | $ | (162,600 | ) | $ | 117,926 |   |
| Adjustments to reconcile net income to net cash  provided by (used in) continuing operating activities: |       |                                                              |       |   |   |   |   |   |   |   |   |
| Income from discontinued operations                                                                     |       | —                                                            |       | (2,662 | ) | — |   | — |   | (2,662 | ) |
| Depreciation and amortization                                                                           |       | —                                                            |       | 61,114 |   | 21,442 |   | — |   | 82,556 |   |
| Earnings (losses) in equity investments, net of  distributions                                          |       | 66,282                                                            |       | 6,542 |   | (1,820 | ) | (59,418 | ) | 11,586 |   |
| Gains on sales of assets                                                                                |       | —                                                            |       | (538 | ) | (59 | ) | — |   | (597 | ) |
| Changes in assets and liabilities and other                                                             |       | (108,054                                                          | )          | (52,375 | ) | (108,222 | ) | 105,804 |   | (162,847 | ) |
| Net cash  provided by (used in) continuing operating activities                                         |       | 76,154                                                            |       | 130,007 |   | (43,985 | ) | (116,214 | ) | 45,962 |   |
| Cash flows from  discontinued operations                                                                |       | —                                                            |       | 3,110 |   | — |   | — |   | 3,110 |   |
| Net cash  provided by (used in) operating activities                                                    |       | 76,154                                                            |       | 133,117 |   | (43,985 | ) | (116,214 | ) | 49,072 |   |
|                                                                                                    |       |                                                              |       |   |   |   |   |   |   |   |   |
| Cash flows from investing activities                                                                    |       | (278,830                                                          | )          | (21,909 | ) | (149,873 | ) | 183,069 |   | (267,543 | ) |
| Cash flows from  financing activities                                                                   |       | 202,121                                                           |       | (124,614 | ) | 191,061 |   | (66,447 | ) | 202,121 |   |
| Net decrease in  cash and cash equivalents                                                              |       | (555                                                              | )          | (13,406 | ) | (2,797 | ) | 408 |   | (16,350 | ) |
| Cash and cash  equivalents at beginning of period                                                       |       | 4,116                                                             |       | 13,596 |   | 2,826 |   | (4,116 | ) | 16,422 |   |
| Cash and cash  equivalents at end of period                                                             |       | $                                                                 | 3,561      |   | $ | 190 |   | $ | 29 |   | $ | (3,708 | ) | $ | 72 |   |

 

**NOTE17.  SUBSEQUENT EVENTS**

On October 6, 2006, wesold certain crude oil pipeline assets and refined products pipeline assets inthe Houston, Texas area, to an affiliate of Enterprise for approximately $11.7million.  These assets, which have beenidle since acquisition, were part of the assets acquired by us in 2005 fromGenco and BP (see Note 5).  The salesproceeds will be used to fund organic growth projects, retire debt or for othergeneral partnership purposes.  Thecarrying value of these pipeline assets at September 30, 2006, wasapproximately $5.6 million.

During October 2006, weexecuted a series of treasury rate lock agreements that extend through June2007 for a notional amount totaling $200.0 million.  These agreements, which are a series of derivativeinstruments, hedge our exposure to increases in the underlying U.S. Treasurybenchmark rate that is expected to be used to establish the fixed interest ratefor debt that we expect to incur in 2007. The weighted average rate under the treasury lock agreements wasapproximately 4.7%.  The actual couponrate of the expected debt issuance will be comprised of the underlying U.S.Treasury benchmark rate, plus a credit spread premium for our debt security.

On November 1, 2006, weannounced plans to construct a new 20-inch diameter lateral pipeline that willconnect our mainline system to Enterprise’s storage facility at Mont Belvieu,Texas.  The new connection, which willprovide delivery of propane into our system at full line flow rates,complements our current ability to source product from MB Storage.  The new lateral will also offer the abilityto deliver other liquid products such as butanes and 

45

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natural gasoline from Enterprise’s storage facilitiesinto our system at reduced flow rates until enhancements can be made.  The capability to deliver butanes and naturalgasoline from MB Storage at full flow rates is not expected to be impacted.  Construction of the new connection isexpected to be completed around January 1, 2007.

Effective November 1,2006, we purchased a refined petroleum product terminal in Aberdeen,Mississippi, for approximately $5.8 million from Mississippi Terminal andMarketing Inc. (“MTMI”).  The facility,located along the Tennessee/TomBigbee waterway system, has storage capacity of130,000 barrels for gasoline and diesel, which are supplied by barge fordelivery to local markets, including Tupelo and Columbus, Mississippi.  In connection with this acquisition, which weplan to integrate into our Downstream Segment, we plan to construct a new500,000-barrel terminal in Boligee, Alabama, at a cost of approximately $25.0million, on an 80-acre site which we are leasing from the Greene CountyIndustrial Development Board under a 60-year agreement.  The Boligee terminal site is locatedapproximately two miles from Colonial Pipeline. The new terminal is expected to begin service during the fourth quarterof 2007.

46

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**Item2.  Management’s Discussion and Analysisof Financial Condition and Results of Operations**

**General**

You should read the following review of our financialposition and results of operations in conjunction with our ConsolidatedFinancial Statements and the notes thereto. The Consolidated Financial Statements should be read in conjunction withthe financial statements and related notes, together with our discussion andanalysis of financial position and results of operations included in ourCurrent Report on Form 8-K filed on June 16, 2006, which recast certaininformation from our Annual Report on Form 10-K for the year ended December 31,2005, as discontinued operations.  Ourdiscussion and analysis includes the following:

·      CautionaryNote Regarding Forward-Looking Statements

·      Overview ofCritical Accounting Policies and Estimates

·      Overview ofBusiness

·      Results ofOperations – Discusses material period-to-period variances in the consolidatedstatements of income

·      FinancialCondition and Liquidity – Analyzes cash flows and financial position

·      OtherConsiderations – Addresses available sources of liquidity, trends, future plansand contingencies that are reasonably likely to materially affect futureliquidity or earnings

·      RecentAccounting Pronouncements

**CautionaryNote Regarding Forward-Looking Statements**

The matters discussed in this Quarterly Report on Form10-Q (this “Report”) include “forward-looking statements” within the meaning ofSection 27A of the Securities Act of 1933 and Section 21E of the SecuritiesExchange Act of 1934.  All statementsthat express belief, expectation, estimates or intentions, as well as thosethat are not statements of historical facts are forward-lookingstatements.  The words “proposed”, “anticipate”,“potential”, “may”, “will”, “could”, “should”, “expect”, “estimate”, “believe”,“intend”, “plan”, “seek” and similar expressions are intended to identifyforward-looking statements.  Withoutlimiting the broader description of forward-looking statements above, wespecifically note that statements included in this document that addressactivities, events or developments that we expect or anticipate will or mayoccur in the future, including such things as future distributions, estimatedfuture capital expenditures (including the amount and nature thereof), businessstrategy and measures to implement strategy, competitive strengths, goals,expansion and growth of our business and operations, plans, references tofuture success, references to intentions as to future matters and other suchmatters are forward-looking statements. These statements are based on certain assumptions and analyses made byus in light of our experience and our perception of historical trends, currentconditions and expected future developments as well as other factors we believeare appropriate under the circumstances. While we believe our expectations reflected in these forward-lookingstatements are reasonable, whether actual results and developments will conformwith our expectations and predictions is subject to a number of risks anduncertainties, including general economic, market or business conditions, theopportunities (or lack thereof) that may be presented to and pursued by us,competitive actions by other pipeline companies, changes in laws or regulationsand other factors, many of which are beyond our control.  For example, the demand for refined productsis dependent upon the price, prevailing economic conditions and demographicchanges in the markets served, trucking and railroad freight, agriculturalusage and military usage; the demand for propane is sensitive to the weatherand prevailing economic conditions; the demand for petrochemicals is dependentupon prices for products produced from petrochemicals; the demand for crude oiland petroleum products is dependent upon the price of crude oil and theproducts produced from the refining of crude 

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oil; and the demand for natural gas is dependent uponthe price of natural gas and the locations in which natural gas isdrilled.  We are also subject toregulatory factors such as the amounts we are allowed to charge our customersfor the services we provide on our regulated pipeline systems.  Consequently, all of the forward-lookingstatements made in this document are qualified by these cautionary statements,and we cannot assure you that actual results or developments that we anticipatewill be realized or, even if substantially realized, will have the expectedconsequences to or effect on us or our business or operations.  Also note that we provide a cautionarydiscussion of risks and uncertainties under the caption “Risk Factors” in ourQuarterly Report on Form 10-Q for the period ended June 30, 2006 and in thisReport; under the caption “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” in our Current Report on Form 8-K filed onJune 16, 2006; and in our Annual Report on Form 10-K for the year endedDecember 31, 2005.

The forward-lookingstatements contained in this Report speak only as of the date hereof.  Except as required by the federal and statesecurities laws, we undertake no obligation to publicly update or revise anyforward-looking statements, whether as a result of new information, futureevents or any other reason.  Allforward-looking statements attributable to TEPPCO Partners, L.P. or any personacting on its behalf are expressly qualified in their entirety by thecautionary statements contained or referred to in this Report and in our futureperiodic reports filed with the Securities and Exchange Commission (“SEC”).

**Overview ofCritical Accounting Policies and Estimates**

A summary of the significant accounting policies we have adopted andfollowed in the preparation of our consolidated financial statements isincluded in our Annual Report on Form 10-K for the year ended December 31,2005, and in our Current Report on Form 8-K filed on June 16, 2006.  Certain of these accounting policies requirethe use of estimates.  As more fullydescribed therein, the following estimates, in our opinion, are subjective innature, require the exercise of judgment and involve complex analysis: revenueand expense accruals, including accruals for power costs, property taxes andcrude oil margins; environmental costs; asset impairment analysis related toproperty, plant and equipment; and amortization expense and asset impairmentanalysis related to goodwill and other intangible assets.  These estimates are based on our knowledgeand understanding of current conditions and actions we may take in thefuture.  Changes in these estimates willoccur as a result of the passage of time and the occurrence of futureevents.  Subsequent changes in theseestimates may have a significant impact on our financial position and resultsof operations.

## ****Overview of Business****

Our business strategy is to continue to increasesustainable cash flow and cash distributions to our unitholders.  The key elements of our strategy are to focuson internal growth prospects in order to increase pipeline system and terminalthroughput, expand and upgrade existing assets and services and construct newpipelines, terminals and facilities; to target accretive and complementaryacquisitions and expansion opportunities that provide attractive growthpotential; to maintain a balanced mix of assets; and to operate in a safe,efficient and environmentally responsible manner.

Certain factorsare key to our operations.  These includethe safe, reliable and efficient operation of the pipelines and facilities thatwe own or operate while meeting the regulations that govern the operation ofour assets and the costs associated with such regulations.  We are also focused on our continued growththrough expansion of the assets that we own and through the acquisition ofassets that complement our current operations. We operate and report in three business segments:

·      Our DownstreamSegment, which is engaged in the transportation and storage of refinedproducts, liquefied petroleum products (“LPGs”) and petrochemicals;

·      Our UpstreamSegment, which is engaged in the gathering, transportation, marketing andstorage of crude oil and distribution of lubrication oils and specialtychemicals; and

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·      OurMidstream Segment, which is engaged in the gathering of natural gas,transportation of natural gas liquids (“NGLs”) and fractionation of NGLs.

Our Downstream Segment revenues are earned fromtransportation and storage of refined products and LPGs, intrastatetransportation of petrochemicals, sale of product inventory and other ancillaryservices.  The two largest operatingexpense items of the Downstream Segment are labor and electric power.  We generally realize higher revenues in thissegment during the first and fourth quarters of each year since theseoperations are somewhat seasonal. Refined products volumes are generally higherduring the second and third quarters because of greater demand for gasolinesduring the spring and summer driving seasons. LPGs volumes are generally higher from November through March due tohigher demand for propane, a major fuel for residential heating.  Our Downstream Segment also includes theresults of operations of the northern portion of the Dean Pipeline, whichtransports refinery grade propylene from Mont Belvieu to Point Comfort,Texas.  Our Downstream Segment alsoincludes our equity investments in Mont Belvieu Storage Partners, L.P. (“MBStorage”), which we are required to divest (see Note 14 in the Notes to theConsolidated Financial Statements), and in Centennial Pipeline LLC (“Centennial”)(see Note 8 in the Notes to the Consolidated Financial Statements).

Our Upstream Segmentrevenues are earned from gathering, transportation, marketing and storage ofcrude oil and distribution of lubrication oils and specialty chemicals,principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region.  Marketing operations consist primarily ofaggregating purchased crude oil along our pipeline systems, or from third partypipeline systems, and arranging the necessary transportation logistics for theultimate sale or delivery of the crude oil to local refineries, marketers orother end users.  Our Upstream Segmentalso includes our equity investment in Seaway Crude Pipeline Company (“Seaway”)(see Note 8 in the Notes to the Consolidated Financial Statements).  Seaway consists of large diameter pipelinesthat transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coastto Cushing, Oklahoma, a crude oil distribution point for the central UnitedStates, and to refineries in the Texas City and Houston areas.

Our Midstream Segmentrevenues are earned from the gathering of coal bed methane and conventionalnatural gas in the San Juan Basin in New Mexico and Colorado, through Val VerdeGas Gathering Company, L.P. (“Val Verde”); transportation of NGLs from twotrunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and apipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; andthe fractionation of NGLs in Colorado. Our Midstream Segment also includes our equity investment in Jonah GasGathering Company (“Jonah”) (see Note 8 in the Notes to the ConsolidatedFinancial Statements).  Jonah, which is ajoint venture between us and an affiliate of Enterprise Products Partners L.P.(“Enterprise”), owns a natural gas gathering system in the Green River Basin insouthwestern Wyoming.  Prior to August 1,2006, when Jonah was wholly-owned by us, operating results for Jonah wereincluded in the consolidated Midstream Segment operating results.  Effective August 1, 2006, we entered into thejoint venture with Enterprise’s affiliate, upon which Jonah was deconsolidated,and its operating results since August 1, 2006, have been accounted for underthe equity method of accounting. Operating results of the Pioneer plant, which we sold to an Enterpriseaffiliate in March 2006, are shown as discontinued operations for the threemonths and nine months ended September 30, 2006 and 2005.

Wecontinue to build a base for long-term growth by pursuing new businessopportunities, increasing throughput on ourpipeline systems, constructing new pipeline and gathering systems, and expandingand upgrading our existing infrastructure. We continue to believe that our business strategy will providecontinued growth in earnings and cash distributions.  Based on a detailed analysis of the businessenvironment, our management has identified key trends or factors, each ofwhich, in turn, drive our growth strategy beyond organic growth as follows:

·      Weexpect that Canadian crude oil imports to the U.S. will increase.

·      Develop competitive optionto move Canadian crude oil to U.S. refining customers through an optimumcombination of new pipeline construction and/or existing pipeline assets withthird parties.

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·      Weexpect that crude oil imports to the U.S. Gulf Coast will increase.

·      Build onshore or offshorecrude oil discharge, handling and transportation facilities to optimize theU.S. Gulf Coast marine delivery options for imported crude oil.

·      Weexpect that refined products imports to the U.S. will increase.

·      Acquire or developfacilities to take advantage of these increased volumes.

·      Weexpect to see changes in commercial terminal ownership and operations.

·      Acquire refined productsterminals and distribution assets to provide logistical service offerings tocompanies seeking to outsource or partner.

·      Ethanolconsumption is mandated to double by 2012.

·      Participate in theaggregation, terminaling and transportation associated with the overall supplyand distribution of ethanol.

·      Weexpect to see continued natural gas gathering and service opportunities in theJonah, Pinedale and San Juan Basin areas.

·      Continued development andexpansion of the Jonah system which serves the Jonah and Pinedale fields in ourMidstream Segment.  Through additionalJonah expansions, which should be completed in the fourth quarter of 2007, weexpect to increase the capacity to 2.4 billion cubic feet per day.

·      Addingnew volumes and improving the operating efficiency of the Val Verde system inour Midstream Segment in New Mexico’s San Juan Basin, through new connectionsof conventional and Colorado coal seam gas.

We also believeother growth opportunities are available to us, including through: expandingour West Texas system and storage capacity at Cushing in our Upstream Segment;increasing throughput on our Midstream Segment NGL systems; expanding ourDownstream Segment system delivery capability of gasoline and diesel fuel inthe Indianapolis and Chicago market areas; utilizing available DownstreamSegment system capacity of Centennial to move refined products to Midwestmarket areas, which enables us to increase movements of long-haul propanevolumes; expanding our Downstream Segment gathering capacity of refinedproducts along the upper Texas Gulf Coast; and pursuing acquisitions or organicgrowth projects in any of our business segments that would complement ourcurrent operations.

For additional discussion ofimportant factors that could affect our growth, please read “-Cautionary NoteRegarding Forward-Looking Statements” in this Report and “Risk Factors” in thisReport and our Quarterly Report on Form 10-Q for the period ended June 30,2006.

Our Upstream Segment’sperformance for 2006 will be impacted by a decrease in our participation ratioin the revenue and expense of Seaway, in accordance with the Seaway CrudePipeline Company Partnership Agreement. From June 2002 through May 2006, we received 60% of revenue and expenseof Seaway.  Thereafter, we receive 40% ofrevenue and expense of Seaway.  Our shareof revenue and expense of Seaway is 47% for 2006 (see Note 8 in the Notes tothe Consolidated Financial Statements).

Consistent with ourbusiness strategy, we continuously evaluate possible acquisitions of assetsthat would complement our current operations, including assets which, ifacquired, would have a material effect on our financial position, results ofoperations or cash flows.

*Jonah Joint Venture*

OnAugust 1, 2006, Enterprise Products Partners L.P. (“Enterprise”), through itsaffiliate, Enterprise Gas Processing, LLC, became our joint venture partner byacquiring an interest in Jonah, the partnership through which we owned theJonah system.  Prior to entering into theJonah joint venture, Enterprise had managed the construction of the Phase Vexpansion and funded the initial costs under a letter of intent we entered intoin February 2006.  In connection with thejoint venture arrangement, we and Enterprise intend to continue the Phase Vexpansion, which is expected to increase the system capacity of the Jonahsystem from 1.5 billion cubic feet (“Bcf”) per day to 

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approximately 2.4Bcf per day and to significantly reduce system operating pressures, which isanticipated to lead to increased production rates and ultimate reserverecoveries.  The first portion of theexpansion, which is expected to increase the system gathering capacity toapproximately 2.0 Bcf per day, is scheduled to be completed in the firstquarter of 2007 at an estimated cost of approximately $295.0 million.  The second portion of the expansion isexpected to cost approximately $170.0 million and be completed by the end of2007.  The overall high level of activityin the greater Green River Basin area has strained locally available resources,including equipment and qualified personnel. Coupled with rising steel costs, these factors are likely to contributeto higher overall costs for the Jonah expansion than previouslyanticipated.  We expect to reimburseEnterprise for approximately 50% of these costs.

Enterprisewill continue to manage the Phase V construction project.  We are entitled to all distributions from thejoint venture until specified milestones are achieved, at which point,Enterprise will be entitled to receive approximately 50% of the incrementalcash flow from portions of the system placed in service as part of theexpansion.  From August 1, 2006, we andEnterprise equally share the costs of the Phase V expansion.  In the third quarter of 2006, we reimbursedEnterprise $65.0 million for 50% of the Phase V cost incurred by it throughAugust 1, 2006 (including its cost of capital of $1.3 million).  At September 30, 2006, we had a payable toEnterprise for costs incurred through September 30, 2006, of $18.9million.  After subsequent milestones areachieved, we and Enterprise will share distributions based on a formula thattakes into account the capital contributions of the parties, includingexpenditures by us prior to the expansion. Based on the formula in the partnership agreement, we expect to own aninterest in Jonah of approximately 80%, with Enterprise owning the remaining20% and serving as operator, with further costs being allocated based on suchownership interests.  The joint ventureis governed by a management committee comprised of two representatives approvedby Enterprise and two representatives approved by us, each with equal votingpower.  This transaction was reviewed andrecommended for approval by the Audit and Conflicts Committee of the Board ofDirectors of our General Partner.

EffectiveAugust 1, 2006, with the formation of the joint venture, Jonah wasdeconsolidated, and we began using the equity method of accounting to accountfor our investment in Jonah.   Under theequity method, we record the costs of our investment within the “EquityInvestments” line on our consolidated balance sheet, and as changes in the netassets of Jonah occur (for example, earnings, contributions and distributions),we will recognize our proportional share of that change in the “EquityInvestments” account.

*EPCO Proposal*

On April 20, 2006, EPCOsubmitted a proposal to the Audit and Conflicts Committee of our GeneralPartner’s Board of Directors to reduce the General Partner’s maximum percentageinterest in our quarterly distributions from 50% to 25% with respect to thatportion of our quarterly cash distribution to partners that exceeds $0.325 perUnit.  In exchange for the agreement toreduce its maximum percentage interest in our quarterly distributions, ourGeneral Partner would receive a number of newly-issued Units that, based on thedistribution rate and the number of Units outstanding at the time of issuance,would result in our General Partner receiving cash distributions from thenewly-issued Units and from its reduced maximum percentage interest in ourquarterly distributions that would approximately equal the cash distributionsour General Partner would have received from its maximum percentage interest inour quarterly distributions without reduction. Based on our distribution rate and outstanding Units as of the date ofthe filing of this Report, the number of newly-issued Units issued to theGeneral Partner would be approximately 14.1 million.  On September 11, 2006, we filed with theSecurities and Exchange Commission a definitive proxy statement that outlinesthe EPCO proposal to be voted upon at a special meeting of our unitholders andother changes to our Partnership Agreement that are part of the EPCO proposal,all of which are conditioned upon one another. Passage of the components of the EPCO proposal effectively requires theaffirmative vote of 66 2/3% of our outstanding Units (issuance of Units to theGeneral Partner requires a majority of the votes cast by a quorum of ourunitholders, but that proposal is conditioned on passage of the changes to ourPartnership Agreement, which require the 66 2/3% approval).  The proxy statement also contains separateproposals for the adoption of an employee Unit purchase plan and a long termincentive plan.  The special meeting wasconvened on October 26, 2006, and adjourned, without voting on the proposals,to November 30, 2006 by the General Partner for lack of a quorum.

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*Recent Developments*

On November 1, 2006, weannounced plans to construct a new 20-inch diameter lateral pipeline that willconnect our mainline system to Enterprise’s storage facility at Mont Belvieu,Texas.  The new connection, which willprovide delivery of propane into our system at full line flow rates,complements our current ability to source product from MB Storage.  The new lateral will also offer the abilityto deliver other liquid products such as butanes and natural gasoline fromEnterprise’s storage facilities into our system at reduced flow rates untilenhancements can be made.  The capabilityto deliver butanes and natural gasoline from MB Storage at full flow rates isnot expected to be impacted. Construction of the new connection is expected to be completed aroundJanuary 1, 2007.

Effective November 1,2006, we purchased a refined petroleum product terminal in Aberdeen,Mississippi, for approximately $5.8 million from Mississippi Terminal andMarketing Inc. (“MTMI”).  The facility,located along the Tennessee/TomBigbee waterway system, has storage capacity of130,000 barrels for gasoline and diesel, which are supplied by barge fordelivery to local markets, including Tupelo and Columbus, Mississippi.  In connection with this acquisition, which weplan to integrate into our Downstream Segment, we plan to construct a new500,000-barrel terminal in Boligee, Alabama, at a cost of approximately $25.0million, on an 80-acre site which we are leasing from the Greene CountyIndustrial Development Board under a 60-year agreement.  The Boligee terminal site is locatedapproximately two miles from Colonial Pipeline. The new terminal is expected to begin service during the fourth quarterof 2007.

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**Results of Operations**

The following tablesummarizes financial information by business segment for the three months andnine months ended September 30, 2006 and 2005 (in thousands):

 
| ** **                                 | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|--------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                 | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Operating revenues:                        |       |                                                 |       |                                                |       |   |   |   |   |
| Downstream  Segment                        |       | $                                                    | 72,358     |                                                | $          | 66,094 |   | $ | 215,758 |   | $ | 207,699 |   |
| Upstream Segment                           |       | 2,453,926                                            |       | 2,380,734                                           |       | 7,152,520 |   | 5,750,514 |   |
| Midstream  Segment (1)                     |       | 43,895                                               |       | 53,641                                              |       | 170,617 |   | 155,481 |   |
| Intersegment  eliminations                 |       | (134                                                 | )          | (342                                                | )          | (7,429 | ) | (2,391 | ) |
| Total operating  revenues                  |       | 2,570,045                                            |       | 2,500,127                                           |       | 7,531,466 |   | 6,111,303 |   |
|                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Operating income:                          |       |                                                 |       |                                                |       |   |   |   |   |
| Downstream  Segment                        |       | 19,586                                               |       | 14,615                                              |       | 59,641 |   | 61,099 |   |
| Upstream Segment                           |       | 19,446                                               |       | 5,207                                               |       | 53,097 |   | 22,199 |   |
| Midstream  Segment (1)                     |       | 12,798                                               |       | 23,556                                              |       | 59,900 |   | 75,129 |   |
| Intersegment  eliminations                 |       | 9                                                    |       | —                                              |       | 9 |   | — |   |
| Total operating  income                    |       | 51,839                                               |       | 43,378                                              |       | 172,647 |   | 158,427 |   |
|                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Equity earnings  (losses):                 |       |                                                 |       |                                                |       |   |   |   |   |
| Downstream  Segment                        |       | (2,949                                               | )          | (651                                                | )          | (6,581 | ) | (2,718 | ) |
| Upstream Segment                           |       | 2,962                                                |       | 5,398                                               |       | 10,257 |   | 19,310 |   |
| Midstream  Segment (1)                     |       | 11,563                                               |       | —                                              |       | 11,563 |   | — |   |
| Intersegment  eliminations                 |       | (9                                                   | )          | —                                              |       | (9 | ) | — |   |
| Total equity  earnings                     |       | 11,567                                               |       | 4,747                                               |       | 15,230 |   | 16,592 |   |
|                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Earnings before  interest:                 |       |                                                 |       |                                                |       |   |   |   |   |
| Downstream  Segment                        |       | 16,926                                               |       | 14,270                                              |       | 54,313 |   | 58,957 |   |
| Upstream Segment                           |       | 22,752                                               |       | 10,708                                              |       | 63,967 |   | 41,641 |   |
| Midstream  Segment (1)                     |       | 24,791                                               |       | 23,631                                              |       | 72,013 |   | 75,306 |   |
| Interest expense                           |       | (24,884                                              | )          | (22,033                                             | )          | (71,642 | ) | (65,202 | ) |
| Interest capitalized                       |       | 1,703                                                |       | 2,307                                               |       | 8,120 |   | 4,562 |   |
| Income before  deferred income tax expense |       | 41,288                                               |       | 28,883                                              |       | 126,771 |   | 115,264 |   |
| Deferred income tax  expense               |       | 143                                                  |       | —                                              |       | 657 |   | — |   |
| Income from  continuing operations         |       | 41,145                                               |       | 28,883                                              |       | 126,114 |   | 115,264 |   |
| Discontinued operations                    |       | —                                               |       | 692                                                 |       | 19,369 |   | 2,662 |   |
| Net income                                 |       | $                                                    | 41,145     |                                                | $          | 29,575 |   | $ | 145,483 |   | $ | 117,926 |   |

 

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(1)          Effective August 1,2006, with the formation of a joint venture with Enterprise, Jonah wasdeconsolidated and has been subsequently accounted for as an equity investment(see Note 8 in the Notes to the Consolidated Financial Statements).

 

The following is adetailed analysis of the results of operations, including reasons for changesin results, by each of our operating segments.

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**DownstreamSegment**

The followingtable provides financial information for the Downstream Segment for the threemonths and nine months ended September 30, 2006 and 2005 (in thousands):
| ** **                             | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** | **Nine Months Ended** | ** ** | ** **   | ** ** |
|----------------------------------------|------------|----------------------------------|------------|--------------|------------|---------------------------------|------------|--------------|------------|
| ** **                             | ** ** | **September 30,**           | ** ** | **Increase** | ** ** | **September 30,**          | ** ** | **Increase** | ** ** |
| ** **                             | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)**                  | ** ** | **2006**     | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| ** **                             | ** ** | ** **                       | ** ** | ** **   | ** ** | ** **                      | ** ** | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues:                              |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Transportation – Refined products |       | $                                | 42,067     |         | $          | 38,240                          |       | $            | 3,827      |   | $ | 113,309 |   | $ | 111,039 |   | $ | 2,270 |   |
| Transportation – LPGs             |       | 16,877                           |       | 16,519       |       | 358                             |       | 59,652       |       | 63,220 |   | (3,568 | ) |
| Other                                  |       | 13,414                           |       | 11,335       |       | 2,079                           |       | 42,797       |       | 33,440 |   | 9,357 |   |
| Total operating revenues               |       | 72,358                           |       | 66,094       |       | 6,264                           |       | 215,758      |       | 207,699 |   | 8,059 |   |
|                                   |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Costs and  expenses:                   |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Operating expense                      |       | 27,799                           |       | 25,602       |       | 2,197                           |       | 77,606       |       | 72,787 |   | 4,819 |   |
| Operating fuel and power               |       | 10,560                           |       | 8,170        |       | 2,390                           |       | 28,183       |       | 23,787 |   | 4,396 |   |
| General and administrative             |       | 3,455                            |       | 4,617        |       | (1,162                          | )          | 13,250       |       | 12,328 |   | 922 |   |
| Depreciation and amortization          |       | 10,713                           |       | 10,098       |       | 615                             |       | 31,143       |       | 29,460 |   | 1,683 |   |
| Taxes – other than income taxes   |       | 259                              |       | 3,016        |       | (2,757                          | )          | 5,974        |       | 8,369 |   | (2,395 | ) |
| Gains on sales of assets               |       | (14                              | )          | (24          | )          | 10                              |       | (39          | )          | (131 | ) | 92 |   |
| Total costs and expenses               |       | 52,772                           |       | 51,479       |       | 1,293                           |       | 156,117      |       | 146,600 |   | 9,517 |   |
|                                   |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Operating income                       |       | 19,586                           |       | 14,615       |       | 4,971                           |       | 59,641       |       | 61,099 |   | (1,458 | ) |
|                                   |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Equity losses                          |       | (2,949                           | )          | (651         | )          | (2,298                          | )          | (6,581       | )          | (2,718 | ) | (3,863 | ) |
| Other income – net                |       | 289                              |       | 306          |       | (17                             | )          | 1,253        |       | 576 |   | 677 |   |
|                                   |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Earnings before  interest              |       | $                                | 16,926     |         | $          | 14,270                          |       | $            | 2,656      |   | $ | 54,313 |   | $ | 58,957 |   | $ | (4,644 | ) |

 

The following table presents volumes delivered inbarrels and average tariff per barrel for the three months and nine monthsended September 30, 2006 and 2005 (in thousands, except tariff information):
| ** **                        | ** ** | **Three Months Ended** | ** ** | **Percentage** | ** ** | **Nine Months Ended** | ** ** | **Percentage** | ** ** |
|-----------------------------------|------------|----------------------------------|------------|----------------|------------|---------------------------------|------------|----------------|------------|
| ** **                        | ** ** | **September 30,**           | ** ** | **Increase**   | ** ** | **September 30,**          | ** ** | **Increase**   | ** ** |
| ** **                        | ** ** | **2006**                         | ** ** | **2005**       | ** ** | **(Decrease)**                  | ** ** | **2006**       | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| **Volumes  Delivered:**           |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Refined products                  |       | 43,018                           |       | 43,067         |       | —                          |       | 125,061        |       | 123,759 |   | 1 | % |
| LPGs                              |       | 9,763                            |       | 8,646          |       | 13                              | %          | 30,880         |       | 31,303 |   | (1 | )% |
| Total                             |       | 52,781                           |       | 51,713         |       | 2                               | %          | 155,941        |       | 155,062 |   | 1 | % |
|                              |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| **Average  Tariff per Barrel:**   |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Refined products                  |       | $                                | 0.98       |           | $          | 0.89                            |       | 10             | %          | $ | 0.91 |   | $ | 0.90 |   | 1 | % |
| LPGs                              |       | 1.73                             |       | 1.91           |       | (9                              | )%         | 1.93           |       | 2.02 |   | (4 | )% |
| Average system  tariff per barrel |       | 1.12                             |       | $              | 1.06       |                            | 6          | %              | 1.11       |   | $ | 1.12 |   | (1 | )% |
|                                   |            |                                  |            |                |            |                                 |            |                |            |  |  |  |  |  |  |  |  |

 

*Three Months Ended September 30,2006 Compared with Three Months Ended September 30, 2005*

 

Revenues from refined products transportationincreased $3.8 million for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2005, primarily due to a 10% increasein the refined products average tariff per barrel.  The average tariff increased primarily due toan increase in gasoline blendstock deliveries, which have a higher tariff, anincrease in system tariffs, which went into effect in April and July 2006, anda shift of volumes from Centennial to TEPPCO tariffs.  Overall, refined products volumes remainedeffectively unchanged between periods. Increases in jet fuel and gasoline blendstock deliveries were offset bylower distillate deliveries.  Short-hauldeliveries of product received into our system from Centennial at CrealSprings, Illinois, also decreased. Centennial, through a lease agreement entered into in February 2003,provides our system with additional 

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pipeline capacity for movement of products originatingin the U.S. Gulf Coast area.  Prior tothe construction of Centennial, deliveries on our pipeline system were limitedby our pipeline capacity and transportation services for our customers wereallocated in accordance with a proration policy.  The Centennial capacity lease has relievedour previously constrained system and has permitted expanded deliveries inmarkets both south and north of Creal Springs, Illinois.  Movement of TEPPCO product via the Centenniallease to the north end of our system permits expanded supply capability of theTEPPCO system for delivery to the south end of our system.

Revenues from LPGs transportation increased $0.4million for the three months ended September 30, 2006, compared with the threemonths ended September 30, 2005, due to an increase in short-haul propanedeliveries on the Texas Gulf Coast.  The LPGs average rate per barreldecreased from the prior period primarily as a result of these increasedshort-haul deliveries during the three months ended September 30, 2006,compared with the three months ended September 30, 2005.

Other operatingrevenues increased $2.1 million for the three months ended September 30, 2006,compared with the three months ended September 30, 2005, primarily due toincreased storage revenues on assets acquired from Texas Genco, LLC in July2005 and higher other system storage revenues, partially offset by decreasedvolumes of product sales.

Costs and expensesincreased $1.3 million for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2005. Operating fuel and power increased $2.4 million primarily due toincreased mainline throughput and higher power rates.  Operating expenses increased $2.2 millionprimarily due to a $1.5 million increase in pipeline operating costs primarilyas a result of acquisitions made in 2005, a $0.7 million increase in rentalexpense on a lease with a third-party pipeline, a $0.6 million increase inrental expense from the Centennial pipeline capacity lease agreement and $0.6million of higher insurance premiums. These increases in operating expenses were partially offset by a $0.8million decrease due to regulatory penalties in the prior year period and a$0.6 million decrease in pipeline inspection and repair costs associated withour integrity management program. Depreciation and amortization expense increased $0.6 million primarilydue to assets placed into service and asset retirements during the 2006 period.  Taxes – other than income taxes decreased$2.7 million primarily due to a true-up of property tax accruals for prior taxyears and higher payroll taxes in the prior year period.  General and administrative expenses decreased$1.2 million primarily due to higher labor and benefits expenses in the prioryear period associated with vesting provisions in certain of our incentivecompensation plans and changes in ownership of our General Partner.  These costs and expenses were offset byhigher expenses relating to our special unitholder meeting to consider EPCO’sproposals to amend and restate our Partnership Agreement and issue Units to ourGeneral Partner, as well as other proposals, and higher executive compensationexpense.

Net losses from equityinvestments increased for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2005, as shown below (in thousands):
|                      | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** |
|----------------------|------------|----------------------------------|------------|--------------|------------|
| ** **           | ** ** | **September 30,**           | ** ** | **Increase** | ** ** |
| ** **           | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)** | ** ** |
| ** **           | ** ** | ** **                       | ** ** | ** **   | ** ** | ** ** | ** ** |
| Centennial           |       | $                                | (4,065     | )            | $          | (2,391 | ) | $ | (1,674 | ) |
| MB Storage           |       | 1,122                            |       | 1,728        |       | (606 | ) |
| Other                |       | (6                               | )          | 12           |       | (18 | ) |
| Total equity  losses |       | $                                | (2,949     | )            | $          | (651 | ) | $ | (2,298 | ) |

 

Equity losses inCentennial increased $1.7 million for the three months ended September 30,2006, compared with the three months ended September 30, 2005, primarily due tolower transportation volumes and increased costs relating to pipelineinspection and repair costs associated with its integrity managementprogram.  Equity earnings in MB Storagedecreased $0.6 million for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2005, primarily due to higher productmeasurement losses on the MB 

55

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Storage system and higheroperating fuel and power resulting from higher power rates and increasedvolumes, partially offset by higher revenues.

*Nine Months Ended September 30,2006 Compared with Nine Months Ended September 30, 2005*

 

Revenues from refined products transportationincreased $2.3 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005, primarily due to a slightoverall increase in refined products volumes transported and a minor increasein the average rate per barrel.  Volumeincreases were due to increased demand for products supplied from the U.S. GulfCoast into Midwest markets resulting from higher distillate price differentialsand a greater demand for gasoline blendstocks, partially offset by unfavorabledifferentials for motor fuels during the first quarter of 2006.  Additionally, refined products revenues increaseddue to increased terminaling activity at truck racks and higher product storagefees.  The average tariff increasedprimarily due to an increase in gasoline blendstock deliveries, which have ahigher tariff, and an increase in system tariffs, which went into effect inApril and July 2006.  The increase in therefined products average tariff rate is partially offset by the impact ofCentennial on the average rates.  When alarger proportion of the refined products deliveries are delivered under a Centennialtariff, TEPPCO’s average tariff declines. Conversely, if the proportion of refined products deliveries movingunder a Centennial origin decrease, the average TEPPCO tariff increases.  Movements of refined products on Centennialtherefore result in a decrease in the refined products average rate per barrel;however, utilizing Centennial for refined products movements allows us toincrease movements of long-haul propane volumes.

Revenuesfrom LPGs transportation decreased $3.6 million for the nine months endedSeptember 30, 2006, compared with the nine months ended September 30, 2005, dueto lower deliveries of propane in the upper Midwest and Northeast market areasas a result of warmer than normal winter weather in the first quarter of 2006,high propane prices and scheduled plant maintenance, known as aturnaround.  The LPGs average rate per barrel decreased from the prioryear period primarily as a result of increased short-haul deliveries during thenine months ended September 30, 2006, compared with the nine months endedSeptember 30, 2005.

Otheroperating revenues increased $9.4 million for the nine months ended September30, 2006, compared with the nine months ended September 30, 2005, primarily dueto increased storage revenue on assets acquired from Texas Genco, LLC in July2005 and increases in other system storage and tender deduction revenues.

Costs and expensesincreased $9.5 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005. Operating expenses increased $4.8 million primarily due to a $7.8million increase in pipeline operating costs primarily as a result ofacquisitions made in 2005, $2.1 million of higher insurance premiums, a $0.7million increase in rental expense on a lease with a third-party pipeline, $0.6million in severance expense as a result of the migration to a shared servicesenvironment with EPCO, $0.4 million of expenses relating to our specialunitholder meeting (“– EPCO Proposal,” above) and a $0.3 million increase inenvironmental remediation and assessment costs. These increases in costs and expenses were partially offset by a $3.5million decrease in pipeline inspection and repair costs associated with ourintegrity management program, $1.4 million in product measurement gains, a $1.0million decrease in labor and benefits expense associated with incentivecompensation plan vestings in the prior year period and a $0.8 million decreasein regulatory penalties for past incidents. Operating fuel and power increased $4.4 million primarily due toincreased mainline throughput and higher power rates.  Depreciation expense increased $1.7 millionprimarily due to assets placed into service, asset retirements in 2006 and therecording of a conditional asset retirement obligation as discussed below.  General and administrative expenses increased$0.9 million primarily due to a $1.1 million increase related to the retirementof an executive in February 2006, $0.7 million in severance expense as a resultof the migration to a shared services environment with EPCO and higherexecutive compensation expense, partially offset by higher labor and benefitsexpenses in the prior year period associated with vesting provisions in certainof our incentive compensation plans and changes in ownership of our GeneralPartner resulting in higher incentive compensation expenses for thatperiod.  Taxes – other than income taxesdecreased $2.4 million primarily due to a true-up of property tax accruals forprior tax years and higher payroll taxes in the prior year period.

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Net losses from equityinvestments increased for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005, as shown below (in thousands):
|                      | ** ** | **Nine Months Ended** | ** ** | ** **   | ** ** |
|----------------------|------------|---------------------------------|------------|--------------|------------|
| ** **           | ** ** | **September 30,**          | ** ** | **Increase** | ** ** |
| ** **           | ** ** | **2006**                        | ** ** | **2005**     | ** ** | **(Decrease)** | ** ** |
| ** **           | ** ** | ** **                      | ** ** | ** **   | ** ** | ** ** | ** ** |
| Centennial           |       | $                               | (11,378    | )            | $          | (8,476 | ) | $ | (2,902 | ) |
| MB Storage           |       | 4,814                           |       | 5,727        |       | (913 | ) |
| Other                |       | (17                             | )          | 31           |       | (48 | ) |
| Total equity  losses |       | $                               | (6,581     | )            | $          | (2,718 | ) | $ | (3,863 | ) |

 

Equity losses inCentennial increased $2.9 million for the nine months ended September 30, 2006,compared with the nine months ended September 30, 2005, primarily due to lowerpropane revenues and volumes primarily due to warmer than normal winter weatherin the Northeast in the 2006 period and increased costs relating to pipelineinspection and repair costs associated with its integrity management program,partially offset by lower amortization expense on the portion of TE Products’excess investment in Centennial as a result of the lower volumes.  Equity earnings in MB Storage decreased $0.9million for the nine months ended September 30, 2006, compared with the ninemonths ended September 30, 2005, primarily due to higher product measurementlosses on the MB Storage system, higher system maintenance expenses and higheroperating fuel and power resulting from higher power rates and increasedvolumes, partially offset by higher revenues.

Other income – netincreased $0.7 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005, due to higher interest incomeearned on cash investments and other investing activities.

*AssetRetirement Obligation*

During the second quarter of 2006, we recorded $0.3million of expense, included in depreciation and amortization expense, relatedto a conditional asset retirement obligation. Additionally, we recorded a $0.4 million liability, which represents thefair value of the conditional asset retirement obligation related to structuralrestoration work to be completed on leased office space that is required uponour anticipated office lease termination (see Note 1 in the Notes to theConsolidated Financial Statements).

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**Upstream Segment**

The following tableprovides financial information for the Upstream Segment for the three monthsand nine months ended September 30, 2006 and 2005 (in thousands):
| ** **                           | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** | **Nine Months Ended** | ** ** | ** **   | ** ** |
|--------------------------------------|------------|----------------------------------|------------|--------------|------------|---------------------------------|------------|--------------|------------|
| ** **                           | ** ** | **September 30,**           | ** ** | **Increase** | ** ** | **September 30,**          | ** ** | **Increase** | ** ** |
| ** **                           | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)**                  | ** ** | **2006**     | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
|                                 |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Revenues:                            |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Sales of petroleum products (1)      |       | $                                | 2,441,750  |         | $          | 2,367,984                       |       | $            | 73,766     |   | $ | 7,116,064 |   | $ | 5,714,353 |   | $ | 1,401,711 |   |
| Transportation – Crude oil      |       | 9,567                            |       | 10,001       |       | (434                            | )          | 29,034       |       | 28,215 |   | 819 |   |
| Other                                |       | 2,609                            |       | 2,749        |       | (140                            | )          | 7,422        |       | 7,946 |   | (524 | ) |
| Total operating revenues             |       | 2,453,926                        |       | 2,380,734    |       | 73,192                          |       | 7,152,520    |       | 5,750,514 |   | 1,402,006 |   |
|                                 |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Costs and  expenses:                 |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Purchases of petroleum products (1)  |       | 2,413,391                        |       | 2,350,107    |       | 63,284                          |       | 7,032,930    |       | 5,665,136 |   | 1,367,794 |   |
| Operating expense                    |       | 12,974                           |       | 14,216       |       | (1,242                          | )          | 40,955       |       | 37,217 |   | 3,738 |   |
| Operating fuel and power             |       | 1,511                            |       | 1,247        |       | 264                             |       | 5,470        |       | 3,709 |   | 1,761 |   |
| General and administrative           |       | 1,460                            |       | 1,756        |       | (296                            | )          | 5,137        |       | 4,483 |   | 654 |   |
| Depreciation and amortization        |       | 3,699                            |       | 6,471        |       | (2,772                          | )          | 10,464       |       | 13,623 |   | (3,159 | ) |
| Taxes – other than income taxes |       | 1,445                            |       | 1,737        |       | (292                            | )          | 4,467        |       | 4,206 |   | 261 |   |
| Gains on sales of assets             |       | —                           |       | (7           | )          | 7                               |       | —       |       | (59 | ) | 59 |   |
| Total costs and expenses             |       | 2,434,480                        |       | 2,375,527    |       | 58,953                          |       | 7,099,423    |       | 5,728,315 |   | 1,371,108 |   |
| Operating income                     |       | 19,446                           |       | 5,207        |       | 14,239                          |       | 53,097       |       | 22,199 |   | 30,898 |   |
| Equity earnings                      |       | 2,962                            |       | 5,398        |       | (2,436                          | )          | 10,257       |       | 19,310 |   | (9,053 | ) |
| Other income – net              |       | 344                              |       | 103          |       | 241                             |       | 613          |       | 132 |   | 481 |   |
| Earnings before  interest            |       | $                                | 22,752     |         | $          | 10,708                          |       | $            | 12,044     |   | $ | 63,967 |   | $ | 41,641 |   | $ | 22,326 |   |

 

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(1)          Amounts for the three months ended September 30, 2006 have been fullyadjusted for the impact of adopting Emerging Issues Task Force (“EITF”)04-13.  Amounts for the nine months endedSeptember 30, 2006 have been adjusted for the period from April 1, 2006 throughSeptember 30, 2006 for the impact of adopting EITF 04-13.  The 2005 periods have not been adjusted forthe adoption of EITF 04-13, as retroactive restatement was not permitted, whichimpacts comparability (for further discussion, see below).

Information presented inthe following table includes the margin of the Upstream Segment, which may beviewed as a non-GAAP (Generally Accepted Accounting Principles) financialmeasure under the rules of the SEC.  Wecalculate the margin of the Upstream Segment as revenues generated from thesale of crude oil and lubrication oil, and transportation of crude oil, lessthe costs of purchases of crude oil and lubrication oil.  We believe that margin is a more meaningfulmeasure of financial performance than sales and purchases of crude oil andlubrication oil due to the significant fluctuations in sales and purchasescaused by variations in the level of volumes marketed and prices for productsmarketed.  Additionally, we use margininternally to evaluate the financial performance of the Upstream Segmentbecause it excludes expenses that are not directly related to the marketing andsales activities being evaluated.  Marginand volume information for the three months and nine months ended September 30,2006 and 2005 is presented below (in thousands, except per barrel and pergallon amounts):

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| ** **                          | ** ** | **Three Months Ended** | ** ** | **Percentage** | ** ** | **Nine Months Ended** | ** ** | **Percentage** | ** ** |
|-------------------------------------|------------|----------------------------------|------------|----------------|------------|---------------------------------|------------|----------------|------------|
| ** **                          | ** ** | **September 30,**           | ** ** | **Increase**   | ** ** | **September 30,**          | ** ** | **Increase**   | ** ** |
| ** **                          | ** ** | **2006**                         | ** ** | **2005**       | ** ** | **(Decrease)**                  | ** ** | **2006**       | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
|                                |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Margins: (1)                        |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Crude oil marketing                 |       | $                                | 14,675     |           | $          | 7,750                           |       | 89%            |       | $ | 46,557 |   | $ | 20,282 |   | 130% |   |
| Lubrication oil sales               |       | 2,221                            |       | 1,951          |       | 14%                             |       | 6,396          |       | 5,383 |   | 19% |   |
| Revenues: (1)                       |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Crude oil transportation            |       | 18,162                           |       | 15,416         |       | 18%                             |       | 50,516         |       | 44,537 |   | 13% |   |
| Crude oil terminaling               |       | 2,868                            |       | 2,761          |       | 4%                              |       | 8,699          |       | 7,230 |   | 20% |   |
| Total margins/revenues              |       | $                                | 37,926     |           | $          | 27,878                          |       | 36%            |       | $ | 112,168 |   | $ | 77,432 |   | 45% |   |
|                                |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Total  barrels/gallons:             |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Crude oil marketing (barrels)       |       | 57,982                           |       | 54,747         |       | 6%                              |       | 167,180        |       | 147,905 |   | 13% |   |
| Lubrication oil volume (gallons)    |       | 3,457                            |       | 3,573          |       | (3)%                            |       | 10,689         |       | 10,898 |   | (2)% |   |
|                                |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Crude oil transportation (barrels)  |       | 23,237                           |       | 23,659         |       | (2)%                            |       | 68,412         |       | 71,181 |   | (4)% |   |
| Crude oil terminaling (barrels)     |       | 30,181                           |       | 28,528         |       | 6%                              |       | 92,929         |       | 76,934 |   | 21% |   |
|                                |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Margin per  barrel or gallon:       |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Crude oil marketing (per barrel)    |       | $                                | 0.253      |           | $          | 0.142                           |       | 79%            |       | $ | 0.278 |   | $ | 0.137 |   | 103% |   |
| Lubrication oil margin (per gallon) |       | 0.642                            |       | 0.546          |       | 18%                             |       | 0.598          |       | 0.494 |   | 21% |   |
|                                |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Average tariff  per barrel:         |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Crude oil transportation            |       | $                                | 0.782      |           | $          | 0.652                           |       | 20%            |       | $ | 0.738 |   | $ | 0.626 |   | 18% |   |
| Crude oil  terminaling              |       | 0.095                            |       | 0.097          |       | (2)%                            |       | 0.094          |       | 0.094 |   | — |   |

 

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(1)                Amounts in this table are presented prior tothe elimination of intercompany sales, revenues and purchases between TEPPCOCrude Oil, L.P. and TEPPCO Crude Pipeline, L.P.

The following table reconciles the Upstream Segmentmargin to operating income using the information presented in the consolidatedstatements of income and the statements of income in Note 13 in the Notes tothe Consolidated Financial Statements (in thousands):
|                                        | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                             | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                             | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| Sales of  petroleum products           |       | $                                | 2,441,750  |                            | $          | 2,367,984 |   | $ | 7,116,064 |   | $ | 5,714,353 |   |
| Transportation –  Crude oil       |       | 9,567                            |       | 10,001                          |       | 29,034 |   | 28,215 |   |
| Less: Purchases  of petroleum products |       | (2,413,391                       | )          | (2,350,107                      | )          | (7,032,930 | ) | (5,665,136 | ) |
| Total margins/revenues                 |       | 37,926                           |       | 27,878                          |       | 112,168 |   | 77,432 |   |
| Other operating  revenues              |       | 2,609                            |       | 2,749                           |       | 7,422 |   | 7,946 |   |
| Net operating revenues                 |       | 40,535                           |       | 30,627                          |       | 119,590 |   | 85,378 |   |
| Operating  expense                     |       | 12,974                           |       | 14,216                          |       | 40,955 |   | 37,217 |   |
| Operating fuel  and power              |       | 1,511                            |       | 1,247                           |       | 5,470 |   | 3,709 |   |
| General and  administrative expense    |       | 1,460                            |       | 1,756                           |       | 5,137 |   | 4,483 |   |
| Depreciation and  amortization         |       | 3,699                            |       | 6,471                           |       | 10,464 |   | 13,623 |   |
| Taxes – other  than income taxes  |       | 1,445                            |       | 1,737                           |       | 4,467 |   | 4,206 |   |
| Gains on sales  of assets              |       | —                           |       | (7                              | )          | — |   | (59 | ) |
| Operating income                       |       | $                                | 19,446     |                            | $          | 5,207 |   | $ | 53,097 |   | $ | 22,199 |   |

 

On April 1, 2006, we adopted EITF 04-13, *Accounting for Purchases and Sales of Inventory with the SameCounterparty* (see Note 1 in the Notes to the Consolidated FinancialStatements), which resulted in crude oil inventory purchases and sales underbuy/sell transactions, which were previously recorded as gross purchases andsales, to be treated as inventory exchanges in our consolidated statements ofincome.  EITF 04-13 reduced gross 

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revenues andpurchases, but did not have a material effect on our financial position, resultsof operations or cash flows.  Under theconsensus reached in EITF 04-13, buy/sell transactions are reported asnon-monetary exchanges and consequently not presented on a gross basis in ourstatements of income.  Implementation ofEITF 04-13 reduced revenues and purchases of petroleum products on ourconsolidated statements of income by approximately $774.4 million for theperiod from April 1, 2006 through September 30, 2006 ($460.7 million for thethree months ended September 30, 2006). The revenues and purchases of petroleum products associated withbuy/sell transactions that are reported on a gross basis in our consolidatedstatements of income for the three months and nine months ended September 30,2005, and for the period from January 1, 2006 through March 31, 2006, areapproximately $494.7 million, $898.0 million and $275.4 million,respectively.  Under the provisions ofthe consensus, retroactive restatement of buy/sell transactions reported inprior periods was not permitted.

*Three Months Ended September 30, 2006 Compared withThree Months Ended September 30, 2005*

Sales of petroleum products increased $73.8 millionfor the three months ended September 30, 2006, compared with the three monthsended September 30, 2005.  Purchases ofpetroleum products increased $63.3 million for the three months ended September30, 2006, compared with the three months ended September 30, 2005.  Operating income increased $14.2 million forthe three months ended September 30, 2006, compared with the three months endedSeptember 30, 2005.  The increases insales and purchases were primarily as a result of an increase in the price ofcrude oil and increased volumes marketed, partially offset by the effects ofthe adoption of EITF 04-13, which reduced each of revenues and purchases ofpetroleum products by $460.7 million for the three months ended September 30,2006.  The average NYMEX price of crudeoil was $70.54 per barrel for the three months ended September 30, 2006,compared with $63.31 per barrel for the three months ended September 30,2005.  The increase in the average priceof crude oil and decreased costs and expenses discussed below, partially offsetby increased purchases of petroleum products were the primary factors resultingin an increase in operating income. Crude oil marketing margin increased $6.9 million primarily due tofavorable market conditions and increased volumes marketed and unrealizedlosses in the 2005 period of $1.2 million related to marking crude oil gradeand location swap contracts to current market value, partially offset byincreased transportation costs.  Crudeoil transportation revenues increased $2.7 million primarily due to increasedtransportation revenues on the Red River system, the South Texas system and theBasin system primarily related to movements on higher tariff segments,increased tariffs and revenues from systems acquired during 2005 and increasesdue to organic growth projects, partially offset by decreases in transportationvolumes on lower tariff segments of our Red River system and lower third-partytransportation volumes.  Lubrication oilsales margin increased $0.3 million due to increased fuel and lubrication oilvolumes and higher margins per gallon on sales of lubrication oils.  Crude oil terminaling revenues increased $0.1million as a result of increased pumpover volumes at Midland, Texas, partiallyoffset by decreased pumpover volumes at Cushing, Oklahoma and a lower averagetariff per barrel.

Other operating revenues decreased $0.2 million forthe three months ended September 30, 2006, compared with the three months endedSeptember 30, 2005, primarily due to lower revenues from documentation andother services to support customers’ trading activity at Midland and Cushing inthe third quarter of 2006.

Costs and expenses, excluding expenses associated withpurchases of crude oil and lubrication oil, decreased $4.3 million for thethree months ended September 30, 2006, compared with the three months endedSeptember 30, 2005.  Depreciation andamortization expense decreased $2.8 million primarily as a result of $2.6million of asset impairments in the prior year period.  Operating expenses decreased $1.2 millionfrom the prior year period primarily due to a $0.5 million decrease in pipelineoperating and maintenance expense, a $0.4 million increase in productmeasurement gains and a $0.4 million decrease in pipeline operatingexpense.  General and administrativeexpenses decreased $0.3 million from the prior year period primarily due toreductions in labor and benefits expense related to plan amendments in theprior year period (see Note 12 in the Notes to the Consolidated FinancialStatements).  Taxes – other than incometaxes decreased $0.3 million from the prior year period primarily due toreductions in property tax accruals, partially offset by a higher propertyasset base in 2006.  Operating fuel andpower increased $0.3 million primarily as a result of higher power rates in the2006 period.

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Equity earnings from our investment in Seaway decreased $2.4 millionfor the three months ended September 30, 2006, compared with the three monthsended September 30, 2005.** **Our equity earnings in Seaway were reduced in part by a decrease in ourparticipation ratio in the revenue and expense of Seaway.  Our sharing ratio for 2005 was 60%, while forthe full year of 2006, it is 47% of the revenue and expense of Seaway (see Note8 in the Notes to the Consolidated Financial Statements).  Equityearnings from our investment in Seaway also decreased due to decreasedtransportation volumes and revenues on the long-haul system primarily attributableto higher transportation demand in the prior year period as a result ofHurricanes Katrina and Rita and due to refinery turnarounds in the currentperiod, partially offset by higher operating expenses in the prior year periodrelated to pipeline integrity costs for the corrective measures taken for thepipeline release in May 2005 and higher operating fuel and power costs relatingto the use of a drag reducing agent and higher power rates in the prior yearperiod.  Long-haul volumes on Seawayaveraged 239,000 barrels per day during the three months ended September 30,2006, compared with 296,000 barrels per day during the three months endedSeptember 30, 2005.

After Seaway’s pipelinerelease in May 2005, the maximum operating pressure on the pipeline system wasreduced by 20% until the cause of the failure was determined.  Corrective measures were implemented upon therelease in 2005 and were completed during the second quarter of 2006.  Seaway operated at reduced maximum pressurethrough May 2006.  On June 1, 2006,Seaway’s operating pressure was increased to 100%.  As a result of operating at reduced maximumpressure, during the third quarter of 2005, we used a drag reducing agent toincrease the flow of product through the pipeline system during the period whenoperating pressures were reduced.  Thedrag reducing agent allowed us to maintain the higher volumes transported, butalso increased our operating costs.  Thereduced pressure did not have a material adverse effect on our financialposition, results of operations or cash flows (see Note 14 in the Notes to theConsolidated Financial Statements).

Other income – netincreased $0.2 million for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2005, due to higher interest incomeearned on cash investments and other investing activities.

*Nine Months Ended September 30, 2006 Compared withNine Months Ended September 30, 2005*

Sales of petroleum products increased $1,401.7 millionfor the nine months ended September 30, 2006, compared with the nine monthsended September 30, 2005.  Purchases ofpetroleum products increased $1,367.8 million for the nine months ended September30, 2006, compared with the nine months ended September 30, 2005.  Operating income increased $30.9 million forthe nine months ended September 30, 2006, compared with the nine months endedSeptember 30, 2005.  The increases insales and purchases were primarily a result of an increase in the price ofcrude oil and increased volumes marketed, partially offset by the effects ofthe adoption of EITF 04-13, which reduced each of revenues and purchases ofpetroleum products by $774.4 million for the nine months ended September 30,2006.  The average NYMEX price of crudeoil was $68.25 per barrel for the nine months ended September 30, 2006,compared with $55.52 per barrel for the nine months ended September 30,2005.  The increase in the average priceof crude oil, partially offset by increased purchases and costs and expensesdiscussed below, were the primary factors resulting in an increase in operatingincome.  Crude oil marketing marginincreased $26.3 million, primarily due to favorable market conditions andincreased volumes marketed and a decrease in unrealized losses compared withthe 2005 period of $0.3 million relating to marking crude oil grade andlocation swap contracts to current market value, partially offset by increasedtransportation costs.  Crude oiltransportation revenues increased $6.0 million primarily due to higher revenueson our Red River system related to movements on higher tariff segments andrevenues from acquisitions in 2005 and increased transportation volumes andrevenues on our South Texas system and West Texas systems, partially offset bydecreases in transportation volumes on lower tariff segments of our Basin andRed River systems.  Crude oil terminalingrevenues increased $1.4 million as a result of increased pumpover volumes atMidland, Texas and Cushing, Oklahoma. Lubrication oil sales margin increased $1.0 million due to increasedfuel and lubrication oil volumes and higher margins per gallon on sales oflubrication oils.

Other operating revenues decreased $0.5 million forthe nine months ended September 30, 2006, compared with the nine months endedSeptember 30, 2005, primarily due to a $1.4 million favorable settlement ofinventory 

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imbalances in thefirst quarter of 2005 and lower revenues from documentation and other servicesto support customers’ trading activity at Midland and Cushing in the first ninemonths of 2006.

Costs and expenses,excluding expenses associated with purchases of crude oil and lubrication oil,increased $3.3 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005. Operating expenses increased $3.7 million from the prior year period,primarily due to a $2.5 million increase in pipeline operating and maintenanceexpense, $0.9 million of higher insurance premiums, a $0.6 million increase asa result of product measurement losses and higher crude oil prices, a $0.6million increase in environmental assessment and remediation costs and $0.4million in severance expense as a result of the migration to a shared servicesenvironment with EPCO, partially offset by a $0.9 million decrease in labor andbenefits expense related to vesting provisions in certain of our compensationplans in the prior year period as a result of changes in ownership of ourGeneral Partner and a $0.3 million decrease in costs associated with ourintegrity management program.  Operatingfuel and power increased $1.8 million primarily as a result of increased powerrates in the 2006 period, partially offset by lower transportationvolumes.  General and administrativeexpenses increased $0.7 million from the prior year period primarily due to$0.4 million in severance expense, an increase in executive compensationexpense and an increase in consulting and contract services.  Taxes – other than income taxes increased $0.3million due to increases in property tax accruals and a higher property assetbase in 2006.  Depreciation andamortization expense decreased $3.2 million primarily due to $2.6 million ofasset impairments and asset retirements during the prior year period.

Equity earnings from our investment in Seawaydecreased $9.1 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005. Our sharing ratio for 2005 was 60%,while for the full year of 2006, it is 47% of the revenue and expense of Seaway(see Note 8 in the Notes to the Consolidated Financial Statements).  Equityearnings from our investment in Seaway also decreased due to higheroperating, general and administrative expenses related to pipeline integritycosts for the corrective measures taken for the pipeline release in May 2005,increased environmental remediation and assessment costs, higher operating fueland power costs relating to the use of a drag reducing agent and higher powerrates, a favorable settlement in thefirst quarter of 2005 with a former owner of Seaway’s crude oil assetsregarding inventory imbalances that were not acquired by us and decreasedtransportation volumes.  Long-haulvolumes on Seaway averaged 247,000 barrels per day during the nine months endedSeptember 30, 2006, compared with 250,000 barrels per day during the ninemonths ended September 30, 2005.

Other income – net increased $0.5 million for the ninemonths ended September 30, 2006, compared with the nine months ended September30, 2005, due to higher interest income earned on cash investments and otherinvesting activities.

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**MidstreamSegment**

The following tableprovides financial information for the Midstream Segment for the three monthsand nine months ended September 30, 2006 and 2005 (in thousands):
| ** **                            | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** | **Nine Months Ended** | ** ** | ** **   | ** ** |
|---------------------------------------|------------|----------------------------------|------------|--------------|------------|---------------------------------|------------|--------------|------------|
| ** **                            | ** ** | **September 30,**           | ** ** | **Increase** | ** ** | **September 30,**          | ** ** | **Increase** | ** ** |
| ** **                            | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)**                  | ** ** | **2006**     | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| Revenues:                             |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Sales of  petroleum products          |       | $                                | 4,990      |         | $          | —                          |       | $            | 4,990      |   | $ | 18,766 |   | $ | — |   | $ | 18,766 |   |
| Gathering –  Natural Gas (1)     |       | 25,022                           |       | 38,833       |       | (13,811                         | )          | 107,856      |       | 112,349 |   | (4,493 | ) |
| Transportation –  NGLs           |       | 10,971                           |       | 11,829       |       | (858                            | )          | 32,362       |       | 33,435 |   | (1,073 | ) |
| Other                                 |       | 2,912                            |       | 2,979        |       | (67                             | )          | 11,633       |       | 9,697 |   | 1,936 |   |
| Total operating  revenues             |       | 43,895                           |       | 53,641       |       | (9,746                          | )          | 170,617      |       | 155,481 |   | 15,136 |   |
|                                  |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Costs and expenses (1):               |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Purchases of  petroleum products      |       | 4,323                            |       | —       |       | 4,323                           |       | 17,272       |       | — |   | 17,272 |   |
| Operating  expense                    |       | 8,529                            |       | 9,415        |       | (886                            | )          | 33,122       |       | 25,625 |   | 7,497 |   |
| Operating fuel  and power             |       | 3,407                            |       | 3,121        |       | 286                             |       | 9,109        |       | 7,658 |   | 1,451 |   |
| General and  administrative expense   |       | 2,079                            |       | 2,144        |       | (65                             | )          | 6,966        |       | 5,011 |   | 1,955 |   |
| Depreciation and  amortization        |       | 11,838                           |       | 14,238       |       | (2,400                          | )          | 42,076       |       | 39,473 |   | 2,603 |   |
| Taxes – other  than income taxes |       | 921                              |       | 1,167        |       | (246                            | )          | 3,543        |       | 2,992 |   | 551 |   |
| Gains on sales  of assets             |       | —                           |       | —       |       | —                          |       | (1,371       | )          | (407 | ) | (964 | ) |
| Total costs and  expenses             |       | 31,097                           |       | 30,085       |       | 1,012                           |       | 110,717      |       | 80,352 |   | 30,365 |   |
| Operating income                      |       | 12,798                           |       | 23,556       |       | (10,758                         | )          | 59,900       |       | 75,129 |   | (15,229 | ) |
| Equity earnings  (1)                  |       | 11,563                           |       | —       |       | 11,563                          |       | 11,563       |       | — |   | 11,563 |   |
| Other income –  net              |       | 430                              |       | 75           |       | 355                             |       | 550          |       | 177 |   | 373 |   |
|                                  |       |                             |       |         |       |                            |       |         |       |   |   |   |   |
| Earnings before  interest             |       | $                                | 24,791     |         | $          | 23,631                          |       | $            | 1,160      |   | $ | 72,013 |   | $ | 75,306 |   | $ | (3,293 | ) |

 

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(1)   Effective August 1, 2006, with the formationof a joint venture with Enterprise, Jonah was deconsolidated and operatingresults, including revenues and costs and expenses, after August 1, 2006 areincluded in equity earnings (see Note 8 in the Notes to the ConsolidatedFinancial Statements).

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The following table presents volume and average rate information forthe Midstream Segment for the three months and nine months ended September 30,2006 and 2005:
|                                                                   | ** ** | **Three Months Ended** | ** ** | **Percentage** | ** ** | **Nine Months Ended** | ** ** | **Percentage** | ** ** |
|-------------------------------------------------------------------|------------|----------------------------------|------------|----------------|------------|---------------------------------|------------|----------------|------------|
| ** **                                                        | ** ** | **September 30,**           | ** ** | **Increase**   | ** ** | **September 30,**          | ** ** | **Increase**   | ** ** |
| ** **                                                        | ** ** | **2006**                         | ** ** | **2005**       | ** ** | **(Decrease)**                  | ** ** | **2006**       | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| Gathering –  Natural Gas – Jonah (1):                   |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Million cubic feet (“MMcf”)                             |       | 118,739                          |       | 105,993        |       | 12%                             |       | 338,755        |       | 302,388 |   | 12% |   |
| Billion British thermal units (“BBtu”)                  |       | 131,188                          |       | 117,006        |       | 12%                             |       | 374,164        |       | 333,823 |   | 12% |   |
| Average fee per Million British thermal unit  (“MMBtu”) |       | $                                | 0.204      |           | $          | 0.185                           |       | 10%            |       | $ | 0.206 |   | $ | 0.187 |   | 10% |   |
|                                                              |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Gathering –  Natural Gas – Val Verde:                   |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| MMcf                                                              |       | 45,003                           |       | 46,265         |       | (3)%                            |       | 137,291        |       | 131,646 |   | 4% |   |
| BBtu                                                              |       | 39,851                           |       | 40,816         |       | (3)%                            |       | 121,458        |       | 115,685 |   | 5% |   |
| Average fee per MMBtu                                             |       | $                                | 0.408      |           | $          | 0.423                           |       | (3)%           |       | $ | 0.405 |   | $ | 0.430 |   | (6)% |   |
|                                                              |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Transportation –  NGLs:                                      |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Thousand barrels                                                  |       | 18,008                           |       | 16,332         |       | 10%                             |       | 51,542         |       | 45,708 |   | 13% |   |
| Average rate per barrel                                           |       | $                                | 0.609      |           | $          | 0.724                           |       | (16)%          |       | $ | 0.628 |   | $ | 0.731 |   | (14)% |   |
|                                                              |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Natural Gas  Sales:                                               |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| BBtu                                                              |       | 3,537                            |       | —         |       | —                          |       | 6,164          |       | — |   | — |   |
| Average fee per MMBtu                                             |       | $                                | 5.29       |           | $          | —                          |       | —         |       | $ | 5.27 |   | $ | — |   | — |   |
|                                                              |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Fractionation –  NGLs:                                       |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Thousand barrels                                                  |       | 1,034                            |       | 1,068          |       | (3)%                            |       | 3,311          |       | 3,294 |   | 1% |   |
| Average rate per barrel                                           |       | $                                | 1.633      |           | $          | 1.768                           |       | (8)%           |       | $ | 1.655 |   | $ | 1.744 |   | (5)% |   |
|                                                              |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Sales –  Condensate (1):                                     |       |                             |       |           |       |                            |       |           |       |   |   |   |   |
| Thousand barrels                                                  |       | 2.7                              |       | 3.4            |       | (20)%                           |       | 45.7           |       | 44.6 |   | 3% |   |
| Average rate per  barrel                                          |       | $                                | 70.37      |           | $          | 55.60                           |       | 27%            |       | $ | 65.81 |   | $ | 50.21 |   | 31% |   |

 

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(1)   Effective August 1, 2006, with the formationof a joint venture with Enterprise, Jonah was deconsolidated and operatingresults after August 1, 2006 are included in equity earnings (see Note 8 in theNotes to the Consolidated Financial Statements).  However, the table includes Jonah’s volumeand average rate information for the full three and nine month periods endedSeptember 30, 2006 and 2005.

EffectiveAugust 1, 2006, with the formation of a joint venture with Enterprise, Jonah,the partnership through which we owned the Jonah system, was deconsolidated andhas been subsequently accounted for as an equity investment.  Through July 31, 2006, Jonah’s operatingresults were fully consolidated in the Midstream Segment operatingresults.  Beginning August 1, 2006, Jonahhas been accounted for as an equity investment and operating results for Jonahfor the period August 1, 2006 through September 30, 2006, are reported asequity earnings.  For the period fromAugust 1, 2006 through September 30, 2006, our sharing in the revenues andexpenses of Jonah was 100% (see “– Jonah Joint Venture” above for furtherinformation).

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*Three Months Ended September 30, 2006 Compared withThree Months Ended September 30, 2005*

Revenues from the gathering of natural gas decreased$13.8 million for the three months ended September 30, 2006, compared with thethree months ended September 30, 2005. Natural gas gathering revenues from the Jonah system decreased $14.2million due to the deconsolidation of Jonah on August 1, 2006, partially offsetby an increase of $1.4 million primarily due to the Phase IV expansion of theJonah system completed in February 2006, prior to deconsolidation.  The Phase IV expansion increased the systemcapacity of Jonah to 1.5 Bcf per day with the addition of 33,000 horsepower ofcompression and approximately 50 miles of pipeline.  Jonah’s gathering volumes averaged 1.3 Bcfper day for the three months ended September 30, 2006, compared with 1.15 Bcfper day for the three months ended September 30, 2005.  Jonah’s average natural gas gathering rateper MMBtu increased 10% primarily due to lower system wellhead pressures.  Jonah’s volumes gathered increased 12.7 Bcfas a result of the Phase IV expansion for the three months ended September 30,2006 as compared to the three months ended September 30, 2005.  Natural gas gathering revenues from the ValVerde system decreased $1.0 million and volumes gathered decreased 1.3 Bcf forthe three months ended September 30, 2006, primarily due to the natural declineof coal bed methane production and a decrease in the average natural gasgathering rate.  During the quarter endedSeptember 30, 2006, we received updated limited production estimates from someof the producers on the Val Verde system, which reduced the future productionforecast of coal bed methane, which in turn, could result in reduced futurerevenues from the Val Verde system.  Thisdecrease was partially offset by an increase in volumes from a natural gasconnection on the Val Verde system and increased volumes from temporary interconnectswith third party gatherers in the third quarter of 2006.  Val Verde’s average natural gas gatheringrate per MMBtu decreased 3% primarily due to contracts entered into relating tothe new connections, which have lower rates than the existing Val Verde system’saverage rates.

In May 2006, we began toaggregate purchases of wellhead gas on Jonah and re-sell the aggregatedquantities at key Jonah delivery points in order to facilitate throughput onJonah.  The purchases and sales aregenerally contracted to occur in the same month to minimize price risk.  During the second quarter of 2006, gaspurchase and sales contracts were finalized and executed and the marketing ofgas on the Jonah system began.  Salesfrom petroleum products relating to the natural gas marketing activities were$5.0 million and purchases of petroleum products were $4.3 million for theperiod from July 1, 2006 through July 31, 2006. Effective August 1, 2006, with the deconsolidation of Jonah, sales andpurchases of natural gas are reported in equity earnings.

Revenues from the transportation of NGLs decreased$0.9 million for the three months ended September 30, 2006, compared with thethree months ended September 30, 2005, primarily due to a decrease in theaverage NGL transportation rate per barrel as a result of increased short-haulmovements on the Chaparral Pipeline and a lower average rate per barrel on thePanola Pipeline.  During the 2006 period,volumes of NGLs transported increased due to increases on the Chaparral, Panola,Wilcox and Dean Pipelines, partially offset by decreased volumes transported onthe San Jacinto Pipeline.

Other operating revenues decreased $0.1 million forthe three months ended September 30, 2006, compared with the three months endedSeptember 30, 2005.  Val Verde’s otheroperating revenue decreased $0.4 million primarily due to a decrease involumes, Jonah’s other operating revenues decreased $0.1 million primarily as aresult of the deconsolidation of Jonah and other miscellaneous operatingrevenues decreased $0.2 million.  Thesedecreases were offset by a $0.6 million increase on the Panola and ChaparralPipelines primarily resulting from new pipeline capacity leases.

Costs and expenses (excluding purchases of petroleumproducts) decreased $3.3 million for the three months ended September 30, 2006,compared with the three months ended September 30, 2005.  Depreciation and amortization expensedecreased $2.4 million primarily due to a $2.7 million decrease on Jonah as aresult of its deconsolidation and a $0.5 million decrease in amortizationexpense on Val Verde as a result of lower volumes on contracts included in theintangible assets, partially offset by a $0.5 million increase in amortizationexpense on Val Verde’s intangible assets as a result of a decrease in theestimated life of intangible assets under the units-of-production method in the2006 period which increased amortization expense and a $0.2 million increase onVal 

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Verde primarily due to accretion expense onconditional asset retirement obligations (as discussed below).  Based on the reduction in some producers’limited production estimates in the third quarter of 2006, we revised theunits-of-production calculation for Val Verde’s gathering agreements intangibleassets, which increased amortization expense in the Midstream Segment byapproximately $0.2 million per month (see Note 2 in the Notes to theConsolidated Financial Statements).  Thisreduction in future production forecasts could reduce future revenues oncertain gathering contracts of the Val Verde system.  Further revisions to these estimates mayoccur as additional production information is made available to us.  Operating expenses decreased $0.9 millionprimarily due to a $2.9 million decrease relating to the deconsolidation ofJonah, partially offset by a $1.4 million increase related to imbalancevaluations and a $0.7 million increase in other pipeline operating andmaintenance expense.  Taxes – other thanincome taxes decreased $0.2 million due to actual property taxes being lowerthan previously estimated, partially offset by a higher property asset base inthe 2006 period.  General andadministrative expenses decreased $0.1 million primarily due to a decrease inconsulting and contract services, partially offset by increased expensesrelating to our special unitholder meeting to consider EPCO’s proposals toamend our Partnership Agreement and issue Units to our General Partner, as wellas other proposals.  Operating fuel andpower increased $0.3 million primarily due to higher transportation volumes andpower rates.

Equity earnings of $11.6million were from our ownership interest in the Jonah joint venture with anaffiliate of Enterprise, which was formed effective August 1, 2006.  Beginning August 1, 2006, revenues and costsand expenses of Jonah have been included in equity earnings based upon ourownership interest in Jonah.  Prior toAugust 1, 2006, Jonah was wholly-owned, and its revenues and costs and expenseswere included in the individual revenues and costs and expenses lineitems.  For the period from August 1,2006 through September 30, 2006, our sharing in the revenues and costs andexpenses of Jonah was 100%.  If therevenues and costs and expenses from Jonah for the three months ended September30, 2006 and 2005, had been accounted for under the same method in bothperiods, operating results from Jonah would have increased $3.8 million in the2006 period, compared with the prior year period, primarily due to increasedvolumes generated from completion of Phase IV of the Jonah expansion project.

Other income – netincreased $0.4 million for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2006, due to higher interest incomeearned on cash investments and other investing activities.

*Nine Months Ended September 30, 2006 Compared withNine Months Ended September 30, 2005*

Revenues from the gathering of natural gas decreased$4.5 million for the nine months ended September 30, 2006, compared with thenine months ended September 30, 2005. Natural gas gathering revenues from the Jonah system decreased $14.3million due to the deconsolidation of Jonah on August 1, 2006, partially offsetby an increase of $10.4 million primarily due to the Phase IV expansion of theJonah system completed in February 2006, prior to deconsolidation.  Jonah’s gathering volumes averaged 1.2 Bcfper day for the nine months ended September 30, 2006, compared with 1.1 Bcf perday for the nine months ended September 30, 2005.  Jonah’s average natural gas gathering rateper MMBtu increased 10% primarily due to lower system wellhead pressures.  Jonah’s volumes gathered increased 36.4 Bcfprimarily as a result of the Phase IV expansion for the nine months endedSeptember 30, 2006, compared to the nine months ended September 30, 2005.  Natural gas gathering revenues from the ValVerde system decreased $0.6 million for the nine months ended September 30,2006, primarily due to the natural decline of coal bed methane production.  Val Verde’s volumes gathered increased 5.6Bcf primarily due to increased volumes from a natural gas connection on the ValVerde system.  Val Verde’s averagenatural gas gathering rate per MMBtu decreased 6% primarily due to contractsentered into relating to the new connections, which have lower rates than theexisting Val Verde system’s average rates.

Sales from petroleumproducts relating to the natural gas marketing activities were $18.8 millionand purchases of petroleum products were $17.3 million for the period fromJanuary 1, 2006, through July 31, 2006.  Effective August 1, 2006, with the deconsolidation of Jonah, sales andpurchases of natural gas are reported in equity earnings.

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Revenues from the transportation of NGLs decreased$1.1 million for the nine months ended September 30, 2006, compared with thenine months ended September 30, 2005, due to a decrease in the average NGLtransportation rate per barrel as a result of increased short-haul movements onthe Chaparral Pipeline and a lower average rate per barrel on the PanolaPipeline.  During the 2006 period, volumesof NGLs transported increased due to increases on the Chaparral, Panola andDean Pipelines, partially offset by decreased volumes transported on the WilcoxPipeline.

Other operating revenues increased $1.9 million forthe nine months ended September 30, 2006, compared with the nine months endedSeptember 30, 2005.  Other operatingrevenues increased $1.1 million on the Panola Pipeline and $0.8 million on theChaparral Pipeline primarily due to new pipeline capacity leases.  Other operating revenues on Jonah increased$0.7 million primarily due to higher condensate sales.  These increases were partially offset by a$0.5 million decrease on Val Verde primarily due to a decrease in volumes.

Costs and expenses (excluding purchases of petroleumproducts) increased $13.1 million for the nine months ended September 30, 2006,compared with the nine months ended September 30, 2005.  Operating expenses increased $7.5 millionprimarily due to a $3.8 million increase related to imbalance valuations, a$3.0 million increase in expense as a result of the migration to a sharedservices environment with EPCO and a $0.5 million increase in other pipelineoperating and maintenance expense. Depreciation and amortization expense increased $2.6 million primarilydue to a $2.9 million increase in amortization expense on Val Verde as a resultof a decrease in the estimated life of intangible assets under theunits-of-production method which increased amortization expense, a $1.5 millionincrease in depreciation expense on Jonah as a result of assets placed intoservice from the Phase IV expansion, a $0.4 million increase on the NGLpipelines as a result of assets placed into service and a $0.2 million increaseon Val Verde due to accretion expense on conditional asset retirementobligations (as discussed below), partially offset by a $1.2 million decreasein amortization expense due to the deconsolidation of Jonah and a $1.0 milliondecrease in amortization expense on Val Verde as a result of lower volumes oncontracts included in the intangible assets in the 2006 period.  General and administrative expenses increased$2.0 million primarily due to an increase in consulting and contract servicesand supplies expense and $0.6 million in severance expense as a result of themigration to a shared services environment with EPCO.  Operating fuel and power increased $1.5million primarily due to higher transportation volumes and power rates.  Taxes – other than income taxes increased$0.6 million due to actual property taxes being higher than previouslyestimated and a higher property asset base in the 2006 period.  During the nine months ended September 30,2006 and 2005, gains of $1.4 million and $0.4 million, respectively, wererecognized on the sales of various equipment at Val Verde.

Equity earnings of $11.6million were from our ownership interest in the Jonah joint venture with anaffiliate of Enterprise, which was formed effective August 1, 2006.  Beginning August 1, 2006, revenues and costsand expenses of Jonah are now included in equity earnings based upon ourownership interest in Jonah.  Prior toAugust 1, 2006, Jonah was wholly-owned, and its revenues and costs and expenseswere included in the individual revenues and costs and expenses lineitems.  For the period from August 1,2006 through September 30, 2006, our sharing in the revenues and costs andexpenses of Jonah was 100%.  If therevenues and costs and expenses from Jonah for the nine months ended September30, 2006 and 2005, had been accounted for under the same method in bothperiods, operating results from Jonah would have increased $25.2 million in the2006 period, compared with the prior year period, primarily due to increasedvolumes generated from completion of Phase IV of the Jonah expansion project.

Other income – netincreased $0.4 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2006, due to higher interest incomeearned on cash investments and other investing activities.

*Asset Retirement Obligations*

During the third quarter of 2006, we recorded $0.3million of expense included in depreciation and amortization expense, relatedto conditional asset retirement obligations. Additionally, we have recorded a $0.7 

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million liability, which represents the fair value, ofthe conditional asset retirement obligations related to the retirement of ourVal Verde gathering system.  During thethird quarter of 2006, we assigned probabilities for settlement dates andsettlement methods for use in an expected present value measurement of fairvalue and recorded asset retirement obligations.

*DiscontinuedOperations*

On March 31, 2006, we sold our ownership interest inthe Pioneer silica gel natural gas processing plant located near Opal, Wyoming,together with Jonah’s rights to process natural gas originating from the Jonahand Pinedale fields, located in southwest Wyoming, to an affiliate ofEnterprise for $38.0 million in cash. The Pioneer plant was not an integral part of our Midstream Segmentoperations, and natural gas processing is not a core business.  We have no continuing involvement in theoperations or results of this plant. This transaction was reviewed and recommended for approval by the Auditand Conflicts Committee of the Board of Directors of our General Partner and afairness opinion was rendered by an independent third-party.  The sales proceeds were used to fund organicgrowth projects, retire debt and for other general partnership purposes.  The carrying value of the Pioneer plant atMarch 31, 2006, prior to the sale, was $19.7 million.  Costs associated with the completion of thetransaction were approximately $0.4 million.

Condensed statements of income for the Pioneer plant,which is classified as discontinued operations, for the three months and ninemonths ended September 30, 2006 and 2005, are presented below (in thousands):
| ** **                            | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|---------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                            | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                            | ** ** | **2006**                         | ** ** | **2005**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                  |       |                             |       |                            |       |   |   |   |   |
| Sales of  petroleum products          |       | $                                | —     |                            | $          | 2,880 |   | $ | 3,828 |   | $ | 7,337 |   |
| Other                                 |       | —                           |       | 789                             |       | 932 |   | 2,141 |   |
| Total operating revenues              |       | —                           |       | 3,669                           |       | 4,760 |   | 9,478 |   |
| Purchases of  petroleum products      |       | —                           |       | 2,585                           |       | 3,000 |   | 5,761 |   |
| Operating  expense                    |       | —                           |       | 205                             |       | 182 |   | 501 |   |
| Depreciation and  amortization        |       | —                           |       | 153                             |       | 51 |   | 459 |   |
| Taxes – other  than income taxes |       | —                           |       | 34                              |       | 30 |   | 95 |   |
| Total costs and expenses              |       | —                           |       | 2,977                           |       | 3,263 |   | 6,816 |   |
| Income from  discontinued operations  |       | $                                | —     |                            | $          | 692 |   | $ | 1,497 |   | $ | 2,662 |   |

 

Sales of petroleumproducts less purchases of petroleum products resulting from the processingactivities at the Jonah Pioneer plant decreased $0.7 million for the ninemonths ended September 30, 2006, compared with the nine months ended September30, 2005, primarily due to the sale of the Pioneer plant on March 31, 2006,partially offset by increased NGL prices. The Pioneer gas processing plant was completed during the first quarterof 2004, as a part of Jonah’s Phase III expansion to increase the processingcapacity in southwestern Wyoming. Pioneer’s processing agreements allowed the producers to elect annuallywhether to be charged under a fee-based arrangement or a fee plus keep-wholearrangement.  Under the fee-basedelection, Jonah received a fee for its processing services.  Under the fee plus keep-whole election, Jonahreceived a lower fee for its processing services, retained and sold the NGLsextracted during the process and delivered to producers the residue gasequivalent in energy to the natural gas received from the producers.  Jonah sold the NGLs it retained and purchasedgas to replace the equivalent energy removed in the liquids.   For the 2005 and 2006 periods, the producerselected the fee plus keep-whole arrangement.

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**Interest Expense and CapitalizedInterest**

*Three Months Ended September 30, 2006 Compared withThree Months Ended September 30, 2005*

Interest expenseincreased $2.9 million for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2005, primarily due to higher shortterm floating interest rates on our revolving credit facility, partially offsetby lower outstanding borrowings during the 2006 period.

Capitalized interestdecreased $0.6 million for the three months ended September 30, 2006, comparedwith the three months ended September 30, 2005, due to lower constructionwork-in-progress balances in 2006 as compared to the 2005 period.

*Nine Months Ended September 30, 2006 Compared withNine Months Ended September 30, 2005*

Interest expenseincreased $6.4 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005, primarily due to higheroutstanding borrowings and higher short term floating interest rates on ourrevolving credit facility, partially offset by reductions in interest expenseof $2.5 million during 2006 related to our interest rate swaps and $2.0 millionof increased interest expense in the 2005 period related to the termination ofa treasury lock (see Note 3 in the Notes to the Consolidated FinancialStatements).

Capitalized interestincreased $3.6 million for the nine months ended September 30, 2006, comparedwith the nine months ended September 30, 2005, due to higher constructionwork-in-progress balances in 2006 as compared to the 2005 period.

**Deferred Income Tax Expense –Texas Margin Tax**

In May 2006, the State of Texas enacted a new businesstax (the “Texas Margin Tax”) that replaces its existing franchise tax.  In general, legal entities that do businessin Texas are subject to the Texas Margin Tax. Limited partnerships, limited liability companies, corporations, limitedliability partnerships and joint ventures are examples of the types of entitiesthat are subject to the Texas Margin Tax. As a result of the change in tax law, our tax status in the state ofTexas changed from nontaxable to taxable. The Texas Margin Tax is considered an income tax for purposes ofadjustments to deferred tax liability, as the tax is determined by applying atax rate to a base that considers both revenues and expenses.  Our deferred income tax expense for statetaxes relates only to Texas Margin Tax obligations.  The Texas Margin Tax becomes effective forfranchise tax reports due on or after January 1, 2008.  The Texas Margin Tax due in 2008 will bebased on revenues earned during the 2007 fiscal year.

The Texas Margin Tax is assessed at 1% ofTexas-sourced taxable margin measured by the ratio of gross receipts frombusiness done in Texas to gross receipts from business done everywhere.  The taxable margin is computed as the lesserof (i) 70% of total revenue or (ii) total revenue less (a) cost of goods soldor (b) compensation.  The deferred taxliability shown on our consolidated balance sheet reflects the net tax effectof temporary differences related to items such as property, plant andequipment; therefore, the deferred tax liability is classified asnoncurrent.  The Texas Margin Tax iscalculated, paid and filed at an affiliated unitary group level.  Generally, an affiliated group is made up ofone or more entities in which a controlling interest of at least 80% is ownedby a common owner or owners. Generally, a business is unitary if it ischaracterized by a sharing or exchange of value between members of the group,and a synergy and mutual benefit all of the members of the group achieved byworking together.

Since the Texas Margin Tax is determined by applying atax rate to a base that considers both revenues and expenses, it hascharacteristics of an income tax. Accordingly, we determined the Texas Margin Tax should be accounted foras an income tax in accordance with the provisions of Statement of FinancialAccounting Standards (“SFAS”) No. 109, *Accounting for IncomeTaxes*.  The base used tocompute the Texas Margin Tax affects book-tax differences.  All effects of a tax law change are accountedfor in the period of the law’s enactment. A change in tax status that results from a change in tax law isrecognized on the enactment date and the effect of recognizing a 

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deferred tax liability or asset is included in incomefrom continuing operations.  Therefore,we have calculated and recorded an estimated deferred tax liability ofapproximately $0.7 million using the enacted tax rate expected to apply totaxable income in the periods in which the deferred tax liability is expectedto be realized or settled.  The non-cashoffsetting charge is shown on our unaudited consolidated statements of incomeas deferred income tax expense for the nine months ended September 30, 2006.

The constitutionality of the Texas Margin Tax is beingquestioned.  The Texas Comptroller hasrequested a formal opinion from the Texas Attorney General on whether the TexasMargin Tax is an impermissible income tax that violates the Texasconstitution.  The Texas constitutionrequires voter approval of any tax imposed on the net income of naturalpersons, including a person’s share of partnership unincorporated associationincome; such approval was not obtained for the Texas Margin Tax.  The Comptroller has requested that theAttorney General determine whether the direct imposition of the Texas MarginTax on partnerships without voter approval violates this constitutionalrequirement.   The Attorney General’sdecision is not expected until late 2006 or early 2007.  If the Texas Margin Tax is ultimatelychallenged in court, the legislation enacting the Texas Margin Tax gives theTexas Supreme Court jurisdiction over the constitutional challenge and allowsthe Court to grant injunctive or declaratory relief.  The Court would have 120 days from the datethe challenge is filed to make a ruling.

**Financial Condition and Liquidity**

Cash generated from operations, credit facilities anddebt and equity offerings are our primary sources of liquidity.  At September 30, 2006, and December 31, 2005,we had working capital deficits of $69.7 million and $38.1 million, respectively.  At September 30, 2006, we had approximately$330.9 million in available borrowing capacity under our revolving creditfacility to cover any working capital needs. Cash flows for the nine months ended September 30, 2006 and 2005 were asfollows (in millions):
|                              | ** ** | **Nine Months Ended** | ** ** |
|------------------------------|------------|---------------------------------|------------|
| ** **                   | ** ** | **September 30,**          | ** ** |
| ** **                   | ** ** | **2006**                        | ** ** | **2005** | ** ** |
| ** **                   | ** ** | ** **                      | ** ** | ** ** | ** ** |
| Cash provided by  (used in): |       |                            |       |   |   |
| Operating activities         |       | $                               | 232.5      |   | $ | 49.1 |   |
| Investing activities         |       | (174.6                          | )          | (267.5 | ) |
| Financing  activities        |       | (58.0                           | )          | 202.1 |   |
|                              |            |                                 |            |  |  |  |  |

 

*OperatingActivities*

Net cash from operating activities for the nine monthsended September 30, 2006 and 2005, was comprised of the following (inmillions):
|                                                       | ** ** | **Nine Months Ended** | ** ** |
|-------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                            | ** ** | **September 30,**          | ** ** |
| ** **                                            | ** ** | **2006**                        | ** ** | **2005** | ** ** |
| ** **                                            | ** ** | ** **                      | ** ** | ** ** | ** ** |
| Net income                                            |       | $                               | 145.5      |   | $ | 117.9 |   |
| Income from  discontinued operations                  |       | (19.4                           | )          | (2.7 | ) |
| Deferred income  tax expense                          |       | 0.7                             |       | — |   |
| Depreciation and  amortization                        |       | 83.7                            |       | 82.6 |   |
| Earnings in  equity investments                       |       | (15.2                           | )          | (16.6 | ) |
| Distributions  from equity investments                |       | 26.5                            |       | 28.2 |   |
| Gains on sales  of assets                             |       | (1.4                            | )          | (0.6 | ) |
| Non-cash portion  of interest expense                 |       | 1.2                             |       | 1.2 |   |
| Cash provided by  (used in) working capital and other |       | 9.4                             |       | (164.0 | ) |
| Net cash provided by continuing operating activities  |       | 231.0                           |       | 46.0 |   |
| Cash flows from  discontinued operations              |       | 1.5                             |       | 3.1 |   |
|                                                  |       |                            |       |   |   |
| Net cash from operating activities                    |       | $                               | 232.5      |   | $ | 49.1 |   |

 

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Net cash provided by operating activities increased$183.4 million for the nine months ended September 30, 2006, compared with thenine months ended September 30, 2005, primarily due to a decrease of $108.2million in crude oil inventory (as discussed below) and due to the timing ofcash disbursements and cash receipts for other working capital components,partially offset by a decrease of $1.7 million in distributions received fromour equity investments in Seaway and MB Storage.  For a discussion of changes in earningsbefore interest, depreciation and amortization expense, equity earnings andconsolidated interest expense – net, see Results of Operations for theDownstream Segment, Upstream Segment and Midstream Segment in Item 2.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operations.

Crude oil inventory decreased $108.2 million for thenine months ended September 30, 2006, compared with the nine months endedSeptember 30, 2005.  During the secondand third quarters of 2005, we purchased crude oil and simultaneously enteredinto offsetting sales contracts for physical delivery during the fourth quarterof 2005.  The purpose of these contractswas to lock in a margin on the crude oil while it was stored in ourfacilities.  These purchases of crude oilhad a negative impact on cash from operating activities (as discussed above)until the crude oil was delivered and payment was received from customers.

Net cash from operating activities for the nine monthsended September 30, 2006 and 2005, included interest payments, net of amountscapitalized, of $84.4 million and $78.5 million, respectively.  Excluding the effects of hedging activitiesand interest capitalized during the year ended December 31, 2006, we expectinterest payments on our fixed rate Senior Notes to be approximately $78.0million.  We expect to make theseinterest payments with cash flows from operating activities.

*InvestingActivities*

Cash flows used in investing activities totaled $174.6million for the nine months ended September 30, 2006, and were comprised of$125.7 million of capital expenditures, $65.4 million of cash contributions forour ownership interest in the Jonah joint venture with Enterprise for capitalexpenditures on its Phase V expansion, $11.0 million for the acquisition ofDownstream Segment assets, $5.6 million of cash paid for linefill on assetsowned,  $4.2 million of cashcontributions for TE Products’ ownership interest in MB Storage for capitalexpenditures and $2.5 million of cash contributions for TE Products’ ownershipinterest in Centennial for operating needs, partially offset by $39.8 millionin net cash proceeds from asset sales in our Midstream Segment, of which $38.0million related to cash proceeds received from the sale of the Pioneer plant onMarch 31, 2006.  Cash flows used ininvesting activities totaled $267.5 million for the nine months ended September30, 2005, and were comprised of $148.1 million of capital expenditures, $68.9million for the acquisition of Downstream Segment assets, $43.3 million for theacquisition of Upstream Segment assets, $5.1 million of cash paid for linefillon assets owned and $2.6 million of cash contributions for TE Products’ownership interest in MB Storage for capital expenditures, partially offset by$0.5 million in net cash proceeds from an asset sale in our Midstream Segment.

*FinancingActivities*

Cash flows used in financing activities totaled $58.0million for the nine months ended September 30, 2006, and were comprised of$206.2 million of distributions paid to unitholders and $46.9 million inrepayments, net of borrowings, on our revolving credit facility, partiallyoffset by $195.1 million of net proceeds received from the public issuance of5.8 million Units in July 2006.  Cashflows provided by financing activities totaled $202.1 million for the ninemonths ended September 30, 2005, and were comprised of $278.8 million of netproceeds received from the public issuance of 7.0 million Units in May and June2005 and $107.5 million in borrowings, net of repayments, on our revolvingcredit facility, partially offset by $184.2 million of distributions paid tounitholders.

We paid cash distributions of $206.2 million ($2.025per Unit) and $184.2 million ($2.00 per Unit) during each of the nine monthsended September 30, 2006 and 2005, respectively.  Additionally, we declared a cash distributionof $0.675 per Unit for the quarter ended September 30, 2006.  We paid the distribution of $72.4 million onNovember 7, 2006, to unitholders of record on October 31, 2006.

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InJuly 2006, we issued and sold in an underwritten public offering 5.0 millionUnits at a price to the public of $35.50 per Unit.  The proceeds from the offering, net ofunderwriting discount, totaled approximately $170.4 million.  On July 12, 2006, 750,000 additional Unitswere sold upon exercise of the underwriters’ over-allotment option granted inconnection with the offering.  Proceedsfrom the over-allotment sale, net of underwriting discount, totaled $25.6million.  The net proceeds from theoffering and the over-allotment were used to reduce indebtedness under ourRevolving Credit Facility.

**OtherConsiderations**

***Universal Shelf***

**We have filed withthe Securities and Exchange Commission a universal shelf registration statementthat, subject to agreement on terms at the time of use and appropriatesupplementation, allows us to issue, in one or more offerings, up to anaggregate of $2.0 billion of equity securities, debt securities or acombination thereof.  Taking into accountour May 2005 and July 2006 equity offerings, in which we issued $290.8 millionand $204.1 million of equity securities, respectively, we had approximately$1.5 billion remaining under this shelf registration, subject to customary marketingterms and conditions.**

*CreditFacilities*

We have in place a $700.0 million unsecured revolvingcredit facility, including the issuance of letters of credit (“Revolving CreditFacility”), which matures on December 13, 2011. Commitments under the credit facility may be increased up to a maximumof $850.0 million upon our request, subject to lender approval and thesatisfaction of certain other conditions. The interest rate is based, at our option, on either the lender’s baserate plus a spread, or LIBOR plus a spread in effect at the time of theborrowings.  Financial covenants in theRevolving Credit Facility require that we maintain a ratio of ConsolidatedFunded Debt to Pro Forma EBITDA (as defined and calculated in the facility) ofless than 4.75 to 1.00 (subject to adjustment for specified acquisitions) and aratio of EBITDA to Interest Expense (as defined and calculated in the facility)of at least 3.00 to 1.00, in each case with respect to specified twelve monthperiods.  Other restrictive covenants inthe Revolving Credit Facility limit our ability to, among other things, incuradditional indebtedness, make distributions in excess of Available Cash (seeNote 10 in the Notes to the Consolidated Financial Statements), incur liens,engage in specified transactions with affiliates and complete mergers,acquisitions and sales of assets.

On July 31, 2006, we amended our Revolving CreditFacility.  The primary revisions were asfollows:

·      The maturity date of thecredit facility was extended from December 13, 2010 to December 13, 2011.  Also under the terms of the amendment, we mayrequest up to two one-year extensions of the maturity date.  These extensions, if requested, will becomeeffective subject to lender approval and satisfaction of certain other conditions.

·      The amendment releases Jonahas a guarantor of the Revolving Credit Facility and restricts the amount ofoutstanding debt of the Jonah joint venture to debt owing to the owners of itspartnership interests and other third-party debt in the principal aggregateamount of $50.0 million.

·      The amendment modifies thefinancial covenants to, among other things, allow us to include in thecalculation of our Consolidated EBITDA (as defined in the Revolving CreditFacility) pro forma adjustments for material capital projects.

·      The amendmentallows for the issuance of Hybrid Securities (as defined in the RevolvingCredit Facility) of up to 15% of our Consolidated Total Capitalization (asdefined in the Revolving Credit Facility).

At September 30, 2006,$359.0 million was outstanding under the Revolving Credit Facility at aweighted average interest rate of 6.02%. At September 30, 2006, we were in compliance with the covenants of thiscredit facility.

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During October 2006, weexecuted a series of treasury rate lock agreements that extend through June2007 for a notional amount totaling $200.0 million.  These agreements, which are derivativeinstruments, hedge our exposure to increases in the underlying U.S. Treasurybenchmark rate that is expected to be used to establish the fixed interest ratefor debt that we expect to incur in 2007. The weighted average rate under the treasury lock agreements wasapproximately 4.7%.  The actual couponrate of the expected debt issuance will be comprised of the underlying U.S.Treasury benchmark rate, plus a credit spread premium for our debt security.

*FutureCapital Needs and Commitments*

We estimate that capitalexpenditures, excluding acquisitions and joint venture contributions, for 2006will be approximately $195.0 million (including $9.0 million of capitalizedinterest).  We expect to spendapproximately $133.0 million for revenue generating projects.  We expect to spend approximately $35.0million to sustain existing operations, including life-cycle replacements forequipment at various facilities and pipeline and tank replacements among all ofour business segments.  We expect tospend approximately $27.0 million to improve operational efficiencies andreduce costs among all of our business segments.  These estimates are lower than previouslyreported amounts primarily due to timing delays of construction projects.  Additionally, amounts related to Jonahcapital expenditures will be reported as joint venture contributions due to thedeconsolidation of Jonah on August 1, 2006. 

During 2006, TE Productsmay be required to contribute additional cash to Centennial to cover capitalexpenditures, acquisitions or other operating needs and to MB Storage to coversignificant capital expenditures or additional acquisitions.  We continually review and evaluate potentialcapital improvements and expansions that would be complementary to our presentbusiness operations.  These expenditurescan vary greatly depending on the magnitude of our transactions.  We may finance capital expenditures throughinternally generated funds, debt or the issuance of additional equity.

Additionally, we expectto contribute approximately $125.0 million to our Jonah joint venture for theconstruction of the Phase V expansion during 2006, of which $65.0 million hasalready been paid.  We expect tocontribute approximately an additional $10.0 million to our Jonah joint venturefor other capital expenditures during the remainder of 2006.  In August 2006, we entered into an amendedand restated general partnership agreement forming a joint venture to expandour Jonah system with an affiliate of Enterprise.  For additional information, see ‘“– Overviewof Business” above.  

*LiquidityOutlook*

We believe that we willcontinue to have adequate liquidity to fund future recurring operating andinvesting activities.  Our primary cashrequirements consist of normal operating expenses, capital expenditures tosustain existing operations and to complete the Jonah expansion, revenuegenerating expenditures, interest payments on our Senior Notes and RevolvingCredit Facility, distributions to our General Partner and unitholders andacquisitions of new assets or businesses. Our cash requirements for 2006 are expected to be funded throughoperating cash flows and our arrangement with an affiliate of Enterprise underthe joint venture agreement related to the Jonah expansion.   Long-term cash requirements for expansionprojects, acquisitions and debt repayments are expected to be funded by severalsources, including cash flows from operating activities, borrowings undercredit facilities, joint ventures and possibly the issuance of additionalequity and debt securities.  Our abilityto complete future debt and equity offerings and the timing of any suchofferings will depend on various factors, including prevailing marketconditions, interest rates, our financial condition and our credit rating atthe time.

*Off-BalanceSheet Arrangements*

We do not rely onoff-balance sheet borrowings to fund our acquisitions.  We have no material off-balance sheetcommitments for indebtedness other than the limited guaranty of Centennialdebt, the limited guarantee of Centennial catastrophic events as discussedbelow and an outstanding letter of credit. In addition, we have entered into various leases covering assetsutilized in several areas of our operations.

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Centennial entered intocredit facilities totaling $150.0 million, and as of September 30, 2006, $150.0million was outstanding under those credit facilities, of which $140.0 millionexpires in 2024, and $10.0 million expires in April 2007.  TE Products and Marathon Petroleum CompanyLLC (“Marathon”) have each guaranteed one-half of the repayment of Centennial’soutstanding debt balance (plus interest) under these credit facilities.  The guarantees arose in order for Centennialto obtain adequate financing, and the proceeds of the credit facilities wereused to fund construction and conversion costs of its pipeline system.  Prior to the expiration of the long-termcredit facility, TE Products could be relinquished from responsibility underthe guarantee should Centennial meet certain financial tests.  If Centennial defaults on its outstandingbalance, the estimated maximum potential amount of future payments for TEProducts and Marathon is $75.0 million each at September 30, 2006.  

TE Products, Marathon and Centennial have entered intoa limited cash call agreement, which allows each member to contribute cash inlieu of Centennial procuring separate insurance in the event of a third-partyliability arising from a catastrophic event. There is an indefinite term for the agreement and each member is tocontribute cash in proportion to its ownership interest, up to a maximum of$50.0 million each.  As a result of thecatastrophic event guarantee, TE Products has recorded a $4.4 millionobligation, which represents the present value of the estimated amount that wewould have to pay under the guarantee. If a catastrophic event were to occur and we were required to contributecash to Centennial, contributions exceeding our deductible might be covered byour insurance, depending upon the nature of the catastrophic event.  

One of our subsidiaries,TEPPCO Crude Oil, L.P. (“TCO”), has entered into master equipment leaseagreements with finance companies for the use of various equipment.  We have guaranteed the full and timelypayment and performance of TCO’s obligations under the agreements.  Generally, events of default would triggerour performance under the guarantee.  Themaximum potential amount of future payments under the guarantee is notestimable, but would include base rental payments for both current and futureequipment, stipulated loss payments in the event any equipment is stolen,damaged, or destroyed and any future indemnity payments.  We carry insurance coverage that may offsetany payments required under the guarantees.

*ContractualObligations*

The following table summarizes our debt repaymentobligations and material contractual commitments as of September 30, 2006 (inmillions):  
| ** **                                  | ** ** | **Amount of Commitment Expiration Per Period** | ** ** |
|---------------------------------------------|------------|-------------------------------------------------------------------------|------------|
| ** **                                  | ** ** | **Total**                                                               | ** ** | **Less than  1 Year** | ** ** | **1-3 Years** | ** ** | **4-5 Years** | ** ** | **After  5 Years** | ** ** |
| ** **                                  | ** ** | ** **                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revolving Credit  Facility, due 2011        |       | $                                                                       | 359.0      |   | $ | — |   | $ | — |   | $ | — |   | $ | 359.0 |   |
| 6.45% Senior  Notes due 2008 (1) (2)        |       | 180.0                                                                   |       | — |   | 180.0 |   | — |   | — |   |
| 7.625% Senior  Notes due 2012 (2)           |       | 500.0                                                                   |       | — |   | — |   | — |   | 500.0 |   |
| 6.125% Senior  Notes due 2013 (2)           |       | 200.0                                                                   |       | — |   | — |   | — |   | 200.0 |   |
| 7.51% Senior  Notes due 2028 (1) (2)        |       | 210.0                                                                   |       | — |   | — |   | — |   | 210.0 |   |
| Interest  payments (3)                      |       | 758.4                                                                   |       | 99.4 |   | 181.3 |   | 175.5 |   | 302.2 |   |
| Debt and interest subtotal                  |       | 2,207.4                                                                 |       | 99.4 |   | 361.3 |   | 175.5 |   | 1,571.2 |   |
|                                        |       |                                                                    |       |   |   |   |   |   |   |   |   |
| Operating leases  (4)                       |       | 72.4                                                                    |       | 18.5 |   | 22.7 |   | 13.5 |   | 17.7 |   |
| Contributions to  Jonah (5)                 |       | 242.0                                                                   |       | 242.0 |   | — |   | — |   | — |   |
| Contributions to  Centennial (6)            |       | 8.6                                                                     |       | 8.6 |   | — |   | — |   | — |   |
| Capital  expenditure obligations (7)        |       | 4.2                                                                     |       | 4.2 |   | — |   | — |   | — |   |
| Standby letter  of credit (8)               |       | 10.1                                                                    |       | 10.1 |   | — |   | — |   | — |   |
| Other  liabilities and deferred credits (9) |       | 8.0                                                                     |       | — |   | 6.3 |   | 0.3 |   | 1.4 |   |
|                                        |       |                                                                    |       |   |   |   |   |   |   |   |   |
| Total                                       |       | $                                                                       | 2,552.7    |   | $ | 382.8 |   | $ | 390.3 |   | $ | 189.3 |   | $ | 1,590.3 |   |

 

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(1)   Obligations of TE Products.

(2)   Our TE Products subsidiary entered into aninterest rate swap agreement to hedge its exposure to changes in the fair valueof its 7.51% Senior Notes due 2028.  AtSeptember 30, 2006, the 7.51% Senior Notes include an adjustment to decreasethe fair value of the debt by $3.9 million related to this interest rate swapagreement.  We also entered into interestrate swap agreements to hedge our exposure to changes in the fair value of our7.625% Senior Notes due 2012.  AtSeptember 30, 2006, the 7.625% Senior Notes include a deferred gain, net ofamortization, from previous interest rate swap terminations of $29.1million.  At September 30, 2006, our6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include$2.1 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and theunamortized debt discounts are excluded from this table.    

(3)   Includes interest payments due on our SeniorNotes and interest payments and commitment fees due on our Revolving CreditFacility. The interest amount calculated on the Revolving Credit Facility isbased on the assumption that the amount outstanding and the interest ratecharged both remain at their current levels. 

(4)   Includes a pipeline capacity lease withCentennial.  In January 2003, TE Productsentered into a pipeline capacity lease agreement with Centennial for a periodof five years that contains a minimum throughput requirement.  For the nine months ended September 30, 2006,TE Products exceeded the minimum throughput requirements on the leaseagreement.

(5)   Expected contributions to Jonah for our shareof the Phase V expansion.  Of thisamount, we expect to contribute approximately $125.0 million during theremainder of 2006 and $117.0 million in 2007.   

(6)   Expected contribution to Centennial during2007 for an obligation of Centennial related to the formation of CentennialPipeline LLC in 2001.

(7)   Includes accruals for costs incurred but notyet paid relating to capital projects.  

(8)   At September 30, 2006, we had outstanding a$10.1 million standby letter of credit in connection with crude oil purchasedduring the third quarter of 2006.  Thepayable related to these purchases of crude oil is expected to be paid duringthe fourth quarter of 2006.

(9)   Excludes approximately $9.5 million oflong-term deferred revenue payments, which are being transferred to income overthe term of the respective revenue contracts and $4.2 million related to ourestimated long-term portion of our obligation under a catastrophic eventguarantee for Centennial.  The amount ofcommitment by year is our best estimate of projected payments of theselong-term liabilities.    

We expect to repay the long-term, senior unsecuredobligations and bank debt through the issuance of additional long-term seniorunsecured debt at the time the 2008, 2012, 2013 and 2028 debt matures, issuanceof additional equity, with proceeds from dispositions of assets, cash flow fromoperations or any combination of the above items. 

In addition to the items in the table above, we haveentered into various operational commitments and agreements related to pipelineoperations and to the marketing, transportation, terminaling and storage ofcrude oil.  The majority of contractualcommitments we make for the purchase of crude oil range in term from athirty-day evergreen to one year.  Asubstantial portion of the contracts for the purchase of crude oil that extendbeyond thirty days include cancellation provisions that allow us to cancel thecontract with thirty days written notice. During the nine months ended September 30, 2006, crude oil purchasesaveraged approximately $781.4 million per month.

Our senior unsecured debtis rated BBB- by Standard and Poors (“S&P”) and Baa3 by Moody’s InvestorsService (“Moody’s”).  S&P assignedthis rating on June 14, 2005, following its review of the ownership structure,corporate governance issues, and proposed funding after the acquisition of theGeneral Partner by DFI.  Both ratings arewith a stable outlook.  A rating reflectsonly the view of a rating agency and is not a recommendation to buy, sell orhold any indebtedness.  Any rating can berevised upward or downward or withdrawn at any time by a rating agency if itdetermines that the circumstances warrant such a change and should be evaluatedindependently of any 

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other rating.  The senior unsecured debt of our subsidiary,TE Products, is also rated BBB- by S&P and Baa3 by Moody’s.  Both ratings are with a stable outlook andwere reaffirmed during the first quarter of 2006.     

***Recent Accounting Pronouncements***

**Seediscussion of new accounting pronouncements in Note 1 in the Notes to theConsolidated Financial Statements.**

**Item 3. Quantitative and Qualitative Disclosures About Market Risk**

For additional discussionof our exposure to market risks, please refer to “Item 7A.  Quantitative and Qualitative DisclosuresAbout Market Risk” in our Annual Report on Form 10-K for the year endedDecember 31, 2005.  

*Commodity Risk*

We may be exposed to market risk through changes incrude oil commodity prices and interest rates. We do not have foreign exchange risks. Our Risk Management Committee has established policies to monitor andcontrol these market risks.  The RiskManagement Committee is comprised, in part, of senior executives of theCompany.

We seek to maintain a position that is substantiallybalanced between crude oil purchases and sales and future deliveryobligations.  On the majority of ourcrude oil derivative contracts, we take the normal purchase and normal saleexclusion in accordance with SFAS No. 133, *Accounting for DerivativeInstruments and Hedging Activities*, and SFAS No. 138, *Accounting for Certain Derivative Instruments and Certain HedgingActivities, an amendment of FASB Statement No. 133*.  

On a small portion of our crude oil marketingbusiness, we enter into derivative contracts such as swaps and other businesshedging devices for which we cannot take the normal purchase and normal saleexclusion.  Generally, hedge accountingis elected.  The terms of these contractsare typically one year or less.  Thepurpose is to balance our position or lock in a margin and, as such, thederivative contracts do not expose us to additional significant marketrisk.  For derivatives where hedgeaccounting is elected, the effective portion of changes in fair value arerecorded in other comprehensive income and reclassified into earnings as suchtransactions are settled.  Forderivatives where hedge accounting is not elected, we mark these transactionsto market and the changes in the fair value are recognized in currentearnings.  This results in some financialstatement variability during quarterly periods; however, any unrealized gainsand losses reflected in the financial statements related to marking thesetransactions to market are offset by realized gains and losses in differentquarterly periods when the transactions are settled.   

At September 30, 2006, we had a limited number ofcommodity derivatives that were accounted for as cash flow hedges.  Gains and losses on these derivatives areoffset against corresponding gains or losses of the hedged item and aredeferred through other comprehensive income, thus minimizing exposure to cashflow risk.  The fair value of the openpositions at September 30, 2006, was a gain of $0.3 million.  Assuming a hypothetical across-the-board 10%price decrease in the applicable forward curve, the change in fair value of thehedging instrument would have been $0.3 million.  The fair value of the open positions wasbased upon both quoted market prices obtained from NYMEX and were estimatedbased on quoted prices from various sources such as independent reportingservices, industry publications, brokers and marketers.  The fair values were determined based uponthe differences by month between the fixed contract price and the relevantforward price curve, the volumes for the applicable month and a discount rateof 6%.

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*InterestRate Risk*

We have utilized and expect to continue to utilizeinterest rate swap agreements to hedge a portion of our cash flow and fairvalue risks.  Interest rate swapagreements are used to manage the fixed and floating interest rate mix of ourtotal debt portfolio and overall cost of borrowing.  Interest rate swaps that manage our cash flowrisk reduce our exposure to increases in the benchmark interest ratesunderlying variable rate debt.  Interestrate swaps that manage our fair value risks are intended to reduce our exposureto changes in the fair value of the fixed rate debt.  Interest rate swap agreements involve theperiodic exchange of payments without the exchange of the notional amount uponwhich the payments are based.  Therelated amount payable to or receivable from counterparties is included as anadjustment to accrued interest.   

At September 30, 2006, we had $359.0 millionoutstanding under our variable interest rate revolving credit facility.  The interest rate is based, at our option, oneither the lender’s base rate plus a spread or LIBOR plus a spread in effect atthe time of the borrowings and is adjusted monthly, bimonthly, quarterly orsemiannually.  On January 20,2006, we entered into interest rate swap agreements with a total notionalamount of $200.0 million to hedge our exposure to increases in the benchmarkinterest rate underlying our variable rate revolving credit facility.  These interest rate swaps mature in January2008.  Under the swap agreements, we paya fixed rate of interest ranging from 4.67% to 4.695% and receive a floatingrate based on a three-month U.S. Dollar LIBOR rate.  In the third quarter of 2006, these swapswere designated as cash flow hedges.  For the period from January 20, 2006 through the date these swaps weredesignated as cash flow hedges, changes in the fair value of the swaps were recognized in earnings, whichresulted in a $2.2 million reductionto interest expense.  Whilethese interest rate swaps remain in effect, future changes in the fair value ofthe cash flow hedges, to the extent the swaps are effective, willbe recognized in other comprehensive income until the hedged interestcosts are recognized in earnings.  AtSeptember 30, 2006, the fair value of these interest rate swaps was $1.5million.  Utilizing the balances of ourvariable interest rate debt outstanding at September 30, 2006, and includingthe effects of hedging activities, if market interest rates increased 100 basispoints, the annual increase in interest expense related to our revolving creditfacility would be $2.4 million.

The following table summarizes the estimated fairvalues of the Senior Notes as of September 30, 2006 and December 31, 2005 (inmillions):
|                                                   | ** ** | ** **      | ** ** | **Fair Value**          | ** ** |
|---------------------------------------------------|------------|-----------------|------------|------------------------------|------------|
| ** **                                        | ** ** | **Face  Value** | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|                                              |       |            |       |                         |       |   |   |
| 6.45% TE  Products Senior Notes, due January 2008 |       | $               | 180.0      |                         | $          | 182.2 |   | $ | 183.7 |   |
| 7.625% Senior  Notes, due February 2012           |       | 500.0           |       | 536.1                        |       | 552.0 |   |
| 6.125% Senior  Notes, due February 2013           |       | 200.0           |       | 200.7                        |       | 205.6 |   |
| 7.51% TE Products  Senior Notes, due January 2028 |       | 210.0           |       | 222.6                        |       | 224.1 |   |
|                                                   |            |                 |            |                              |            |  |  |  |  |  |

 

In October 2001, TE Products entered into an interestrate swap agreement to hedge its exposure to changes in the fair value of itsfixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as afair value hedge.  The swap agreement hasa notional amount of $210.0 million and matures in January 2028 to match theprincipal and maturity of the TE Products Senior Notes.  Under the swap agreement, TE Products pays afloating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus aspread of 147 basis points, and receives a fixed rate of interest of7.51%.  During the nine months endedSeptember 30, 2006, and 2005, we recognized reductions in interest expense of$1.5 million and $4.6 million, respectively, related to the difference betweenthe fixed rate and the floating rate of interest on the interest rateswap.  During the quarters endedSeptember 30, 2006 and 2005, we reviewed the hedge effectiveness of thisinterest rate swap and noted that no gain or loss from ineffectiveness wasrequired to be recognized.  The fairvalues of this interest rate swap were losses of approximately $3.9 million and$0.9 million at September 30, 2006, and December 31, 2005, respectively.  Utilizing the balance of the 7.51% TEProducts Senior Notes outstanding at September 30, 2006, and including theeffects of hedging activities, if market interest rates increased 100 basispoints, the annual increase in interest expense would be $2.1 million.

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**Item 4. Controls and Procedures**

As of the end of theperiod covered by this report, our management carried out an evaluation, withthe participation of our principal executive officer (the “CEO”) and ourprincipal financial officer (the “CFO”), of the effectiveness of our disclosurecontrols and procedures pursuant to Rule 13a-15 of the Securities Exchange Actof 1934.  Based on those evaluations, asof September 30, 2006, the CEO and CFO concluded:

(i)    that our disclosure controlsand procedures are designed to ensure that information required to be disclosedby us in the reports that we file or submit under the Securities Exchange Actof 1934 is recorded, processed, summarized and reported within the time periodsspecified in the SEC’s rules and forms, and that such information isaccumulated and communicated to our management, including the CEO and CFO, asappropriate to allow timely decisions regarding required disclosure; and 

(ii)   thatour disclosure controls and procedures are effective.

*Changes in Internal Control overFinancial Reporting*

During 2006, we commenceda project to replace or upgrade our general ledger and consolidationsoftware.  The implementation is expectedto occur in the first quarter of 2007. The project is not in response to anyidentified deficiency or weakness in our internal control over financialreporting.  Other than these proposedchanges, there has been no change in our internal control over financialreporting during the third quarter of 2006 that has materially affected, or isreasonably likely to materially affect, our internal control over financialreporting.  

The certifications of ourGeneral Partner’s CEO and CFO required under Sections 302 and 906 of theSarbanes-Oxley Act of 2002 have been included as exhibits to this Report.  

**PART II. OTHER INFORMATION**

**Item 1. Legal Proceedings**

We have been, in theordinary course of business, a defendant in various lawsuits and a party tovarious other legal proceedings, some of which are covered in whole or in partby insurance.  We believe that theoutcome of these lawsuits and other proceedings will not individually or in theaggregate have a material adverse effect on our consolidated financialposition, results of operations or cash flows. See discussion of legal proceedings in Note 14 in the Notes to theConsolidated Financial Statements, which is incorporated into this item byreference.

**Item 1A. Risk Factors**

Unitholders and potentialinvestors in our Units should carefully consider the risk factors set forthbelow and in our Quarterly Report on Form 10-Q for the period ended June 30,2006, in addition to other information in our Annual Report on Form 10-K forthe year ended December 31, 2005, our Current Report on Form 8-K filed on June16, 2006 and this Report.  We areidentifying these risk factors as important factors that could cause our actualresults to differ materially from those contained in any written or oralforward-looking statements made by or on behalf of us.  

***Thesuccess of our Jonah gas gathering operations is substantially dependent uponEnterprise. ***

We own our interest inthe Jonah gas gathering system, which represents a significant component of ourMidstream Segment and its potential for future growth, through a joint venturewith Enterprise.  The joint venture isgoverned by a management committee comprised of two representatives approved byan Enterprise affiliate and two representatives approved by subsidiaries ofours.  We expect to ultimately own an 80%interest in the joint venture, with Enterprise’s affiliate owning the remaining20%.  However, each representative on themanagement committee 

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is entitled to one vote,and the joint venture agreement generally requires the affirmative vote of amajority of the members of the management committee to approve an action.  Moreover, Enterprise is responsible formanaging construction of the Phase V expansion of the system, for half of thecosts of the project and for operating the joint venture.  We and Enterprise may not always agree on thebest course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause thejoint venture to take action that we believed to be in our best interests.  Further, Enterprise may experienceunanticipated delays or costs in construction or operation of the project, whichcould require additional capital contributions by us and Enterprise or diminishexpected benefits from the project.  Anyof these factors could materially and adversely affect our results ofoperations, financial condition and prospects.
| **Item 6.** | **Exhibits.** |
|-------------|---------------|
|        |          |
| ** **  | Exhibit       | ** ** | ** ** |
| ** **  | **Number**    | ** ** | **Description** |
|        |          |   |   |
|        | 3.1           |   | Certificate of Limited Partnership of TEPPCO  Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO  Partners, L.P. (Commission File No. 33-32203) and incorporated herein by  reference). |
|        | 3.2           |   | Third Amended and Restated Agreement of Limited  Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as  Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the quarter ended September 30, 2001 and incorporated herein by  reference). |
|        | 3.3           |   | Limited Liability Company Agreement of Texas Eastern  Products Pipeline Company, LLC, dated March 31, 2000 (Filed as Exhibit 3.3 to  Form 10-Q/A of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the  quarter ended June 30, 2005 and incorporated herein by reference). |
|        | 3.4           |   | Amendment to Limited Liability Company Agreement of  Texas Eastern Products Pipeline Company, LLC, dated March 22, 2005 (Filed as  Exhibit 3.4 to Form 10-Q/A of TEPPCO Partners, L.P. (Commission File No. 1-10403)  for the quarter ended June 30, 2005 and incorporated herein by reference). |
|        | 3.5           |   | Amendment to Limited Liability Company Agreement of  Texas Eastern Products Pipeline Company, LLC, dated June 15, 2006, but  effective as of February 24, 2005 (Filed as Exhibit 3.1 to the Current Report  on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on  June 16, 2006. |
|        | 4.1           |   | Form of Certificate representing Limited Partner  Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners,  L.P. (Commission File No. 33-32203) and incorporated herein by reference). |
|        | 4.2           |   | Form of Indenture between TE Products Pipeline  Company, Limited Partnership and The Bank of New York, as Trustee, dated as  of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company,  Limited Partnership’s Registration Statement on Form S-3 (Commission File No.  333-38473) and incorporated herein by reference). |
|        | 4.3           |   | Form of Certificate representing Class B Units  (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File  No. 1-10403) for the year ended December 31, 1998 and incorporated herein by  reference). |
|        | 4.4           |   | Form of Indenture between TEPPCO Partners, L.P., as  issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO  Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary  guarantors, and First Union National Bank, NA, as trustee, dated as of  February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P.  (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated  herein by reference). |
|        | 4.5           |   | First Supplemental Indenture between TEPPCO  Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership,  TCTM, L.P., TEPPCO Midstream Companies, |

 

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|        |   |   | L.P. and Jonah Gas Gathering Company, as subsidiary  guarantors, and First Union National Bank, NA, as trustee, dated as of  February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P.  (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated  herein by reference).                                                                                                                                                                                                                                                                                                                                  |
|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   | 4.6    |   | Second Supplemental Indenture, dated as of June 27,  2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company,  Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah  Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas  Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank,  National Association, formerly known as First Union National Bank, as trustee  (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File  No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by  reference).                      |
|   | 4.7    |   | Third Supplemental Indenture among TEPPCO Partners,  L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM,  L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val  Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia  Bank, National Association, as trustee, dated as of January 30, 2003 (Filed  as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the year ended December 31, 2002 and incorporated herein by  reference).                                                                                                              |
|   | 4.8*   |   | Full Release of Guarantee dated as of July 31, 2006  by Wachovia Bank, National Association, as trustee, in favor of Jonah Gas  Gathering Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
|   | 10.1   |   | Third Amendment to Amended and Restated Credit  Agreement, dated as of July 31, 2006, by and among TEPPCO Partners, L.P., the  Borrower, several banks and other financial institutions, the Lenders, SunTrust  Bank, as the Administrative Agent for the Lenders and as the LC Issuing Bank,  Wachovia Bank, National Association, as Syndication Agent, and BNP Paribas,  JPMorgan Chase Bank, N.A., and The Royal Bank of Scotland Plc, as  Co-Documentation Agents (Filed as Exhibit 10.3 to Current Report on Form 8-K  of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed August 3, 2006  and incorporated herein by reference). |
|   | 10.2   |   | Amended and Restated Partnership Agreement of Jonah  Gas Gathering Company dated as of August 1, 2006 (Filed as Exhibit 10.1 to  Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No.  1-10403) filed August 3, 2006 and incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                  |
|   | 10.3   |   | Contribution Agreement among TEPPCO GP, Inc., TEPPCO  Midstream Companies, L.P. and Enterprise Gas Processing, LLC filed August 1,  2006 (Filed as Exhibit 10.2 to Current Report on Form 8-K of TEPPCO Partners,  L.P. (Commission File No. 1-10403) dated as of August 3, 2006 and  incorporated herein by reference).                                                                                                                                                                                                                                                                                                                         |
|   | 10.4   |   | Transaction Agreement by and between TEPPCO  Partners, L.P. and Texas Eastern Products Pipeline Company, LLC dated as of  September 5, 2006 (Filed as Exhibit 10 to Current Report on Form 8-K of  TEPPCO Partners, L.P. (Commission File No. 1-10403) filed September 12, 2006  and incorporated herein by reference).                                                                                                                                                                                                                                                                                                                          |
|   | 12.1*  |   | Statement of Computation of Ratio of Earnings to  Fixed Charges.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|   | 31.1*  |   | Certification of Chief Executive Officer Pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
|   | 31.2*  |   | Certification of Chief Financial Officer Pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
|   | 32.1** |   | Certification of Chief Executive Officer Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
|   | 32.2** |   | Certification of Chief Financial Officer Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |

----

  * Filed herewith.

  ** Furnished herewith pursuant to Item601(b)-(32) of Regulation S-K.  

+ A management contractor compensation plan or arrangement.

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**SIGNATURES**

** **

Pursuant to therequirements of the Securities Exchange Act of 1934, the Registrant has dulycaused this report to be signed on its behalf by the undersigned thereunto dulyauthorized.
|                        |                                                                                                                              | TEPPCO Partners, L.P.        |   |
|------------------------|-----------------------------------------------------------------------------------------------------------------------------------|------------------------------|--------|
|                   |                                                                                                                              |                         |
|                   | By:                                                                                                                          | /s/  JERRY E.  THOMPSON |   |   |
| Date: November 7, 2006 | Jerry E.  Thompson,  President and Chief Executive Officer of  Texas Eastern Products Pipeline Company, LLC, General Partner      |                         |
|                   |                                                                                                                              |                         |
|                   | By:                                                                                                                          | /s/  WILLIAM  G. MANIAS |   |   |
| Date: November 7, 2006 | William G.  Manias,  Vice President and Chief Financial Officer of  Texas Eastern Products Pipeline Company, LLC, General Partner |                         |
|                        |                                                                                                                                   |                              |        |  |  |  |

 

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