**UNITED STATESSECURITIES AND EXCHANGE COMMISSION********Washington, D.C. 20549**

----

**FORM 10-Q**

**x****QUARTERLY REPORTPURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**

**For the quarterly period ended June 30, 2006**

**OR**

**o****TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**

**Commission File No. 1-10403**

----

**TEPPCO Partners,L.P.**(Exact name of Registrant as specified in its charter)
| **Delaware**             | **76-0291058**          |
|--------------------------|-------------------------|
| (State  of Incorporation | (I.R.S.  Employer       |
| or  Organization)        | Identification  Number) |

 

**1100 Louisiana Street, Suite 1300Houston, Texas 77002**(Address of principal executive offices, including zip code)

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

**2929 Allen ParkwayP.O. Box 2521Houston, Texas 77252-2521**(Former address)

Indicate by check mark whether the registrant (1) has filed all reportsrequired to be filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject to suchfiling requirements for the past 90 days.Yes  x**  **No  o

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 12b-2 of the Exchange Act.  (Checkone):    Large accelerated filer x     AcceleratedFiler o    Non-accelerated Filer o

Indicateby check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act).  Yes  o  No  x

Indicate the number of shares outstanding of each of the issuer’s classesof common stock, as of the latest practicable date.  Limited Partner Units outstanding as ofAugust 3, 2006:   **75,713,554**

 

----

**TEPPCO PARTNERS, L.P.**

**TABLE OF CONTENTS**
|                                                                                                                               | ** ** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------|------------|------------|
| **PART  I. FINANCIAL INFORMATION**                                                                                            |       |       |
| ** **                                                                                                                    |       |       |
| Item  1. Financial Statements                                                                                                 |       |       |
| Consolidated  Balance Sheets as of June 30, 2006 (unaudited) and December 31, 2005  (unaudited)                               |       |       |
|                                                                                                                          |       |       |
| Consolidated Statements of Income for the three months  and six months ended June 30, 2006 and 2005 (unaudited)               |       |       |
|                                                                                                                          |       |       |
| Consolidated Statements of Cash Flows for the six  months ended June 30, 2006 and 2005 (unaudited)                            |       |       |
|                                                                                                                          |       |       |
| Consolidated Statement of Partners’ Capital for the  six months ended June 30, 2006 (unaudited)                          |       |       |
|                                                                                                                          |       |       |
| Consolidated Statements of Comprehensive Income for  the three months and six months ended June 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

----

**PART I.FINANCIAL INFORMATION**

**Item 1.Financial Statements**

**TEPPCO PARTNERS,  L.P.**

**CONSOLIDATEDBALANCE SHEETS(Unaudited)(in thousands)**
| ** **                                                                                                           | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                                                                                           | ** ** | **2006**          | ** ** | **2005**              | ** ** |
|                                                                                                                 |       |              |       |                  |       |
| **ASSETS**                                                                                                           |       |              |       |                  |       |
| ** **                                                                                                           | ** ** | ** **        | ** ** | ** **            | ** ** |
| Current assets:                                                                                                      |       |              |       |                  |       |
| Cash and cash  equivalents                                                                                           |       | $                 | 185        |                  | $          | 119 |   |
| Accounts  receivable, trade (net of allowance for doubtful accounts of $100 and $250)                                |       | 830,129           |       | 803,373               |       |
| Accounts  receivable, related parties                                                                                |       | 2,063             |       | 5,207                 |       |
| Inventories                                                                                                          |       | 40,077            |       | 29,069                |       |
| Other                                                                                                                |       | 56,358            |       | 61,361                |       |
| Total current  assets                                                                                                |       | 928,812           |       | 899,129               |       |
| Property, plant  and equipment, at cost (net of accumulated depreciation and amortization of  $512,814 and $474,332) |       | 1,957,451         |       | 1,960,068             |       |
| Equity  investments                                                                                                  |       | 353,519           |       | 359,656               |       |
| Intangible  assets                                                                                                   |       | 360,600           |       | 376,908               |       |
| Goodwill                                                                                                             |       | 16,944            |       | 16,944                |       |
| Other assets                                                                                                         |       | 69,809            |       | 67,833                |       |
| Total assets                                                                                                         |       | $                 | 3,687,135  |                  | $          | 3,680,538 |   |
|                                                                                                                 |       |              |       |                  |       |
| **LIABILITIES  AND PARTNERS’ CAPITAL**                                                                          |       |              |       |                  |       |
| ** **                                                                                                           | ** ** | ** **        | ** ** | ** **            | ** ** |
| Current liabilities:                                                                                                 |       |              |       |                  |       |
| Accounts payable  and accrued liabilities                                                                            |       | $                 | 828,270    |                  | $          | 800,033 |   |
| Accounts  payable, related parties                                                                                   |       | 19,661            |       | 11,836                |       |
| Accrued interest                                                                                                     |       | 32,036            |       | 32,840                |       |
| Other accrued  taxes                                                                                                 |       | 18,510            |       | 16,532                |       |
| Other                                                                                                                |       | 37,584            |       | 75,970                |       |
| Total current  liabilities                                                                                           |       | 936,061           |       | 937,211               |       |
| Senior notes                                                                                                         |       | 1,106,677         |       | 1,119,121             |       |
| Other long-term debt                                                                                                 |       | 445,000           |       | 405,900               |       |
| Deferred tax liability                                                                                               |       | 514               |       | —                |       |
| Other liabilities and  deferred credits                                                                              |       | 27,233            |       | 16,936                |       |
| Commitments and  contingencies                                                                                       |       |              |       |                  |       |
| Partners’ capital:                                                                                              |       |              |       |                  |       |
| Accumulated  other comprehensive (loss) income                                                                       |       | (262              | )          | 11                    |       |
| General  partner’s interest                                                                                     |       | (70,145           | )          | (61,487               | )          |
| Limited  partners’ interests                                                                                    |       | 1,242,057         |       | 1,262,846             |       |
| Total partners’  capital                                                                                        |       | 1,171,650         |       | 1,201,370             |       |
| Total liabilities and  partners’ capital                                                                        |       | $                 | 3,687,135  |                  | $          | 3,680,538 |   |

 

Seeaccompanying Notes to Unaudited Consolidated Financial Statements.

1

----

**TEPPCO PARTNERS, L.P.**

**CONSOLIDATED STATEMENTS OF INCOME(Unaudited)(in thousands, except per Unit amounts)**
| ** **                                  | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|---------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                  | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                  | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
| Operating  revenues:                        |       |                             |       |                           |       |   |   |   |   |
| Sales of petroleum products                 |       | $                                | 2,287,266  |                           | $          | 1,961,302 |   | $ | 4,683,612 |   | $ | 3,346,369 |   |
| Transportation – Refined products      |       | 39,443                           |       | 37,834                         |       | 71,242 |   | 72,799 |   |
| Transportation – LPGs                  |       | 13,354                           |       | 14,470                         |       | 42,775 |   | 46,701 |   |
| Transportation – Crude oil             |       | 10,544                           |       | 9,042                          |       | 19,467 |   | 18,214 |   |
| Transportation – NGLs                  |       | 10,738                           |       | 11,387                         |       | 21,391 |   | 21,606 |   |
| Gathering – Natural gas                |       | 41,459                           |       | 36,956                         |       | 82,834 |   | 73,516 |   |
| Other                                       |       | 22,248                           |       | 16,394                         |       | 40,100 |   | 31,971 |   |
| Total operating revenues                    |       | 2,425,052                        |       | 2,087,385                      |       | 4,961,421 |   | 3,611,176 |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Costs and  expenses:                        |       |                             |       |                           |       |   |   |   |   |
| Purchases of petroleum products             |       | 2,254,756                        |       | 1,941,890                      |       | 4,625,796 |   | 3,312,980 |   |
| Operating expense                           |       | 55,275                           |       | 43,721                         |       | 101,778 |   | 86,396 |   |
| Operating fuel and power                    |       | 12,987                           |       | 11,546                         |       | 27,284 |   | 22,616 |   |
| General and administrative                  |       | 9,158                            |       | 6,100                          |       | 18,359 |   | 13,305 |   |
| Depreciation and amortization               |       | 28,676                           |       | 26,138                         |       | 57,433 |   | 51,749 |   |
| Taxes – other than income taxes        |       | 6,048                            |       | 4,241                          |       | 11,359 |   | 9,647 |   |
| Gains on sales of assets                    |       | (18                              | )          | (68                            | )          | (1,396 | ) | (566 | ) |
| Total costs and expenses                    |       | 2,366,882                        |       | 2,033,568                      |       | 4,840,613 |   | 3,496,127 |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Operating income                            |       | 58,170                           |       | 53,817                         |       | 120,808 |   | 115,049 |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Interest expense  – net                |       | (19,198                          | )          | (21,627                        | )          | (40,341 | ) | (40,914 | ) |
| Equity earnings                             |       | 2,674                            |       | 7,751                          |       | 3,663 |   | 11,845 |   |
| Other income –  net                    |       | 454                              |       | 135                            |       | 1,353 |   | 401 |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Income before deferred income tax expense   |       | 42,100                           |       | 40,076                         |       | 85,483 |   | 86,381 |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Deferred income  tax expense                |       | 514                              |       | —                         |       | 514 |   | — |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Income from continuing operations           |       | 41,586                           |       | 40,076                         |       | 84,969 |   | 86,381 |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Income (loss)  from discontinued operations |       | (110                             | )          | 846                            |       | 1,497 |   | 1,970 |   |
| Gain on sale of  discontinued operations    |       | (12                              | )          | —                         |       | 17,872 |   | — |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Discontinued operations                     |       | (122                             | )          | 846                            |       | 19,369 |   | 1,970 |   |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Net income                                  |       | $                                | 41,464     |                           | $          | 40,922 |   | $ | 104,338 |   | $ | 88,351 |   |

 

2

----

 
| ** **                                               | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|----------------------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                               | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                               | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                                     |       |                             |       |                           |       |   |   |   |   |
| Net Income  Allocation:                                  |       |                             |       |                           |       |   |   |   |   |
| Limited Partner  Unitholders:                            |       |                             |       |                           |       |   |   |   |   |
| Income from continuing operations                        |       | $                                | 29,360     |                           | $          | 28,154 |   | $ | 59,988 |   | $ | 61,101 |   |
| Income from discontinued operations                      |       | (86                              | )          | 594                            |       | 13,674 |   | 1,394 |   |
| Total Limited Partner Unitholders net income  allocation |       | 29,274                           |       | 28,748                         |       | 73,662 |   | 62,495 |   |
|                                                     |       |                             |       |                           |       |   |   |   |   |
| General Partner:                                         |       |                             |       |                           |       |   |   |   |   |
| Income from continuing operations                        |       | 12,226                           |       | 11,922                         |       | 24,981 |   | 25,280 |   |
| Income from discontinued operations                      |       | (36                              | )          | 252                            |       | 5,695 |   | 576 |   |
| Total General Partner net income allocation              |       | 12,190                           |       | 12,174                         |       | 30,676 |   | 25,856 |   |
| Total net income allocated                               |       | $                                | 41,464     |                           | $          | 40,922 |   | $ | 104,338 |   | $ | 88,351 |   |
|                                                     |       |                             |       |                           |       |   |   |   |   |
| Basic and  diluted net income per Limited Partner Unit:  |       |                             |       |                           |       |   |   |   |   |
|                                                     |       |                             |       |                           |       |   |   |   |   |
| Continuing operations                                    |       | $                                | 0.42       |                           | $          | 0.42 |   | $ | 0.85 |   | $ | 0.94 |   |
| Discontinued operations                                  |       | —                           |       | 0.01                           |       | 0.20 |   | 0.02 |   |
| Basic and diluted net income per Limited Partner  Unit   |       | $                                | 0.42       |                           | $          | 0.43 |   | $ | 1.05 |   | $ | 0.96 |   |
|                                                     |       |                             |       |                           |       |   |   |   |   |
| Weighted average  Limited Partner Units outstanding      |       | 69,964                           |       | 66,559                         |       | 69,964 |   | 64,789 |   |

 

Seeaccompanying Notes to Unaudited Consolidated Financial Statements.

3

----

**TEPPCO PARTNERS, L.P.**

**CONSOLIDATED STATEMENTS OF CASHFLOWS(Unaudited)(in thousands)**
| ** **                                                                                | ** ** | **Six Months Ended** | ** ** |
|-------------------------------------------------------------------------------------------|------------|--------------------------------|------------|
| ** **                                                                                | ** ** | **June 30,**              | ** ** |
| ** **                                                                                | ** ** | **2006**                       | ** ** | **2005** | ** ** |
| ** **                                                                                | ** ** | ** **                     | ** ** | ** ** | ** ** |
| Cash flows from  operating activities:                                                    |       |                           |       |   |   |
| Net income                                                                                |       | $                              | 104,338    |   | $ | 88,351 |   |
| Adjustments to reconcile net income to cash provided  by continuing operating activities: |       |                           |       |   |   |
| Income from discontinued operations                                                       |       | (19,369                        | )          | (1,970 | ) |
| Deferred income tax expense                                                               |       | 514                            |       | — |   |
| Depreciation and amortization                                                             |       | 57,433                         |       | 51,749 |   |
| Earnings in equity investments                                                            |       | (3,663                         | )          | (11,845 | ) |
| Distributions from equity investments                                                     |       | 16,297                         |       | 19,047 |   |
| Gains on sales of assets                                                                  |       | (1,396                         | )          | (566 | ) |
| Non-cash portion of interest expense                                                      |       | 840                            |       | 810 |   |
| Increase in accounts receivable, trade                                                    |       | (26,756                        | )          | (133,049 | ) |
| Decrease in accounts receivable, related parties                                          |       | 3,144                          |       | 8,443 |   |
| Increase in inventories                                                                   |       | (10,981                        | )          | (70,562 | ) |
| (Increase) decrease in other current assets                                               |       | 5,003                          |       | (15,265 | ) |
| Increase in accounts payable and accrued expenses                                         |       | 14,374                         |       | 116,025 |   |
| Increase (decrease) in accounts payable, related  parties                                 |       | 7,825                          |       | (19,234 | ) |
| Other                                                                                     |       | (6,069                         | )          | (4,232 | ) |
| Net cash provided by continuing operating activities                                      |       | 141,534                        |       | 27,702 |   |
| Net cash provided by discontinued operations                                              |       | 1,521                          |       | 2,251 |   |
| Net cash provided by operating activities                                                 |       | 143,055                        |       | 29,953 |   |
| Cash flows from investing activities:                                                     |       |                           |       |   |   |
| Proceeds from the sales of assets                                                         |       | 39,750                         |       | 510 |   |
| Purchase of assets                                                                        |       | —                         |       | (42,482 | ) |
| Investment in Centennial Pipeline LLC                                                     |       | (2,500                         | )          | — |   |
| Investment in Mont Belvieu Storage Partners, L.P.                                         |       | (1,720                         | )          | (1,109 | ) |
| Cash paid for linefill on assets owned                                                    |       | (1,371                         | )          | (5,353 | ) |
| Capital expenditures                                                                      |       | (82,463                        | )          | (82,963 | ) |
| Net cash used in investing activities                                                     |       | (48,304                        | )          | (131,397 | ) |
| Cash flows from financing activities:                                                     |       |                           |       |   |   |
| Proceeds from revolving credit facility                                                   |       | 305,550                        |       | 299,307 |   |
| Repayments on revolving credit facility                                                   |       | (266,450                       | )          | (374,307 | ) |
| Issuance of Limited Partner Units, net                                                    |       | —                         |       | 278,832 |   |
| Distributions paid                                                                        |       | (133,785                       | )          | (117,316 | ) |
| Net cash provided by (used in) financing activities                                       |       | (94,685                        | )          | 86,516 |   |
| Net increase (decrease) in cash and cash equivalents                                      |       | 66                             |       | (14,928 | ) |
| Cash and cash equivalents at beginning of period                                          |       | 119                            |       | 16,422 |   |
| Cash and cash equivalents at end of period                                                |       | $                              | 185        |   | $ | 1,494 |   |
| **Supplemental  disclosure of cash flows:**                                               |       |                           |       |   |   |
| Cash paid for  interest (net of amounts capitalized)                                      |       | $                              | 42,074     |   | $ | 41,067 |   |

 

Seeaccompanying Notes to Unaudited Consolidated Financial Statements.

4

----

**TEPPCO PARTNERS,L.P.**

**CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL(Unaudited)(in thousands, 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 |   |
| Net income allocation                                     |       | —          |       | 30,676             |       | 73,662             |       | —                 |       | 104,338    |       |
| Cash distributions                                        |       | —          |       | (39,334            | )          | (94,451            | )          | —                 |       | (133,785   | )          |
| Changes in fair values of interest rate cash flow  hedges |       | —          |       | —             |       | —             |       | 1,671                  |       | 1,671      |       |
| Changes in fair values of interest rate cash flow  hedges |       | —          |       | —             |       | —             |       | (1,671                 | )          | (1,671     | )          |
| Changes in fair values of crude oil cash flow hedges      |       | —          |       | —             |       | —             |       | (273                   | )          | (273       | )          |
|                                                      |       |            |       |               |       |               |       |                   |       |       |       |
| Partners’ capital at  June 30, 2006                  |       | 69,963,554      |       | $                  | (70,145    | )                  | $          | 1,242,057              |       | $          | (262       | ) | $ | 1,171,650 |   |

 

Seeaccompanying Notes to Unaudited Consolidated Financial Statements.

5

----

**TEPPCOPARTNERS,  L.P.**

**CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME(Unaudited)(in thousands)**
| ** **                                                | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                | ** ** | **2006**                                        | ** ** | **2005**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                                      |       |                                            |       |                                          |       |   |   |   |   |
| Net income                                                |       | $                                               | 41,464     |                                          | $          | 40,922 |   | $ | 104,338 |   | $ | 88,351 |   |
|                                                      |       |                                            |       |                                          |       |   |   |   |   |
| Changes in fair  values of interest rate cash flow hedges |       | 1,671                                           |       | —                                        |       | 1,671 |   | — |   |
| Changes in fair  values of interest rate cash flow hedges |       | (1,671                                          | )          | —                                        |       | (1,671 | ) | — |   |
| Changes in fair  values of crude oil cash flow hedges     |       | (509                                            | )          | —                                        |       | (273 | ) | — |   |
|                                                      |       |                                            |       |                                          |       |   |   |   |   |
| Comprehensive  income                                     |       | $                                               | 40,955     |                                          | $          | 40,922 |   | $ | 104,065 |   | $ | 88,351 |   |

 

Seeaccompanying Notes to Unaudited Consolidated Financial Statements.

6

----

**TEPPCO PARTNERS, L.P.**

**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS(Unaudited)**

**NOTE 1.  ORGANIZATION AND BASIS OF PRESENTATION**

TEPPCO Partners, L.P.(the “Partnership”), a Delaware limited partnership, is a master limitedpartnership formed in March 1990.  Weoperate through TE Products Pipeline Company, Limited Partnership (“TE Products”),TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”).  Collectively, TE Products, TCTM and TEPPCOMidstream are referred to as the “Operating Partnerships.”  Texas Eastern Products Pipeline Company, LLC(the “Company” or “General Partner”), a Delaware 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 an indirect wholly owned subsidiary of DukeEnergy Field Services, LLC (“DEFS”), a joint venture between Duke EnergyCorporation (“Duke Energy”) and ConocoPhillips. Duke Energy held an interest of approximately 70% in DEFS, andConocoPhillips held the remaining interest of approximately 30%.  On February 24, 2005, the General Partner wasacquired 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 DanL. Duncan, for approximately $1.1 billion. As a result of the transaction, DFI owns and controls the 2% generalpartner interest in us and has the right to receive the incentive distributionrights associated with the general partner interest.  In conjunction with an amended and restatedadministrative services agreement (“ASA”), EPCO performs all management,administrative and operating functions required for us, and we reimburse EPCOfor all direct and indirect expenses that have been incurred in managingus.  As a result of the sale of ourGeneral Partner, DEFS and Duke Energy continued to provide some administrativeservices for us for a period of up to one year after the sale, at which time,we or EPCO assumed these services.  Priorto the sale of our General Partner, DEFS also managed and operated certain ofour TEPPCO Midstream assets for us under contractual agreements.  We assumed the operations of these assetsfrom DEFS, and certain DEFS employees became employees of EPCO effective June1, 2005.

In connection with ourformation, the Company received 2,500,000 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 June 30, 2006, none of these Limited Partner Units had been soldby DFI.

The accompanyingunaudited consolidated financial statements reflect all adjustments that are,in the opinion of our management, of a normal and recurring nature andnecessary for a fair statement of our financial position as of June 30, 2006,and the results of our operations and cash flows for the periodspresented.  The results of operations forthe three months and six months ended June 30, 2006, are not necessarilyindicative of results of our operations for the full year 2006.  You should read these interim financialstatements in conjunction with our consolidated financial statements and notesthereto presented in our Current Report on Form 8-K filed on June 16, 2006,which recast certain information from our Annual Report on Form 10-K for theyear ended December 31, 2005, as discontinued operations. We have reclassifiedcertain amounts from prior periods to conform to the current presentation.

7

----

**Business Segments**

We operate and report inthree business segments: transportation and storage of refined products,liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”);gathering, transportation, marketing and storage of crude oil and distributionof lubrication oils and specialty chemicals (“Upstream Segment”); and gatheringof natural gas, fractionation of natural gas liquids (“NGLs”) andtransportation of NGLs (“Midstream Segment”). Our reportable segments offer different products and services and aremanaged separately because each requires different business strategies.

Our interstatetransportation operations, including rates charged to customers, are subject toregulations prescribed by the Federal Energy Regulatory Commission (“FERC”).  We refer to refined products, LPGs,petrochemicals, crude oil, NGLs and natural gas in this Report, collectively,as “petroleum products” or “products.”

**Net Income Per Unit**

Basic net income perLimited Partner Unit (“Unit” or “Units”) is computed by dividing net income,after deduction of the General Partner’s interest, by the weighted averagenumber of Units outstanding (a total of 70.0 million Units and 66.6 millionUnits for the three months ended June 30, 2006 and 2005, respectively, and atotal of 70.0 million Units and 64.8 million Units for the six months ended June30, 2006 and 2005, respectively). The General Partner’s percentage interest inour net income is based on its percentage of cash distributions from AvailableCash for each period (see Note 9).  TheGeneral Partner was allocated $12.2 million (representing 29.4%) and $12.2million (representing 29.75%) of our net income for the three months ended June30, 2006 and 2005, respectively, and $30.7 million (representing 29.4%) and$25.9 million (representing 29.27%) of our net income for the six months endedJune 30, 2006 and 2005, respectively. The General Partner’s percentage interest in our net income increases ascash distributions paid per Unit increase, in accordance with the Third Amendedand Restated Agreement of Limited Partnership of TEPPCO Partners, L.P. (“PartnershipAgreement”).

Diluted net income perUnit equaled basic net income per Unit for each of the three-month andsix-month periods ended June 30, 2006 and 2005, as there were no dilutiveinstruments outstanding.

**Deferred Income Tax Expense for Certain Pipeline Operations**

In May 2006, the State ofTexas enacted a new business tax (the “Texas Margin Tax”) that replaces itsexisting franchise tax.  In general,legal entities that do business in Texas are subject to the new margintax.  Limited partnerships, limitedliability companies, corporations, limited liability partnerships and jointventures are examples of the types of entities subject to the Texas MarginTax.  As a result of the change in taxlaw, our tax status in the state of Texas changed from nontaxable totaxable.  The tax is considered an incometax for purposes of adjustments to deferred tax liability, as the tax isdetermined by applying a tax rate to a base that considers both revenues andexpenses.  Our deferred income taxexpense for state taxes 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 isassessed at 1% of Texas-sourced taxable margin, which 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 noncurrent.  We have calculated and recorded an estimateddeferred tax liability of approximately $0.5 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 three months and six months ended June 30, 2006.

8

----

Since the Texas MarginTax is determined by applying a tax rate to a base that considers both revenuesand expenses, it has characteristics of an income tax.  Accordingly, we determined the Texas MarginTax should be accounted for as an income tax in accordance with the provisionsof Statement of Financial Accounting Standards (“SFAS”) No. 109, *Accounting for Income Taxes*.

**Asset Retirement Obligations**

During the second quarterof 2006, we recorded $0.3 million of expense, included in depreciation andamortization expense, related to a conditional asset retirementobligation.  Additionally, we recorded a$0.4 million liability, which represents the fair value, as measured at June30, 2006, 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. This conditional asset retirement obligation was not previouslyrecorded, due to the indeterminate range of settlement dates and settlementmethods, during the implementation of SFAS No. 143, *Accountingfor Asset Retirement Obligations*, and Financial Accounting StandardsBoard (“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.  With the availability of new information, wewere able to assign probabilities for settlement dates and settlement methodsfor use in an expected present value measurement of fair value.

**New Accounting Pronouncements**

In December 2004, theFASB issued SFAS No. 123(R) (revised 2004), *Share-BasedPayment*.  SFAS 123(R) is arevision of SFAS No. 123, *Accounting forStock-Based Compensation*, as amended by SFAS No. 148,*Accounting for Stock-Based Compensation — Transitionand Disclosure* and supersedes Accounting Principles Board (“APB”)Opinion No. 25, *Accounting for Stock Issuedto Employees*.  SFAS 123(R)requires that the cost resulting from all share-based payment transactions berecognized in the financial statements at fair value.  In April 2005, both the FASB and theSecurities and Exchange Commission decided to delay the effective date forpublic companies to implement SFAS 123(R). SFAS 123(R) became effective for public companies for annual periodsbeginning after June 15, 2005. Accordingly, we adopted SFAS 123(R) in the first quarter of 2006.  We adopted SFAS 123(R) under the modifiedprospective transition method.  We havedetermined that our 1999 and 2005 Phantom Unit Plans are liability awards underthe provisions of this statement.  Noadditional compensation expense has been recorded in connection with theadoption of SFAS 123(R) as we have historically recorded the associatedliabilities at fair value.  The adoptionof SFAS 123(R) did not have a material effect on our financial position,results of operations or cash flows.

In June 2005, theEmerging Issues Task Force (“EITF”) reached consensus in EITF 04-5, *Determining Whether a General Partner, or the General Partners as aGroup, Controls a Limited Partnership or Similar Entity When the LimitedPartners Have Certain Rights*, to provide guidance on how generalpartners in a limited partnership should determine whether they control alimited partnership and therefore should consolidate it.  The EITF agreed that the presumption ofgeneral partner control would be overcome only when the limited partners haveeither of two types of rights. The first type, referred to as “kick-out rights,”is the right to dissolve or liquidate the partnership or otherwise remove thegeneral partner without cause.  Thesecond type, referred to as “participating rights,” is the right to effectivelyparticipate in significant decisions made in the ordinary course of thepartnership’s business. The kick-out rights and the participating rights mustbe substantive in order to overcome the presumption of general partner control.The consensus is effective for general partners of all new limited partnershipsformed and for existing limited partnerships for which the partnershipagreements are modified subsequent to the date of FASB ratification (June 29,2005).  For existing limited partnershipsthat have not been modified, the guidance in EITF 04-5 is effective no laterthan the beginning of the first reporting period in fiscal years beginningafter December 15, 2005.  Although thisEITF did not directly impact us, it did impact our General Partner.  Our General Partner

9

----

adopted this EITFon January 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 FASBissued SFAS No. 154, *Accounting Changes andError Corrections*.  SFAS 154establishes new standards on accounting for changes in accountingprinciples.  All such changes must beaccounted for by retrospective application to the financial statements of priorperiods unless it is impracticable to do so. SFAS 154 completely replaces APB Opinion No. 20, *AccountingChanges*, and SFAS No. 3, *Reporting AccountingChanges in Interim Periods*. However, it carries forward the guidance in those pronouncements withrespect to accounting for changes in estimates, changes in the reportingentity, and the correction of errors. SFAS 154 is effective for accounting changes and error corrections madein fiscal years beginning after December 15, 2005, with early adoptionpermitted for changes and corrections made in years beginning after June 1,2005. The application of SFAS 154 does not affect the transition provisions ofany existing pronouncements, including those that are in the transition phaseas of the effective date of SFAS 154. The adoption of SFAS 154 did not have a material effect on our financialposition, results of operations or cash flows.

In September 2005, theEITF reached consensus in EITF 04-13, *Accounting for Purchasesand Sales of Inventory with the Same Counterparty*, to define when apurchase and a sale of inventory with the same party that operates in the sameline of business should be considered a single nonmonetary transaction subjectto APB Opinion No. 29, *Accounting for NonmonetaryTransactions*.  Two or moreinventory transactions with the same party should be combined if they areentered into in contemplation of one another. The EITF also requires entities to account for exchanges of inventory inthe same line of business at fair value or recorded amounts based on inventoryclassification.  The guidance in EITF04-13 is effective for new inventory arrangements entered into in reportingperiods beginning after March 15, 2006. We adopted EITF 04-13 on April 1, 2006, which resulted in crude oilinventory purchases and sales under buy/sell transactions, which werepreviously recorded as gross purchases and sales, to be treated as inventoryexchanges in our consolidated statements of income.  EITF 04-13 reduced gross revenues andpurchases, but did not have a material effect on our financial position,results of operations or cash flows.  Thetreatment of buy/sell transactions under EITF 04-13 reduced the relative amountof revenues and purchases of petroleum products on our consolidated statementof income by approximately $313.7 million for the periods ended June 30,2006.  The revenues and purchases ofpetroleum products associated with buy/sell transactions that are reported on agross basis in our consolidated statements of income for the three months endedJune 30, 2005, and for the six months ended June 30, 2006 and 2005, areapproximately $326.9 million, $589.1 million and $403.3 million, respectively.

In February 2006, theFASB issued SFAS No. 155, **Accounting for Certain Hybrid Financial Instruments,**whichamends SFAS No. 133, **Accounting for Derivative Instruments and HedgingActivities** and SFAS No. 140, **Accounting for Transfers and Servicingof Financial Assets and Extinguishments of Liabilities**.This statement improves the financial reporting of certain hybrid financialinstruments and simplifies the accounting for these instruments. SFAS 155permits fair value remeasurement for any hybrid financial instrument thatcontains an embedded derivative that otherwise would require bifurcation,clarifies which interest-only and principal-only strips are not subject to therequirements of SFAS 133, establishes a requirement to evaluate interestsin securitized financial assets to identify interests that are freestandingderivatives or that are hybrid financial instruments that contain an embeddedderivative requiring bifurcation, clarifies that concentrations of credit riskin the form of subordination are not embedded derivatives, and amends SFAS 140to eliminate the prohibition on a qualifying special-purpose entity fromholding a derivative financial instrument that pertains to a beneficialinterest other than another derivative financial instrument. SFAS 155 iseffective for all financial instruments acquired, issued, or subject to aremeasurement event occurring after the fiscal year that begins afterSeptember 15, 2006 (January 1, 2007).  At June 30, 2006, we did nothave any hybrid financial securities outstanding and, as such, we do notbelieve that adoption of this statement will have a material effect on ourfinancial position, results of operations or cash flows, unless such hybridsecurities are issued by us prior to SFAS 155 becoming effective.

10

----

In June 2006, the EITFreached consensus in EITF 06-3, *How Taxes Collected fromCustomers and Remitted to Governmental Authorities Should Be Presented in theIncome Statement (That Is, Gross versus Net Presentation)*.  The accounting guidance permits companies toelect to present on either a gross or net basis sales and other taxes that areimposed on and concurrent with individual revenue-producing transactionsbetween a seller and a customer.  The grossbasis includes the taxes in revenues and costs; the net basis excludes thetaxes from revenues. The accounting guidance does not apply to tax systems thatare based on gross receipts or total revenues. EITF 06-3 requires companies to disclose their policy for presenting thetaxes and disclose any amounts presented on a gross basis if those amounts aresignificant.  The guidance in EITF 06-3is effective January 1, 2007.  As amatter of policy, we report such taxes on a net basis.  We believe that adoption of EITF 06-3 willnot have a material effect on our financial position, results of operations orcash flows.

**NOTE 2. GOODWILL AND OTHER INTANGIBLEASSETS**

**Goodwill**

Goodwill represents theexcess of purchase price over fair value of net assets acquired and ispresented on the consolidated balance sheets net of accumulatedamortization.  We account for goodwillunder SFAS No. 142, *Goodwill and OtherIntangible Assets,*which was issued by the FASB in July 2001.  SFAS 142 prohibits amortization of goodwill,but instead requires testing for impairment at least annually. We test goodwillfor impairment annually at December 31.

To perform an impairmenttest of goodwill, we have identified our reporting units and have determinedthe carrying value of each reporting unit by assigning the assets and liabilities,including the existing goodwill, to those reporting units.  We then determine the fair value of eachreporting unit and compare it to the carrying value of the reporting unit.  We will continue to compare the fair value ofeach reporting unit to its carrying value on an annual basis to determine if animpairment loss has occurred.   Therehave been no goodwill impairment losses recorded since the adoption of SFAS142.

The following table presents the carrying amount ofgoodwill at both June 30, 2006 and December 31, 2005, by business segment (inthousands):

|          | ** ** | **Downstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Upstream  Segment** | ** ** | **Segments  Total** | ** ** |
|----------|------------|-------------------------|------------|------------------------|------------|-----------------------|------------|---------------------|------------|
| Goodwill |       | $                       | —     |                   | $          | 2,777                 |       | $                   | 14,167     |   | $ | 16,944 |   |
|          |            |                         |            |                        |            |                       |            |                     |            |  |  |  |  |

 

11

----

**Other Intangible Assets**

The following table reflects the components ofintangible assets, including excess investments, being amortized at June 30,2006, and December 31, 2005 (in thousands):

|                                         | ** ** | **June 30, 2006**     | ** ** | **December 31, 2005** | ** ** |
|-----------------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| ** **                              | ** ** | **Gross Carrying  Amount** | ** ** | **Accumulated  Amortization**   | ** ** | **Gross Carrying  Amount** | ** ** | **Accumulated  Amortization** | ** ** |
| Intangible  assets:                     |       |                            |       |                            |       |   |   |   |   |
| Gathering and transportation agreements |       | $                               | 464,337    |                            | $          | (133,682 | ) | $ | 464,337 |   | $ | (118,921 | ) |
| Fractionation agreement                 |       | 38,000                          |       | (15,675                         | )          | 38,000 |   | (14,725 | ) |
| Other                                   |       | 9,898                           |       | (2,278                          | )          | 10,226 |   | (2,009 | ) |
| Subtotal                                |       | 512,235                         |       | (151,635                        | )          | 512,563 |   | (135,655 | ) |
|                                    |       |                            |       |                            |       |   |   |   |   |
| Excess  investments:                    |       |                            |       |                            |       |   |   |   |   |
| Centennial Pipeline LLC                 |       | 33,390                          |       | (14,651                         | )          | 33,390 |   | (12,947 | ) |
| Seaway Crude Pipeline Company           |       | 27,100                          |       | (4,110                          | )          | 27,100 |   | (3,764 | ) |
| Subtotal                                |       | 60,490                          |       | (18,761                         | )          | 60,490 |   | (16,711 | ) |
|                                    |       |                            |       |                            |       |   |   |   |   |
| Total intangible  assets                |       | $                               | 572,725    |                            | $          | (170,396 | ) | $ | 573,053 |   | $ | (152,366 | ) |

 

SFAS 142 requires that intangible assets with finiteuseful lives be amortized over their respective estimated useful lives.  If an intangible asset has a finite usefullife, but the precise length of that life is not known, that intangible assetshall be amortized over the best estimate of its useful life.  At a minimum, we will assess the useful livesand residual values of all intangible assets on an annual basis to determine ifadjustments are required.  Amortizationexpense on intangible assets was $8.0 million and $7.0 million for the threemonths ended June 30, 2006 and 2005, respectively, and $16.0 million and $14.1million for the six months ended June 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 June 30, 2006 and 2005, respectively, and $2.4 million and $2.5million for the six months ended June 30, 2006 and 2005, respectively.

The values assigned toour intangible assets for natural gas gathering contracts on the Jonah GasGathering System (“Jonah” or “Jonah system”) and the Val Verde Gas GatheringSystem (“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 updated throughputestimates from some of the producers on the systems, and as a result, weevaluate the remaining expected useful lives of the contract assets based onthe best available information. Revisions to these estimates may occur as additional production informationis made available to us.

The values assigned toour fractionation agreement and other intangible assets are generally amortizedon a straight-line basis.  Ourfractionation agreement is being amortized over its contract period of 20years.  The amortization periods for ourother intangible assets, which include non-compete and other agreements, rangefrom 3 years to 15 years.  The value of$8.7 million assigned to our crude supply and transportation intangible customercontracts is being amortized on a unit-of-production basis.

The value assigned to ourexcess investment in Centennial Pipeline LLC was created upon itsformation.  Approximately $30.0 millionis related to a contract and is being amortized on a unit-of-production basisbased upon the volumes transported under the contract compared to theguaranteed total throughput of the contract over a 10-year life.  The remaining $3.4 million is related to apipeline and is being amortized on a straight-line basis over the life of thepipeline, which is 35 years.  The valueassigned to our excess investment in Seaway Crude Pipeline

12

----

Company wascreated upon acquisition of our 50% ownership interest in 2000.  We are amortizing the $27.1 million excessinvestment on a straight-line basis over a 39-year life related primarily tothe life of the pipeline.

The following table setsforth the estimated amortization expense of intangible assets and the estimatedamortization expense allocated to equity earnings for the years ending December31 (in thousands):

|      | ** ** | **Intangible Assets** | ** ** | **Excess Investments** | ** ** |
|------|------------|----------------------------|------------|-----------------------------|------------|
| 2006 |       | $                          | 32,254     |                        | $          | 4,691 |   |
| 2007 |       | 33,379                     |       | 5,113                       |       |
| 2008 |       | 32,950                     |       | 5,438                       |       |
| 2009 |       | 30,703                     |       | 6,878                       |       |
| 2010 |       | 27,322                     |       | 7,042                       |       |
|      |            |                            |            |                             |            |  |  |

 

**NOTE 3.  INTEREST RATE SWAPS**

In October 2001, TEProducts entered into an interest rate swap agreement to hedge its exposure tochanges in the fair value of its fixed rate 7.51% Senior Notes due 2028. Wedesignated this swap agreement as a fair value hedge.  The swap agreement has a notional amount of$210.0 million and matures in January 2028 to match the principal and maturityof the TE Products Senior Notes.  Underthe swap agreement, TE Products pays a floating rate of interest based on athree-month U.S. Dollar LIBOR rate, plus a spread of 147 basis points, andreceives a fixed rate of interest of 7.51%. During the six months ended June 30, 2006 and 2005, we recognizedreductions in interest expense of $1.2 million and $3.3 million, respectively,related to the difference between the fixed rate and the floating rate of intereston the interest rate swap.  During thequarters ended June 30, 2006 and 2005, we measured the hedge effectiveness ofthis interest rate swap and noted that no gain or loss from ineffectiveness wasrequired to be recognized.   The fairvalue of this interest rate swap was a loss of approximately $11.3 million and$0.9 million at June 30, 2006, and December 31, 2005, respectively.

During 2002, we enteredinto interest rate swap agreements, designated as fair value hedges, to hedgeour exposure to changes in the fair value of our fixed rate 7.625% Senior Notesdue 2012.  The swap agreements had acombined notional amount of $500.0 million and matured in 2012 to match theprincipal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based ona U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interestof 7.625%.  These swap agreements werelater terminated 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 June 30, 2006, the unamortized balance ofthe deferred gains was $30.2 million.  Inthe event of early extinguishment of the Senior Notes, any remainingunamortized gains would be recognized in the consolidated statement of incomeat the time of extinguishment.

During May 2005, we executeda treasury rate lock agreement for a notional amount of $200.0 million to hedgeour exposure to increases in the treasury rate that was to be used to establishthe fixed interest rate for a debt offering that was proposed to occur in thesecond quarter of 2005.  During June2005, the proposed debt offering was cancelled, and the treasury lock wasterminated with a realized loss of $2.0 million.  The realized loss was recorded as a componentof interest expense in the consolidated statements of income in June 2005.

On January 20, 2006, we entered into interest rate swapagreements with a total notional amount of $200.0 million to hedge our exposureto increases in the benchmark interest rate underlying our variable raterevolving credit facility.  Theseinterest rate swaps mature in January 2008. For the periodfrom January 20, 2006 through June 30,2006, changes in the fair value of the swaps were recognized in earnings, which forthe six months ended June 30, 2006, was a $2.5million reduction to interest expense.  Underthe swap agreements, we pay a fixed rate of interest ranging from 4.67% to4.695% and receive a floating rate based on a three-month U.S. Dollar LIBORrate.  Because these swaps will bedesignated as cash flow hedges effective in the third quarter of2006, future changes in fair value, to the extent the swaps areeffective, will be recognized in other comprehensive income until thehedged interest costs are recognized in earnings.

13

----

**NOTE 4.  ACQUISITIONS**

**MexiaPipeline**

On March 31, 2005, wepurchased crude oil pipeline assets for $7.1 million from BP Pipelines (NorthAmerica) Inc. (“BP”).  The assets includeapproximately 158 miles of pipeline, which extend from Mexia, Texas, to theHouston, Texas, area and two stations in south Houston with connections to a BPpipeline that originates in south Houston. We funded the purchase through borrowings under our revolving creditfacility, and we allocated the purchase price to property, plant and equipment.  We have integrated these assets into ourSouth Texas pipeline system, which is included in our Upstream Segment.

**Storageand Terminaling Assets**

On April 1, 2005, wepurchased crude oil storage and terminaling assets in Cushing, Oklahoma, fromKoch Supply & Trading, L.P. for $35.4 million.  The assets consist of eight storage tankswith 945,000 barrels of storage capacity, receipt and delivery manifolds,interconnections to several pipelines, crude oil inventory and approximately 70acres of land.  We funded the purchasethrough borrowings under our revolving credit facility.  We allocated the purchase price to property,plant and equipment and inventory.

**NOTE 5.  DISPOSITIONS AND DISCONTINUED OPERATIONS**

**Pioneer Plant**

On March 31, 2006, wesold our ownership interest in the Pioneer silica gel natural gas processingplant located near Opal, Wyoming, together with Jonah’s rights to processnatural gas originating from the Jonah and Pinedale fields, located insouthwest Wyoming, to an affiliate of Enterprise Products Partners L.P. (“Enterprise”)for $38.0 million in cash.  The Pioneerplant was not an integral part of our Midstream Segment operations, and naturalgas processing is not a core business. We have no continuing involvement in the operations or results of thisplant.    This transaction was reviewedand approved by the Audit and Conflicts Committee of the board of directors ofour General Partner and a fairness opinion was rendered by an independentthird-party.  The sales proceeds wereused to fund organic growth projects, retire debt and for other generalpartnership purposes.  The carrying valueof the Pioneer plant at March 31, 2006, prior to the sale, was $19.7million.  Costs associated with thecompletion of the transaction were approximately $0.4 million.

14

----

Condensed statements ofincome for the Pioneer plant, which is classified as discontinued operations,for the three months and six months ended June 30, 2006 and 2005, are presentedbelow (in thousands):    
| ** **                                  | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|---------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                  | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                  | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Sales of  petroleum products                |       | $                                | 18         |                           | $          | 2,315 |   | $ | 3,828 |   | $ | 4,457 |   |
| Other                                       |       | 11                               |       | 680                            |       | 932 |   | 1,352 |   |
| Total operating revenues                    |       | 29                               |       | 2,995                          |       | 4,760 |   | 5,809 |   |
| Purchases of  petroleum products            |       | 139                              |       | 1,806                          |       | 3,000 |   | 3,176 |   |
| Operating  expenses                         |       | —                           |       | 158                            |       | 182 |   | 296 |   |
| Depreciation and  amortization              |       | —                           |       | 154                            |       | 51 |   | 306 |   |
| Taxes – other  than income taxes       |       | —                           |       | 31                             |       | 30 |   | 61 |   |
| Total costs and expenses                    |       | 139                              |       | 2,149                          |       | 3,263 |   | 3,839 |   |
| Income (loss)  from discontinued operations |       | $                                | (110       | )                              | $          | 846 |   | $ | 1,497 |   | $ | 1,970 |   |

 

Assets of thediscontinued operations consisted of the following at December 31, 2005 (inthousands):

|                                     | ** ** | **December 31,  2005** | ** ** |
|-------------------------------------|------------|-----------------------------|------------|
| Inventories                         |       | $                           | 7          |   |
| Property, plant  and equipment, net |       | 19,812                      |       |
| Assets of discontinued  operations  |       | $                           | 19,819     |   |

 

Cash flows fromdiscontinued operations for the six months ended June 30, 2006 and 2005, arepresented below (in thousands):

|                                         | ** ** | **Six Months Ended** | ** ** |
|-----------------------------------------|------------|--------------------------------|------------|
| ** **                              | ** ** | **June 30,**              | ** ** |
| ** **                              | ** ** | **2006**                       | ** ** | **2005** | ** ** |
| Cash flows from  operating activities:  |       |                           |       |   |   |
| Net income                              |       | $                              | 19,369     |   | $ | 1,970 |   |
| Depreciation and amortization           |       | 51                             |       | 306 |   |
| Gain on sale of Pioneer plant           |       | (17,872                        | )          | — |   |
| Increase in inventories                 |       | (27                            | )          | (25 | ) |
|                                    |       |                           |       |   |   |
| Cash flow from  discontinued operations |       | $                              | 1,521      |   | 2,251 |   |
|                                         |            |                                |            |  |  |  |  |

 

15

----

**NOTE 6.  INVENTORIES**

Inventories are valued at the lower of cost (based on weightedaverage cost method) or market.  Thecosts of inventories did not exceed market values at June 30, 2006, andDecember 31, 2005.  The major componentsof inventories were as follows (in thousands):
|                                           | ** ** | **June 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|-------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| Crude oil (1)                             |       | $                       | 10,860     |                        | $          | 3,021 |   |
| Refined products                          |       | —                  |       | 4,461                       |       |
| LPGs                                      |       | 13,278                  |       | 7,403                       |       |
| Lubrication oils  and specialty chemicals |       | 6,859                   |       | 5,740                       |       |
| Materials and  supplies                   |       | 9,062                   |       | 8,203                       |       |
| Other                                     |       | 18                      |       | 241                         |       |
| Total                                     |       | $                       | 40,077     |                        | $          | 29,069 |   |

 

----

**(1) At June 30, 2006, substantially all ofour crude oil inventory was subject to forward sales contracts.**

**NOTE 7.  EQUITYINVESTMENTS**

Through one of ourindirect wholly owned subsidiaries, we own a 50% ownership interest in SeawayCrude Pipeline Company (“Seaway”).  Theremaining 50% interest is owned by ConocoPhillips.  We operate the Seaway assets.  Seaway owns a pipeline that carries mostlyimported crude oil from a marine terminal at Freeport, Texas, to Cushing,Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in theTexas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides forvarying participation ratios throughout the life of Seaway.  From June 2002 through December 31, 2005, wereceived 60% of revenue and expense of Seaway. For 2006, we are allocated 60% of revenue and expense for the periodJanuary 1, 2006, through May 12, 2006, and 40% for the period May 13, 2006,through December 31, 2006.  Our share ofrevenue and expense of Seaway is 47% for 2006. Thereafter, we will receive 40% of revenue and expense of Seaway.  During the six months ended June 30, 2006 and2005, we received distributions from Seaway of $8.5 million and $11.7 million,respectively.  During the six monthsended June 30, 2006 and 2005, we did not invest any additional funds in Seaway.

TE Products owns a 50%ownership interest in Centennial Pipeline LLC (“Centennial”), and MarathonPetroleum Company LLC (“Marathon”) owns the remaining 50% interest. Centennialowns an interstate refined petroleum products pipeline extending from the upperTexas Gulf Coast to central Illinois. During the six months ended June 30, 2006, TE Products contributed $2.5million to Centennial.  During the sixmonths ended June 30, 2005, TE Products did not invest any additional funds inCentennial.  TE Products has received nocash distributions from Centennial since its formation.

TE Products owns a 50%ownership interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”), andLouis Dreyfus Energy Services L.P. (“Louis Dreyfus”) owns the remaining 50%interest.  MB Storage owns storagecapacity at the Mont Belvieu fractionation and storage complex and a short haultransportation shuttle system that ties Mont Belvieu, Texas, to the upper TexasGulf Coast energy marketplace. MB Storage is a service-oriented, fee-basedventure serving the fractionation, refining and petrochemical industries withsubstantial capacity and flexibility for the transportation, terminaling andstorage of NGLs, LPGs and refined products. MB Storage has no commodity trading activity.  TE Products operates the facilities for MBStorage (see Note 13 regarding expected divestiture of MB Storage).

16

----

For the years ended December31, 2006 and 2005, TE Products receives the first $1.7 million per quarter (or$6.78 million on an annual basis) of MB Storage’s income before depreciationexpense, as defined in the 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 six months ended June30, 2006 and 2005, TE Products’ sharing ratios in the earnings of MB Storagewere approximately 61.4% and 62.6%, respectively.  During the six months ended June 30, 2006, TEProducts received distributions from MB Storage of $7.8 million and contributed$1.7 million to MB Storage.  During thesix months ended June 30, 2005, TE Products received distributions of $7.3 millionfrom MB Storage and contributed $1.1 million to MB Storage.

We use the equity methodof accounting to account for our investments in Seaway, Centennial and MBStorage.  Summarized combined financialinformation for Seaway, Centennial and MB Storage for the six months ended June30, 2006 and 2005, is presented below (in thousands):

|            | ** ** | **Six Months Ended  June 30,** | ** ** |
|------------|------------|-----------------------------------------------|------------|
| ** ** | ** ** | **2006**                                      | ** ** | **2005** | ** ** |
| Revenues   |       | $                                             | 82,782     |   | $ | 81,046 |   |
| Net income |       | 17,842                                        |       | 28,191 |   |
|            |            |                                               |            |  |  |  |  |

 

Summarized combinedbalance sheet information for Seaway, Centennial and MB Storage as of June 30,2006, and December 31, 2005, is presented below (in thousands):

|                         | ** ** | **June 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|-------------------------|------------|-------------------------|------------|-----------------------------|------------|
| Current assets          |       | $                       | 56,462     |                        | $          | 60,082 |   |
| Noncurrent  assets      |       | 626,258                 |       | 630,212                     |       |
| Current  liabilities    |       | 19,559                  |       | 32,242                      |       |
| Long-term debt          |       | 150,000                 |       | 150,000                     |       |
| Noncurrent  liabilities |       | 20,933                  |       | 13,626                      |       |
| Partners’ capital  |       | 492,228                 |       | 494,426                     |       |
|                         |            |                         |            |                             |            |  |  |

 

**NOTE 8.  DEBT**

## **SeniorNotes**

On January 27, 1998, TEProducts completed the issuance of $180.0 million principal amount of 6.45%Senior Notes due 2008, and $210.0 million principal amount of 7.51% SeniorNotes due 2028 (collectively the “TE Products Senior Notes”).  The 6.45% TE Products Senior Notes wereissued at a discount of $0.3 million and are being accreted to their face valueover the term of the notes.  The 6.45% TEProducts Senior Notes due 2008 may not be redeemed prior to their maturity onJanuary 15, 2008.  The 7.51% TE ProductsSenior Notes due 2028, issued at par, may be redeemed at any time after January15, 2008, at the option of TE Products, in whole or in part, at the followingredemption prices (expressed in percentages of the principal amount) during thetwelve months beginning January 15 of the years indicated:

17

----

 

|          | ** ** | **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 at100% of the principal amount, together in each case with accrued interest atthe redemption date.

The TE Products SeniorNotes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually inarrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Productsand rank pari passu with all other unsecured and unsubordinated indebtedness ofTE Products.  The indenture governing theTE Products Senior Notes contains covenants, including, but not limited to,covenants limiting the creation of liens securing indebtedness and sale andleaseback transactions.  However, theindenture does not limit our ability to incur additional indebtedness.  As of June 30, 2006, TE Products was incompliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, wecompleted the issuance of $500.0 million principal amount of 7.625% SeniorNotes due 2012.  The 7.625% Senior Noteswere issued at a discount of $2.2 million and are being accreted to their facevalue over the term of the notes.  TheSenior Notes may be redeemed at any time at our option with the payment ofaccrued interest and a make-whole premium determined by discounting remaininginterest and principal payments using a discount rate equal to the rate of theUnited States Treasury securities of comparable remaining maturity plus 35basis points.  The indenture governingour 7.625% Senior Notes contains covenants, including, but not limited to,covenants limiting the creation of liens securing indebtedness and sale andleaseback transactions.  However, theindenture does not limit our ability to incur additional indebtedness.  As of June 30, 2006, we were in compliancewith the covenants of these Senior Notes.

On January 30, 2003, wecompleted the issuance of $200.0 million principal amount of 6.125% SeniorNotes due 2013.  The 6.125% Senior Noteswere issued at a discount of $1.4 million and are being accreted to their facevalue over the term of the notes.  TheSenior Notes may be redeemed at any time at our option with the payment ofaccrued interest and a make-whole premium determined by discounting remaininginterest and principal payments using a discount rate equal to the rate of theUnited States Treasury securities of comparable remaining maturity plus 35basis points.  The indenture governingour 6.125% Senior Notes contains covenants, including, but not limited to,covenants limiting the creation of liens securing indebtedness and sale andleaseback transactions.  However, theindenture does not limit our ability to incur additional indebtedness.  As of June 30, 2006, we were in compliancewith the covenants of these Senior Notes.

The following tablesummarizes the estimated fair values of the Senior Notes as of June 30, 2006,and December 31, 2005 (in millions):

|                                                   | ** ** | ** **      | ** ** | **Fair Value**     | ** ** |
|---------------------------------------------------|------------|-----------------|------------|-------------------------|------------|
| ** **                                        | ** ** | **Face  Value** | ** ** | **June 30,  2006** | ** ** | **December 31,  2005** | ** ** |
| 6.45% TE  Products Senior Notes, due January 2008 |       | $               | 180.0      |                    | $          | 181.0 |   | $ | 183.7 |   |
| 7.625% Senior  Notes, due February 2012           |       | 500.0           |       | 526.9                   |       | 552.0 |   |
| 6.125% Senior  Notes, due February 2013           |       | 200.0           |       | 196.1                   |       | 205.6 |   |
| 7.51% TE Products  Senior Notes, due January 2028 |       | 210.0           |       | 221.1                   |       | 224.1 |   |
|                                                   |            |                 |            |                         |            |  |  |  |  |  |

 

18

----

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).

## **RevolvingCredit Facility**

On October 21, 2004, we entered into a $600.0 millionunsecured revolving credit facility with a five year term, including theissuance of letters of credit of up to $100.0 million (“Revolving CreditFacility”).  The interest rate is based,at our option, on either the lender’s base rate plus a spread, or LIBOR plus aspread in effect at the time of the borrowings. Financial covenants in the Revolving Credit Facility require that wemaintain a ratio of Consolidated Funded Debt to Pro Forma EBITDA (as definedand calculated in the facility) of less than 4.75 to 1.00 (subject toadjustment for specified acquisitions) and a ratio of EBITDA to InterestExpense (as defined and calculated in the facility) of at least 3.00 to 1.00,in each case with respect to specified twelve month periods.  Other restrictive covenants in the RevolvingCredit Facility limit our ability to, among other things, incur additionalindebtedness, make distributions in excess of Available Cash (see Note 9),incur liens, engage in specified transactions with affiliates and completemergers, acquisitions and sales of assets. On February 23, 2005, we amended our Revolving Credit Facility to removethe requirement that DEFS must at all times own, directly or indirectly, 100%of our General Partner, to allow for its acquisition by DFI (see Note 1).  During the second quarter of 2005, we used aportion of the proceeds from an equity offering in May 2005 to repay a portionof the Revolving Credit Facility.  OnDecember 13, 2005, we again amended our Revolving Credit Facility as follows:

·                  Totalbank commitments increased from $600.0 million to $700.0 million.  The amendment also provided that thecommitments under the credit facility may be increased up to a maximum of$850.0 million upon our request, subject to lender approval and thesatisfaction of certain other conditions.

·                  Thefacility fee and the borrowing rate then in effect were reduced by 0.275%.

·                  Thematurity date of the credit facility was extended from October 21, 2009, toDecember 13, 2010.  Also under the termsof the amendment, we may request up to two, one-year extensions of the maturitydate.  These extensions, if requested,will become effective subject to lender approval and satisfaction of certainother conditions.

·                  The amendment also removed the $100.0million limit on the total amount of standby letters of credit that can beoutstanding under the credit facility.

At June 30, 2006, $445.0 million was outstanding underthe Revolving Credit Facility at a weighted average interest rate of 5.8%.  At June 30, 2006, we were in compliance withthe covenants of this credit facility. Please see Note 16 for informationregarding an amendment to the Revolving Credit Facility.

19

----

The following table summarizes the principal amountsoutstanding under all of our debt instruments as of June 30, 2006, and December31, 2005 (in thousands):

|                                                                         | ** ** | **June 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|-------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|
|                                                                    |       |                    |       |                        |       |
| Revolving Credit  Facility, due December 2010                           |       | $                       | 445,000    |                        | $          | 405,900 |   |
| 6.45% TE  Products Senior Notes, due January 2008                       |       | 179,952                 |       | 179,937                     |       |
| 7.625% Senior  Notes, due February 2012                                 |       | 498,770                 |       | 498,659                     |       |
| 6.125% Senior  Notes, due February 2013                                 |       | 199,059                 |       | 198,988                     |       |
| 7.51% TE  Products Senior Notes, due January 2028                       |       | 210,000                 |       | 210,000                     |       |
| Total borrowings                                                        |       | 1,532,781               |       | 1,493,484                   |       |
| Adjustment to  carrying value associated with hedges of fair valueswaps |       | 18,896                  |       | 31,537                      |       |
| Total Debt Instruments                                                  |       | $                       | 1,551,677  |                        | $          | 1,525,021 |   |

 

**Letter of Credit**

At June 30, 2006, we had outstanding a $14.2 millionstandby letter of credit in connection with crude oil purchased in the secondquarter of 2006.  The payable related tothese purchases of crude oil is expected to be paid during the third quarter of2006.

**NOTE 9.  PARTNERS’ CAPITAL AND DISTRIBUTIONS**

## **QuarterlyDistributions of Available Cash**

We make quarterly cash distributions of all of our availablecash, generally defined in our Partnership Agreement as consolidated cashreceipts less consolidated cash disbursements and cash reserves established bythe General Partner in its reasonable discretion (“Available Cash”).  Pursuant to the Partnership Agreement, theGeneral Partner receives incremental incentive cash distributions whenunitholders’ cash distributions exceed certain target thresholds 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 |       | 50              | %          | 50          | %          |

 

20

----

The following table reflects the allocation of totaldistributions paid during the six months ended June 30, 2006 and 2005 (inthousands, except per Unit amounts):

|                                         | ** ** | **Six Months Ended  June 30,** | ** ** |
|-----------------------------------------|------------|-----------------------------------------------|------------|
| ** **                              | ** ** | **2006**                                      | ** ** | **2005** | ** ** |
| Limited Partner  Units                  |       | $                                             | 94,451     |   | $ | 83,473 |   |
| General Partner  Ownership Interest     |       | 1,928                                         |       | 1,703 |   |
| General Partner  Incentive              |       | 37,406                                        |       | 32,140 |   |
| Total Cash Distributions Paid           |       | $                                             | 133,785    |   | $ | 117,316 |   |
| Total Cash  Distributions Paid Per Unit |       | $                                             | 1.350      |   | $ | 1.325 |   |

 

On August7, 2006, we will pay a cash distribution of $0.675 per Unit for the quarterended June 30, 2006.  The second quarter2006 cash distribution will total $72.4 million.

**General Partner’sInterest**

As of June 30, 2006, and December 31, 2005, we haddeficit balances of $70.1 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 sixmonths ended June 30, 2006, the General Partner was allocated $30.7 million(representing 29.4%) of our net income and received $39.3 million in cashdistributions.

Capital Accounts, as defined under our PartnershipAgreement, are maintained for our General Partner and our limitedpartners.  The Capital Account provisionsof our Partnership 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.  AtJune 30, 2006, and December 31, 2005, the General Partner’s Capital Accountbalance 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 six months ended June 30, 2006, resulted in deficitsin the General Partner’s equity account at December 31, 2005, and June 30,2006.  Future cash distributions thatexceed net income will result in an increase in the deficit balance in theGeneral Partner’s equity account.

21

----

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.

**EPCO Proposal**

OnApril 20, 2006, EPCO submitted a proposal to the Audit and Conflicts Committeeof our General Partner’s Board of Directors to reduce the General Partner’smaximum percentage interest in our quarterly distributions from 50% to 25% withrespect to that portion of our quarterly cash distribution to partners thatexceeds $0.325 per Unit.  In exchange forthe agreement to reduce its maximum percentage interest in our quarterlydistributions, our General Partner would receive a number of newly-issued Unitsthat, based on the distribution rate and the number of Units outstanding at thetime of issuance, would result in our General Partner receiving cashdistributions from the newly-issued Units and from its reduced maximumpercentage interest in our quarterly distributions that would approximatelyequal the cash distributions our General Partner would have received from itsmaximum percentage interest in our quarterly distributions withoutreduction.  Based on our distributionrate and outstanding Units as of the date of the filing of this Report, thenumber of newly-issued Units issued to the General Partner would beapproximately 14.1 million.  We filed withthe Securities and Exchange Commission a preliminary proxy statement thatoutlines the EPCO proposal for which we will solicit approval from ourunitholders at a special meeting.  Theproxy statement also contains separate proposals for the adoption of anemployee Unit purchase plan and a long term incentive plan.

**NOTE 10. RELATED PARTY TRANSACTIONS**

**EPCO and Affiliates 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).

22

----

The following tablesummarizes the related party transactions with EPCO and affiliates and DEFS andaffiliates for the three months and six months ended June 30, 2006 and 2005 (inmillions):
| ** **                                        | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|---------------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                        | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                        | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                              |       |                             |       |                           |       |   |   |   |   |
| Revenues from  EPCO and affiliates: (1)           |       |                             |       |                           |       |   |   |   |   |
| Sales of petroleum products                       |       | $                                | 2.0        |                           | $          | — |   | $ | 2.1 |   | $ | — |   |
| Transportation – NGLs                        |       | 2.9                              |       | 2.0                            |       | 4.6 |   | 2.9 |   |
| Transportation – LPGs                        |       | 0.6                              |       | 0.7                            |       | 2.4 |   | 1.6 |   |
|                                              |       |                             |       |                           |       |   |   |   |   |
| Costs and  Expenses from EPCO and affiliates: (1) |       |                             |       |                           |       |   |   |   |   |
| Payroll, administrative and other (2)             |       | 33.4                             |       | 8.8                            |       | 62.4 |   | 8.8 |   |
| Purchases of petroleum products                   |       | 10.8                             |       | —                         |       | 16.4 |   | — |   |
|                                              |       |                             |       |                           |       |   |   |   |   |
| 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 (5) (4)         |       | —                           |       | —                         |       | — |   | 16.2 |   |
| Purchases of  petroleum products                  |       | —                           |       | —                         |       | — |   | 38.5 |   |
|                                                   |            |                                  |            |                                |            |  |  |  |  |  |  |  |  |

 

----

(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, wehave assumed these activities.

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

At June 30, 2006 and December 31, 2005, we had areceivable from EPCO and affiliates of $1.1 million and $4.3 million, respectively,related to sales and transportation services provided to EPCO andaffiliates.  At June 30, 2006 andDecember 31, 2005, we had a payable to EPCO and affiliates of $16.9 million and$9.8 million, respectively, related to direct payroll, payroll related costsand other operational related costs.

Beginning February 24, 2005, the majority of ourinsurance coverage, including property, liability, business interruption, autoand directors and officers’ liability insurance, was obtained throughEPCO.  For the three months and sixmonths ended June 30, 2006, we incurred insurance expense related to premiumspaid by EPCO of $4.4 million and $7.1 million, respectively, and $2.1 millionfor the three months and six months ended June 30, 2005.

23

----

At June 30, 2006 and December 31, 2005, we hadinsurance reimbursement receivables due from EPCO of $1.8 million and $1.3million, 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 from the Jonahand Pinedale fields, located in southwest Wyoming to an affiliate of Enterprisefor $38.0 million.  We recognized a gainof approximately $17.9 million on the sale of this asset (see Note 5).

*JonahJoint Venture*

On August 1, 2006,Enterprise (through an affiliate) became our joint venture partner by acquiringan interest in our Jonah Gas Gathering Company, the partnership through whichwe owned the Jonah system.  Prior toentering into the joint venture, Enterprise had managed the construction of thePhase V expansion and funded the initial costs under a letter of intent weentered into in February 2006.  Inconnection with the joint venture arrangement, we and Enterprise intend tocontinue the Phase V expansion, which is expected to increase the systemcapacity of the Jonah system from 1.5 billion cubic feet per day (“Bcf/d”) to approximately2.4 Bcf/d 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 to approximately2.0 Bcf/d, is scheduled to be completed in the first quarter of 2007 at anestimated cost of approximately $275.0 million. The second portion of the expansion is expected to cost approximately$140.0 million and be completed by the end of 2007.  

 

Enterprise will continueto 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 50% of the incremental cash flow fromportions of the system placed in service as part of the expansion.  After subsequent milestones are achieved, weand Enterprise will share distributions based on a formula that takes intoaccount the capital contributions of the parties, including expenditures by usprior to the expansion.  In the thirdquarter of 2006, we will reimburse Enterprise for 50% of the Phase V costincurred by it through August 1, 2006 (including its cost of capital).  From August 1, 2006, we and Enterpriseequally share the costs of the Phase V expansion.  Upon completion of the expansion project andbased on the formula in the partnership agreement, we expect to own an interestin Jonah Gas Gathering Company of approximately 80%, with Enterprise owning theremaining 20% and serving as operator and with further costs being allocatedbased on such ownership interests.  Thejoint venture will be governed by a management committee comprised of tworepresentatives approved by Enterprise and two representatives approved by us,each with equal voting power.  Thistransaction was reviewed and approved by the Audit and Conflicts Committee ofthe board of directors of our General Partner. Through June 30, 2006, Enterprise had incurred approximately $106.9million of costs related to the expansion, of which $97.8 million has been paidto vendors by Enterprise.

 

**NOTE 11.  EMPLOYEEBENEFIT PLANS**

## **RetirementPlans**

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 noadditional pay credits after that date, and all plan participants were 100%vested regardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, 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

24

----

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 third 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.

The components of net pension benefits costs for theTEPPCO RCBP and the TEPPCO SBP for the three months and six months ended June30, 2006 and 2005, were as follows (in thousands):

|                                                | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|------------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                     | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                     | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
| Service cost  benefit earned during the period |       | $                                | —     |                           | $          | 1,069 |   | $ | — |   | $ | 2,099 |   |
| Interest cost on  projected benefit obligation |       | 255                              |       | 234                            |       | 506 |   | 468 |   |
| Expected return  on plan assets                |       | (115                             | )          | (223                           | )          | (236 | ) | (520 | ) |
| Amortization of  prior service cost            |       | —                           |       | 1                              |       | — |   | 3 |   |
| Amortization of  actuarial losses              |       | 35                               |       | 30                             |       | 70 |   | 56 |   |
| SFAS 88  curtailment charge                    |       | —                           |       | 50                             |       | — |   | 50 |   |
| Net pension  benefits costs                    |       | $                                | 175        |                           | $          | 1,161 |   | $ | 340 |   | $ | 2,156 |   |

 

## **OtherPostretirement 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, towards retiredemployee medical costs.  The retiree paidall 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.  Employees eligiblefor these benefits received them through December 31, 2005, however, effectiveDecember 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 the TEPPCOOPB.  The employees participating in thisplan at that time were transferred to DEFS, who is expected to providepostretirement benefits to these retirees. We

25

----

recorded a one-time settlement to DEFS in the thirdquarter of 2005 of $0.4 million for the remaining postretirement benefits.

The components of net postretirement benefits cost forthe TEPPCO OPB for the three months and six months ended June 30, 2006 and2005, were as follows (in thousands):

|                                                                 | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                                      | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                                      | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
| Service cost  benefit earned during the period                  |       | $                                | —     |                           | $          | 32 |   | $ | — |   | $ | 81 |   |
| Interest cost on  accumulated postretirement benefit obligation |       | —                           |       | 28                             |       | — |   | 69 |   |
| Amortization of  prior service cost                             |       | —                           |       | 21                             |       | — |   | 53 |   |
| Recognized net  actuarial loss                                  |       | —                           |       | 2                              |       | — |   | 4 |   |
| SFAS 106  curtailment credit                                    |       | —                           |       | (1,676                         | )          | — |   | (1,676 | ) |
| Net  postretirement benefits costs                              |       | $                                | —     |                           | $          | (1,593 | ) | $ | — |   | $ | (1,469 | ) |

 

## Effective June 1, 2005, the payroll functionsperformed by DEFS for our General Partner were transferred from DEFS toEPCO.  For those employees who werereceiving certain other postretirement benefits at the time of the acquisitionof our General Partner by DFI, DEFS is expected to continue to provide thesebenefits to those employees.  EffectiveJune 1, 2005, EPCO began providing certain other postretirement benefits tothose employees who became eligible for the benefits after June 1, 2005, andwill charge those benefit related costs to us. As a result of these changes, we recorded a $1.2 million reduction inour other postretirement obligation in June 2005.

## **EstimatedFuture 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 12. SEGMENT INFORMATION**

We have three reporting segments:

·                  Our Downstream Segment, which isengaged in the transportation and storage of refined products, LPGs andpetrochemicals;

·                  Our Upstream Segment, which isengaged in the gathering, transportation, marketing and storage of crude oiland distribution of lubrication oils and specialty chemicals; and

·                  Our Midstream Segment, which isengaged in the gathering of natural gas, fractionation of NGLs andtransportation 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

26

----

largest operating expense items of the DownstreamSegment are labor and electric power.  Wegenerally realize higher revenues during the first and fourth quarters of eachyear since our operations are somewhat seasonal. Refined products volumes aregenerally higher during the second and third quarters because of greater demandfor gasolines during the spring and summer driving seasons. LPGs volumes aregenerally higher from November through March due to higher demand in theNortheast 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 also includes ourequity investments in Centennial and MB Storage (see Note 7).

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 7).  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 MidstreamSegment revenues are earned from the gathering of natural gas in the GreenRiver Basin in southwestern Wyoming, through Jonah, and the gathering of coalbed methane and conventional natural gas in the San Juan Basin in New Mexicoand Colorado, through Val Verde; transportation of NGLs from two trunkline NGLpipelines in South Texas, two NGL pipelines in East Texas and a pipeline system(Chaparral) from West Texas and New Mexico to Mont Belvieu; and thefractionation of NGLs in Colorado. Operating results of the Pioneer plant for the three months and sixmonths ended June 30, 2006 and 2005 are shown as discontinued operations.

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.  Implementationof EITF 04-13 as of April 1, 2006, reduced gross revenues and purchases for thethree months ended June 30, 2006, but did not have a material effect on ourfinancial 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 $313.7 million for the periods ended June 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 ended June 30, 2005, and for the six months ended June 30, 2006and 2005, are approximately $326.9 million, $589.1 million and $403.3 million,respectively.

27

----

The tablebelow includes financial information by reporting segment for the three monthsand six months ended June 30, 2006 and 2005 (in thousands):
| ** **                                                                   | ** ** | **Three Months Ended June 30, 2006** | ** ** |
|------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                   | ** ** | **Downstream  Segment**                                       | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|                                                                         |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |
| Sales of  petroleum products                                                 |       | $                                                             | —     |   | $ | 2,273,878 |   | $ | 13,776 |   | $ | 2,287,654 |   | $ | (388 | ) | $ | 2,287,266 |   |
| Operating  revenues                                                          |       | 69,333                                                        |       | 13,134 |   | 56,569 |   | 139,036 |   | (1,250 | ) | 137,786 |   |
| Purchases of  petroleum products                                             |       | —                                                        |       | 2,243,143 |   | 12,949 |   | 2,256,092 |   | (1,336 | ) | 2,254,756 |   |
| Operating  expenses, including power                                         |       | 37,743                                                        |       | 18,160 |   | 18,709 |   | 74,612 |   | (302 | ) | 74,310 |   |
| General and  administrative expenses                                         |       | 4,701                                                         |       | 1,870 |   | 2,587 |   | 9,158 |   | — |   | 9,158 |   |
| Depreciation and  amortization expense                                       |       | 10,133                                                        |       | 3,494 |   | 15,049 |   | 28,676 |   | — |   | 28,676 |   |
| Gains on sales  of assets                                                    |       | (18                                                           | )          | — |   | — |   | (18 | ) | — |   | (18 | ) |
| Operating income                                                             |       | 16,774                                                        |       | 20,345 |   | 21,051 |   | 58,170 |   | — |   | 58,170 |   |
| Equity earnings  (losses)                                                    |       | (2,366                                                        | )          | 5,040 |   | — |   | 2,674 |   | — |   | 2,674 |   |
| Other income,  net                                                           |       | 185                                                           |       | 225 |   | 44 |   | 454 |   | — |   | 454 |   |
| Earnings before  interest, deferred income taxes and discontinued operations |       | $                                                             | 14,593     |   | $ | 25,610 |   | $ | 21,095 |   | $ | 61,298 |   | $ | — |   | $ | 61,298 |   |

 
| ** **                                                                         | ** ** | **Three Months Ended June 30, 2005** | ** ** |
|------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Downstream  Segment**                                       | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|                                                                               |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |
| Sales of  petroleum products                                                       |       | $                                                             | —     |   | $ | 1,961,302 |   | $ | — |   | $ | 1,961,302 |   | $ | — |   | $ | 1,961,302 |   |
| Operating  revenues                                                                |       | 63,438                                                        |       | 11,698 |   | 51,656 |   | 126,792 |   | (709 | ) | 126,083 |   |
| Purchases of  petroleum products                                                   |       | —                                                        |       | 1,942,599 |   | — |   | 1,942,599 |   | (709 | ) | 1,941,890 |   |
| Operating  expenses, including power                                               |       | 35,171                                                        |       | 13,995 |   | 10,342 |   | 59,508 |   | — |   | 59,508 |   |
| General and  administrative expenses                                               |       | 3,509                                                         |       | 1,219 |   | 1,372 |   | 6,100 |   | — |   | 6,100 |   |
| Depreciation and  amortization expense                                             |       | 9,801                                                         |       | 3,651 |   | 12,686 |   | 26,138 |   | — |   | 26,138 |   |
| Gains on sales  of assets                                                          |       | (15                                                           | )          | (53 | ) | — |   | (68 | ) | — |   | (68 | ) |
| Operating income                                                                   |       | 14,972                                                        |       | 11,589 |   | 27,256 |   | 53,817 |   | — |   | 53,817 |   |
| Equity earnings  (losses)                                                          |       | (246                                                          | )          | 7,997 |   | — |   | 7,751 |   | — |   | 7,751 |   |
| Other income,  net                                                                 |       | 121                                                           |       | (46 | ) | 60 |   | 135 |   | — |   | 135 |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                             | 14,847     |   | $ | 19,540 |   | $ | 27,316 |   | $ | 61,703 |   | $ | — |   | $ | 61,703 |   |

 

28

----

 
| ** **                                                                         | ** ** | **Six Months Ended June 30, 2006** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Downstream**                                              | ** ** | **Upstream** | ** ** | **Midstream** | ** ** | **Segments** | ** ** | **Partnership** | ** ** | ** ** | ** ** |
| ** **                                                                         | ** ** | **Segment**                                                 | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** | **and Other** | ** ** | **Consolidated** | ** ** |
| ** **                                                                         | ** ** | ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Sales of petroleum  products                                                       |       | $                                                           | —     |   | $ | 4,674,314 |   | $ | 13,776 |   | $ | 4,688,090 |   | $ | (4,478 | ) | $ | 4,683,612 |   |
| Operating revenues                                                                 |       | 143,400                                                     |       | 24,280 |   | 112,946 |   | 280,626 |   | (2,817 | ) | 277,809 |   |
| Purchases of petroleum  products                                                   |       | —                                                      |       | 4,619,539 |   | 12,949 |   | 4,632,488 |   | (6,692 | ) | 4,625,796 |   |
| Operating expenses,  including power                                               |       | 73,145                                                      |       | 34,962 |   | 32,917 |   | 141,024 |   | (603 | ) | 140,421 |   |
| General and  administrative expenses                                               |       | 9,795                                                       |       | 3,677 |   | 4,887 |   | 18,359 |   | — |   | 18,359 |   |
| Depreciation and  amortization expense                                             |       | 20,430                                                      |       | 6,765 |   | 30,238 |   | 57,433 |   | — |   | 57,433 |   |
| Gains on sales of  assets                                                          |       | (25                                                         | )          | — |   | (1,371 | ) | (1,396 | ) | — |   | (1,396 | ) |
| Operating income                                                                   |       | 40,055                                                      |       | 33,651 |   | 47,102 |   | 120,808 |   | — |   | 120,808 |   |
| Equity earnings  (losses)                                                          |       | (3,632                                                      | )          | 7,295 |   | — |   | 3,663 |   | — |   | 3,663 |   |
| Other income, net                                                                  |       | 964                                                         |       | 269 |   | 120 |   | 1,353 |   | — |   | 1,353 |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                           | 37,387     |   | $ | 41,215 |   | $ | 47,222 |   | $ | 125,824 |   | $ | — |   | $ | 125,824 |   |

 
| ** **                                                                         | ** ** | **Six Months Ended June 30, 2005** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **Downstream**                                              | ** ** | **Upstream** | ** ** | **Midstream** | ** ** | **Segments** | ** ** | **Partnership** | ** ** | ** ** | ** ** |
| ** **                                                                         | ** ** | **Segment**                                                 | ** ** | **Segment** | ** ** | **Segment** | ** ** | **Total** | ** ** | **and Other** | ** ** | **Consolidated** | ** ** |
| ** **                                                                         | ** ** | ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Sales of petroleum  products                                                       |       | $                                                           | —     |   | $ | 3,346,369 |   | $ | — |   | $ | 3,346,369 |   | $ | — |   | $ | 3,346,369 |   |
| Operating revenues                                                                 |       | 141,605                                                     |       | 23,411 |   | 101,840 |   | 266,856 |   | (2,049 | ) | 264,807 |   |
| Purchases of petroleum  products                                                   |       | —                                                      |       | 3,315,029 |   | — |   | 3,315,029 |   | (2,049 | ) | 3,312,980 |   |
| Operating expenses, including  power                                               |       | 68,155                                                      |       | 27,932 |   | 22,572 |   | 118,659 |   | — |   | 118,659 |   |
| General and  administrative expenses                                               |       | 7,711                                                       |       | 2,727 |   | 2,867 |   | 13,305 |   | — |   | 13,305 |   |
| Depreciation and amortization  expense                                             |       | 19,362                                                      |       | 7,152 |   | 25,235 |   | 51,749 |   | — |   | 51,749 |   |
| Gains on sales of  assets                                                          |       | (107                                                        | )          | (52 | ) | (407 | ) | (566 | ) | — |   | (566 | ) |
| Operating income                                                                   |       | 46,484                                                      |       | 16,992 |   | 51,573 |   | 115,049 |   | — |   | 115,049 |   |
| Equity earnings  (losses)                                                          |       | (2,067                                                      | )          | 13,912 |   | — |   | 11,845 |   | — |   | 11,845 |   |
| Other income, net                                                                  |       | 270                                                         |       | 29 |   | 102 |   | 401 |   | — |   | 401 |   |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                                           | 44,687     |   | $ | 30,933 |   | $ | 51,675 |   | $ | 127,295 |   | $ | — |   | $ | 127,295 |   |

 

29

----

The following tableincludes total assets, capital expenditures, and significant non-cash investingactivities for each segment as of and for the periods ended June 30, 2006, andDecember 31, 2005 (in thousands):

 
| ** **                     | ** ** | **Downstream** | ** ** | **Upstream** | ** ** | **Midstream** | ** ** | **Segments** | ** ** | **Partnership**    | ** ** | ** **       | ** ** |
|--------------------------------|------------|----------------|------------|--------------|------------|---------------|------------|--------------|------------|--------------------|------------|------------------|------------|
| ** **                     | ** ** | **Segment**    | ** ** | **Segment**  | ** ** | **Segment**   | ** ** | **Total**    | ** ** | **and Other** | ** ** | **Consolidated** | ** ** |
| June 30, 2006:                 |       |           |       |         |       |          |       |         |       |               |       |             |       |
| Total assets                   |       | $              | 1,059,421  |         | $          | 1,419,512     |       | $            | 1,227,797  |               | $          | 3,706,730        |       | $ | (19,595 | ) | $ | 3,687,135 |   |
| Capital expenditures           |       | 27,273         |       | 22,223       |       | 32,955        |       | 82,451       |       | 12                 |       | 82,463           |       |
| ** **                     | ** ** | ** **     | ** ** | ** **   | ** ** | ** **    | ** ** | ** **   | ** ** | ** **         | ** ** | ** **       | ** ** |
| 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 six months ended June 30, 2006 and 2005 (in thousands):
| ** **                                                                         | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                                         | ** ** | **2006**                                        | ** ** | **2005**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                                                               | ** ** | ** **                                      |       |                                          | ** ** | ** ** |   |   | ** ** |
| Earnings before  interest, deferred income tax expense and discontinued operations |       | $                                               | 61,298     |                                          | $          | 61,703 |   | $ | 125,824 |   | $ | 127,295 |   |
| Interest expense  – net                                                       |       | (19,198                                         | )          | (21,627                                       | )          | (40,341 | ) | (40,914 | ) |
| Income before deferred income tax expense                                          |       | 42,100                                          |       | 40,076                                        |       | 85,483 |   | 86,381 |   |
| Deferred income  tax expense                                                       |       | 514                                             |       | —                                        |       | 514 |   | — |   |
| Income from continuing operations                                                  |       | 41,586                                          |       | 40,076                                        |       | 84,969 |   | 86,381 |   |
| Discontinued  operations                                                           |       | (122                                            | )          | 846                                           |       | 19,369 |   | 1,970 |   |
| Net income                                                                         |       | $                                               | 41,464     |                                          | $          | 40,922 |   | $ | 104,338 |   | $ | 88,351 |   |

 

**NOTE 13.  COMMITMENTS AND CONTINGENCIES**

**Litigation**

In the fall of1999, the General Partner and TE Products were named as defendants in alawsuit in Jackson County Circuit Court, Jackson County, Indiana, styled *Ryan E. McCleery and Marcia S. McCleery, et al. andMichael 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 causedthe materials 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.  Althoughwe did not settle with all plaintiffs and we therefore remain named parties inthe *Michael and Linda Robson, et al. v.Texas Eastern Corporation, et al*. action, a co-defendant has agreed,by Cooperative Defense Agreement, to fund the defense and satisfy allfinal judgments which might be rendered with the remaining claims

30

----

asserted against us.  Consequently, we do not believe that theoutcome of these remaining claims will have a material adverse effect on ourfinancial 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 May 2003, the General Partner was named as adefendant in a lawsuit styled *John R. James, et al. v. JGraves Insulation Company, et al.* as filed in the first JudicialDistrict Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are allegedto have suffered damages as a result of alleged exposure to asbestos-containingproducts and materials.  According to thepetition and as a result of a preliminary investigation, the General Partnerbelieves that the only claim asserted against it results from one individualfor the period from July 1971 through June 1972, who is alleged to have workedon a facility owned by the General Partner’s predecessor.  This period represents a small portion of thetotal alleged exposure period from January 1964 through December 2001 for thisindividual.  The individual’s claimsinvolve numerous employers and alleged job sites.  In response to the exception filed on behalfof the General Partner, the plaintiffs have agreed to voluntarily dismiss theGeneral Partner from the suit.  We do notbelieve that the outcome of this lawsuit will have a material adverse effect onour 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 matter reside orformerly resided on land that was once the site of a refinery owned by one ofour co-defendants.  The former refineryis located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arisingfrom alleged contamination of the refinery property.  The plaintiffs have recently pursuedcertification as a class and have significantly increased their demand toapproximately $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 thisproperty.  While we cannot predict theultimate outcome, we do not believe that the outcome of this lawsuit will havea material adverse effect on our financial position, results of operations orcash 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 processing andfractionation plants, pipelines, and associated facilities are subject tomultiple environmental obligations and potential liabilities under a variety offederal, state and local laws and regulations. These include, withoutlimitation: the Comprehensive Environmental Response, Compensation, andLiability Act; the Resource Conservation and Recovery Act; the Clean Air Act;the Federal Water Pollution Control Act or the Clean Water Act; the OilPollution Act; and analogous state and local laws and regulations. Such lawsand

31

----

regulations affect many aspects of our present and future operations,and generally require us to obtain and comply with a wide variety ofenvironmental registrations, licenses, permits, inspections and otherapprovals, with respect to air emissions, water quality, wastewater discharges,and solid and hazardous waste management. Failure to comply with theserequirements may expose us to fines, penalties and/or interruptions in ouroperations that could influence our results of operations. If an accidentalleak, spill or release of hazardous substances occurs at any facilities that weown, operate or otherwise use, or where we send materials for treatment ordisposal, we could be held jointly and severally liable for all resultingliabilities, including investigation, remedial and clean-up costs. Likewise, wecould be required to remove or remediate previously disposed wastes or propertycontamination, including groundwater contamination.  Any or all of this could materially affectour results of operations and cash flows.

 

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 regulationcompliance or remediation, and actual future expenditures may be different fromthe amounts we currently anticipate. Revised or additional regulations thatresult in increased compliance costs or additional operating restrictions,particularly if those costs are not fully recoverable from our customers, couldhave  a material adverse effect on ourbusiness, financial position, results of operations and cash flows.  At June 30, 2006, and December 31, 2005, wehave an accrued liability of $2.1 million and $2.4 million, respectively,related to sites requiring environmental remediation activities.

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 June 30, 2006, wehave an accrued liability of $0.2 million for remediation costs at our Arcadiafacility.  We do not expect that thecompletion of the remediation program proposed to the LDEQ will have a futurematerial adverse effect on our financial position, results of operations orcash 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, is seekinga civil penalty against us for alleged violations of the Clean Water Act (“CWA”)arising out of this release, as well as three smaller spills at other locationsin 2004 and 2005.  We have agreed withthe DOJ on a proposed penalty of $2.865 million, along with our commitment toimplement additional spill prevention measures, and expect to finalize thesettlement in the third quarter of 2006. We do not expect this settlement to have a material adverse effect onour financial position, results of operations or cash 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 has resulted in claims by neighboring landowners,for which we anticipate a financial settlement in the range of $0.7 million to$0.8 million.  In addition, the releaseresulted in a Corrective 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

32

----

100%.  We have a 50% ownershipinterest in Seaway, and any settlement should be covered by our insurance.  We do not expect the completion of ourobligations relating to the Colbert release to have a material adverse effecton our financial position, results of operations or 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 proposed penalty of $0.1 million.  We are currently in settlement discussionswith OSHA.  We do not expect that anysettlement of this citation will have a material adverse effect on ourfinancial 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.

On March 26, 2004, a decision in *ARCOProducts Co., et al. v. SFPP*, Docket Nos. OR96-2-000 et al., wasissued by the FERC, which made several significant determinations with respectto finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”).  The decision largely clarifies, but does notfully quantify, the standard required for a complainant to demonstrate that anoil pipeline’s rates are no longer subject to the rate protection of the EP Actby demonstrating that a substantial change in circumstances has occurred since1992 with respect to the basis of the rates being challenged.  In the decision, the FERC found that alimited number of rate elements will significantly affect the economic basisfor a pipeline company’s rates.  Theelements identified in the decision are volume changes, allowed total returnand total cost-of-service (including major cost elements such as rate base, taxrates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rates and incometax allowances as stand-alone factors. Judicial review of that decision, which has been sought by a number ofparties to the case, is currently pending before the U.S. Court of Appeals forthe District of Columbia Circuit.  Wehave not yet determined the impact, if any, that the decision, if it isultimately upheld, would have on our rates if they were reviewed under thecriteria of this decision.

On July 20, 2004, the District of Columbia Circuitissued an opinion in *BP West Coast Products LLCv. FERC*.  In reviewing aseries of orders involving SFPP, L.P., the court held among other things thatthe FERC had not adequately justified its policy of providing an oil pipelinelimited partnership with an income tax allowance equal to the proportion of itsincome attributable to partnership interests owned by corporate partners.  Under the FERC’s initial ruling, SFPP, L.P.was permitted an income tax allowance on its cost-of-service filing for thepercentage of its net operating (pre-tax) income attributable to partnershipunits held by corporations, and was denied an income tax allowance equal to thepercentage attributable to partnership units held by non-corporatepartners.  The court remanded the caseback to the FERC for further review.  Followingthe court’s remand, on May 4, 2005, the FERC issued its Policy Statement onIncome Tax Allowances, which permits regulated partnerships, limited liabilitycompanies and other pass-through entities an income tax allowance on theirincome attributable to any owner that has an actual or potential income taxliability on that income, regardless whether the owner is an individual orcorporation.  If there is more than onelevel of pass-through entities, the regulated company income must be traced towhere the ultimate tax liability lies. The Policy Statement is to be applied in individual cases, and theregulated entity bears the burden of proof to establish the tax status of itsowners.  On December 16, 2005, the FERCissued the first of those decisions, in an order involving SFPP (the “SFPPOrder”).  The SFPP Order confirmed that amaster limited partnership is entitled to a tax allowance with respect topartnership income for which there is an “actual or potential income taxliability” and determined that a unitholder that is required to file a Form1040 or

33

----

Form 1120 tax return that includes partnership income or loss ispresumed to have an actual or potential income tax liability sufficient tosupport a tax allowance on that partnership income.  The FERC also established certain otherpresumptions, including that corporate unitholders are presumed to be taxed atthe maximum corporate tax rate of 35% while individual unitholders (and certainother types of unitholders taxed like individuals) are presumed to be taxed ata 28% tax rate.  The SFPP Order remainssubject to further administrative proceedings, including review by the FERC ofcompliance filings made by SFPP on March 7, 2006, as well as judicial review.  The ultimate outcome of the FERC’s inquiry onincome tax allowance should not affect our current rates and rate structurebecause our rates are not based on cost-of-service methodology.  However, the outcome of the income taxallowance would become relevant to us should we (i) elect in the future to usecost-of-service to support our rates, or (ii) be required to use suchmethodology to defend our indexed rates.

 

**Other**

Centennial entered into credit facilities totaling$150.0 million, and as of June 30, 2006, $150.0 million was outstanding underthose credit facilities, of which $140.0 million expires in 2024, and $10.0million 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 thecredit facilities were used to fund construction and conversion costs of itspipeline system.  Prior to the expirationof the long-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 June 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 $4.5 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.

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.

On February 24,2005, the General Partner was acquired from DEFS by DFI.  The General Partner owns a 2% general partnerinterest in us and is the general partner of the Partnership.  On March 11, 2005, the Bureau of Competitionof the Federal Trade Commission (“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 have cooperatedfully with this investigation.  In orderto resolve the matter, we and our General Partner have negotiated with thestaff of the FTC and agreed to a proposal that, if accepted by the FTC, wouldrequire the divestiture of our 50% ownership interest in MB Storage and certainrelated assets.

34

----

**NOTE 14. 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 six months ended June 30,2006, the components of accumulated other comprehensive income reflected on ourconsolidated balance sheets were composed of crude oil hedges and interest rateswaps.  The crude oil hedges mature inDecember 2006 and December 2007.  Whilethe crude oil hedges are in effect, changes in their fair values, to the extentthe hedges are effective, are recognized in accumulated other comprehensiveincome until they are recognized in net income in future periods.  The interest rate swaps mature in January2008, are related to our variable rate revolving credit facility and aredesignated as cash flow hedges beginning in the third quarter of 2006.

The accumulatedbalance of other comprehensive loss related to our cash flow hedge is asfollows (in thousands):

 

| Balance at December 31, 2005                              |   | $      | 11     |   |
|-----------------------------------------------------------|--------|--------|--------|--------|
| Changes in fair values of interest rate cash flow  hedges |   | 1,671  |   |
| Changes in fair values of interest rate cash flow  hedges |   | (1,671 | )      |
| Changes in fair values of crude oil cash flow hedges      |   | (273   | )      |
| Balance at June 30,  2006                                 |   | $      | (262   | )      |

 

**NOTE 15.  SUPPLEMENTALCONDENSED CONSOLIDATING FINANCIAL INFORMATION**

TE Products Pipeline Company, Limited Partnership,TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company andVal Verde Gas Gathering Company, L.P., have issued guarantees of our debt securities.  The guarantees are full, unconditional, andjoint and several.  These significantsubsidiaries, TE Products Pipeline Company, Limited Partnership, TCTM, L.P.,TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde GasGathering Company, L.P., are collectively referred to as the “GuarantorSubsidiaries.”  The guarantees issued byJonah Gas Gathering Company, which were outstanding during the periodspresented below, were released on July 31, 2006, in connection with the jointventure entered into with Enterprise on that date (see Note 16).

The followingsupplemental condensed consolidating financial information reflects ourseparate accounts, the combined accounts of the Guarantor Subsidiaries, thecombined accounts of our other non-guarantor subsidiaries, the combinedconsolidating adjustments and eliminations and our consolidated accounts forthe dates and periods indicated.  Forpurposes of the following consolidating information, our investments in oursubsidiaries and the Guarantor Subsidiaries’ investments in their subsidiariesare accounted for under the equity method of accounting.

35

----

 
| ** **                                    | ** ** | **June 30, 2006**           | ** ** |
|-----------------------------------------------|------------|---------------------------------------|------------|
| ** **                                    | ** ** | **TEPPCO  Partners, L .P.** | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                    | ** ** | **(in thousands)**               | ** ** |
| Assets                                        |       | ** **                            |       | ** ** |   | ** ** |   | ** ** |   | ** ** | ** ** |
| Current assets                           |       | $                                     | 42,291     |   | **$          76,978** |   | **$        861,110** |   | **$       (51,567)** |   | **$        928,812** | ** ** |
| Property, plant and equipment – net      |       | —                                |       | 1,316,037 |   | 641,414 |   | — |   | 1,957,451 |   |
| Equity investments                            |       | 1,171,941                             |       | 462,165 |   | 201,626 |   | (1,482,213 | ) | 353,519 |   |
| Intercompany notes receivable                 |       | 1,171,699                             |       | — |   | — |   | (1,171,699 | ) | — |   |
| Intangible assets                             |       | —                                |       | 330,014 |   | 30,586 |   | — |   | 360,600 |   |
| Other assets                                  |       | 5,038                                 |       | 23,172 |   | 58,543 |   | — |   | 86,753 |   |
| Total assets                                  |       | $                                     | 2,390,969  |   | $ | 2,208,366 |   | $ | 1,793,279 |   | $ | (2,705,479 | ) | $ | 3,687,135 |   |
| Liabilities and  partners’ capital       |       |                                  |       |   |   |   |   |   |   |   |   |
| Current liabilities                           |       | $                                     | 44,617     |   | $ | 102,430 |   | $ | 842,808 |   | $ | (53,794 | ) | $ | 936,061 |   |
| Long-term debt                                |       | 1,173,053                             |       | 378,624 |   | — |   | — |   | 1,551,677 |   |
| Intercompany notes payable                    |       | —                                |       | 640,624 |   | 531,076 |   | (1,171,700 | ) | — |   |
| Other long term liabilities                   |       | 1,387                                 |       | 25,457 |   | 903 |   | — |   | 27,747 |   |
| Total partners’ capital                  |       | 1,171,912                             |       | 1,061,231 |   | 418,492 |   | (1,479,985 | ) | 1,171,650 |   |
| Total  liabilities and partners’ capital |       | $                                     | 2,390,969  |   | $ | 2,208,366 |   | $ | 1,793,279 |   | $ | (2,705,479 | ) | $ | 3,687,135 |   |

 
| ** **                                    | ** ** | **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 |   |

 

36

----

 
| ** **                                | ** ** | **Three Months Ended June 30, 2006** | ** ** |
|-------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                | ** ** | **TEPPCO  Partners, L.P.**                               | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                | ** ** | **(in thousands)**                                       | ** ** |
| Operating  revenues                       |       | $                                                             | —     |   | $ | 109,775 |   | $ | 2,317,678 |   | $ | (2,401 | ) | $ | 2,425,052 |   |
| Costs and  expenses                       |       | —                                                        |       | 81,190 |   | 2,288,111 |   | (2,401 | ) | 2,366,900 |   |
| Gains on sales  of assets                 |       | —                                                        |       | (18 | ) | — |   | — |   | (18 | ) |
| Operating income                          |       | —                                                        |       | 28,603 |   | 29,567 |   | — |   | 58,170 |   |
| Interest expense  – net              |       | —                                                        |       | (13,504 | ) | (5,694 | ) | — |   | (19,198 | ) |
| Equity earnings                           |       | 41,464                                                        |       | 26,783 |   | 5,040 |   | (70,613 | ) | 2,674 |   |
| Other income –  net                  |       | —                                                        |       | 202 |   | 252 |   | — |   | 454 |   |
| Income before deferred income tax expense |       | 41,464                                                        |       | 42,084 |   | 29,165 |   | (70,613 | ) | 42,100 |   |
| Deferred income  tax expense              |       | —                                                        |       | 498 |   | 16 |   | — |   | 514 |   |
| Income from continuing operations         |       | 41,464                                                        |       | 41,586 |   | 29,149 |   | (70,613 | ) | 41,586 |   |
| Discontinued  operations                  |       | —                                                        |       | (122 | ) | — |   | — |   | (122 | ) |
| Net income                                |       | $                                                             | 41,464     |   | $ | 41,464 |   | $ | 29,149 |   | $ | (70,613 | ) | $ | 41,464 |   |

 
| ** **                        | ** ** | **Three Months Ended June 30, 2005** | ** ** |
|-----------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                        | ** ** | **TEPPCO  Partners, L.P.**                               | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                        | ** ** | **(in thousands)**                                       | ** ** |
| Operating  revenues               |       | $                                                             | —     |   | $ | 100,662 |   | $ | 1,987,432 |   | $ | (709 | ) | $ | 2,087,385 |   |
| Costs and  expenses               |       | —                                                        |       | 67,120 |   | 1,967,225 |   | (709 | ) | 2,033,636 |   |
| Gains on sales  of assets         |       | —                                                        |       | (15 | ) | (53 | ) | — |   | (68 | ) |
| Operating income                  |       | —                                                        |       | 33,557 |   | 20,260 |   | — |   | 53,817 |   |
| Interest expense  – net      |       | —                                                        |       | (14,257 | ) | (7,370 | ) | — |   | (21,627 | ) |
| Equity earnings                   |       | 40,922                                                        |       | 20,614 |   | 7,997 |   | (61,782 | ) | 7,751 |   |
| Other income –  net          |       | —                                                        |       | 162 |   | (27 | ) | — |   | 135 |   |
| Income from continuing operations |       | 40,922                                                        |       | 40,076 |   | 20,860 |   | (61,782 | ) | 40,076 |   |
| Discontinued  operations          |       | —                                                        |       | 846 |   | — |   | — |   | 846 |   |
| Net income                        |       | $                                                             | 40,922     |   | $ | 40,922 |   | $ | 20,860 |   | $ | (61,782 | ) | $ | 40,922 |   |

 

37

----

 
| ** **                                | ** ** | **Six Months Ended June 30, 2006** | ** ** |
|-------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                | ** ** | **TEPPCO  Partners, L.P.**                             | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                | ** ** | **(in thousands)**                                     | ** ** |
| Operating revenues                        |       | $                                                           | —     |   | $ | 224,835 |   | $ | 4,744,644 |   | $ | (8,058 | ) | $ | 4,961,421 |   |
| Costs and  expenses                       |       | —                                                      |       | 156,953 |   | 4,693,114 |   | (8,058 | ) | 4,842,009 |   |
| Gains on sales  of assets                 |       | —                                                      |       | (1,396 | ) | — |   | — |   | (1,396 | ) |
| Operating income                          |       | —                                                      |       | 69,278 |   | 51,530 |   | — |   | 120,808 |   |
| Interest expense  – net              |       | —                                                      |       | (27,881 | ) | (12,460 | ) | — |   | (40,341 | ) |
| Equity earnings                           |       | 104,338                                                     |       | 43,045 |   | 7,295 |   | (151,015 | ) | 3,663 |   |
| Other income –  net                  |       | —                                                      |       | 1,025 |   | 328 |   | — |   | 1,353 |   |
| Income before deferred income tax expense |       | 104,338                                                     |       | 85,467 |   | 46,693 |   | (151,015 | ) | 85,483 |   |
| Deferred income  tax expense              |       | —                                                      |       | 498 |   | 16 |   | — |   | 514 |   |
| Income from continuing operations         |       | 104,338                                                     |       | 84,969 |   | 46,677 |   | (151,015 | ) | 84,969 |   |
| Discontinued  operations                  |       | —                                                      |       | 19,369 |   | — |   | — |   | 19,369 |   |
| Net income                                |       | $                                                           | 104,338    |   | $ | 104,338 |   | $ | 46,677 |   | $ | (151,015 | ) | $ | 104,338 |   |

 
| ** **                        | ** ** | **Six Months Ended June 30, 2005** | ** ** |
|-----------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                        | ** ** | **TEPPCO  Partners, L.P.**                             | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                        | ** ** | **(in thousands)**                                     | ** ** |
| Operating  revenues               |       | $                                                           | —     |   | $ | 215,773 |   | $ | 3,397,452 |   | $ | (2,049 | ) | $ | 3,611,176 |   |
| Costs and  expenses               |       | —                                                      |       | 133,209 |   | 3,365,533 |   | (2,049 | ) | 3,496,693 |   |
| Gains on sales  of assets         |       | —                                                      |       | (514 | ) | (52 | ) | — |   | (566 | ) |
| Operating income                  |       | —                                                      |       | 83,078 |   | 31,971 |   | — |   | 115,049 |   |
| Interest expense  – net      |       | —                                                      |       | (27,275 | ) | (13,639 | ) | — |   | (40,914 | ) |
| Equity earnings                   |       | 88,351                                                      |       | 30,233 |   | 13,912 |   | (120,651 | ) | 11,845 |   |
| Other income –  net          |       | —                                                      |       | 345 |   | 56 |   | — |   | 401 |   |
| Income from continuing operations |       | 88,351                                                      |       | 86,381 |   | 32,300 |   | (120,651 | ) | 86,381 |   |
| Discontinued  operations          |       | —                                                      |       | 1,970 |   | — |   | — |   | 1,970 |   |
| Net income                        |       | $                                                           | 88,351     |   | $ | 88,351 |   | $ | 32,300 |   | $ | (120,651 | ) | $ | 88,351 |   |

 

38

----

 
| ** **                                                                                    | ** ** | **Six Months Ended June 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                                                                                    |       | $                                                           | 104,338    |   | $ | 104,338 |   | $ | 46,677 |   | $ | (151,015 | ) | $ | 104,338 |   |
| 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                                                                  |       | —                                                      |       | 498 |   | 16 |   | — |   | 514 |   |
| Depreciation and  amortization                                                                |       | —                                                      |       | 45,114 |   | 12,319 |   | — |   | 57,433 |   |
| Earnings in  equity investments, net of distributions                                         |       | 29,447                                                      |       | 3,591 |   | 1,162 |   | (21,566 | ) | 12,634 |   |
| Gains on sales  of assets                                                                     |       | —                                                      |       | (1,396 | ) | — |   | — |   | (1,396 | ) |
| Changes in  assets and liabilities and other                                                  |       | (31,902                                                     | )          | 11,640 |   | (18,034 | ) | 25,676 |   | (12,620 | ) |
| Net cash provided by  continuing operating activities                                         |       | 101,883                                                     |       | 144,416 |   | 42,140 |   | (146,905 | ) | 141,534 |   |
| Cash flows from  discontinued operations                                                      |       | —                                                      |       | 1,521 |   | — |   | — |   | 1,521 |   |
| Net cash provided by  operating activities                                                    |       | 101,883                                                     |       | 145,937 |   | 42,140 |   | (146,905 | ) | 143,055 |   |
|                                                                                          |       |                                                        |       |   |   |   |   |   |   |   |   |
| Cash flows from  investing activities                                                         |       | —                                                      |       | 85,290 |   | (29,960 | ) | (103,634 | ) | (48,304 | ) |
| Cash flows from  financing activities                                                         |       | (94,685                                                     | )          | (231,289 | ) | (12,051 | ) | 243,340 |   | (94,685 | ) |
| Net increase (decrease)  in cash and cash equivalents                                         |       | 7,198                                                       |       | (62 | ) | 129 |   | (7,199 | ) | 66 |   |
| Cash and cash  equivalents at beginning of period                                             |       | 1,978                                                       |       | 62 |   | 45 |   | (1,966 | ) | 119 |   |
| Cash and cash equivalents at end of period                                                    |       | $                                                           | 9,176      |   | $ | — |   | $ | 174 |   | $ | (9,165 | ) | $ | 185 |   |

 

39

----

 
| ** **                                                                                               | ** ** | **Six Months Ended June 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                                                                                               |       | $                                                           | 88,351     |   | $ | 88,351 |   | $ | 32,300 |   | $ | (120,651 | ) | $ | 88,351 |   |
| Adjustments to  reconcile net income to net cash provided by (used in) continuing operating  activities: |       |                                                        |       |   |   |   |   |   |   |   |   |
| Income from  discontinued operations                                                                     |       | —                                                      |       | (1,970 | ) | — |   | — |   | (1,970 | ) |
| Depreciation and  amortization                                                                           |       | —                                                      |       | 39,514 |   | 12,235 |   | — |   | 51,749 |   |
| Earnings  (losses) in equity investments, net of distributions                                           |       | 28,965                                                      |       | 731 |   | (2,165 | ) | (20,329 | ) | 7,202 |   |
| Gains on sales  of assets                                                                                |       | —                                                      |       | (514 | ) | (52 | ) | — |   | (566 | ) |
| Changes in  assets and liabilities and other                                                             |       | 74,856                                                      |       | (29,979 | ) | (85,699 | ) | (76,242 | ) | (117,064 | ) |
| Net cash provided by  continuing operating activities                                                    |       | 192,172                                                     |       | 96,133 |   | (43,381 | ) | (217,222 | ) | 27,702 |   |
| Cash flows from  discontinued operations                                                                 |       | —                                                      |       | 2,251 |   | — |   | — |   | 2,251 |   |
| Net cash provided by  (used in) operating activities                                                     |       | 192,172                                                     |       | 98,384 |   | (43,381 | ) | (217,222 | ) | 29,953 |   |
|                                                                                                     |       |                                                        |       |   |   |   |   |   |   |   |   |
| Cash flows from  investing activities                                                                    |       | (278,832                                                    | )          | (2,606 | ) | (67,447 | ) | 217,488 |   | (131,397 | ) |
| Cash flows from  financing activities                                                                    |       | 86,516                                                      |       | (108,122 | ) | 108,244 |   | (122 | ) | 86,516 |   |
| Net increase (decrease)  in cash and cash equivalents                                                    |       | (144                                                        | )          | (12,344 | ) | (2,584 | ) | 144 |   | (14,928 | ) |
| 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                                                               |       | $                                                           | 3,972      |   | $ | 1,252 |   | $ | 242 |   | $ | (3,972 | ) | $ | 1,494 |   |

 

**NOTE 16.  SUBSEQUENTEVENTS**

In July 2006, we issued and sold in an underwrittenpublic offering 5.0 million Units at a price to the public of $35.50 perUnit.  The proceeds from the offering,net of underwriting 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.

On July 31, 2006, we executed a third amendment (“ThirdAmendment”) to our Revolving Credit Facility which extends the maturity date ofamounts borrowed under the Revolving Credit Facility from December 2010 toDecember 2011.  The Third Amendment alsoreleases Jonah as a guarantor of the Revolving Credit Facility. The ThirdAmendment restricts the amount of outstanding debt of the Jonah joint ventureto debt owing to the owners of its partnership interests and other debt in theprincipal aggregate amount of $50.0 million. In addition, the Third Amendment allows for swing line loans up to $25.0million (within the $700.0 million total borrowing limit) and modifies ourfinancial covenants to, among other things, allow us to include in thecalculation of our Consolidated EBITDA (as defined in the Revolving CreditFacility, as amended) pro forma adjustments for material projects.

Effective July 31, 2006, Jonah Gas GatheringCompany was also released from its guarantee to Wachovia Bank pursuant to theprovisions of Section 14.04 dated as of February 20, 2002, of the Indenturebetween us, as issuer, TE Products, TCTM, TEPPCO Midstream and Jonah GasGathering Company, each as subsidiary guarantors and Wachovia Bank, as trustee.

40

----

**Item 2.  Management’sDiscussion and Analysis of 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:

·                  Cautionary Note RegardingForward-Looking Statements.

·                  Overview of Critical AccountingPolicies and Estimates.

·                  Overview of Business.

·                  Results of Operations – Discussesmaterial period-to-period variances in the consolidated statements of income.

·                  Financial Condition and Liquidity –Analyzes cash flows and financial position.

·                  Other Considerations – Addressesavailable sources of liquidity, trends, future plans and contingencies that arereasonably likely to materially affect future liquidity or earnings.

·                  Recent Accounting 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, estimated futurecapital 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

41

----

petroleum products is dependent upon the price ofcrude oil and the products produced from the refining of crude oil; and thedemand for natural gas is dependent upon the price of natural gas and thelocations in which natural gas is drilled. We are also subject to regulatory factors such as the amounts we areallowed to charge our customers for the services we provide on our regulatedpipeline systems.  Consequently, all ofthe forward-looking statements made in this document are qualified by thesecautionary statements, and we cannot assure you that actual results ordevelopments that we anticipate will be realized or, even if substantiallyrealized, will have the expected consequences to or effect on us or ourbusiness or operations.  Also note thatwe provide a cautionary discussion of risks and uncertainties under the caption“Risk Factors” and elsewhere in this Form 10-Q; under the caption “Management’sDiscussion and Analysis of Financial Condition and Results of Operations” inour Current Report on Form 8-K filed on June 16, 2006; and in our Annual Reporton Form 10-K for the year ended December 31, 2005.

Theforward-looking statements contained in this Report speak only as of the datehereof.  Except as required by thefederal and state securities laws, we undertake no obligation to publiclyupdate or revise any forward-looking statements, whether as a result of newinformation, future events or any other reason. All forward-looking statements attributable to TEPPCO Partners, L.P. orany person acting on its behalf are expressly qualified in their entirety bythe cautionary statements contained or referred to in this Quarterly Report onForm 10-Q and in our future periodic reports filed with the Securities andExchange Commission (“SEC”).  In light ofthese risks, uncertainties and assumptions, the forward-looking eventsdiscussed in this Report may not occur. For additional discussion of such risks and uncertainties, see ourAnnual Report on Form 10-K for the year ended December 31, 2005, and otherfilings we have made with the SEC.

**Overview of Critical Accounting Policies and Estimates**

A summary of the significant accounting policies wehave adopted and followed in the preparation of our consolidated financialstatements is included in our Annual Report on Form 10-K for the year endedDecember 31, 2005, and in our Current Report on Form 8-K filed on June 16,2006.  Certain of these accountingpolicies require the use of estimates. As more fully described therein, the following estimates, in ouropinion, are subjective in nature, require the exercise of judgment and involvecomplex analysis: revenue and expense accruals, including accruals for powercosts, property taxes and crude oil margins; environmental costs; asset impairmentanalysis related to property, plant and equipment; and amortization expense andasset impairment analysis 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 factors are key to ouroperations.  These include the safe,reliable and efficient operation of the pipelines and facilities that we own oroperate while meeting the regulations that govern the operation of our assetsand the costs associated with such regulations. We are also focused on our continued growth through expansion of theassets that we own and through the acquisition of assets that complement ourcurrent operations.  We operate andreport in three business segments:

·                  Our Downstream Segment, which isengaged in the transportation and storage of refined products, liquefiedpetroleum products (“LPGs”) and petrochemicals;

42

----

·                  Our Upstream Segment, which isengaged in the gathering, transportation, marketing and storage of crude oiland distribution of lubrication oils and specialty chemicals; and

·                  Our MidstreamSegment, which is engaged in the gathering of natural gas, transportation ofnatural 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 duringthe first and fourth quarters of each year since our operations are somewhatseasonal. Refined products volumes are generally higher during the second andthird quarters because of greater demand for gasolines during the spring andsummer driving seasons.  LPGs volumes aregenerally higher from November through March due to higher demand for propane,a major fuel for residential heating. Our Downstream Segment also includes the results of operations of thenorthern portion of the Dean Pipeline, which transports refinery gradepropylene from Mont Belvieu to Point Comfort, Texas.  Our Downstream Segment also includes ourequity investments in Centennial Pipeline LLC (“Centennial”) and Mont BelvieuStorage Partners, L.P. (“MB Storage”) (see Note 7 in the Notes to theConsolidated Financial Statements).

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 crude oilalong our pipeline systems, or from third party pipeline systems, and arrangingthe necessary transportation logistics for the ultimate sale or delivery of thecrude oil to local refineries, marketers or other end users.  Our Upstream Segment also includes our equityinvestment in Seaway Crude Pipeline Company (“Seaway”) (see Note 7 in the Notesto the Consolidated Financial Statements). Seaway consists of large diameter pipelines that transport crude oilfrom Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, acrude oil distribution point for the central United States, and to refineriesin the Texas City and Houston areas.

Our Midstream Segment revenues are earned from thegathering of natural gas in the Green River Basin in southwestern Wyoming,through Jonah, and the gathering of coal bed methane and conventional naturalgas in the San Juan Basin in New Mexico and Colorado, through Val Verde;transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGLpipelines in East Texas and a pipeline system (Chaparral) from West Texas andNew Mexico to Mont Belvieu; and the fractionation of NGLs in Colorado.

We continue to build a base for long-term growth bypursuing new business opportunities, increasing throughput on our pipeline systems, constructing new pipeline andgathering systems, and expanding and upgrading our existinginfrastructure.  We remainconfident that our business strategy will provide continued growth in earningsand cash distributions.  We believe thefollowing factors are important to our growth potential:

·                  Continueddevelopment and expansion of the Jonah system which serves the Jonah andPinedale fields in our Midstream Segment. Through additional Jonah expansions, which should be completed in thefourth quarter of 2007, we expect to increase the capacity to 2.4 billion cubicfeet per day.

·                  Expandingour Downstream Segment gathering capacity of refined products along the upperTexas Gulf Coast.

·                  Utilizingavailable Downstream Segment system capacity of Centennial to move refinedproducts to Midwest market areas, which enables us to increase movements oflong-haul propane volumes.

·                  Expandingour Downstream Segment system delivery capability of gasoline and diesel fuelin the Indianapolis and Chicago market areas.

·                  Continuedintegration of 2005 acquisitions by our Upstream Segment into our existingasset base.

·                  Expandingour West Texas system and storage capacity at Cushing in our Upstream Segment.

43

----

·                  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.

·                  Increasingthroughput on our Midstream Segment NGL systems.

·                  Pursuingacquisitions or organic growth projects in any of our business segments thatwould complement our current operations.

For additional discussion ofimportant factors that could affect our growth, please read “-Cautionary NoteRegarding Forward-Looking Statements” and “Risk Factors” in this Report.

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 receive 60% of revenue and expenseof Seaway.  Thereafter, we will receive40% of revenue and expense of Seaway. Our share of revenue and expense of Seaway is 47% for 2006 (see Note 7in the Notes to the 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*

We expect to further expand theJonah system.  On August 1, 2006,Enterprise Products Partners L.P. (“Enterprise”) (through an affiliate) becameour joint venture partner by acquiring an interest in our Jonah Gas GatheringCompany, the partnership through which we owned the Jonah system.  Prior to entering into the joint venture,Enterprise had managed the construction of the Phase V expansion and funded theinitial costs under a letter of intent we entered into in February 2006.  In connection with the joint venturearrangement, we and Enterprise intend to continue the Phase V expansion, whichis expected to increase the system capacity of the Jonah system from 1.5billion cubic feet per day (“Bcf/d”) to approximately 2.4 Bcf/d and tosignificantly reduce system operating pressures, which is anticipated to leadto increased production rates and ultimate reserve recoveries.  The first portion of the expansion, which isexpected to increase the system gathering capacity to approximately 2.0 Bcf/d,is scheduled to be completed in the first quarter of 2007 at an estimated costof approximately $275.0 million.  Thesecond portion of the expansion is expected to cost approximately $140.0 millionand be completed by the end of 2007.  

Enterprise will continue tomanage the Phase V construction project. We are entitled to all distributions from the joint venture untilspecified milestones are achieved, at which point, Enterprise will be entitled toreceive 50% of the incremental cash flow from portions of the system placed inservice as part of the expansion.  Aftersubsequent milestones are achieved, we and Enterprise will share distributionsbased on a formula that takes into account the capital contributions of theparties, including expenditures by us prior to the expansion.  In the third quarter of 2006, we willreimburse Enterprise for 50% of the Phase V cost incurred by it through August1, 2006 (including its cost of capital). From August 1, 2006, we and Enterprise equally share the costs of thePhase V expansion.  Upon completion ofthe expansion project and based on the formula in the partnership agreement, weexpect to own an interest in Jonah Gas Gathering Company of approximately 80%, withEnterprise owning the remaining 20% and serving as operator and with furthercosts being allocated based on such ownership interests.  The joint venture will be governed by amanagement committee comprised of two representatives approved by Enterpriseand two representatives approved by us, each with equal voting power.  This transaction was reviewed andapproved by the Audit and Conflicts Committee of the board of directors of ourGeneral Partner.  Through June 30, 2006, Enterprise had incurred approximately $106.9million of costs related to the expansion, of which $97.8 million has been paidto vendors by Enterprise.

*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 the newlyissued Units and from its reduced maximum percentage interest in our quarterlydistributions that would approximately equal the cash distributions our GeneralPartner would have received from its maximum percentage interest in ourquarterly 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.  We filed with the Securities and Exchange

44

----

Commission apreliminary proxy statement that outlines the EPCO proposal for which we willsolicit approval from our unitholders at a special meeting.  The proxy statement also contains separateproposals for the adoption of an employee Unit purchase plan and a long termincentive plan.

**Results ofOperations**

The following tablesummarizes financial information by business segment for the three months andsix months ended June 30, 2006 and 2005 (in thousands):
| ** **                                | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                | ** ** | **2006**                                        | ** ** | **2005**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                      |       |                                            |       |                                          |       |   |   |   |   |
| Operating  revenues:                      |       |                                            |       |                                          |       |   |   |   |   |
| Downstream Segment                        |       | $                                               | 69,333     |                                          | $          | 63,438 |   | $ | 143,400 |   | $ | 141,605 |   |
| Upstream Segment                          |       | 2,287,012                                       |       | 1,973,000                                     |       | 4,698,594 |   | 3,369,780 |   |
| Midstream Segment                         |       | 70,345                                          |       | 51,656                                        |       | 126,722 |   | 101,840 |   |
| Intersegment eliminations                 |       | (1,638                                          | )          | (709                                          | )          | (7,295 | ) | (2,049 | ) |
| Total operating revenues                  |       | 2,425,052                                       |       | 2,087,385                                     |       | 4,961,421 |   | 3,611,176 |   |
|                                      |       |                                            |       |                                          |       |   |   |   |   |
| Operating  income:                        |       |                                            |       |                                          |       |   |   |   |   |
| Downstream Segment                        |       | 16,774                                          |       | 14,972                                        |       | 40,055 |   | 46,484 |   |
| Upstream Segment                          |       | 20,345                                          |       | 11,589                                        |       | 33,651 |   | 16,992 |   |
| Midstream Segment                         |       | 21,051                                          |       | 27,256                                        |       | 47,102 |   | 51,573 |   |
| Total operating income                    |       | 58,170                                          |       | 53,817                                        |       | 120,808 |   | 115,049 |   |
|                                      |       |                                            |       |                                          |       |   |   |   |   |
| Earnings before  interest:                |       |                                            |       |                                          |       |   |   |   |   |
| Downstream Segment                        |       | 14,593                                          |       | 14,847                                        |       | 37,387 |   | 44,687 |   |
| Upstream Segment                          |       | 25,610                                          |       | 19,540                                        |       | 41,215 |   | 30,933 |   |
| Midstream Segment                         |       | 21,095                                          |       | 27,316                                        |       | 47,222 |   | 51,675 |   |
|                                      |       |                                            |       |                                          |       |   |   |   |   |
| Interest expense                          |       | (22,356                                         | )          | (22,780                                       | )          | (46,758 | ) | (43,169 | ) |
| Interest  capitalized                     |       | 3,158                                           |       | 1,153                                         |       | 6,417 |   | 2,255 |   |
| Income before deferred income tax expense |       | 42,100                                          |       | 40,076                                        |       | 85,483 |   | 86,381 |   |
| Deferred income  tax expense              |       | 514                                             |       | —                                        |       | 514 |   | — |   |
| Income from continuing operations         |       | 41,586                                          |       | 40,076                                        |       | 84,969 |   | 86,381 |   |
| Discontinued  operations                  |       | (122                                            | )          | 846                                           |       | 19,369 |   | 1,970 |   |
| Net income                                |       | $                                               | 41,464     |                                          | $          | 40,922 |   | $ | 104,338 |   | $ | 88,351 |   |

 

Thefollowing is a detailed analysis of the results of operations, includingreasons for changes in results, by each of our operating segments.

45

----

**Downstream Segment**

The following table provides financial information forthe Downstream Segment for the three months and six months ended June 30, 2006and 2005 (in thousands):
| ** **                             | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** | **Six Months Ended** | ** ** | ** **   | ** ** |
|----------------------------------------|------------|----------------------------------|------------|--------------|------------|--------------------------------|------------|--------------|------------|
| ** **                             | ** ** | **June 30,**                | ** ** | **Increase** | ** ** | **June 30,**              | ** ** | **Increase** | ** ** |
| ** **                             | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)**                 | ** ** | **2006**     | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| ** **                             | ** ** | ** **                       | ** ** | ** **   | ** ** | ** **                     | ** ** | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues:                              |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Transportation – Refined products |       | $                                | 39,443     |         | $          | 37,834                         |       | $            | 1,609      |   | $ | 71,242 |   | $ | 72,799 |   | $ | (1,557 | ) |
| Transportation – LPGs             |       | 13,354                           |       | 14,470       |       | (1,116                         | )          | 42,775       |       | 46,701 |   | (3,926 | ) |
| Other                                  |       | 16,536                           |       | 11,134       |       | 5,402                          |       | 29,383       |       | 22,105 |   | 7,278 |   |
| Total operating revenues               |       | 69,333                           |       | 63,438       |       | 5,895                          |       | 143,400      |       | 141,605 |   | 1,795 |   |
|                                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Costs and  expenses:                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Operating expense                      |       | 26,305                           |       | 24,772       |       | 1,533                          |       | 49,807       |       | 47,185 |   | 2,622 |   |
| Operating fuel and power               |       | 8,318                            |       | 7,957        |       | 361                            |       | 17,623       |       | 15,617 |   | 2,006 |   |
| General and administrative             |       | 4,701                            |       | 3,509        |       | 1,192                          |       | 9,795        |       | 7,711 |   | 2,084 |   |
| Depreciation and amortization          |       | 10,133                           |       | 9,801        |       | 332                            |       | 20,430       |       | 19,362 |   | 1,068 |   |
| Taxes – other than income taxes   |       | 3,120                            |       | 2,442        |       | 678                            |       | 5,715        |       | 5,353 |   | 362 |   |
| Gains on sales of assets               |       | (18                              | )          | (15          | )          | (3                             | )          | (25          | )          | (107 | ) | 82 |   |
| Total costs and expenses               |       | 52,559                           |       | 48,466       |       | 4,093                          |       | 103,345      |       | 95,121 |   | 8,224 |   |
|                                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Operating income                       |       | 16,774                           |       | 14,972       |       | 1,802                          |       | 40,055       |       | 46,484 |   | (6,429 | ) |
|                                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Equity losses                          |       | (2,366                           | )          | (246         | )          | (2,120                         | )          | (3,632       | )          | (2,067 | ) | (1,565 | ) |
| Other income –  net               |       | 185                              |       | 121          |       | 64                             |       | 964          |       | 270 |   | 694 |   |
|                                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Earnings before  interest              |       | $                                | 14,593     |         | $          | 14,847                         |       | $            | (254       | ) | $ | 37,387 |   | $ | 44,687 |   | $ | (7,300 | ) |

 

The following table presents volumes delivered inbarrels and average tariff per barrel for the three months and six months endedJune 30, 2006 and 2005 (in thousands, except tariff information):
| ** **                        | ** ** | **Three Months Ended** | ** ** | **Percentage** | ** ** | **Six Months Ended** | ** ** | **Percentage** | ** ** |
|-----------------------------------|------------|----------------------------------|------------|----------------|------------|--------------------------------|------------|----------------|------------|
| ** **                        | ** ** | **June 30,**                | ** ** | **Increase**   | ** ** | **June 30,**              | ** ** | **Increase**   | ** ** |
| ** **                        | ** ** | **2006**                         | ** ** | **2005**       | ** ** | **(Decrease)**                 | ** ** | **2006**       | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| **Volumes  Delivered:**           |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Refined products                  |       | 46,049                           |       | 42,097         |       | 9                              | %          | 81,857         |       | 80,692 |   | 1 | % |
| LPGs                              |       | 8,277                            |       | 7,855          |       | 5                              | %          | 21,117         |       | 22,657 |   | (7 | )% |
| Total                             |       | 54,326                           |       | 49,952         |       | 9                              | %          | 102,974        |       | 103,349 |   | — |   |
|                              |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| **Average  Tariff per Barrel:**   |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Refined products                  |       | $                                | 0.86       |           | $          | 0.90                           |       | (4             | )%         | $ | 0.87 |   | $ | 0.90 |   | (3 | )% |
| LPGs                              |       | 1.33                             |       | 1.84           |       | (28                            | )%         | 1.91           |       | 2.06 |   | (7 | )% |
| Average system  tariff per barrel |       | 0.93                             |       | 1.05           |       | (11                            | )%         | 1.08           |       | 1.16 |   | (7 | )% |
|                                   |            |                                  |            |                |            |                                |            |                |            |  |  |  |  |  |  |  |  |

 

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

Revenues from refined products transportationincreased $1.6 million for the three months ended June 30, 2006, compared withthe three months ended June 30, 2005, primarily due to an overall increase of9% in the refined products volumes delivered. Volume increases were due to increased demand for products supplied fromthe U.S. Gulf Coast into Midwest markets resulting from higher distillate pricedifferentials and a greater demand for gasoline.  Refined products revenues were also impactedby a strong demand for gasoline blendstocks, partially offset by lower averagetariff jet fuel volumes during the three months ended June 30, 2006, comparedwith the three months ended June 30, 2005. In February 2003, we entered into a lease agreement with Centennial thatincreased our flexibility to deliver refined products to our market areas.  As a result, Centennial has provided oursystem with

46

----

additional pipeline capacity for movement of productsoriginating in the U.S. Gulf Coast area. Prior to the construction of Centennial, deliveries on our pipelinesystem were limited by our pipeline capacity, and transportation services forour customers were allocated 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.  Movements of refined products on Centennialhas resulted 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.

Revenues from LPGs transportation decreased $1.1million for the three months ended June 30, 2006, compared with the threemonths ended June 30, 2005, due to lower deliveries of propane in the upperMidwest and Northeast market areas as a result of high propane prices delayingsummer fill programs and scheduled maintenance, known as a turnaround, on amid-continent petrochemical plant. Additionally, revenues decreased due to lower isobutane deliveriesresulting from a Midwest refinery turnaround. The LPGs average rate per barrel decreased from the prior periodprimarily as a result of increased short-haul deliveries during the threemonths ended June 30, 2006, compared with the three months ended June 30, 2005.

Otheroperating revenues increased $5.4 million for the three months ended June 30,2006, compared with the three months ended June 30, 2005, primarily due toincreased volumes of product sales, higher storage revenues on assets acquiredfrom Texas Genco, LLC in July 2005 and higher refined products tender deductionrevenue.

Costs andexpenses increased $4.1 million for the three months ended June 30, 2006,compared with the three months ended June 30, 2005.  Operating expenses increased $1.5 millionprimarily due to a $2.0 million increase in pipeline operating costs primarilyas a result of acquisitions made in 2005, $1.0 million of higher insurancepremiums, a $0.7 million regulatory penalty for past incidents, $0.6 million inseverance expense resulting from the migration to a shared services environmentwith EPCO and $0.4 million of expenses relating to the proposed reduction inthe General Partner’s maximum percentage interest in our distributions (seeNote 9 in the Notes to the Consolidated Financial Statements). These increasesin operating expenses were partially offset by $1.8 million in productmeasurement gains and a $1.0 million decrease in pipeline inspection and repaircosts associated with our integrity management program.  General and administrative expenses increased$1.2 million primarily due to severance expense resulting from the migration toa shared services environment with EPCO and other executive compensationexpense.  Taxes — other than income taxesincreased $0.7 million primarily due to a higher property asset base.  Operating fuel and power increased $0.4million primarily due to increased mainline throughput and higher powerrates.  Depreciation and amortizationexpense increased $0.3 million primarily due to the recording of a conditionalasset retirement obligation, as discussed below.

Netlosses from equity investments increased for the three months ended June 30,2006, compared with the three months ended June 30, 2005, as shown below (inthousands):

|                      | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** |
|----------------------|------------|----------------------------------|------------|--------------|------------|
| ** **           | ** ** | **June 30,**                | ** ** | **Increase** | ** ** |
| ** **           | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)** | ** ** |
| ** **           | ** ** | ** **                       | ** ** | ** **   | ** ** | ** ** | ** ** |
| Centennial           |       | $                                | (3,401     | )            | $          | (1,634 | ) | $ | (1,767 | ) |
| MB Storage           |       | 1,043                            |       | 1,365        |       | (322 | ) |
| Other                |       | (8                               | )          | 23           |       | (31 | ) |
| Total equity  losses |       | $                                | (2,366     | )            | $          | (246 | ) | $ | (2,120 | ) |

 

Equity losses inCentennial increased $1.8 million for the three months ended June 30, 2006,compared with the three months ended June 30, 2005, primarily due to lowertransportation revenues and increased costs relating to pipeline inspection andrepair costs associated with its integrity management program, partially offsetby lower amortization expense on the portion of TE Products’ excess investmentin Centennial resulting from slightly lower

47

----

volumes.  Equity earnings in MB Storage decreased $0.3million for the three months ended June 30, 2006, compared with the threemonths ended June 30, 2005, primarily due to higher system maintenance expenseson the MB Storage system and higher general and administrative expenses,partially offset by higher revenues.

*Six Months Ended June 30, 2006Compared with Six Months Ended June 30, 2005*

Revenues from refined products transportationdecreased $1.6 million for the six months ended June 30, 2006, compared withthe six months ended June 30, 2005, primarily due to a decrease in the averagerate per barrel, partially offset by a 1% increase in the refined productsvolumes delivered.  Volume increases weredue to increased demand for products supplied from the U.S. Gulf Coast intoMidwest markets resulting from higher distillate price differentials and agreater demand for gasoline.  Refinedproducts volumes were also impacted by unfavorable differentials for motorfuels and distillate during the first quarter of 2006.  Movements of refined products on Centennialhas resulted 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 $3.9 million for the six months ended June30, 2006, compared with the six months ended June 30, 2005, due to lowerdeliveries of propane in the upper Midwest and Northeast market areas as aresult of warmer than normal winter weather, high propane prices and plantturnarounds.  The LPGs average rate perbarrel decreased from the prior period primarily as a result of increasedshort-haul deliveries during the six months ended June 30, 2006, compared withthe six months ended June 30, 2005.

Otheroperating revenues increased $7.3 million for the six months ended June 30,2006, compared with the six months ended June 30, 2005, primarily due toincreased volumes of product sales, higher storage revenues on assets acquiredfrom Texas Genco, LLC in July 2005 and higher refined products tender deductionrevenue.

Costs andexpenses increased $8.3 million for the six months ended June 30, 2006,compared with the six months ended June 30, 2005.  Operating expense increased $2.6 millionprimarily due to a $3.8 million increase in pipeline operating costs primarilyas a result of acquisitions made in 2005, $1.5 million of higher insurancepremiums, $0.6 million in severance expense as a result of the migration to ashared services environment with EPCO, $0.4 million of expenses relating to theproposed reduction in the General Partner’s maximum percentage interest in ourdistributions (see Note 9 in the Notes to the Consolidated FinancialStatements) and increases related to regulatory penalties for past incidents,environmental remediation and assessments costs and transition costs.  These increases in costs and expenses werepartially offset by a $3.0 million decrease in pipeline inspection and repaircosts associated with our integrity management program, $1.5 million in productmeasurement gains and a $0.7 million decrease in rental expense from theCentennial pipeline capacity lease agreement. General and administrative expenses increased $2.1 million primarily dueto a $1.1 million increase relating to the retirement of an executive inFebruary 2006 and $0.6 million in severance expense as a result of themigration to a shared services environment with EPCO and higher other executivecompensation expense.  Operating fuel andpower increased $2.0 million primarily due to increased mainline throughput andhigher power rates.  Depreciation expenseincreased $1.1 million primarily due to assets placed into service, assetretirements in 2006 and the recording of a conditional asset retirementobligation as discussed below.  Taxes –other than income taxes increased $0.4 million primarily due to a higherproperty asset base in the 2006 period.

Netlosses from equity investments increased for the six months ended June 30,2006, compared with the six months ended June 30, 2005, as shown below (inthousands):

|                      | ** ** | **Six Months Ended** | ** ** | ** **   | ** ** |
|----------------------|------------|--------------------------------|------------|--------------|------------|
| ** **           | ** ** | **June 30,**              | ** ** | **Increase** | ** ** |
| ** **           | ** ** | **2006**                       | ** ** | **2005**     | ** ** | **(Decrease)** | ** ** |
| ** **           | ** ** | ** **                     | ** ** | ** **   | ** ** | ** ** | ** ** |
| Centennial           |       | $                              | (7,313     | )            | $          | (6,084 | ) | $ | (1,229 | ) |
| MB Storage           |       | 3,692                          |       | 3,998        |       | (306 | ) |
| Other                |       | (11                            | )          | 19           |       | (30 | ) |
| Total equity  losses |       | $                              | (3,632     | )            | $          | (2,067 | ) | $ | (1,565 | ) |

 

48

----

Equitylosses in Centennial increased $1.2 million for the six months ended June 30,2006, compared with the six months ended June 30, 2005, primarily due to lowertransportation revenues and volumes primarily due to warmer than normal winterweather in the Northeast and increased costs relating to pipeline inspectionand repair costs associated with its integrity management program. Equityearnings in MB Storage decreased $0.3 million for the six months ended June 30,2006, compared with the six months ended June 30, 2005, primarily due to highersystem maintenance expenses and higher general and administrative expenses,partially offset by higher revenues.

Otherincome – net increased $0.7 million for the six months ended June 30, 2006,compared with the six months ended June 30, 2005, due to higher interest incomeearned on cash investments and other investing activities.

*Asset Retirement Obligations*

During the secondquarter of 2006, we recorded $0.3 million of expense, included in depreciationand amortization expense, related to a conditional asset retirement obligation.Additionally, we recorded a $0.4 million liability, which represents the fairvalue, as measured at June 30, 2006, of the conditional asset retirementobligation related to structural restoration work to be completed on leasedoffice space that is required upon our anticipated office lease termination(see Note 1 in the Notes to the Consolidated Financial Statements).

**UpstreamSegment**

Thefollowing table provides financial information for the Upstream Segment for thethree months and six months ended June 30, 2006 and 2005 (in thousands):
| ** **                             | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** | **Six Months Ended** | ** ** | ** **   | ** ** |
|----------------------------------------|------------|----------------------------------|------------|--------------|------------|--------------------------------|------------|--------------|------------|
| ** **                             | ** ** | **June 30,**                | ** ** | **Increase** | ** ** | **June 30,**              | ** ** | **Increase** | ** ** |
| ** **                             | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)**                 | ** ** | **2006**     | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| ** **                             | ** ** | ** **                       | ** ** | ** **   |       | ** **                     |       | ** **   | ** ** | ** ** |   | ** ** | ** ** |
| Revenues:                              |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Sales of petroleum  products           |       | $                                | 2,273,878  |         | $          | 1,961,302                      |       | $            | 312,576    |   | $ | 4,674,314 |   | $ | 3,346,369 |   | $ | 1,327,945 |   |
| Transportation – Crude  oil       |       | 10,544                           |       | 9,042        |       | 1,502                          |       | 19,467       |       | 18,214 |   | 1,253 |   |
| Other                                  |       | 2,590                            |       | 2,656        |       | (66                            | )          | 4,813        |       | 5,197 |   | (384 | ) |
| Total operating revenues               |       | 2,287,012                        |       | 1,973,000    |       | 314,012                        |       | 4,698,594    |       | 3,369,780 |   | 1,328,814 |   |
|                                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Costs and expenses:                    |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Purchases of petroleum  products       |       | 2,243,143                        |       | 1,942,599    |       | 300,544                        |       | 4,619,539    |       | 3,315,029 |   | 1,304,510 |   |
| Operating expense                      |       | 14,837                           |       | 11,693       |       | 3,144                          |       | 27,981       |       | 23,001 |   | 4,980 |   |
| Operating fuel and power               |       | 1,766                            |       | 1,234        |       | 532                            |       | 3,959        |       | 2,462 |   | 1,497 |   |
| General and  administrative            |       | 1,870                            |       | 1,219        |       | 651                            |       | 3,677        |       | 2,727 |   | 950 |   |
| Depreciation and  amortization         |       | 3,494                            |       | 3,651        |       | (157                           | )          | 6,765        |       | 7,152 |   | (387 | ) |
| Taxes – other than  income taxes. |       | 1,557                            |       | 1,068        |       | 489                            |       | 3,022        |       | 2,469 |   | 553 |   |
| Gains on sales of assets               |       | —                           |       | (53          | )          | 53                             |       | —       |       | (52 | ) | 52 |   |
| Total costs and expenses               |       | 2,266,667                        |       | 1,961,411    |       | 305,256                        |       | 4,664,943    |       | 3,352,788 |   | 1,312,155 |   |
| Operating income                       |       | 20,345                           |       | 11,589       |       | 8,756                          |       | 33,651       |       | 16,992 |   | 16,659 |   |
|                                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Equity earnings                        |       | 5,040                            |       | 7,997        |       | (2,957                         | )          | 7,295        |       | 13,912 |   | (6,617 | ) |
| Other income – net                |       | 225                              |       | (46          | )          | 271                            |       | 269          |       | 29 |   | 240 |   |
| Earnings before  interest              |       | $                                | 25,610     |         | $          | 19,540                         |       | $            | 6,070      |   | $ | 41,215 |   | $ | 30,933 |   | $ | 10,282 |   |

 

Informationpresented in the following table includes the margin of the Upstream Segment,which may be viewed as a non-GAAP (Generally Accepted Accounting Principles)financial measure under the rules of the SEC. We calculate the margin of theUpstream Segment as revenues generated from the sale of crude oil andlubrication oil, and transportation of crude oil, less the costs of purchasesof crude oil and lubrication oil. We believe that

49

----

margin is a more meaningful measure offinancial performance than sales and purchases of crude oil and lubrication oildue to the significant fluctuations in sales and purchases caused by variationsin the level of volumes marketed and prices for products marketed. Additionally,we use margin internally to evaluate the financial performance of the UpstreamSegment because it excludes expenses that are not directly related to themarketing and sales activities being evaluated. Margin and volume informationfor the three months and six months ended June 30, 2006 and 2005 is presentedbelow (in thousands, except per barrel and per gallon amounts):
| ** **                           | ** ** | **Three Months Ended** | ** ** | **Percentage** | ** ** | **Six Months Ended** | ** ** | **Percentage** | ** ** |
|--------------------------------------|------------|----------------------------------|------------|----------------|------------|--------------------------------|------------|----------------|------------|
| ** **                           | ** ** | **June 30,**                | ** ** | **Increase**   | ** ** | **June 30,**              | ** ** | **Increase**   | ** ** |
| ** **                           | ** ** | **2006**                         | ** ** | **2005**       | ** ** | **(Decrease)**                 | ** ** | **2006**       | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
|                                 |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Margins: (1)                         |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Crude oil  marketing                 |       | $                                | 19,096     |           | $          | 9,056                          |       | 111            | %          | $ | 31,882 |   | $ | 12,532 |   | 154 | % |
| Lubrication oil  sales               |       | 2,044                            |       | 1,675          |       | 22                             | %          | 4,175          |       | 3,432 |   | 22 | % |
| Revenues: (1)                        |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Crude oil  transportation            |       | 16,586                           |       | 14,968         |       | 11                             | %          | 32,354         |       | 29,121 |   | 11 | % |
| Crude oil  terminaling               |       | 3,553                            |       | 2,046          |       | 74                             | %          | 5,831          |       | 4,469 |   | 30 | % |
| Total  margins/revenues              |       | $                                | 41,279     |           | $          | 27,745                         |       | 49             | %          | $ | 74,242 |   | $ | 49,554 |   | 50 | % |
|                                 |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Total barrels/gallons:               |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Crude oil  marketing (barrels)       |       | 56,257                           |       | 48,864         |       | 15                             | %          | 109,198        |       | 93,158 |   | 17 | % |
| Lubrication oil  volume (gallons)    |       | 3,377                            |       | 3,153          |       | 7                              | %          | 7,232          |       | 7,325 |   | (1 | )% |
|                                 |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Crude oil  transportation (barrels)  |       | 22,847                           |       | 23,768         |       | (4                             | )%         | 45,175         |       | 47,522 |   | (5 | )% |
| Crude oil  terminaling (barrels)     |       | 38,305                           |       | 21,287         |       | 80                             | %          | 62,748         |       | 48,406 |   | 30 | % |
|                                 |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Margin per barrel or  gallon:        |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Crude oil  marketing (per barrel)    |       | $                                | 0.339      |           | $          | 0.185                          |       | 83             | %          | $ | 0.292 |   | $ | 0.135 |   | 116 | % |
| Lubrication oil  margin (per gallon) |       | 0.605                            |       | 0.531          |       | 14                             | %          | 0.577          |       | 0.469 |   | 23 | % |
|                                 |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Average tariff per  barrel:          |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Crude oil  transportation            |       | $                                | 0.726      |           | $          | 0.630                          |       | 15             | %          | $ | 0.716 |   | $ | 0.613 |   | 17 | % |
| Crude oil  terminaling               |       | 0.093                            |       | 0.096          |       | (3                             | )%         | 0.093          |       | 0.092 |   | 1 | % |

 

----

(1)                Amounts in this table arepresented prior to the elimination of intercompany sales, revenues andpurchases between TEPPCO Crude Oil, L.P. and TEPPCO Crude Pipeline, L.P.

50

----

Thefollowing table reconciles the Upstream Segment margin to operating incomeusing the information presented in the consolidated statements of income andthe statements of income in Note 12 in the Notes to the Consolidated FinancialStatements (in thousands):
|                                             | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|---------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                  | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                  | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
| Sales of  petroleum products                |       | $                                | 2,273,878  |                           | $          | 1,961,302 |   | $ | 4,674,314 |   | $ | 3,346,369 |   |
| Transportation –  Crude oil            |       | 10,544                           |       | 9,042                          |       | 19,467 |   | 18,214 |   |
| Less:  Purchases of petroleum products |       | (2,243,143                       | )          | (1,942,599                     | )          | (4,619,539 | ) | (3,315,029 | ) |
| Total margins/revenues                      |       | 41,279                           |       | 27,745                         |       | 74,242 |   | 49,554 |   |
| Other operating  revenues                   |       | 2,590                            |       | 2,656                          |       | 4,813 |   | 5,197 |   |
| Net operating revenues                      |       | 43,869                           |       | 30,401                         |       | 79,055 |   | 54,751 |   |
| Operating  expense                          |       | 14,837                           |       | 11,693                         |       | 27,981 |   | 23,001 |   |
| Operating fuel  and power                   |       | 1,766                            |       | 1,234                          |       | 3,959 |   | 2,462 |   |
| General and  administrative expense         |       | 1,870                            |       | 1,219                          |       | 3,677 |   | 2,727 |   |
| Depreciation and  amortization              |       | 3,494                            |       | 3,651                          |       | 6,765 |   | 7,152 |   |
| Taxes – other  than income taxes       |       | 1,557                            |       | 1,068                          |       | 3,022 |   | 2,469 |   |
| Gains on sales  of assets                   |       | —                           |       | (53                            | )          | — |   | (52 | ) |
| Operating income                            |       | $                                | 20,345     |                           | $          | 11,589 |   | $ | 33,651 |   | $ | 16,992 |   |

 

On April1, 2006, we adopted Emerging Issues Task Force (“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. Implementation of EITF 04-13 as of April 1, 2006, reduced grossrevenues and purchases for the three months ended June 30, 2006, but did nothave a material effect on our financial position, results of operations or cashflows. Under the consensus reached in EITF 04-13, buy/sell transactions arereported as non-monetary exchanges and consequently not presented on a grossbasis in our statements of income. Implementation of EITF 04-13 reducedrevenues and purchases of petroleum products on our consolidated statements ofincome by approximately $313.7 million for the periods ended June 30, 2006. Underthe provisions of the consensus, retroactive restatement of buy/selltransactions reported in prior periods was not permitted.

*Three MonthsEnded June 30, 2006 Compared with Three Months Ended June 30, 2005*

Sales ofpetroleum products increased $312.6 million for the three months ended June 30,2006, compared with the three months ended June 30, 2005. Purchases ofpetroleum products increased $300.5 million for the three months ended June 30,2006, compared with the three months ended June 30, 2005. Operating incomeincreased $8.8 million for the three months ended June 30, 2006, compared withthe three months ended June 20, 3005. The increases in sales and purchases wereprimarily as a result of an increase in the price of crude oil and increasedvolumes marketed. The average NYMEX price of crude oil was $70.40 per barrelfor the three months ended June 30, 2006, compared with $53.03 per barrel forthe three months ended June 30, 2005. The increase in the average price ofcrude oil, partially offset by increased purchases and costs and expensesdiscussed below, resulted in an increase in operating income. Crude oilmarketing margin increased $10.0 million primarily due to favorable marketconditions and increased volumes marketed, partially offset by increasedtransportation costs and unrealized gains in the 2005 period of $1.8 millionrelating to marking crude oil grade and location swap contracts to currentmarket value. Crude oil transportation revenues increased $1.6 millionprimarily due to increased transportation revenues on the Red River system, theSouth Texas system and the West Texas system primarily related to movements onhigher tariff segments, increased tariffs and revenues from systems acquiredduring 2005 and increases due to organic growth projects, partially offset bylower transportation volumes. Crude oil terminaling revenues increased

51

----

$1.5 million as a result of increasedpumpover volumes at Midland, Texas and Cushing, Oklahoma. Lubrication oil salesmargin increased $0.4 million due to increased sales of chemical volumes.

Costs andexpenses, excluding expenses associated with purchases of crude oil andlubrication oil, increased $4.7 million for the three months ended June 30,2006, compared with the three months ended June 30, 2005. Operating expensesincreased $3.1 million from the prior year period primarily due to a $1.6million increase in product measurement losses, a $0.7 million increase inpipeline operating and maintenance expense as a result of acquisitions and thecontinued integration of Genesis assets into our system, $0.4 million inseverance expense as a result of the migration to a shared services environmentwith EPCO, higher insurance premiums and expenses relating to the proposedreduction in the General Partner’s maximum percentage interest in ourdistributions (see Note 9 in the Notes to the Consolidated FinancialStatements). General and administrative expenses increased $0.7 million fromthe prior year period primarily due to $0.4 million in severance expense as aresult of the migration to a shared services environment with EPCO and higherother executive compensation expense. Operating fuel and power increased $0.5million primarily as a result of higher power rates in the 2006 period. Taxes –other than income taxes increased $0.5 million from the prior year periodprimarily due to a higher property asset base in 2006 and an increase inpayroll tax expense. Depreciation and amortization expense decreased $0.2million as a result of asset retirements during the prior year period.

Equityearnings from our investment in Seaway decreased $3.0 million for the threemonths ended June 30, 2006, compared with the three months ended June 30, 2005.Our equity earnings in Seaway were reducedby a decrease in our participation ratio in the revenue and expense of Seaway. Oursharing ratio for 2005 was 60%, while for the full year of 2006, it is 47% ofthe revenue and expense of Seaway (see Note 7 in the Notes to the ConsolidatedFinancial Statements). Equity earnings from our investment in Seaway alsodecreased due to higher operating, general and administrative expensesrelated to pipeline integrity costs for the corrective measures taken for thepipeline release in May 2005, increased environmental remediation andassessment costs and higher operating fuel and power costs relating to the useof a drag reducing agent and higher power rates, partially offset by increasedtransportation volumes.

After Seaway’spipeline release in May 2005, the maximum operating pressure on the pipelinesystem was reduced by 20% until the cause of the failure was determined. Correctivemeasures were implemented upon the release in 2005 and have been completed. Seawayoperated at reduced maximum pressure through May 2006. On June 1, 2006, Seaway’soperating pressure was increased to 100%. As a result of operating at reducedmaximum pressure, during the third quarter of 2005, we began using a dragreducing agent to increase the flow of product through the pipeline system. Thedrag reducing agent allowed us to maintain the higher volumes transported, butalso increased our operating costs. The reduced pressure did not have amaterial adverse effect on our financial position, results of operations orcash flows (see Note 13 in the Notes to the Consolidated Financial Statements).

*Six Months EndedJune 30, 2006 Compared with Six Months Ended June 30, 2005*

Sales ofpetroleum products increased $1,327.9 million for the six months ended June 30,2006, compared with the six months ended June 30, 2005. Purchases of petroleumproducts increased $1,304.5 million for the six months ended June 30, 2006,compared with the six months ended June 30, 2005. Operating income increased$16.7 million for the three months ended June 30, 2006, compared with the threemonths ended June 30, 3005. The increases in sales and purchases were primarilyas a result of an increase in the price of crude oil and increased volumesmarketed. The average NYMEX price of crude oil was $66.84 per barrel for thesix months ended June 30, 2006, compared with $51.37 per barrel for the sixmonths ended June 30, 2005. The increase in the average price of crude oil,partially offset by increased purchases and costs and expenses discussed below,resulted in an increase in operating income. Crude oil marketing marginincreased $19.4 million, primarily due to favorable market conditions andincreased volumes marketed, partially offset by increased transportation costsand unrealized gains in the 2005 period of $0.8 million relating to markingcrude oil grade and location swap contracts to current market value. Crude oiltransportation revenues increased $3.2 million primarily due to increasedtransportation volumes and revenues on our South Texas system and West Texassystems, higher revenues on our Red River system related to movements on highertariff segments and revenues from acquisitions in 2005, partially offset bydecreases in

52

----

transportation volumes on lower tariffsegments of our Basin and Red River systems. Crude oil terminaling revenuesincreased $1.4 million as a result of an increase in pumpover volumes atMidland, Texas and Cushing, Oklahoma. Lubrication oil sales margin increased$0.7 million due to increased sales of chemical volumes.

Otheroperating revenues decreased $0.4 million for the six months ended June 30,2006, compared with the six months ended June 30, 2005, primarily due to a $1.4million favorable settlement of inventory imbalances in the first quarter of2005 and lower revenues from documentation and other services to supportcustomers’ trading activity at Midland and Cushing in the first six months of2006.

Costs andexpenses, excluding expenses associated with purchases of crude oil andlubrication oil, increased $7.7 million for the six months ended June 30, 2006,compared with the six months ended June 30, 2005. Operating expenses increased$5.0 million from the prior year period, primarily due to a $3.1 millionincrease in supplies and pipeline operating and maintenance expense, a $1.0million increase as a result of product measurement losses and higher crude oilprices, $0.8 million of higher insurance premiums, a $0.5 million increase inenvironmental assessment and remediation costs and $0.4 million in severance expenseas a result of the migration to a shared services environment with EPCO,partially offset by a $0.6 million decrease in labor and benefits expenserelated to vesting provisions in certain of our compensation plans as a resultof changes in ownership of our General Partner in the prior year period. Operatingfuel and power increased $1.5 million primarily as a result of increased powerrates in the 2006 period, partially offset by lower transportation volumes.General and administrative expenses increased $1.0 million from the prior yearperiod primarily due to $0.4 million in severance expense, an increase in otherexecutive compensation expense and an increase in consulting and contractservices. Taxes – other than income taxes increased $0.5 million due toincreases in property tax accruals and a higher property asset base in 2006. Depreciationand amortization expense decreased $0.4 million as a result of assetretirements during the prior year period.

Equityearnings from our investment in Seaway decreased $6.6 million for the sixmonths ended June 30, 2006, compared with the six months ended June 30, 2005. Our sharing ratio for 2005 was 60%, while for thefull year of 2006, it is 47% of the revenue and expense of Seaway (see Note 7in the Notes to the Consolidated Financial Statements). Equity earnings fromour investment in Seaway also decreased due to higher operating, generaland administrative expenses related to pipeline integrity costs for thecorrective measures taken for the pipeline release in May 2005, increasedenvironmental remediation and assessment costs, higher operating fuel and powercosts relating to the use of a drag reducing agent and higher power rates and a favorable settlement in the firstquarter of 2005 with a former owner of Seaway’s crude oil assets regardinginventory imbalances that were not acquired by us, partially offset byincreased transportation volumes.

53

----

**MidstreamSegment**

Thefollowing table provides financial information for the Midstream Segment forthe three months and six months ended June 30, 2006 and 2005 (in thousands):
| ** **                            | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** | **Six Months Ended** | ** ** | ** **   | ** ** |
|---------------------------------------|------------|----------------------------------|------------|--------------|------------|--------------------------------|------------|--------------|------------|
| ** **                            | ** ** | **June 30,**                | ** ** | **Increase** | ** ** | **June 30,**              | ** ** | **Increase** | ** ** |
| ** **                            | ** ** | **2006**                         | ** ** | **2005**     | ** ** | **(Decrease)**                 | ** ** | **2006**     | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| Revenues:                             |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Sales of petroleum  products          |       | $                                | 13,776     |         | $          | —                         |       | $            | 13,776     |   | $ | 13,776 |   | $ | — |   | $ | 13,776 |   |
| Gathering – Natural Gas          |       | 41,459                           |       | 36,956       |       | 4,503                          |       | 82,834       |       | 73,516 |   | 9,318 |   |
| Transportation – NGLs            |       | 10,738                           |       | 11,387       |       | (649                           | )          | 21,391       |       | 21,606 |   | (215 | ) |
| Other                                 |       | 4,372                            |       | 3,313        |       | 1,059                          |       | 8,721        |       | 6,718 |   | 2,003 |   |
| Total operating revenues              |       | 70,345                           |       | 51,656       |       | 18,689                         |       | 126,722      |       | 101,840 |   | 24,882 |   |
|                                  |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Costs and expenses:                   |       |                             |       |         |       |                           |       |         |       |   |   |   |   |
| Purchases of petroleum  products      |       | 12,949                           |       | —       |       | 12,949                         |       | 12,949       |       | — |   | 12,949 |   |
| Operating expense                     |       | 14,435                           |       | 7,256        |       | 7,179                          |       | 24,593       |       | 16,210 |   | 8,383 |   |
| Operating fuel and power              |       | 2,903                            |       | 2,355        |       | 548                            |       | 5,702        |       | 4,537 |   | 1,165 |   |
| General and  administrative expense   |       | 2,587                            |       | 1,372        |       | 1,215                          |       | 4,887        |       | 2,867 |   | 2,020 |   |
| Depreciation and  amortization        |       | 15,049                           |       | 12,686       |       | 2,363                          |       | 30,238       |       | 25,235 |   | 5,003 |   |
| Taxes – other than  income taxes |       | 1,371                            |       | 731          |       | 640                            |       | 2,622        |       | 1,825 |   | 797 |   |
| Gains on sales of assets              |       | —                           |       | —       |       | —                         |       | (1,371       | )          | (407 | ) | (964 | ) |
| Total costs and expenses              |       | 49,294                           |       | 24,400       |       | 24,894                         |       | 79,620       |       | 50,267 |   | 29,353 |   |
| Operating income                      |       | 21,051                           |       | 27,256       |       | (6,205                         | )          | 47,102       |       | 51,573 |   | (4,471 | ) |
| Other income – net               |       | 44                               |       | 60           |       | (16                            | )          | 120          |       | 102 |   | 18 |   |
| Earnings before interest              |       | $                                | 21,095     |         | $          | 27,316                         |       | $            | (6,221     | ) | $ | 47,222 |   | $ | 51,675 |   | $ | (4,453 | ) |

 

54

----

Thefollowing table presents volume and average rate information for the MidstreamSegment for the three months and six months ended June 30, 2006 and 2005:
| ** **                                                        | ** ** | **Three Months Ended** | ** ** | **Percentage** | ** ** | **Six Months Ended** | ** ** | **Percentage** | ** ** |
|-------------------------------------------------------------------|------------|----------------------------------|------------|----------------|------------|--------------------------------|------------|----------------|------------|
| ** **                                                        | ** ** | **June 30,**                | ** ** | **Increase**   | ** ** | **June 30,**              | ** ** | **Increase**   | ** ** |
| ** **                                                        | ** ** | **2006**                         | ** ** | **2005**       | ** ** | **(Decrease)**                 | ** ** | **2006**       | ** ** | **2005** | ** ** | **(Decrease)** | ** ** |
| Gathering – Natural Gas –  Jonah:                       |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Million cubic  feet (“MMcf”)                            |       | 111,346                          |       | 99,045         |       | 12                             | %          | 220,016        |       | 196,395 |   | 12 | % |
| Billion British  thermal units (“BBtu”)                 |       | 122,969                          |       | 109,516        |       | 12                             | %          | 242,976        |       | 216,817 |   | 12 | % |
| Average fee per  Million British thermal unit (“MMBtu”) |       | $                                | 0.210      |           | $          | 0.189                          |       | 11             | %          | $ | 0.208 |   | $ | 0.189 |   | 10 | % |
|                                                              |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Gathering – Natural Gas –  Val Verde:                   |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| MMcf                                                              |       | 46,938                           |       | 44,560         |       | 5                              | %          | 92,288         |       | 87,885 |   | 5 | % |
| BBtu                                                              |       | 41,675                           |       | 39,451         |       | 6                              | %          | 81,606         |       | 77,540 |   | 5 | % |
| Average fee per  MMBtu                                            |       | $                                | 0.389      |           | $          | 0.411                          |       | (5             | )%         | $ | 0.404 |   | $ | 0.420 |   | (4 | )% |
| Transportation – NGLs:                                       |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Thousand barrels                                                  |       | 17,652                           |       | 15,540         |       | 14                             | %          | 33,518         |       | 29,376 |   | 14 | % |
| Average rate per  barrel                                          |       | $                                | 0.608      |           | $          | 0.733                          |       | (17            | )%         | $ | 0.638 |   | $ | 0.735 |   | (13 | )% |
| Natural Gas Sales:                                                |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| BBtu                                                              |       | 2,627                            |       | —         |       | —                         |       | 2,627          |       | — |   | — |   |
| Average fee per  MMBtu                                            |       | $                                | 5.242      |           | $          | —                         |       | —         |       | $ | 5.242 |   | $ | — |   | — |   |
| Fractionation – NGLs:                                        |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Thousand barrels                                                  |       | 1,125                            |       | 1,087          |       | 3                              | %          | 2,277          |       | 2,226 |   | 2 | % |
| Average rate per  barrel                                          |       | $                                | 1.850      |           | $          | 1.820                          |       | 2              | %          | $ | 1.666 |   | $ | 1.732 |   | (4 | )% |
| Sales – Condensate:                                          |       |                             |       |           |       |                           |       |           |       |   |   |   |   |
| Thousand barrels                                                  |       | 18.3                             |       | 13.3           |       | 38                             | %          | 43.0           |       | 41.2 |   | 4 | % |
| Average rate per  barrel                                          |       | $                                | 68.20      |           | $          | 53.24                          |       | 28             | %          | $ | 65.52 |   | $ | 49.77 |   | 32 | % |

 

*Three MonthsEnded June 30, 2006 Compared with Three Months Ended June 30, 2005*

Revenues from thegathering of natural gas increased $4.5 million for the three months ended June30, 2006, compared with the three months ended June 30, 2005. Natural gasgathering revenues from the Jonah system increased $4.5 million and volumesgathered increased 12.3 billion cubic feet (“Bcf”) for the three months endedJune 30, 2006, primarily due to the expansion of the Jonah system in 2005. ThePhase IV expansion project on Jonah was completed in February 2006. Theexpansion increased the system capacity of Jonah to 1.5 Bcf per day with theaddition of 33,000 horsepower of compression and approximately 50 miles ofpipeline. Jonah’s average natural gas gathering rate per MMcf increased due tolower system wellhead pressures. Natural gas gathering revenues from the ValVerde system remained constant and volumes gathered increased 2.4 Bcf for thethree months ended June 30, 2006, primarily due to increased volumes from anatural gas connection on the Val Verde system and increased volumes fromtemporary interconnects with third party gatherers, partially offset by adecrease in the average natural gas gathering rate. Val Verde’s average naturalgas gathering rate per MMcf decreased due to contracts entered into relating tothe new connections, which have lower rates than the existing Val Verde system’saverage rates.

In late2005, we began to aggregate purchases of wellhead gas on Jonah and re-sell theaggregated quantities at key Jonah delivery points in order to facilitatethroughput on Jonah. The purchases and sales are generally contracted to occurin the same month to minimize price risk. During the second quarter of 2006,gas purchase and sales contracts were finalized and executed and the marketingof gas on the Jonah system began. Sales from petroleum products relating to thenatural gas marketing activities were $13.8 million for the three months endedJune 30, 2006, and purchases of petroleum products were $13.0 million.

55

----

Revenues from thetransportation of NGLs decreased $0.7 million for the three months ended June30, 2006, compared with the three months ended June 30, 2005, primarily due toa decrease in the average NGL transportation rate per barrel due to increasedshort-haul movements on the Chaparral Pipeline and a lower average rate perbarrel on the Panola Pipeline. During the 2006 period, volumes of NGLs transportedincreased due to increases on the Chaparral, Panola and Dean Pipelines,partially offset by decreased volumes transported on the Wilcox Pipeline.

Other operatingrevenues increased $1.1 million for the three months ended June 30, 2006,compared with the three months ended June 30, 2005, primarily due to newpipeline capacity leases on the Chaparral and Panola Pipelines and highercondensate sales on Jonah.

Costs and expenses(excluding purchases of petroleum products) increased $11.9 million for thethree months ended June 30, 2006, compared with the three months ended June 30,2005. Operating expense increased $7.2 million primarily due to $2.3 million ofexpenses relating to the formation of a joint venture for the expansion of theJonah system and to the proposed reduction in the General Partner’s maximumpercentage interest in our distributions (see Note 9 in the Notes to theConsolidated Financial Statements), a $1.7 million increase related toimbalance valuations, $0.8 million in severance expense as a result of themigration to a shared services environment with EPCO and an increase in otherpipeline operating and maintenance expense. Depreciation expense increased $1.3million primarily due to an increase on Jonah as a result of assets placed intoservice from the Phase IV expansion. Amortization expense increased $1.1million primarily due to an increase of $0.9 million on Val Verde due to highervolumes on contracts included in the intangible assets in the 2006 period. Generaland administrative expense increased $1.2 million primarily due to $0.6 millionin severance expense as a result of the migration to a shared servicesenvironment with EPCO and an increase in consulting and contract services. Taxes– other than income taxes increased $0.6 million due to actual property taxesbeing higher than previously estimated and a higher property asset base in the2006 period. Operating fuel and power increased $0.5 million primarily due tohigher transportation volumes and power rates.

*Six Months EndedJune 30, 2006 Compared with Six Months Ended June 30, 2005*

Revenues from thegathering of natural gas increased $9.3 million for the six months ended June30, 2006, compared with the six months ended June 30, 2005. Natural gasgathering revenues from the Jonah system increased $8.9 million and volumesgathered increased 23.6 Bcf for the six months ended June 30, 2006, primarilydue to the expansion of the Jonah system in 2005. Jonah’s average natural gasgathering rate per MMcf increased due to lower system wellhead pressures. Naturalgas gathering revenues from the Val Verde system increased $0.4 million andvolumes gathered increased 4.4 Bcf for the six months ended June 30, 2006,primarily due to increased volumes from a natural gas connection on the ValVerde system, better performance from coal seam infill wells and increasedvolumes from temporary interconnects with third party gatherers. Val Verde’saverage natural gas gathering rate per MMcf decreased due to contracts enteredinto relating to the new connections, which have lower rates than the existingVal Verde system’s average rates.

Salesfrom petroleum products relating to natural gas marketing activities were $13.8million for the six months ended June 30, 2006, and purchases of petroleumproducts were $13.0 million.

Revenues from thetransportation of NGLs decreased $0.2 million for the six months ended June 30,2006, compared with the six months ended June 30, 2005, due to a decrease inthe average NGL transportation rate per barrel primarily due to an increase inshort-haul movements on the Chaparral Pipeline and a lower average rate perbarrel on the Panola Pipeline. During the 2006 period, volumes of NGLs transportedincreased due to increases on the Chaparral, Panola and Dean Pipelines, partiallyoffset by decreased volumes transported on the Wilcox Pipeline.

Other operatingrevenues increased $2.0 million for the six months ended June 30, 2006,compared with the six months ended June 30, 2005. Other operating revenuesincreased $1.4 million as a result of new pipeline capacity leases on theChaparral Pipeline and the Panola Pipeline and $0.7 million on Jonah primarilydue to higher condensate sales.

56

----

Costs and expenses(excluding purchases of petroleum products) increased $16.4 million for the sixmonths ended June 30, 2006, compared with the six months ended June 30, 2005. Operatingexpense increased $8.4 million primarily due to $2.3 million of expensesrelating to the formation of a joint venture for the expansion of the Jonah systemand to the proposed reduction in the General Partner’s maximum percentageinterest in our distributions (see Note 9 in the Notes to the ConsolidatedFinancial Statements), a $2.3 million increase related to imbalance valuations,$0.8 million in severance expense as a result of the migration to a sharedservices environment with EPCO and an increase in other pipeline operating andmaintenance expense. Depreciation expense increased $2.8 million primarily dueto an increase on Jonah as a result of assets placed into service from thePhase IV expansion. Amortization expense increased $2.2 million primarily dueto an increase of $2.0 million on Val Verde due to higher volumes on contractsincluded in the intangible assets in the 2006 period. General and administrativeexpense increased $2.0 million primarily due to $0.6 million in severanceexpense as a result of the migration to a shared services environment with EPCOand an increase in consulting and contract services and supplies expense. Operatingfuel and power increased $1.2 million primarily due to higher transportationvolumes and power rates. Taxes – other than income taxes increased $0.8 milliondue to actual property taxes being higher than previously estimated and ahigher property asset base in the 2006 period. During the six months ended June30, 2006 and 2005, gains of $1.0 million and $0.4 million, respectively, wererecognized on the sales of various equipment at Val Verde.

*Discontinued Operations*

On March 31, 2006,we sold our ownership interest in the Pioneer silica gel natural gas processingplant located near Opal, Wyoming, together with Jonah’s rights to processnatural gas originating from the Jonah and Pinedale fields, located insouthwest Wyoming, to an affiliate of Enterprise for $38.0 million in cash. ThePioneer plant was not an integral part of our Midstream Segment operations, andnatural gas processing is not a core business. We have no continuinginvolvement in the operations or results of this plant. This transaction wasreviewed and approved by the Audit and Conflicts Committee of the board ofdirectors of our General Partner and a fairness opinion was rendered by anindependent third-party. The sales proceeds were used to fund organic growthprojects, retire debt and for other general partnership purposes. The carryingvalue of the Pioneer plant at March 31, 2006, prior to the sale, was $19.7million. Costs associated with the completion of the transaction wereapproximately $0.4 million.

Condensedstatements of income for the Pioneer plant, which is classified as discontinuedoperations, for the three months and six months ended June 30, 2006 and 2005,are presented below (in thousands):
| ** **                                  | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|---------------------------------------------|------------|----------------------------------|------------|--------------------------------|------------|
| ** **                                  | ** ** | **June 30,**                | ** ** | **June 30,**              | ** ** |
| ** **                                  | ** ** | **2006**                         | ** ** | **2005**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                        |       |                             |       |                           |       |   |   |   |   |
| Sales of  petroleum products                |       | $                                | 18         |                           | $          | 2,315 |   | $ | 3,828 |   | $ | 4,457 |   |
| Other                                       |       | 11                               |       | 680                            |       | 932 |   | 1,352 |   |
| Total operating revenues                    |       | 29                               |       | 2,995                          |       | 4,760 |   | 5,809 |   |
| Purchases of  petroleum products            |       | 139                              |       | 1,806                          |       | 3,000 |   | 3,176 |   |
| Operating  expenses                         |       | —                           |       | 158                            |       | 182 |   | 296 |   |
| Depreciation and  amortization              |       | —                           |       | 154                            |       | 51 |   | 306 |   |
| Taxes – other  than income taxes       |       | —                           |       | 31                             |       | 30 |   | 61 |   |
| Total costs and expenses                    |       | 139                              |       | 2,149                          |       | 3,263 |   | 3,839 |   |
| Income (loss)  from discontinued operations |       | $                                | (110       | )                              | $          | 846 |   | $ | 1,497 |   | $ | 1,970 |   |

 

Sales ofpetroleum products less purchases of petroleum products resulting from theprocessing activities at the Jonah Pioneer plant decreased $0.5 million for thesix months ended June 30, 2006, compared with the six months ended June 30,2005, primarily due to the sale of the Pioneer plant on March 31, 2006,partially offset by increased NGL prices. The Pioneer gas processing plant wascompleted during the first quarter of 2004, as a part of Jonah’s Phase IIIexpansion to increase the processing capacity in southwestern Wyoming. Pioneer’sprocessing agreements allowed the producers to elect annually whether to becharged under a fee-based arrangement or a fee

57

----

plus keep-whole arrangement. Under thefee-based election, Jonah received a fee for its processing services. Under thefee plus keep-whole election, Jonah received a lower fee for its processingservices, retained and sold the NGLs extracted during the process and deliveredto producers the residue gas equivalent in energy to the natural gas receivedfrom the producers. Jonah sold the NGLs it retained and purchased gas toreplace the equivalent energy removed in the liquids. For the 2005 and 2006periods, the producers elected the fee plus keep-whole arrangement.

**Interest Expense and CapitalizedInterest**

*Three MonthsEnded June 30, 2006 Compared with Three Months Ended June 30, 2005*

Interestexpense decreased $0.4 million for the three months ended June 30, 2006,compared with the three months ended June 30, 2005, primarily due to reductionsin interest expense of $2.5 million during 2006 related to interest rate swapsand $2.0 million of increased interest expense in the 2005 period related tothe termination of a treasury lock (see Note 3 in the Notes to the ConsolidatedFinancial Statements), partially offset by higher outstanding borrowings andhigher short term floating interest rates on our revolving credit facility.

Capitalizedinterest increased $2.0 million for the three months ended June 30, 2006,compared with the three months ended June 30, 2005, due to higher constructionwork-in-progress balances in 2006 as compared to the 2005 period.

*Six Months EndedJune 30, 2006 Compared with Six Months Ended June 30, 2005*

Interestexpense increased $3.6 million for the six months ended June 30, 2006, comparedwith the six months ended June 30, 2005, primarily due to higher outstandingborrowings and higher short term floating interest rates on our revolvingcredit facility, partially offset by reductions in interest expense of $2.5million during 2006 related to our interest rate swaps and $2.0 million ofincreased interest expense in the 2005 period related to the termination of atreasury lock (see Note 3 in the Notes to the Consolidated FinancialStatements).

Capitalizedinterest increased $4.2 million for the six months ended June 30, 2006,compared with the six months ended June 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, theState of Texas enacted a new business tax (the “Texas Margin Tax”) thatreplaces its existing franchise tax. In general, legal entities that dobusiness in Texas are subject to the new margin tax. Limited partnerships,limited liability companies, corporations, limited liability partnerships andjoint ventures are examples of the types of entities that are subject to theTexas Margin Tax. As a result of this change in tax law, our tax status in thestate of Texas changed from nontaxable to taxable. The Texas Margin Tax isconsidered an income tax for purposes of adjustments to deferred tax liability,as the tax is determined by applying a tax rate to a base that considers bothrevenues and expenses. Our deferred income tax expense for state taxes relatesonly to Texas Margin Tax obligations. The Texas Margin Tax becomes effectivefor franchise tax reports due on or after January 1, 2008. The Texas Margin Taxdue in 2008 will be based on revenues earned during the 2007 fiscal year.

The Texas MarginTax is assessed at 1% of Texas-sourced taxable margin measured by the ratio ofgross receipts from business done in Texas to gross receipts from business doneeverywhere. The taxable margin is computed as the lesser of (i) 70% of totalrevenue or (ii) total revenue less (a) cost of goods sold or (b) compensation. Thedeferred tax liability shown on our consolidated balance sheet reflects the nettax effect of temporary differences related to items such as property, plantand equipment; therefore, the deferred tax liability is classified asnoncurrent. The Texas Margin Tax is calculated, paid and filed at an affiliatedunitary group level. Generally, an affiliated group is made up of one or moreentities in which a controlling interest of at least 80% is owned by a commonowner or owners. Generally, a business is unitary if it is characterized by asharing or exchange

58

----

of value between members of the group, and a synergyand mutual benefit all of the members of the group achieved by workingtogether.

Since the TexasMargin Tax is determined by applying a tax rate to a base that considers bothrevenues and expenses, it has characteristics of an income tax. Accordingly, wedetermined the Texas Margin Tax should be accounted for as an income tax inaccordance with the provisions of SFAS No. 109, *Accountingfor Income Taxes*. The base used to compute the Texas Margin Taxaffects book-tax differences. All effects of a tax law change are accounted forin the period of the law’s enactment. A change in tax status that results froma change in tax law is recognized on the enactment date and the effect ofrecognizing a deferred tax liability or asset is included in income fromcontinuing operations. Therefore, we have calculated and recorded an estimateddeferred tax liability of approximately $0.5 million using the enacted tax rateexpected to apply to taxable income in the periods in which the deferred taxliability is expected to be realized or settled.

Theconstitutionality of the Texas Margin Tax is being questioned. The TexasComptroller has requested a formal opinion from the Texas Attorney General onwhether the Texas Margin Tax is an impermissible income tax that violates theTexas constitution. The Texas constitution requires voter approval of any taximposed on the net income of natural persons, including a person’s share ofpartnership unincorporated association income; such approval was not obtainedfor the Texas Margin Tax. The Comptroller has requested that the AttorneyGeneral determine whether the direct imposition of the Texas Margin Tax onparterships without voter approval violates this constitutional requirement. TheAttorney General’s decision is not expected until late 2006 or early 2007. Ifthe Texas Margin Tax is ultimately challenged in court, the legislationenacting the Texas Margin Tax gives the Texas Supreme Court jurisdiction overthe constitutional challenge and allows the Court to grant injunctive ordeclaratory relief. The Court would have 120 days from the date the challengeis filed to make a ruling.

**Financial Condition and Liquidity**

Cash generatedfrom operations, credit facilities and debt and equity offerings are ourprimary sources of liquidity. At June 30, 2006, and December 31, 2005, we hadworking capital deficits of $7.2 million and $38.1 million, respectively. AtJune 30, 2006, we had approximately $240.8 million in available borrowingcapacity under our revolving credit facility to cover any working capital needs.Cash flows for the six months ended June 30, 2006 and 2005 were as follows (inmillions):
|                              | ** ** | **Six Months Ended** | ** ** |
|------------------------------|------------|--------------------------------|------------|
| ** **                   | ** ** | **June 30,**              | ** ** |
| ** **                   | ** ** | **2006**                       | ** ** | **2005** | ** ** |
| ** **                   | ** ** | ** **                     | ** ** | ** ** | ** ** |
| Cash provided by  (used in): |       |                           |       |   |   |
| Operating activities         |       | $                              | 143.1      |   | $ | 30.0 |   |
| Investing activities         |       | (48.3                          | )          | (131.4 | ) |
| Financing  activities        |       | (94.7                          | )          | 86.5 |   |
|                              |            |                                |            |  |  |  |  |

 

59

----

*Operating Activities*

Net cash fromoperating activities for the six months ended June 30, 2006 and 2005, wascomprised of the following (in millions):
|                                                      | ** ** | **Six Months Ended** | ** ** |
|------------------------------------------------------|------------|--------------------------------|------------|
| ** **                                           | ** ** | **June 30,**              | ** ** |
| ** **                                           | ** ** | **2006**                       | ** ** | **2005** | ** ** |
| Net income                                           |       | $                              | 104.3      |   | $ | 88.4 |   |
| Income from  discontinued operations                 |       | (19.4                          | )          | (2.0 | ) |
| Deferred income  tax expense                         |       | 0.5                            |       | — |   |
| Depreciation and  amortization                       |       | 57.4                           |       | 51.7 |   |
| Earnings in  equity investments                      |       | (3.7                           | )          | (11.9 | ) |
| Distributions  from equity investments               |       | 16.3                           |       | 19.0 |   |
| Gains on sales  of assets                            |       | (1.4                           | )          | (0.6 | ) |
| Non-cash portion  of interest expense                |       | 0.8                            |       | 0.8 |   |
| Cash used in  working capital and other              |       | (13.2                          | )          | (117.7 | ) |
| Net cash provided by continuing operating activities |       | 141.6                          |       | 27.7 |   |
| Cash flows from  discontinued operations             |       | 1.5                            |       | 2.3 |   |
| Net cash from operating activities                   |       | $                              | 143.1      |   | $ | 30.0 |   |

 

Net cash providedby operating activities increased $113.1 million for the six months ended June30, 2006, compared with the six months ended June 30, 2005, primarily due to adecrease of $67.6 million in crude oil inventory (as discussed below) and dueto the timing of cash disbursements and cash receipts for other working capitalcomponents, partially offset by a decrease of $2.7 million in distributionsreceived from our 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.

During the secondquarter of 2005, we purchased crude oil and simultaneously entered intooffsetting sales contracts for physical delivery during the fourth quarter of2005.  The purpose of these contracts wasto 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 fromoperating activities for the six months ended June 30, 2006 and 2005, includedinterest payments, net of amounts capitalized, of $42.1 million and $41.1million, respectively.  Excluding the effectsof hedging activities and interest capitalized during the year ended December31, 2006, we expect interest payments on our fixed rate Senior Notes to beapproximately $78.0 million.  We expectto pay our interest payments with cash flows from operating activities.

*Investing Activities*

Cash flows used ininvesting activities totaled $48.3 million for the six months ended June 30,2006, and were comprised of $82.5 million of capital expenditures, $2.5 millionof cash contributions for TE Products’ ownership interest in Centennial foroperating needs, $1.7 million of cash contributions for TE Products’ ownershipinterest in MB Storage for capital expenditures and $1.4 million of cash paidfor linefill on assets owned, partially offset by $39.8 million in net cashproceeds from asset sales in our Midstream Segment, of which $38.0 millionrelated to cash proceeds received from the sale of the Pioneer plant on March31, 2006.  Cash flows used in investingactivities totaled $131.4 million for the six months ended June 30, 2005, andwere comprised of $82.9 million of capital expenditures, $42.5 million for theacquisition of crude oil assets, $5.4 million of cash paid for linefill on

60

----

assets owned and $1.1 million of cash contributionsfor TE Products’ ownership interest in MB Storage for capital expenditures,partially offset by $0.5 million in net cash proceeds from asset sales in ourUpstream and Downstream Segments.

*Financing Activities*

Cash flows used infinancing activities totaled $94.7 million for the six months ended June 30,2006, and were comprised of $133.8 million of distributions paid tounitholders, partially offset by $39.1 million in borrowings, net ofrepayments, on our revolving credit facility. Cash flows provided by financing activities totaled $86.5 million forthe six months ended June 30, 2005, and were comprised of $278.8 million fromthe issuance of 7.0 million Units in May and June 2005, partially offset by$117.3 million of distributions paid to unitholders and $75.0 million in repayments,net of borrowings, on our revolving credit facility.

We paid cashdistributions of $133.8 million ($1.350 per Unit) and $117.3 million ($1.325per Unit) during each of the six months ended June 30, 2006 and 2005,respectively.  Additionally, we declareda cash distribution of $0.675 per Unit for the quarter ended June 30,2006.  We will pay the distribution of$72.4 million on August 7, 2006, to unitholders of record on July 31, 2006.

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.

**Other Considerations**

***Universal Shelf***

**We have filed with the Securities andExchange Commission a universal shelf registration statement that, subject toagreement on terms at the time of use and appropriate supplementation, allowsus to issue, in one or more offerings, up to an aggregate of $2.0 billion ofequity securities, debt securities or a combination thereof.  Taking into account our May 2005 and July2006 equity offerings, in which we issued $290.8 million and $204.1 million ofequity securities, respectively, we had $1.5 billion remaining under this shelfregistration, subject to customary marketing terms and conditions.**

*Credit Facilities*

We havein place an unsecured revolving credit facility for up to $700.0 million (“RevolvingCredit Facility”), which may be increased up to a maximum of $850.0 millionupon our request, subject to lender approval and the satisfaction of certainother conditions.  The Revolving CreditFacility expires on December 13, 2010. Interest is payable at an applicable margin above either the lender’sbase rate or LIBOR.  At June 30, 2006,$445.0 million was outstanding under the facility, and we had $240.8 million ofavailable borrowing capacity, which includes $14.2 million of outstandingletters of credit.  Financial covenantsin the Revolving Credit Facility require that we maintain a ratio ofConsolidated Funded Debt to Pro Forma EBITDA (as defined and calculated in thefacility) of less than 4.75 to 1.00 (subject to adjustment for specified acquisitions)and a ratio of EBITDA to Interest Expense (as defined and calculated in thefacility) of at least 3.00 to 1.00, in each case with respect to specifiedtwelve month periods.  Other restrictivecovenants in the credit agreement limit our ability to, among other things,incur additional indebtedness, make distributions in excess of Available Cash,incur liens, engage in specified transactions with affiliates and completemergers, acquisitions and sales of assets. At June 30, 2006, we were in compliance with the covenants of theRevolving Credit Facility.  In July 2006,we used the net proceeds of $195.5 million from the July 2006 equity offeringto reduce outstanding borrowings under the Revolving Credit Facility.

61

----

On July 31,2006, we executed a third amendment (“Third Amendment”) to our Revolving CreditFacility which extends the maturity date of amounts borrowed under theRevolving Credit Facility from December 2010 to December 2011.  The Third Amendment also releases Jonah as aguarantor of the Revolving Credit Facility. The Third Amendment restricts theamount of outstanding debt of the Jonah joint venture to debt owing to theowners of its partnership interests and other debt in the principal aggregateamount of $50.0 million.  In addition,the Third Amendment allows for swing line loans up to $25.0 million (within the$700.0 million total borrowing limit) and modifies our financial covenants to,among other things, allow us to include in the calculation of our ConsolidatedEBITDA (as defined in the Revolving Credit Facility, as amended) pro formaadjustments for material projects.

EffectiveJuly 31, 2006, Jonah Gas Gathering Company was also released from itsguarantee to Wachovia Bank pursuant to the provisions of Section 14.04 dated asof February 20, 2002, of the Indenture between us, as issuer,TE Products, TCTM, TEPPCO Midstream and Jonah Gas Gathering Company, eachas subsidiary guarantors and Wachovia Bank, as trustee.

*Future CapitalNeeds and Commitments*

Weestimate that capital expenditures, excluding acquisitions, for 2006 will beapproximately $271.1 million (including $6.0 million of capitalizedinterest).  We expect to spendapproximately $195.0 million for revenue generating projects.  Capital spending on revenue generatingprojects and facility improvements will include approximately $85.4 million forthe expansion of our Downstream Segment facilities.  We expect to spend $45.5 million to expandour Upstream Segment pipelines and facilities in West Texas and Oklahoma andapproximately $64.1 million to expand our Midstream Segment assets, withfurther expansions on our Jonah system. We expect to spend approximately $39.9 million to sustain existingoperations, including life-cycle replacements for equipment at variousfacilities and pipeline and tank replacements among all of our businesssegments.  We expect to spendapproximately $30.2 million to improve operational efficiencies and reducecosts among all of our business segments. During 2006, TE Products may be required to contribute additional cashto Centennial to cover capital expenditures, acquisitions or other operatingneeds and to MB Storage to cover significant capital expenditures or additionalacquisitions.  We continually review andevaluate potential capital improvements and expansions that would becomplementary to our present business operations.  These expenditures can vary greatly dependingon the magnitude of our transactions.  Wemay finance capital expenditures through internally generated funds, debt orthe issuance of additional equity.

Additionally,during the remainder of 2006, we expect to contribute approximately $119.0million to our Jonah joint venture for the construction of the Phase Vexpansion.  In August 2006, we enteredinto an amended and restated general partnership agreement forming a jointventure to expand our Jonah system with an affiliate of Enterprise.  For additional information, see “-Overview ofBusiness” above.

*Liquidity Outlook*

We believe that wewill continue 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 through operatingcash flows and our arrangement with an affiliate of Enterprise under the jointventure 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-Balance Sheet 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

62

----

Centennial catastrophic events as discussed below andan outstanding letter of credit.  Inaddition, we have entered into various leases covering assets utilized inseveral areas of our operations.

Centennial enteredinto credit facilities totaling $150.0 million, and as of June 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-term creditfacility, TE Products could be relinquished from responsibility under theguarantee should Centennial meet certain financial tests.  If Centennial defaults on its outstandingbalance, the estimated maximum potential amount of future payments for TE Productsand Marathon is $75.0 million each at June 30, 2006.

TE Products,Marathon and Centennial have entered into a limited cash call agreement, whichallows each member to contribute cash in lieu of Centennial procuring separateinsurance in the event of a third-party liability arising from a catastrophicevent.  There is an indefinite term forthe agreement and each member is to contribute cash in proportion to itsownership interest, up to a maximum of $50.0 million each.  As a result of the catastrophic eventguarantee, TE Products has recorded a $4.5 million obligation, which representsthe present value of the estimated amount that we would have to pay under theguarantee.  If a catastrophic event wereto occur and we were required to contribute cash to Centennial, contributionsexceeding our deductible might be covered by our insurance.

One of oursubsidiaries, TEPPCO Crude Oil, L.P. (“TCO”), has entered into master equipmentlease agreements 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.

*Contractual Obligations*

The followingtable summarizes our debt repayment obligations and material contractualcommitments as of June 30, 2006 (in millions): 
| ** **                                  | ** ** | **Amount of Commitment Expiration Per Period** | ** ** |
|---------------------------------------------|------------|-------------------------------------------------------------------------|------------|
| ** **                                  | ** ** | **Total**                                                               | ** ** | **Less than  1 Year** | ** ** | **1-3 Years** | ** ** | **4-5 Years** | ** ** | **After  5 Years** | ** ** |
|                                        |       |                                                                    |       |   |   |   |   |   |   |   |   |
| Revolving Credit  Facility                  |       | $                                                                       | 445.0      |   | $ | — |   | $ | — |   | $ | 445.0 |   | $ | — |   |
| 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)                       |       | 799.6                                                                   |       | 103.5 |   | 195.5 |   | 169.9 |   | 330.7 |   |
| Debt and  interest subtotal                 |       | 2,334.6                                                                 |       | 103.5 |   | 375.5 |   | 614.9 |   | 1,240.7 |   |
| Operating leases (4)                        |       | 75.3                                                                    |       | 18.4 |   | 24.4 |   | 13.6 |   | 18.9 |   |
| Capital expenditure  obligations (5)        |       | 1.0                                                                     |       | 1.0 |   | — |   | — |   | — |   |
| Standby letter of  credit (6)               |       | 14.2                                                                    |       | 14.2 |   | — |   | — |   | — |   |
| Other liabilities and  deferred credits (7) |       | 14.6                                                                    |       | — |   | 13.5 |   | 0.3 |   | 0.8 |   |
| Total                                       |       | $                                                                       | 2,439.7    |   | $ | 137.1 |   | $ | 413.4 |   | $ | 628.8 |   | $ | 1,260.4 |   |

 

63

----

----

(1)          Obligations of TE Products.

(2)          Our TE Products subsidiary entered into an interest rateswap agreement to hedge its exposure to changes in the fair value of its 7.51%Senior Notes due 2028.  At June 30, 2006,the 7.51% Senior Notes include an adjustment to decrease the fair value of thedebt by $11.3 million related to this interest rate swap agreement.  We also entered into interest rate swapagreements to hedge our exposure to changes in the fair value of our 7.625%Senior Notes due 2012.  At June 30, 2006,the 7.625% Senior Notes include a deferred gain, net of amortization, fromprevious interest rate swap terminations of $30.2 million.  At June 30, 2006, our 6.45% Senior Notes, our7.625% Senior Notes and our 6.125% Senior Notes include $2.2 million ofunamortized debt discounts.  The fairvalue adjustments, the deferred gain adjustment and the unamortized debtdiscounts are excluded from this table.

(3)          Includes interest payments due on our Senior Notes andinterest payments and commitment fees due on our Revolving Credit Facility. Theinterest amount calculated on the Revolving Credit Facility is based on theassumption that the amount outstanding and the interest rate charged bothremain at their current levels.

(4)          Includes a pipeline capacity lease with Centennial.  In January 2003, TE Products entered into apipeline capacity lease agreement with Centennial for a period of five yearsthat contains a minimum throughput requirement. For the six months ended June 30, 2006, TE Products exceeded the minimumthroughput requirements on the lease agreement.

(5)          Includes accruals for costs incurred but not yet paidrelating to capital projects.

(6)          At June 30, 2006, we had outstanding a $14.2 millionstandby letter of credit in connection with crude oil purchased in the firstquarter of 2006.  The payable related tothese purchases of crude oil is expected to be paid during the third quarter of2006.

(7)          Excludes approximately $8.4 million of long-termdeferred revenue payments, which are being transferred to income over the termof the respective revenue contracts and $4.2 million related to our estimatedlong-term portion of our obligation under a catastrophic event guarantee forCentennial.  The amount of commitment byyear is our best estimate of projected payments of these long-term liabilities.

We expect to repaythe long-term, senior unsecured obligations and bank debt through the issuanceof additional long-term senior unsecured debt at the time the 2008, 2012, 2013and 2028 debt matures, issuance of additional equity, with proceeds fromdispositions of assets, cash flow from operations or any combination of theabove items.

In addition to theitems in the table above, we have entered into various operational commitmentsand agreements related to pipeline operations and to the marketing,transportation, terminaling and storage of crude oil.  The majority of contractual commitments wemake for the purchase of crude oil range in term from a thirty-day evergreen toone year.  A substantial portion of thecontracts for the purchase of crude oil that extend beyond thirty days includecancellation provisions that allow us to cancel the contract with thirty dayswritten notice.  During the six monthsended June 30, 2006, crude oil purchases averaged approximately $769.9 millionper month.

Our seniorunsecured debt is rated BBB- by Standard and Poors (“S&P”) and Baa3 byMoody’s Investors Service (“Moody’s”). S&P assigned this rating on June 14, 2005, following its review ofthe ownership structure, corporate governance issues, and proposed fundingafter the acquisition of the General Partner by DFI.  Both ratings are with a stable outlook.  A rating reflects only the view of a ratingagency and is not a recommendation to buy, sell or hold any indebtedness.  Any rating can be revised upward or downwardor withdrawn at any time by a rating agency if it determines that thecircumstances warrant such a change and should be evaluated independently ofany other rating.  The senior unsecureddebt of our subsidiary, TE Products, is also rated BBB- by S&P and Baa3 byMoody’s.  Both ratings are with a stableoutlook and were reaffirmed during the first quarter of 2006.

64

----

***RecentAccounting Pronouncements***

**See discussion ofnew accounting pronouncements in Note 1 in the Notes to the ConsolidatedFinancial Statements.**

**Item 3.  Quantitativeand Qualitative Disclosures About Market Risk**

Foradditional discussion of our exposure to market risks, please refer to “Item7A.  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 exposedto market risk through changes in crude oil commodity prices and interestrates.  We do not have foreign exchangerisks.  Our Risk Management Committee hasestablished policies to monitor and control these market risks.  The Risk Management Committee is comprised,in part, of senior executives of the Company.

We seek tomaintain a position that is substantially balanced between crude oil purchasesand sales and future delivery obligations. On the majority of our crude oil derivative contracts, we take thenormal purchase and normal sale exclusion in accordance with SFAS No. 133, *Accounting for Derivative Instruments and Hedging Activities*,and SFAS No. 138, *Accounting for Certain DerivativeInstruments and Certain Hedging Activities, an amendment of FASB Statement No.133*.

On a small portionof our crude oil marketing business, we enter into derivative contracts such asswaps and other business hedging devices for which we cannot take the normalpurchase and normal sale exclusion. Generally, hedge accounting is elected. The terms of these contracts are typically one year or less.  The purpose is to balance our position orlock in a margin and, as such, the derivative contracts do not expose us toadditional significant market risk.  Forderivatives where hedge accounting is elected, the effective portion of changesin fair value are recorded in other comprehensive income and reclassified intoearnings as such transactions are settled. For derivatives where hedge accounting is not elected, we mark thesetransactions to market and the changes in the fair value are recognized incurrent earnings.  This results in somefinancial statement variability during quarterly periods; however, anyunrealized gains and losses reflected in the financial statements related tomarking these transactions to market are offset by realized gains and losses indifferent quarterly periods when the transactions are settled.

At June 30, 2006,we had a limited number of commodity derivatives that were accounted for ascash flow hedges.  Gains and losses onthese derivatives are offset against corresponding gains or losses of thehedged item and are deferred through other comprehensive income, thusminimizing exposure to cash flow risk. The fair value of the open positions at June 30, 2006, was a loss of$0.2 million.  Assuming a hypotheticalacross-the-board 10% price decrease in the applicable forward curve, the changein fair value of the hedging instrument would have been $0.2 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%.

*Interest Rate Risk*

We have utilizedand expect to continue to utilize interest rate swap agreements to hedge aportion of our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floatinginterest rate

65

----

mix of our total debt portfolio and overall cost ofborrowing.  Interest rate swaps thatmanage our cash flow risk reduce our exposure to increases in the benchmarkinterest rates underlying variable rate debt. Interest rate swaps that manage our fair value risks are intended toreduce our exposure to 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 June 30, 2006,we had $445.0 million outstanding under our variable interest rate revolvingcredit facility.  The interest rate isbased, at our option, on either the lender’s base rate plus a spread or LIBORplus a spread in effect at the time of the borrowings and is adjusted monthly,bimonthly, quarterly or semiannually. On January 20, 2006, we entered into interest rate swap agreementswith a total notional amount of $200.0 million to hedge our exposure toincreases in the benchmark interest rate underlying our variable rate revolvingcredit facility.  These interest rateswaps mature in January 2008.  For the period from January 20, 2006 through June 30, 2006, changes in thefair value of the swaps were recognizedin earnings, which for the six months ended June 30,2006, was a $2.5 million reductionto interest expense.  Under the swap agreements, we pay afixed rate of interest ranging from 4.67% to 4.695% and receive a floating ratebased on a three-month U.S. Dollar LIBOR rate. Because these swaps will be designated as cash flow hedgeseffective in the third quarter of 2006, future changes in fair value, tothe extent the swaps are effective, will be recognized in othercomprehensive income until the hedged interest costs are recognized inearnings.  Utilizing the balances of ourvariable interest rate debt outstanding at June 30, 2006, and including theeffects 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 followingtable summarizes the estimated fair values of the Senior Notes as of June 30,2006 and December 31, 2005 (in millions):
|                                                   | ** ** | **Fair Value** | ** ** |
|---------------------------------------------------|------------|---------------------|------------|
| ** **                                        | ** ** | **Face  Value**     | ** ** | **June 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|                                              |       |                |       |   |   |   |   |
| 6.45% TE Products  Senior Notes, due January 2008 |       | $                   | 180.0      |   | $ | 181.0 |   | $ | 183.7 |   |
| 7.625% Senior Notes,  due February 2012           |       | 500.0               |       | 526.9 |   | 552.0 |   |
| 6.125% Senior Notes,  due February 2013           |       | 200.0               |       | 196.1 |   | 205.6 |   |
| 7.51% TE Products Senior Notes, due January 2028  |       | 210.0               |       | 221.1 |   | 224.1 |   |
|                                                   |            |                     |            |  |  |  |  |  |  |  |

 

In October 2001,TE Products entered into an interest rate swap agreement to hedge its exposureto changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. Wedesignated this swap agreement as a fair value hedge.  The swap agreement has a notional amount of$210.0 million and matures in January 2028 to match the principal and maturityof the TE Products Senior Notes.  Underthe swap agreement, TE Products pays a floating rate of interest based on athree-month U.S. Dollar LIBOR rate, plus a spread of 147 basis points, andreceives a fixed rate of interest of 7.51%. During the six months ended June 30, 2006, and 2005, we recognizedreductions in interest expense of $1.2 million and $3.3 million, respectively,related to the difference between the fixed rate and the floating rate ofinterest on the interest rate swap. During the quarters ended June 30, 2006 and 2005, we measured the hedgeeffectiveness of this interest rate swap and noted that no gain or loss fromineffectiveness was required to be recognized. The fair value of this interest rate swap was a loss of approximately$11.3 million and $0.9 million at June 30, 2006, and December 31, 2005,respectively.  Utilizing the balance ofthe 7.51% TE Products Senior Notes outstanding at June 30, 2006, and includingthe effects of hedging activities, if market interest rates increased 100 basispoints, the annual increase in interest expense would be $2.1 million.

**Item 4.  Controls andProcedures**

As of theend of the period covered by this report, our management carried out anevaluation, with the participation of our principal executive officer (the “CEO”)and our principal financial officer (the “CFO”), of the effectiveness of ourdisclosure controls and procedures pursuant to Rule 13a-15 of the SecuritiesExchange Act of 1934.  Based on thoseevaluations, as of June 30, 2006, the CEO and CFO concluded:

66

----

(i)             that our disclosure controls and procedures aredesigned to ensure that information required to be disclosed by us in thereports that we file or submit under the Securities Exchange Act of 1934 isrecorded, processed, summarized and reported within the time periods specifiedin the SEC’s rules and forms, and that such information is accumulated andcommunicated to our management, including the CEO and CFO, as appropriate toallow timely decisions regarding required disclosure; and

(ii)          that our disclosure controls and procedures are effective.

*Changes inInternal Control over Financial Reporting*

There hasbeen no change in our internal control over financial reporting during thesecond quarter of 2006 that has materially affected, or is reasonably likely tomaterially affect, our internal control over financial reporting.

**PART II.  OTHER INFORMATION**

**Item 1.  Legal Proceedings**

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 thatthe outcome of these lawsuits and other proceedings will not individually or inthe aggregate have a material adverse effect on our consolidated financial position,results of operations or cash flows.  Seediscussion of legal proceedings in Note 13 in the Notes to the ConsolidatedFinancial Statements, which is incorporated into this item by reference.

**Item 1A.  Risk Factors**

Unitholdersand potential investors in our Units should carefully consider the followingrisk factors in addition to other information in this Report, our Annual Reporton Form 10-K for the year ended December 31, 2005 and our Current Report onForm 8-K filed on June 16, 2006.  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.  We are relying upon the safe-harbor forforward-looking statements, and any such statements made by or on behalf of usare qualified by reference to the following cautionary statements, as well asto those set forth elsewhere in this Report.

**RisksRelating to Our Business**

***Potentialfuture acquisitions and expansions may affect our business by substantiallyincreasing the level of our indebtedness and contingent liabilities andincreasing our risks of being unable to effectively integrate these newoperations.***

As part of ourbusiness strategy, we evaluate and acquire assets and businesses and undertakeexpansions that we believe complement our existing assets and businesses.  Acquisitions and expansions may requiresubstantial capital or the incurrence of substantial indebtedness.  Consummation of future acquisitions andexpansions may significantly change our capitalization and results ofoperations.  Our growth may be limited ifacquisitions or expansions are not made on economically favorable terms.

Acquisitions andbusiness expansions involve numerous risks, including difficulties in theassimilation of the assets and operations of the acquired businesses,inefficiencies and difficulties that arise because of unfamiliarity with newassets, personnel and the businesses associated with them and new geographic areasand the diversion of management’s attention from other business concerns.  Further, unexpected costs and challenges mayarise whenever businesses with different operations or management are combined,and we may experience unanticipated delays in realizing the benefits of anacquisition.  Following an acquisition,we may discover previously unknown liabilities

67

----

associated with the acquired business for which we mayhave no recourse or limited recourse under applicable indemnificationprovisions.

***Our future debtlevel may limit our future financial and operating flexibility.***

As ofJune 30, 2006, we had approximately $1.5 billion of consolidated debtoutstanding, consisting of $445.0 million of borrowings under ourrevolving credit facility and $1.1 billion principal amount of seniornotes.   In July 2006, we used the netproceeds of $195.5 million from the July 2006 equity offering to reduceoutstanding borrowings under the Revolving Credit Facility.  The amount of our future debt could havesignificant effects on our operations, including, among other things:

·                  a significantportion of our cash flow could be dedicated to the payment of principal andinterest on our future debt and may not be available for other purposes,including the payment of distributions on our Units and capital expenditures;

·                  credit ratingagencies may view our debt level negatively;

·                  covenantscontained in our existing debt arrangements will require us to continue to meetfinancial tests that may adversely affect our flexibility in planning for andreacting to changes in our business;

·                  our ability toobtain additional financing for working capital, capital expenditures,acquisitions and general partnership purposes may be limited;

·                  we may be at acompetitive disadvantage relative to similar companies that have less debt; and

·                  we may be morevulnerable to adverse economic and industry conditions as a result of oursignificant debt level.

Our revolvingcredit facility contains restrictive financial and other covenants that, amongother things, limit our ability to incur additional indebtedness, make distributionsin excess of Available Cash (see Note 9 in the Notes to the ConsolidatedFinancial Statements for discussion of Available Cash), and complete mergers,acquisitions and sales of assets.  Thefacility also prevents us from making a distribution if an event of defaultunder the facility has occurred or would occur as a result of thedistribution.  Our breach of theserestrictions or restrictions in the provisions of our other indebtedness couldpermit the holders of the indebtedness to declare all amounts outstandingthereunder to be immediately due and payable and, in the case of our revolvingcredit facility, to terminate all commitments to extend further credit.  Although our revolving credit facility restrictsour ability to incur additional debt above certain levels, any debt we mayincur in compliance with these restrictions may still be substantial.

Our ability toaccess capital markets to raise capital on favorable terms will be affected byour debt level, the amount of our debt maturing in the next several years andcurrent maturities, and by prevailing market conditions.  Moreover, if the rating agencies were todowngrade our credit ratings, then we could experience an increase in ourborrowing costs, difficulty accessing capital markets or a reduction in themarket price of our Units.  Such adevelopment could adversely affect our ability to obtain financing for workingcapital, capital expenditures or acquisitions or to refinance existingindebtedness.  If we are unable to accessthe capital markets on favorable terms at the time a debt obligation becomesdue in the future, we might be forced to refinance some of our debt obligationsthrough bank credit, as opposed to long-term public debt securities or equitysecurities.  The price and terms uponwhich we might receive such extensions or additional bank credit, if at all,could be more onerous than those contained in existing debt agreements.  Any such arrangements could, in turn,increase the risk that our leverage may adversely affect our future financialand operating flexibility and thereby impact our ability to pay cashdistributions at expected rates.

68

----

***Our cashdistributions may vary based on our operating performance and level of cashreserves.***

Distributions aredependent on the amount of cash we generate and may fluctuate based on ourperformance.  We cannot guarantee that wewill continue to pay distributions at the current level each quarter.  The actual amount of cash that is availableto be distributed each quarter will depend upon numerous factors, some of whichare beyond our control and the control of our General Partner.  These factors include but are not limited tothe following:

·                  the volume ofproducts that we handle and the prices we receive for our services;

·                  the level of ouroperating costs;

·                  the level ofcompetition in our business segments;

·                  prevailingeconomic conditions;

·                  the level ofcapital expenditures we make;

·                  the restrictionscontained in our debt agreements and debt service requirements;

·                  fluctuations inour working capital needs;

·                  the cost ofacquisitions, if any; and

·                  the amount, ifany, of cash reserves established by our General Partner in its solediscretion.

In addition, ourability to pay the minimum quarterly distribution each quarter dependsprimarily on our cash flow, including cash flow from financial reserves andworking capital borrowings, not solely on profitability, which is affected bynon-cash items.  As a result, we may makecash distributions during periods when we record losses and we may not makedistributions during periods when we record net income.

***The interruption ofdistributions to us from our subsidiaries and joint ventures may affect ourability to satisfy our obligations and to make distributions to our partners.***

We are a holdingcompany with no material operations.  Ouronly significant assets are the equity interests we own in our subsidiaries andjoint ventures.  As a result, we dependupon the earnings and cash flow of our subsidiaries and joint ventures and thedistribution of their cash to us in order to meet our obligations and to allowus to make distributions to our partners. In addition, charter documents and other agreements governing our jointventures may restrict or limit the occurrence and amount of distributions to usunder certain circumstances.

***Expanding our natural gas gathering business by constructingnew pipelines and compression facilities subjects us to construction risks andrisks that natural gas supplies will not be available upon completion of thenew pipelines and cash flows from such capital projects may not be immediate******.***

Weengage in several construction and expansion projects involving existing andnew facilities that require significant capital expenditures, which may exceedour estimates.  We intend to expand thecapacity of our existing natural gas gathering systems through the constructionof additional facilities.  Generally, wemay have only limited natural gas supplies committed to these facilities priorto their construction.  Moreover, we mayconstruct facilities to capture anticipated future growth in production in aregion in which anticipated production growth does not materialize.  As a result, there is the risk that newfacilities may not be able to attract enough natural gas to achieve ourexpected investment return, which could adversely affect our financial positionor results of operations.  Additionally,operating cash flow from a particular project may not be realized until aperiod of time after its completion or at expected levels.  Construction and expansion projects may occurover an extended period of time.  If weexperience unanticipated or extended delays in generating operating cash flowfrom these projects, we may be required to reduce or reprioritize our capitalbudget, sell non-core assets, access the capital markets or decrease or limitdistributions to unitholders in order to meet our capital requirements.

***Our tariff rates are subject to review and possibleadjustment by federal and state regulators, which could have a material adverseeffect on our financial condition and results of operations******.***

69

----

The Federal EnergyRegulatory Commission (“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.  It can also require refunds of amountscollected pursuant to rates that are ultimately found to be unlawful.  The FERC and interested parties can alsochallenge tariff rates that have become final and effective.  Because of the complexity of rate making, thelawfulness of any rate is never assured.

The FERC usesprescribed rate methodologies for approving regulated tariff rates fortransporting crude oil and refined products. Our interstate tariff rates are either market-based or derived inaccordance with the FERC’s indexing methodology, which currently allows apipeline to increase its rates by a percentage linked to the producer priceindex for finished goods.  Thesemethodologies may limit our ability to set rates based on our actual costs ormay delay the use of rates reflecting increased costs.  Changes in the FERC’s approved methodologyfor approving rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates couldadversely affect our cash flow. Challenges to our tariff rates could be filed with the FERC.

The intrastateliquids pipeline transportation services we provide are subject to variousstate laws and regulations that apply to the rates we charge and the terms andconditions of the services we offer. Although state regulation typically is less onerous than FERCregulation, the rates we charge and the provision of our services may besubject to challenge.

Although ournatural gas gathering systems are generally exempt from FERC regulation underthe Natural Gas Act of 1938, FERC regulation still significantly affects ournatural gas gathering business.  Inrecent years, the FERC has pursued pro-competition policies in its regulationof interstate natural gas pipelines.  Ifthe FERC does not continue this approach, it could have an adverse effect onthe rates we are able to charge in the future. In addition, our natural gas gathering operations could be adverselyaffected in the future should they become subject to the application of federalregulation of rates and services. Additional rules and legislation pertaining to these matters areconsidered and adopted from time to time. We cannot predict what effect, if any, such regulatory changes andlegislation might have on our operations, but we could be required to incuradditional capital expenditures.

***Ourpartnership status may be a disadvantage to us in calculating our cost ofservice for rate-making purposes.***

In May 2005,the FERC issued a policy statement permitting the inclusion of an income taxallowance in the cost of service-based rates of a pipeline for partnershipinterests held by partners with an actual or potential income tax liability onpublic utility income, if the pipeline proves that the owner of the partnershipinterest has an actual or potential income tax liability.  On December 16, 2005, the FERC issuedits first significant case-specific oil pipeline review of the income taxallowance issue in another pipeline company’s rate case.  The FERC reaffirmed its new income taxallowance policy and directed the subject pipeline to provide certain evidencenecessary for the pipeline to determine its income tax allowance.  The new tax allowance policy and theDecember 16 order have been appealed to the United States Court of Appealsfor the District of Columbia Circuit.  Asa result, the ultimate outcome of these proceedings is not certain and couldresult in changes to the FERC’s treatment of income tax allowances in cost ofservice.  Depending upon how the policystatement on income tax allowances is applied in practice to pipelinesorganized as pass-through entities, and whether it is ultimately upheld ormodified on judicial review, these decisions might adversely affect us.

***Competitioncould adversely affect our operating results.***

Ourrefined products and LPG transportation business competes with other pipelinesin the areas where we deliver products. We also compete with trucks, barges and railroads in some of the areaswe serve.  Competitive pressures mayadversely affect our tariff rates or volumes shipped.  The crude oil gathering and marketingbusiness is characterized by thin margins and intense competition for suppliesof crude oil at the wellhead.  A declinein domestic crude oil production has intensified competition among gatherersand marketers.  Our crude oil

70

----

transportationbusiness competes with common carriers and proprietary pipelines owned andoperated by major oil companies, large independent pipeline companies and othercompanies in the areas where our pipeline systems deliver crude oil and naturalgas liquids.

Newsupplies of natural gas are necessary to offset natural declines in productionfrom wells connected to our gathering system and to increase throughput volume,and we encounter competition in obtaining contracts to gather natural gassupplies.  Competition in natural gasgathering is based in large part on reputation, efficiency, system reliability,gathering system capacity and price arrangements.  Our key competitors in the gas gatheringsegment include independent gas gatherers and major integrated energycompanies.  Alternate gatheringfacilities are available to producers we serve, and those producers may alsoelect to construct proprietary gas gathering systems.  If the production delivered to our gatheringsystem declines, our revenues from such operations will decline.

***Ourbusiness requires extensive credit risk management that may not be adequate toprotect against customer nonpayment.***

Risks ofnonpayment and nonperformance by customers are a major consideration in ourbusinesses.  Our credit procedures andpolicies may not be adequate to fully eliminate customer credit risk.  We manage our exposure to credit risk throughcredit analysis, credit approvals, credit limits and monitoringprocedures.  We utilize letters of creditand guarantees for certain of our receivables. However, these procedures and policies do not fully eliminate customercredit risk.

***Ourcrude oil marketing business involves risks relating to product prices.***

Ourcrude oil operations subject us to pricing risks as we buy and sell crude oilfor delivery on our crude oil pipelines. These are the risks that price relationships between delivery points,classes of products or delivery periods will change after our initial purchasesand before physical delivery of the crude oil.

***Our pipelines are dependent ontheir interconnections with other pipelines to reach their destination markets.***

Decreasedthroughput on interconnected pipelines due to testing, line repair and reducedpressures could result in reduced throughput on our pipeline systems.  Such reduced throughput may adversely impactour profitability.

***Reduceddemand could affect shipments on the pipelines.***

Ourproducts pipeline business depends in large part on the demand for refinedproducts and LPGs in the markets served by our pipelines.  Reductions in that demand adversely affectour pipeline business.  Market demandvaries based upon the different end uses of the products we ship.  We cannot predict the impact of future fuelconservation measures, alternate fuel requirements, government regulation ortechnological advances in fuel economy and energy-generation devices, all ofwhich could reduce the demand for refined petroleum products and LPGs in theareas we serve.  Demand for gasoline,which has in recent years accounted for approximately forty percent of ourrefined products transportation revenues, depends upon price, prevailingeconomic conditions and demographic changes in the markets we serve.  Weather conditions, government policy andcrop prices affect the demand for refined products used in agriculturaloperations.  Demand for jet fuel, whichhas in recent years accounted for approximately twenty percent of our refinedproducts revenues, depends on prevailing economic conditions and militaryusage.  Propane deliveries are generallysensitive to the weather and meaningful year-to-year variances have occurredand will likely continue to occur.

***Ourgathering system profits and cash flow depend on the volumes of natural gasproduced from the fields served by our gathering systems and are subject tofactors beyond our control.***

Regionalproduction levels drive the volume of natural gas gathered on our systems.  We cannot influence or control the operationor development of the gas fields we serve. Production levels may be affected by:

71

----

·                  the absolute price of, volatility inthe price of, and market demand for natural gas;

·                  changes in lawsand regulations, particularly with regard to taxes, denial of reduced welldensity spacing, safety and protection of the environment;

·                  the depletionrates of existing wells;

·                  adverse weatherand other natural phenomena;

·                  the availabilityof drilling and service rigs; and

·                  industrychanges, including the effect of consolidations or divestitures.

Our gatheringsystems are connected to natural gas reserves and wells, from which theproduction will naturally decline over time, which means that our cash flowsassociated with these wells will also decline over time.  To maintain or increase throughput levels onour gathering systems, we must continually compete for and obtain new naturalgas supplies.  Our ability to obtainadditional sources of natural gas depends in part on the level of successfuldrilling activity near our gathering systems, which depends on a number offactors, including energy prices, over which we have no control.

***The use ofderivative financial instruments could result in material financial losses byus.***

We historicallyhave sought to limit a portion of the adverse effects resulting from changes incommodity prices and interest rates by using financial derivative instrumentsand other hedging mechanisms from time to time. To the extent that we hedge our commodity price and interest rateexposures, we will forego the benefits we would otherwise experience ifcommodity prices or interest rates were to change in our favor.  In addition, even though monitored bymanagement, hedging activities can result in losses.  Such losses could occur under variouscircumstances, including if a counterparty does not perform its obligationsunder the hedge arrangement, the hedge is imperfect, or hedging policies andprocedures are not followed.

***Our pipelineintegrity program may impose significant costs and liabilities on us.***

The U.S.Department of Transportation issued final rules (effective March 2001 withrespect to hazardous liquid pipelines and February 2004 with respect tonatural gas pipelines) requiring pipeline operators to develop integrity managementprograms to comprehensively evaluate their pipelines and take measures toprotect pipeline segments located in what the rules refer to as “highconsequence areas.”  The final ruleresulted from the enactment of the Pipeline Safety Improvement Act of 2002.  At this time, we cannot predict the ultimatecosts of compliance with this rule because those costs will depend on thenumber and extent of any repairs found to be necessary as a result of thepipeline integrity testing that is required by the rule.  We will continue our pipeline integritytesting programs to assess and maintain the integrity of our pipelines.  The results of these tests could cause us toincur significant and unanticipated capital and operating expenditures forrepairs or upgrades deemed necessary to ensure the continued safe and reliableoperation of our pipelines.

***Ouroperations are subject to governmental laws and regulations relating to theprotection of the environment and safety which may expose us to significantcosts and liabilities.***

Our facilities aresubject to multiple environmental obligations and potential liabilities under avariety of federal, state and local laws and regulations.  Such laws and regulations affect many aspectsof our present and future operations, and generally require us to obtain andcomply with a wide variety of environmental registrations, licenses, permits,inspections and other approvals, with respect to air emissions, water quality,wastewater discharges, and solid and 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.  Ifan accidental leak, spill or release of hazardous substances occurs at anyfacilities that we own, operate or otherwise use, or where we send materialsfor treatment or disposal, we could be held jointly and severally liable forall resulting liabilities, including investigation, remedial and clean-upcosts.  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 currently own or lease, andhave owned or

72

----

leased, many properties that have been used for manyyears to terminal or store crude oil, petroleum products or otherchemicals.  Owners, tenants or users ofthese properties may have disposed of or released hydrocarbons or solid wasteson or under them.  Additionally, somesites we operate are located near current or former refining and terminalingoperations.  There is a risk thatcontamination has migrated from those sites to ours.

Further, we cannotensure that existing environmental regulations will not be revised or that newregulations will not be adopted or become applicable to us.  The clear trend in environmental regulationis to place more restrictions and limitations on activities that may beperceived to affect the environment, and thus there can be no assurance as tothe amount or timing of future expenditures for environmental regulationcompliance or remediation, and actual future expenditures may be different fromthe amounts we currently anticipate. Revised or additional regulations that result in increased compliancecosts or additional operating restrictions, particularly if those costs are notfully recoverable from our customers, could have material adverse effect on ourbusiness, financial position, results of operations and cash flows.

Various state andfederal governmental authorities including the U.S. Environmental ProtectionAgency, the Bureau of Land Management, the Department of Transportation and theOccupational Safety and Health Administration have the power to enforcecompliance with these regulations and the permits issued under them, andviolators are subject to administrative, civil and criminal penalties,including civil fines, injunctions or both. Liability may be incurred without regard to fault under CERCLA, RCRA,and analogous state laws for the remediation of contaminated areas.  Private parties, including the owners ofproperties through which our pipeline systems pass, may also have the right topursue legal actions to enforce compliance as well as to seek damages fornon-compliance with environmental laws and regulations or for personal injuryor property damage.

Our insurance maynot cover all environmental risks and costs or may not provide sufficientcoverage in the event an environmental claim is made against us.  Our business may be adversely affected byincreased costs due to stricter pollution control requirements or liabilitiesresulting from non-compliance with required operating or other regulatorypermits.  New environmental regulationsmight adversely affect our products and activities, including storage,transportation and construction and maintenance activities, as well as wastemanagement and air emissions.  Federaland state agencies also could impose additional safety requirements, any ofwhich could affect our profitability.

Contaminationresulting from spills or releases of petroleum products is an inherent riskwithin the petroleum pipeline industry. While the costs of remediating groundwater contamination are generallysite-specific, such costs can vary substantially and may be material.

***Terroristattacks aimed at our facilities could adversely affect our business.***

On September 11,2001, the United States was the target of terrorist attacks of unprecedentedscale.  Since the September 11th attacks,the United States government has issued warnings that energy assets,specifically our nation’s pipeline infrastructure, may be the future target ofterrorist organizations.  Thesedevelopments have subjected our operations to increased risks.  Any future terrorist attack on ourfacilities, those of our customers and, in some cases, those of otherpipelines, could have a material adverse effect on our business.

Changes in theinsurance markets attributable to terrorist attacks may make certain types ofinsurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantlymore expensive than our existing insurance coverage.  Instability in the financial markets as aresult of terrorism or war could also affect our ability to raise capital.

73

----

***Our business involves many hazards and operational risks,some of which may not be fully covered by insurance. If a significant accidentor event occurs that is not fully insured, our operations and financial resultscould be adversely affected******.***

Our operations aresubject to the many hazards inherent in the transportation of refined petroleumproducts, LPGs, NGLs, petrochemicals, and crude oil; the gathering,compressing, and treating of natural gas, including ruptures, leaks and fires.  These risks could result in substantiallosses due to personal injury or loss of life, severe damage to and destructionof property and equipment and pollution or other environmental damage and mayresult in curtailment or suspension of our related operations.  We are not fully insured against all risksincident to our business, including environmental accidents that might occur,and market conditions have caused premiums and deductibles for some of ourinsurance policies to increase substantively. If a significant accident or event occurs that is not fully insured, itcould adversely affect our financial position or results of operations.

***We depend on the leadership and involvement of our keypersonnel for the success of our business.***

We depend on theleadership and involvement of our key personnel to identify and developbusiness opportunities and make strategic decisions.  Our president and chief executive officer waselected in April 2006, our chief financial officer was elected inJanuary 2006, and our general counsel was elected in March 2006.  Our president and chief executive officer hasover 35 years of relevant experience and our chief financial officer andgeneral counsel each have approximately 20 years of relevantexperience.  While retention plans are inplace for certain senior executives, any future unplanned departures could havea material adverse effect on our business, financial condition and results ofoperations.  Legacy senior executiveshave compensation agreements in place but new officers may not be party to anycompensation agreements.

**RisksRelating to Our Units as a Result of Our Partnership Structure**

***Wemay issue additional limited partnership interests, diluting existing interestsof unitholders and benefiting our General Partner*.**

Our partnershipagreement allows us to issue additional Units and other equity securitieswithout unitholder approval. These additional securities may be issued to raisecash or acquire additional assets or businesses or for other partnershippurposes. Our partnership agreement does not limit the number of Units andother equity securities we may issue. If we issue additional Units or otherequity securities, the proportionate partnership interest and voting power ofour existing unitholders will decrease and the ratio of taxable income todistributions may increase. The issuance could negatively affect the amount ofcash distributed to unitholders and the market price of our Units.

***Cost reimbursementsand fees due our General Partner and its affiliates may be substantial and willreduce our cash available for distribution to holders of our Units.***

Prior to makingany distribution on our Units, we will reimburse our General Partner and itsaffiliates, including EPCO and the officers and directors of our GeneralPartner, for expenses they incur on our behalf. The reimbursement of expensescould adversely affect our ability to pay cash distributions to holders of ourUnits. Under our partnership agreement, our General Partner has sole discretionto determine the amount of these expenses. Under the administrative servicesagreement pursuant to which EPCO provides various services to us, we areobligated to pay EPCO for all direct and indirect costs and expenses associatedwith services it provides that relate to our business or activities. Inaddition, our General Partner and its affiliates may provide other services tous for which we will be charged fees as determined by our General Partner.

***OurGeneral Partner and its affiliates may have conflicts with our partnership.***

The directors andofficers of our General Partner and its affiliates (including EPCO and otheraffiliates of EPCO) have duties to manage the General Partner in a manner thatis beneficial to its member. At the same time, the General Partner has dutiesto manage us in a manner that is beneficial to us. EPCO also controls anotherpublicly

74

----

traded partnership, Enterprise, that engages insimilar lines of business. We have significant business relationships withEnterprise and EPCO and other entities controlled by Dan L. Duncan.Therefore, our General Partner’s duties to us may conflict with the duties ofits officers and directors to its member. Provisions of our partnershipagreement, the partnership agreements for each of our operating partnershipsand/or the administrative services agreement provide for a standard of carethat may allow our General Partner to approve actions in the context ofpossible conflicts, which under state law a corporation would be required toanalyze with greater scrutiny. Possible conflicts may include, among others,the following:

·                  decisions of ourGeneral Partner regarding the amount and timing of cash expenditures,borrowings and issuances of additional Units or other equity securities thatcan affect the amount of cash that is available for distribution to unitholdersand the amount of payments we make to our General Partner with respect to itsincreasing percentage interests in our distributions;

·                  decisions of ourGeneral Partner regarding our acquisitions, expansions or business strategy,which may provide benefits to the General Partner and its affiliates;

·                  under ourpartnership agreement, it is not a breach of our General Partner’s fiduciaryduties for affiliates of our General Partner to engage in activities that competewith us;

·                  the directorsand officers of our General Partner are allowed to resolve conflicts ofinterest involving us and EPCO and its affiliates and are allowed to take intoaccount the interests of parties other than us, such as EPCO and its affiliates,including Enterprise, in resolving these conflicts of interest;

·                  any resolutionof a conflict of interest by the directors and officers of our General Partnernot made in bad faith and that is fair and reasonable to us is binding on thepartners and will not constitute a breach of our partnership agreement;

·                  we do not haveany employees and we rely solely on employees of EPCO;

·                  our partnershipagreement does not restrict the General Partner from causing us to pay it orits affiliates for any services rendered to us or entering into additionalcontractual arrangements with any of these entities on our behalf; and

·                  the directorsand officers of our General Partner and EPCO control the enforcement ofobligations owed to us by our General Partner, EPCO and its affiliates.

***Unitholdershave limited voting rights and control of management.***

OurGeneral Partner manages and controls our activities and the activities of ouroperating partnerships. Unitholders have no right to elect the General Partneror the directors of the General Partner on an annual or other ongoing basis.However, if the General Partner resigns or is removed, its successor may beelected by holders of a majority of the Units. Unitholders may remove theGeneral Partner only by a vote of the holders of at least 662¤3%of the Units and only after receiving state regulatory approvals required forthe transfer of control of a public utility. Our partnership agreement alsocontains provisions limiting the ability of unitholders to call meetings or toacquire information about our operations. As a result, unitholders will havelimited influence on matters affecting our operations, and third parties mayfind it difficult to gain control of us or influence our actions.

***EPCO’s employees,including some of our executive officers and directors, may be subjected toconflicts in managing our business and the allocation of time and compensationcosts between our business and the business of EPCO and its other affiliates.***

Certain of ourexecutive officers and three of our directors are also officers and/ordirectors of EPCO and other affiliates of EPCO, including Enterprise. Theserelationships may create conflicts of interest regarding corporateopportunities and other matters, and the resolution of any such conflicts maynot always be in our or our unitholders’ best interests. In addition, theseoverlapping executive officers and directors allocate their time among us, EPCOand other affiliates of EPCO. These officers and directors face potentialconflicts regarding the allocation of their time, which may adversely affectour business, results of operations and financial condition.

75

----

We have enteredinto an administrative services agreement that governs business opportunitiesamong entities controlled by our General Partner, including us (“TEPPCOCompanies”), entities controlled by the general partners of Enterprise GPHoldings L.P. and Enterprise, including Enterprise GP Holdings and Enterprise (“EnterpriseCompanies”), and EPCO and its other affiliates. Under the administrativeservices agreement, we have no obligation to present any business opportunityoffered to or discovered by us to the Enterprise Companies, and they are notobligated to present business opportunities that are offered to or discovered bythem to us. However, the agreement requires that business opportunities offeredto or discovered by EPCO, which controls both the TEPPCO Companies and theEnterprise Companies, be offered first to certain Enterprise Companies beforethey may be pursued by EPCO and its other affiliates or offered to us.

Under theadministrative services agreement, EPCO and its affiliates provide alladministrative, operational and other services, including employee support, forus and our General Partner. Some of the EPCO employees providing these servicesto us may also have duties and responsibilities related to EPCO and its otheraffiliates, including Enterprise. The services performed by these sharedpersonnel will generally be limited to non-commercial functions, including butnot limited to human resources, information technology, financial andaccounting services and legal services. EPCO may encounter conflicts ofinterest in allocating the available time and employee costs of sharedpersonnel between us and other EPCO affiliates.

We do not have anindependent compensation committee, and aspects of the compensation of ourexecutive officers and other key employees, including base salary, are notreviewed or approved by our independent directors. The determination of executiveofficer and key employee compensation could involve conflicts of interestresulting in economically unfavorable arrangements for us.

***Our General Partnerhas a limited call right that may require unitholders to sell their Units at anundesirable time or price.***

If at any timepersons other than our General Partner and its affiliates own less than 15% ofthe Units then outstanding, our General Partner will have the right, but notthe obligation, which it may assign to any of its affiliates or to us, to acquireall, but not less than all, of the remaining Units held by unaffiliated personsat a price not less than the then-current market price. As a result,unitholders may be required to sell their Units at an undesirable time or priceand may therefore not receive any return on their investment. They may alsoincur a tax liability upon a sale of their Units.

***Our unitholders maynot have limited liability if a court finds that limited partner actionsconstitute control of our business.***

Under Delawarelaw, our General Partner generally has unlimited liability for our obligations,such as our debts and environmental liabilities, except for those of ourcontractual obligations that are expressly made without recourse to our GeneralPartner. Further, unitholders could be held liable for our obligations to thesame extent as a General Partner if a court determined that the right oflimited partners to remove our General Partner or to take other action underour partnership agreement constituted participation in the ““control” of ourbusiness.

In addition,Section 17-607 of the Delaware Revised Uniform Limited Partnership Actprovides that, under some circumstances, a limited partner may be liable to usfor the amount of a distribution for a period of three years from the date ofthe distribution.

***The credit and riskprofile of our General Partner and its owners could adversely affect our creditratings and profile.***

The credit andbusiness risk profiles of the general partner or owners of a general partnermay be factors in credit evaluations of a master limited partnership. This isbecause the general partner can exercise significant influence over thebusiness activities of the partnership, including its cash distribution andacquisition strategy and business risk profile. Another factor that may beconsidered is the financial condition of the general partner and its

76

----

owners, including the degree of their financialleverage and their dependence on cash flow from the partnership to servicetheir indebtedness.

Entitiescontrolling the owner of our General Partner have significant indebtednessoutstanding and are dependent principally on the cash distributions from theGeneral Partner and limited partner equity interests in us to service suchindebtedness. Any distributions by us to such entities will be made only aftersatisfying our then current obligations to our creditors. Although we havetaken certain steps in our organizational structure, financial reporting andcontractual relationships to reflect the separateness of us from our GeneralPartner and the entities that control our General Partner, our credit ratingsand business risk profile could be adversely affected if the ratings and riskprofiles of the entities that control our General Partner were viewed as substantiallylower or more risky than ours.

***Control of ourGeneral Partner may be transferred to a third party without unitholder consent.***

Our GeneralPartner may transfer its general partner interest to a third party in a mergeror in a sale of all or substantially all of its assets without the consent ofthe unitholders. Furthermore, our partnership agreement does not restrict theability of the owners of our General Partner or DFI from transferring all or aportion of their respective ownership interest in our General Partner or DFI toa third party. The new owners of our General Partner or DFI would then be in aposition to replace the board of directors and officers of our General Partnerwith its own choices and thereby influence the decisions taken by the board ofdirectors and officers.

**Tax Risks to Unitholders**

***Our tax treatmentdepends on our status as a partnership for federal income tax purposes, as wellas our not being subject to a material amount of entity-level taxation byindividual states. The amount of cash available for distribution to you wouldbe substantially reduced if the Internal Revenue Service, or IRS, treats us asa corporation or we become subject to a material amount of entity-leveltaxation for state tax purposes.***

The anticipated after-taxeconomic benefit of an investment in the Units depends largely on our beingtreated as a partnership for federal income tax purposes. We have notrequested, and do not plan to request, a ruling from the IRS on this or anyother tax matter affecting us.

If we were treatedas a corporation for federal income tax purposes, we would pay federal incometax on our income at the corporate tax rate, which is currently a maximum of35% and would likely pay state income tax at varying rates.  Distributions to you would generally be taxedagain as corporate distributions, and no income, gains, losses or deductionswould flow through to you.  Because a taxwould be imposed upon us as a corporation, our cash available for distributionto you would be substantially reduced. Therefore, our treatment as a corporation would result in a materialreduction in the anticipated cash flow and after-tax return to the unitholders,likely causing a substantial reduction in the value of our Units.

Current law maychange so as to cause us to be treated as a corporation for federal income taxpurposes or otherwise subject us to entity-level federal income taxation. Ourpartnership agreement currently provides that if a law is enacted that subjectsus to taxation as a corporation or otherwise subjects us to entity-leveltaxation for federal income tax purposes, the minimum quarterly distributionamount and the target distribution level will be adjusted to reflect the impactof that law on us, including any related imposition of state and local incometaxes. A unitholder vote on a number of proposed amendments to our partnershipagreement, including an amendment that would permit our General Partner tosimilarly adjust the minimum quarterly distribution amount and the target distributionlevel for entity-level taxation arising from a change in the interpretation ofexisting law or the enactment of a state or local law subjecting us toentity-level taxation, is currently pending.

In addition,several states are evaluating ways to subject partnerships to entity-leveltaxation through the imposition of state income, franchise and other forms oftaxation. For example, we will be subject to a new entity-level tax on theportion of our income generated in Texas beginning in 2007. Specifically, theTexas margin tax will

77

----

be imposed at a maximum effective rate of 0.7% of ourgross income apportioned to Texas. Imposition of such tax on us by Texas, orany other state, will reduce the cash available for distribution to you.

***A successful IRScontest of the federal income tax positions we take may adversely affect themarket for our Units, and the cost of any IRS contest will reduce our cashavailable for distribution to our unitholders.***

We have notrequested a ruling from the IRS with respect to our treatment as a partnershipfor federal income tax purposes or any other matter affecting us. The IRS mayadopt positions that differ from the positions we take. It may be necessary toresort to administrative or court proceedings to sustain some or all of thepositions we take.  A court may not agreewith all of the positions we take. Any contest with the IRS may materially andadversely impact the market for our Units and the price at which they trade. Inaddition, our costs of any contest with the IRS will be borne indirectly by ourunitholders and our General Partner because the costs will reduce our cashavailable for distribution.

***You may be requiredto pay taxes on income from us even if you do not receive any cashdistributions from us.***

Because ourunitholders will be treated as partners to whom we will allocate taxable incomewhich could be different in amount than the cash we distribute, you will berequired to pay any federal income taxes and, in some cases, state and localincome taxes on your share of our taxable income even if you receive no cashdistributions from us. You may not receive cash distributions from us equal toyour share of our taxable income or even equal to the tax liability thatresults from that income.

***Tax gain or loss ondisposition of Units could be more or less than expected.***

If you sell yourUnits, you will recognize a gain or loss equal to the difference between theamount realized and your tax basis in those Units. Prior distributions to youin excess of the total net taxable income you were allocated for a Unit, whichdecreased your tax basis in that Unit, will, in effect, become taxable incometo you if the Unit is sold at a price greater than your tax basis in that Unit,even if the price is less than your original cost. A substantial portion of theamount realized, whether or not representing gain, may be ordinary income. Ifyou sell your Units, you may incur a tax liability in excess of the amount ofcash you receive from the sale. If the IRS successfully contests some positionswe take, unitholders could recognize more gain on the sale of Units than wouldbe the case under those positions, without the benefit of decreased income inprior years.

***Tax-exempt entitiesand foreign persons face unique tax issues from owning Units that may result inadverse tax consequences to them.***

Investment inUnits by tax-exempt entities, such as individual retirement accounts (“IRAs”),other retirement plans, and non-U.S. persons raises issues unique to them. Forexample, virtually all of our income allocated to organizations that are exemptfrom federal income tax, including IRAs and other retirement plans, will beunrelated business taxable income and will be taxable to them. Distributions tonon-U.S. persons will be reduced by withholding taxes at the highest applicableeffective tax rate, and non-U.S. persons will be required to file United Statesfederal tax returns and pay tax on their share of our taxable income. If youare a tax-exempt entity or a non-U.S. person you should consult your taxadvisor before investing in our Units.

***We treat eachpurchaser of our Units as having the same tax benefits without regard to theactual Units purchased. The IRS may challenge this treatment, which couldadversely affect the value of the Units.***

We takedepreciation and amortization positions that may not conform to all aspects ofexisting Treasury regulations. We take these positions for a number of reasons,including the fact that we cannot match transferors and transferees of Units. Asuccessful IRS challenge to those positions could adversely affect the amountof tax benefits available to you. It also could affect the timing of these taxbenefits or the amount of gain from the sale of Units and could have a negativeimpact on the value of our Units or result in audit adjustments to your taxreturns.

78

----

***Unitholders may besubject to state and local taxes and return filing requirements.***

In addition tofederal income taxes, you will likely be subject to other taxes, includingforeign, state and local taxes, unincorporated business taxes and estate,inheritance or intangible taxes that are imposed by the various jurisdictionsin which we do business or own property, even if you do not live in any ofthose jurisdictions.  You will likely berequired to file foreign, state and local income tax returns and pay state andlocal income taxes in some or all of these jurisdictions. Further, you may besubject to penalties for failure to comply with those requirements.  Our operating subsidiaries own assets and dobusiness in Alabama, Arkansas, Colorado, Illinois, Indiana, Kansas, Kentucky,Louisiana, Mississippi, Missouri, Montana, Nebraska, New Mexico, New York,North Dakota, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Dakota, Texas,Utah, West Virginia and Wyoming.  Each ofthese states, other than South Dakota, Texas and Wyoming currently imposes apersonal income tax and many impose an income tax on corporations and otherentities.  As we make acquisitions orexpand our business, we may own assets or do business in additional states thatimpose a personal income tax.  It is yourresponsibility to file all United States federal, foreign, state and local taxreturns.

***The sale orexchange of 50% or more of our capital and profits interests during any twelve-monthperiod will result in the termination of our partnership for federal income taxpurposes.***

We will beconsidered to have terminated for federal income tax purposes if there is asale or exchange of 50% or more of the total interests in our capital andprofits within a twelve-month period. Our termination would, among other things, result in the closing of ourtaxable year for all unitholders and could result in a deferral of depreciationdeductions allowable in computing our taxable income.  If this occurs, you will be allocated anincreased amount of federal taxable income for the year in which we areconsidered to be terminated as a percentage of the cash distributed to you withrespect to that period.

**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).                                                                                             |

 

79

----

 
| 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, 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).                                                                                                                    |
| 10.1+* |   | Texas Eastern Products Pipeline Company, LLC 2000  Long Term Incentive Plan Notice of 2006 Award.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 10.2+* |   | Texas Eastern Products Pipeline Company, LLC 2005  Phantom Unit Plan Notice of 2006 Award.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 10.3   |   | 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) dated as of August  3, 2006 and incorporated herein by reference). |
| 10.4   |   | 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) dated as of August 3, 2006 and incorporated herein by reference).                                                                                                                                                                                                                                                                                                                                                                  |
| 10.5   |   | Contribution Agreement among TEPPCO GP, Inc., TEPPCO  Midstream Companies, L.P. and Enterprise Gas Processing, LLC dated as of  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).                                                                                                                                                                                                                                                                                                                         |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

 

80

----

 
| 32.2** |   | Certification of Chief Financial Officer Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002. |
|--------|--------|------------------------------------------------------------------------------------------------------|

 

----

*  Filed herewith.

**Furnished herewith pursuant to Item 601(b)-(32) of Regulation S-K.

+A management contract or compensation plan or arrangement.

**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.
|                            |   |                                                           | TEPPCO Partners, L.P. |
|----------------------------|--------|----------------------------------------------------------------|-----------------------|
|                       |   |                                                           |                  |
|                       |   |                                                           | By:                   | /s/   JERRY E.  THOMPSON |   |
|                       |   | Jerry E. Thompson,                                             |
| Date:  August 4, 2006 |   | President and Chief Executive Officer of                       |
|                       |   | Texas Eastern Products Pipeline Company, LLC,  General Partner |
|                       |   |                                                           |
|                       |   |                                                           |
|                       |   |                                                           | By:                   | /s/   WILLIAM  G. MANIAS |   |
|                       |   | William G. Manias,                                             |
| Date:  August 4, 2006 |   | Vice President and Chief Financial Officer of                  |
|                       |   | Texas Eastern Products Pipeline Company, LLC,  General Partner |

 

81

----