10-Q 1 h91919e10-q.txt TEPPCO PARTNERS LP - SEPTEMBER 30, 2001 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTER ENDED SEPTEMBER 30, 2001 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) 2929 ALLEN PARKWAY P.O. BOX 2521 HOUSTON, TEXAS 77252-2521 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES, INCLUDING ZIP CODE) (713) 759-3636 (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- ================================================================================ PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS TEPPCO PARTNERS, L.P. CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)

SEPTEMBER 30, DECEMBER 31, 2001 2000 ----------- ----------- (UNAUDITED) ASSETS Current assets: Cash and cash equivalents ................................... $ 33,031 $ 27,096 Accounts receivable, trade .................................. 293,439 303,394 Inventories ................................................. 26,756 24,784 Other ....................................................... 6,141 8,123 ----------- ----------- Total current assets ..................................... 359,367 363,397 ----------- ----------- Property, plant and equipment, at cost (Net of accumulated depreciation and amortization of $276,769 and $251,165) ..... 1,143,196 949,705 Equity investments ............................................ 269,893 241,648 Intangible assets ............................................. 240,500 34,174 Goodwill ...................................................... 24,756 4,214 Other assets .................................................. 35,838 29,672 ----------- ----------- Total assets ............................................. $ 2,073,550 $ 1,622,810 =========== =========== LIABILITIES AND PARTNERS' CAPITAL Current liabilities: Notes payable ............................................... $ 360,000 $ -- Accounts payable and accrued liabilities .................... 294,364 293,720 Accounts payable, general partner ........................... 13,253 6,637 Accrued interest ............................................ 8,831 18,633 Other accrued taxes ......................................... 10,780 10,501 Other ....................................................... 42,043 28,780 ----------- ----------- Total current liabilities ................................ 729,271 358,271 ----------- ----------- Senior Notes .................................................. 389,807 389,784 Other long-term debt .......................................... 472,000 446,000 Other liabilities and deferred credits ........................ 15,956 3,991 Minority interest ............................................. -- 4,296 Redeemable Class B Units held by related party ................ 106,270 105,411 Partners' capital: Accumulated other comprehensive loss ........................ (26,992) -- General partner's interest .................................. 11,848 1,824 Limited partners' interests ................................. 375,390 313,233 ----------- ----------- Total partners' capital .................................. 360,246 315,057 ----------- ----------- Commitments and contingencies (Note 9) Total liabilities and partners' capital .................. $ 2,073,550 $ 1,622,810 =========== ===========

See accompanying Notes to Consolidated Financial Statements. 2 TEPPCO PARTNERS, L.P. CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

THREE MONTHS THREE MONTHS NINE MONTHS NINE MONTHS ENDED ENDED ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, 2001 2000 2001 2000 ------------- -------------- ------------- ------------- Operating revenues: Sales of crude oil and petroleum products ........ $ 915,296 $ 686,732 $ 2,601,580 $2,059,160 Transportation - Refined products ................ 32,161 29,483 109,748 90,198 Transportation - LPGs ............................ 15,669 14,477 54,174 47,961 Transportation - crude oil and NGLs .............. 12,167 7,932 34,484 15,834 Mont Belvieu operations .......................... 3,977 3,015 9,871 10,369 Other - net ...................................... 11,546 8,259 39,876 24,772 ------------- -------------- ------------- ------------ Total operating revenues ....................... 990,816 749,898 2,849,733 2,248,294 ------------- -------------- ------------- ------------ Costs and expenses: Purchases of crude oil and petroleum products .... 902,126 679,459 2,566,621 2,039,763 Operating, general and administrative ............ 38,181 27,735 96,086 77,303 Operating fuel and power ......................... 9,125 8,838 27,946 24,677 Depreciation and amortization .................... 10,411 9,154 31,175 25,740 Taxes - other than income taxes .................. 3,852 2,805 11,409 7,986 ------------- -------------- ------------- ------------ Total costs and expenses ....................... 963,695 727,991 2,733,237 2,175,469 ------------- -------------- ------------- ------------ Operating income ............................... 27,121 21,907 116,496 72,825 Interest expense ................................... (15,679) (15,967) (47,365) (32,949) Interest capitalized ............................... 1,105 1,551 2,040 3,816 Equity earnings .................................... 5,645 9,325 15,270 9,325 Other income - net ................................. 997 548 2,224 2,180 ------------- -------------- ------------- ------------ Income before minority interest ................ 19,189 17,364 88,665 55,197 Minority interest .................................. (97) (175) (800) (557) ------------- -------------- ------------- ------------ Net income ..................................... $ 19,092 $ 17,189 $ 87,865 $ 54,640 ============= ============== ============= ============ Net Income Allocation: Limited Partner Unitholders ........................ $ 12,113 $ 11,995 $ 62,035 $ 39,491 Class B Unitholder ................................. 1,357 1,619 7,027 5,333 General Partner .................................... 5,622 3,575 18,803 9,816 ------------- -------------- ------------- ------------ Total net income allocated ..................... $ 19,092 $ 17,189 $ 87,865 $ 54,640 ============= ============== ============= ============ Basic and diluted net income per Limited Partner and Class B Unit .................... . $ 0.35 $ 0.41 $ 1.79 $ 1.36 ============= ============== ============= ============ Weighted average Limited Partner and Class B Units outstanding ............................... 38,867 32,917 38,544 32,917

See accompanying Notes to Consolidated Financial Statements. 3 TEPPCO PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED) (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

NINE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, 2001 2000 ------------- ------------- Cash flows from operating activities: Net income ....................................................... $ 87,865 $ 54,640 Depreciation and amortization .................................... 31,175 25,740 Earnings in equity investments, net of distributions ............. 6,090 (8,370) Noncash portion of interest expense .............................. 2,175 1,475 Decrease (increase) in accounts receivable, trade ................ 9,292 (34,619) Increase in inventories .......................................... (1,972) (3,006) Decrease (increase) in other current assets ...................... (3,524) 2,205 Increase (decrease) in accounts payable and accrued expenses ..... (16,231) 48,989 Other ............................................................ (1,412) (9,087) ----------- ------------- Net cash provided by operating activities ...................... 113,458 77,967 ----------- ------------- Cash flows from investing activities: Proceeds from cash investments ................................... 3,236 1,475 Purchases of cash investments .................................... -- (2,000) Purchases of ARCO assets, net of cash received ................... -- (322,640) Purchase of crude oil assets ..................................... (20,000) (7,843) Proceeds from the sale of assets ................................. 1,300 -- Purchase of Jonah Gas Gathering Company .......................... (359,834) -- Investments in Centennial Pipeline Company ....................... (34,335) (2,984) Capital expenditures ............................................. (61,966) (53,272) ----------- ------------- Net cash used in investing activities .......................... (471,599) (387,264) ----------- ------------- Cash flows from financing activities: Proceeds from term loan and revolving credit facility ............ 427,000 453,000 Repayment of term loan and revolving credit facility ............. (41,000) (86,000) Debt issuance cost ............................................... (2,601) (7,074) Proceeds from the issuance of Limited Partner Units, net ......... 54,588 -- General Partner contributions .................................... 1,114 -- Distributions .................................................... (75,025) (58,207) ----------- ------------- Net cash provided by financing activities ...................... 364,076 301,719 ----------- ------------- Net increase (decrease) in cash and cash equivalents ............... 5,935 (7,578) Cash and cash equivalents at beginning of period ................... 27,096 32,593 ----------- ------------- Cash and cash equivalents at end of period ......................... $ 33,031 $ 25,015 =========== ============= SUPPLEMENTAL DISCLOSURE OF CASH FLOWS: Interest paid during the period (net of capitalized interest) .... $ 52,022 $ 27,709 =========== =============

See accompanying Notes to Consolidated Financial Statements. 4 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 1. ORGANIZATION AND BASIS OF PRESENTATION TEPPCO Partners, L.P. (the "Partnership"), a Delaware limited partnership, was formed in March 1990. The Partnership operates through TE Products Pipeline Company, Limited Partnership (the "Downstream Segment"), TCTM, L.P. (the "Upstream Segment") and TEPPCO Midstream Companies, L.P. (the "Midstream Segment"). Collectively the Downstream Segment, the Upstream Segment and the Midstream Segment 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 the general partner of the Partnership. The General Partner is a wholly owned subsidiary of Duke Energy Field Services, LP ("DEFS"), a joint venture between Duke Energy Corporation ("Duke Energy") and Phillips Petroleum Company. Duke Energy holds a majority interest in DEFS. The Company, as general partner, performs all management and operating functions required for the Partnership pursuant to the Agreements of Limited Partnership of TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P. and TEPPCO Midstream Companies, L.P. (the "Partnership Agreements"). The General Partner is reimbursed by the Partnership for all reasonable direct and indirect expenses incurred in managing the Partnership. On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be wholly-owned by the Partnership. TEPPCO GP, Inc. ("TEPPCO GP"), a subsidiary of the Partnership, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by the Partnership were transferred to the Partnership. In exchange for this contribution, the Company's interest as general partner of the Partnership was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in the Partnership and the Operating Partnerships. As a result, the Partnership holds a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a .001% general partner interest. The accompanying unaudited consolidated financial statements reflect all adjustments that are, in the opinion of management, of a normal and recurring nature and necessary for a fair statement of the financial position of the Partnership as of September 30, 2001, and the results of operations and cash flows for the periods presented. The results of operations for the nine months ended September 30, 2001, are not necessarily indicative of results of operations for the full year 2001. The interim financial statements should be read in conjunction with the Partnership's consolidated financial statements and notes thereto presented in the TEPPCO Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2000. Certain amounts from prior periods have been reclassified to conform to current presentation. The Partnership operates in three segments: refined products, liquefied petroleum gases ("LPGs") and petrochemicals transportation ("Downstream Segment"); crude oil and natural gas liquids ("NGLs") transportation and marketing ("Upstream Segment"); and natural gas gathering ("Midstream Segment"). The Partnership's reportable segments offer different products and services and are managed separately because each requires different business strategies. The Upstream Segment was acquired as a unit in November 1998, and the management at the time of the acquisition was RETAINED. The Midstream Segment was acquired on September 30, 2001 and will be commercially managed and operated by DEFS. The Partnership's interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission ("FERC"). Refined products, LPGs, petrochemicals, crude oil and NGLs are referred to herein, collectively, as "petroleum products" or "products." Basic net income per Unit is computed by dividing net income, after deduction of the general partner's interest, by the weighted average number of Limited Partner Units and Class B Units outstanding (a total of 38.9 5 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) million Units for the nine months ended September 30, 2001, and 32.9 million Units for the nine months ended September 30, 2000). The General Partner's percentage interest in net income is based on its percentage of cash distributions from Available Cash for each period (see Note 7. Quarterly Distributions of Available Cash). The General Partner was allocated $18.8 million (representing 21.4%) and $9.8 million (representing 17.96%) of net income for the nine months ended September 30, 2001, and 2000, respectively. Diluted net income per Unit is similar to the computation of basic net income per Unit above, except that the denominator was increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the quarters ended September 30, 2001 and 2000, the denominator was increased by 45,110 Units and 23,877 Units, respectively. For the nine months ended September 30, 2001 and 2000, the denominator was increased by 33,277 Units and 21,193 Units, respectively. NOTE 2. NEW ACCOUNTING PRONOUNCEMENTS Effective January 1, 2001, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Special accounting for derivatives qualifying as fair value hedges allows a derivative's gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings. Adoption of SFAS 133 at January 1, 2001 resulted in the recognition of $10.1 million of derivative liabilities, $4.1 million of which are included in current liabilities and $6.0 million of which are included in other noncurrent liabilities on the Partnership's balance sheet, and $10.1 million of hedging losses included in accumulated other comprehensive loss, a component of Partners' capital, as the cumulative effect of the change in accounting principle. The hedging losses included in accumulated other comprehensive loss will be transferred to earnings as the forecasted transactions actually occur. Approximately $4.1 million of the loss included in accumulated other comprehensive loss as of January 1, 2001 was anticipated to be transferred into earnings during 2001. The cumulative effect of the accounting change had no effect on the Partnership's net income or its earnings per Unit amounts for the nine months ended September 30, 2001. Amounts were determined as of January 1, 2001 based on quoted market values, the Partnership's portfolio of derivative instruments, and the Partnership's measurement of hedge effectiveness. From time to time, the Partnership has utilized and expects to continue to utilize derivative financial instruments with respect to a portion of its interest rate risks and its crude oil marketing activities to achieve a more predictable cash flow by reducing its exposure to interest rate and crude oil price fluctuations. These transactions generally are swaps and forwards and are entered into with major financial institutions or commodities trading institutions. Derivative financial instruments used in the Partnership's Upstream Segment are intended to reduce the Partnership's exposure to fluctuations in the market price of crude oil, while derivative financial instruments related to the Partnership's interest rate risks are intended to reduce the Partnership's exposure to increases in the benchmark interest rates underlying the Partnership's variable rate revolving credit facility. Through December 31, 6 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) 2000, gains and losses from financial instruments used in the Partnership's Upstream Segment have been recognized in revenues for the periods to which the derivative financial instruments relate, and gains and losses from its interest rate financial instruments have been recognized in interest expense for the periods to which the derivative financial instruments relate. As of September 30, 2001, the Upstream Segment had open positions on option contracts it had written for 100,000 barrels of crude oil and futures contracts for the sale of 50,000 barrels of crude oil. During the nine months ended September 30, 2001, a loss of $22,500 was recognized on such contracts. Also as of September 30, 2001, the Partnership had in place an interest rate swap agreement to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facilities. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership pays a fixed rate of interest of 6.955% and receives a floating rate based on a three month USD LIBOR rate. The interest rate swap is designated as a cash flow hedge, therefore, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. During the nine month period ended September 30, 2001, the Partnership recognized $4.0 million in losses, included in interest expense, on the interest rate swap attributable to interest costs occurring in 2001. No gain or loss from ineffectiveness was required to be recognized. The fair value of the interest rate swap agreement was a loss of approximately $22.1 million at September 30, 2001. Approximately $10.1 million (inclusive of the $4.1 million related to the cumulative effect of the accounting change not yet recognized) of such amount is anticipated to be transferred into earnings over the next twelve months. During 2001, the Partnership executed treasury rate lock agreements with a combined notional amount of $400 million to hedge its exposure to increases in the treasury rate that will be used to establish the fixed interest rate for the debt offering that is probable to occur in the fourth quarter of 2001. Under the treasury rate lock agreements, the Partnership pays a fixed rate of interest, and receives a floating rate based on the three month treasury rate. The treasury rate locks are designated as cash flow hedges, therefore, the changes in fair value, to the extent the treasury rate locks are effective, are recognized in other comprehensive income until the actual debt offering occurs. Upon completion of the debt offering, the realized gain or loss on the treasury rate locks will be amortized out of accumulated other comprehensive income into interest expense over the life of the debt obligation. During April 2001, a treasury lock with a notional amount of $200 million was terminated with a realized gain of $1.1 million. The realized gain was recorded as a component of accumulated other comprehensive income. As of September 30, 2001, a notional amount of $200 million remained outstanding. The fair value of the outstanding treasury rate locks was a loss of approximately $6.0 million at September 30, 2001. In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS 141 requires that the purchase method of accounting be used for all business combinations and specifies that certain acquired intangible assets be reported apart from goodwill. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. The Partnership has adopted SFAS 141, and will adopt SFAS 142 effective January 1, 2002. At September 30, 2001, the Partnership had $24.8 million of unamortized goodwill. Amortization expense related to goodwill was $0.1 million and $0.8 million for the year ended December 31, 2000 and the nine months ended September 30, 2001, respectively. The Partnership has not determined the impact of adopting SFAS 142 at the date of this report, including whether any transitional impairment losses will be required to be recognized as the cumulative effect of a change in accounting principle. 7 NOTE 3. ACQUISITIONS On July 20, 2000, the Partnership completed an acquisition of ARCO Pipe Line Company ("ARCO"), a wholly owned subsidiary of Atlantic Richfield Company, for $322.6 million, which included $4.1 million of acquisition related costs other than the purchase price. The purchased assets included ARCO's 50-percent ownership interest in Seaway Crude Pipeline Company ("Seaway"), which owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma and from a marine terminal at Texas City, Texas to refineries in the Texas City and Houston areas. The Partnership assumed ARCO's role as operator of this pipeline. The Partnership also acquired: (i) ARCO's crude oil terminal facilities in Cushing and Midland, Texas, including the line transfer and pumpover business at each location; (ii) an undivided ownership interest in both the Rancho Pipeline, a crude oil pipeline from West Texas to Houston, and the Basin Pipeline, a crude oil pipeline running from Jal, New Mexico, through Midland to Cushing, both of which are operated by another joint owner; and (iii) the receipt and delivery pipelines known as the West Texas Trunk System, which is located around the Midland terminal. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from July 20, 2000. In October 2000, the Partnership received a settlement notice from Atlantic Richfield Company for payment of a net aggregate amount of approximately $12.9 million in post-closing adjustments related to the purchase of ARCO. A large portion of the requested adjustment related to an indemnity for payment of accrued income taxes. In August 2001, the Partnership and Atlantic Richfield Company reached a settlement of $11.0 million for the post-closing adjustments. The Partnership recorded the settlement as an increase to the purchase price of ARCO. The Partnership paid the settlement amount to Atlantic Richfield Company on October 15, 2001. On September 30, 2001, the Partnership completed the purchase of the Jonah Gas Gathering Company ("Jonah") from Alberta Energy Company for $360 million. The acquisition serves as an entry into the natural gas gathering industry for the Partnership. Goodwill recognized in the purchase amounted to approximately $10.4 million. The Jonah system consists of approximately 300 miles of pipelines ranging in size from four to 20 inches in diameter, four compressor stations with an aggregate of approximately 21,200 horsepower and related metering facilities. Gas gathered on the Jonah system is collected from approximately 300 producing wells in the Green River Basin in southwestern Wyoming. Gas is delivered to gas processing facilities owned by others. The Partnership owns a processing facility which extracts condensate prior to delivery of natural gas to DEFS' Overland Trail Transmission system and Questar. From these processing facilities, the natural gas is delivered to several interstate pipeline systems located in the region for transportation to end-use markets. Interstate pipelines in the region include the Overland Trail Transmission system, owned by our affiliate DEFS, Kern River, Northwest, Colorado Interstate Gas and Questar. These pipeline systems provide access for natural gas collected by the Jonah system to end-user markets throughout the Midwest, the West Coast and the Rocky Mountain regions. The Jonah assets will be commercially managed and operated by DEFS. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition will be included in the consolidated financial statements from September 30, 2001. The following table presents unaudited pro forma results of the Partnership as though the acquisitions of the ARCO and Jonah businesses occurred at the beginning of the respective periods (in thousands, except per Unit amounts).

QUARTER ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------- ------------------------- 2001 2000 2001 2000 ---------- ---------- ---------- ---------- Revenues .................................... $ 998,535 $ 757,070 $2,873,004 $2,281,465 Net Income .................................. 15,432 13,824 77,076 41,739 Basic and diluted net income per Limited Partner and Class B Unit ................ $ 0.28 $ 0.33 $ 1.57 $ 1.04

8 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) The following table allocates the estimated fair value of Jonah assets acquired on September 30, 2001. The Partnership is in the process of obtaining third-party valuations of certain assets, thus, the allocation of the purchase price is pending and subject to refinement.

(in thousands) Property, plant and equipment ................. $ 141,570 Intangible assets ............................. 208,000 Goodwill ...................................... 10,395 --------- Total assets ......................... 359,965 --------- Total liabilities assumed...................... (490) --------- Net assets acquired................... $ 359,475 =========

The value assigned to intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production. The value assigned to intangible assets will be amortized over the expected lives of the contracts (approximately 16 years) in proportion to the timing of expected contractual volumes. The assigned value of goodwill is attributable to the natural gas gathering assets that fully comprise the Midstream Segment. NOTE 4. INVENTORIES Inventories are carried at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows (in thousands):

SEPTEMBER 30, DECEMBER 31, 2001 2000 ------------- ------------ Crude oil ............................ $13,833 $14,635 Gasolines ............................ 453 3,795 Propane .............................. 463 -- Butanes .............................. 2,597 267 Fuel oil ............................. 44 82 Other products ....................... 4,491 2,693 Materials and supplies ............... 4,875 3,312 ------- ------- Total ...................... $26,756 $24,784 ======= =======

The costs of inventories did not exceed market values at September 30, 2001, and December 31, 2000. NOTE 5. EQUITY INVESTMENTS Seaway is a partnership between the Upstream Segment and Phillips Petroleum Company ("Phillips"). The Upstream Segment purchased its 50-percent voting interest in Seaway on July 20, 2000 (see Note 3. Acquisitions). The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of the Seaway Partnership. From July 20, 2000, through May 2002, the Upstream Segment receives 80% of revenue and expense of Seaway. From June 2002 through May 2006, the Upstream Segment receives 60% of 9 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and expense to the Upstream Segment. The Partnership uses the equity method of accounting for its investment in Seaway. Summarized financial information for Seaway as of and for the nine months ended September 30, 2001 is presented below (in thousands): Current assets ....................................... $ 40,023 Non current assets ................................... 277,295 Current liabilities .................................. 9,184 Partners' capital .................................... 308,134 Revenues ............................................. 55,719 Net income ........................................... 27,283 NOTE 6. LONG TERM DEBT SENIOR NOTES On January 27, 1998, the Downstream Segment completed the issuance of $180 million principal amount of 6.45% Senior Notes due 2008, and $210 million principal amount of 7.51% Senior Notes due 2028 (collectively the "Senior Notes"). The 6.45% Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% Senior Notes due 2028 may be redeemed at any time after January 15, 2008, at the option of the Downstream Segment, in whole or in part, at a premium. The Senior Notes do not have sinking fund requirements. Interest on the Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The Senior Notes are unsecured obligations of the Downstream Segment and rank on a parity with all other unsecured and unsubordinated indebtedness of the Downstream Segment. The indenture governing the Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit the Partnership's ability to incur additional indebtedness. On October 4, 2001, the Partnership entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its $210 million principal amount of 7.51% fixed rate Senior Notes. The swap agreement has a notional amount of $210 million and matures in January 2028 to match the principal and maturity of the Senior Notes. Under the swap agreement, the Partnership pays a floating rate based on a three month USD LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. OTHER LONG TERM DEBT AND CREDIT FACILITIES On July 14, 2000, the Partnership entered into a $75 million term loan and a $475 million revolving credit facility. On July 21, 2000, the Partnership borrowed $75 million under the term loan and $340 million under the revolving credit facility. The funds were used to finance the acquisition of the ARCO assets (see Note 3. Acquisitions) and to refinance existing credit facilities, other than the Senior Notes. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000. On April 6, 2001, the Partnership's $475 million revolving credit agreement was amended to permit borrowings up to $500 million and to allow for letters of credit up to $20 million. The term of the revised credit agreement was extended to April 6, 2004. Additionally, on April 6, 2001, the Partnership entered into a 364-day, $200 million revolving credit agreement. The interest rate is based on the Partnership's option of either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreements contain restrictive financial covenants that 10 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) require the Partnership to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. At September 30, 2001, $472 million was outstanding under the revolving credit facility at a weighted average interest rate of 4.9%. On July 21, 2000, the Partnership entered into a three year swap agreement to hedge a portion of its exposure on the variable rate credit facilities. On April 6, 2001 the swap agreement was extended until April 6, 2004 to match the maturity of the variable rate credit facility above. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership pays a fixed rate of interest of 6.955% and receives a floating rate based on a three month USD LIBOR rate. SHORT TERM CREDIT FACILITY On September 28, 2001, the Partnership entered into a $400 million credit facility with SunTrust Bank. The Partnership borrowed $360 million under the facility for the acquisition of the Jonah assets (see Note 3. Acquisitions). The credit facility is payable in June 2002. The interest rate is based on the Partnership's option of either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreements contain restrictive financial covenants that require the Partnership to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. At September 30, 2001, $360 million was outstanding under the credit facility at an interest rate of 3.63%. NOTE 7. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH The Partnership makes quarterly cash distributions of all of its Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the Company receives incremental incentive cash distributions to the extent that cash distributions on a per Unit basis exceed certain target thresholds. The Following table shows the allocation between the Company and the unitholders of each increment of cash distributed per Unit:

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%

The following table reflects the allocation of total distributions paid for the nine month periods ended September 30, 2001 and 2000 (in thousands, except per Unit amounts).

NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2001 2000 ------- ------- Limited Partner Units ............................. $53,865 $42,775 General Partner Interest .......................... 817 491 General Partner Incentive ......................... 13,674 8,576 ------- ------- Total Partners' Capital Cash Distributions .... 68,356 51,842 Class B Units ..................................... 6,169 5,777 Minority Interest ................................. 500 588 ------- ------- Total Cash Distributions Paid ................. $75,025 $58,207 ======= ======= Total Cash Distributions Paid Per Unit ............ $ 1.575 $ 1.475 ======= =======

11 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) On October 17, 2001, the Partnership declared a cash distribution of $0.575 per Limited Partner Unit and Class B Unit for the quarter ended September 30, 2001. The distribution was paid on November 5, 2001, to Unitholders of record on October 31, 2001. NOTE 8. SEGMENT DATA The Partnership operates in three segments: refined products, LPGs, and petrochemicals transportation, which operates through the Downstream Segment; crude oil and NGLs transportation and marketing, which operates through the Upstream Segment; and natural gas gathering, which operates through the Midstream Segment. The amounts indicated below as "Partnership and Other" relate primarily to intercompany eliminations and assets held by the Partnership that have not been allocated to the Operating Partnerships. The Downstream Segment is engaged in the interstate transportation, storage and terminaling of petroleum products and LPGs, intrastate transportation of petrochemicals and the fractionation of NGLs. Revenues are derived from the transportation of refined products and LPGs, the storage and short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex, sale of product inventory and other ancillary services. The Downstream Segment is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. The Partnership owns and operates a pipeline system extending from southeast Texas through the central and midwestern United States to the northeastern United States. The Upstream Segment gathers, stores, transports and markets crude oil principally in Oklahoma, Texas and the Rocky Mountain region; operates two trunkline NGL pipelines in South Texas and two NGL pipelines in East Texas; and distributes lube oils and specialty chemicals to industrial and commercial accounts. On July 20, 2000, the Partnership acquired certain assets from ARCO (see Note 3. Acquisitions). The acquisition was accounted for under the purchase method of accounting. The results of the acquisition have been included in the Upstream Segment since the purchase on July 20, 2000. The Midstream Segment gathers natural gas in the Green River Basin in southwest Wyoming. On September 30, 2001, the Partnership acquired Jonah Gas Gathering Company from Alberta Energy Corporation (see Note 3. Acquisitions). The acquisition was accounted for under the purchase method of accounting. The results of operations of the acquisition will be included in periods subsequent to September 30, 2001. The table below includes interim financial information by business segment for the interim periods ended September 30, 2001 and 2000 (in thousands): 12 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED)

THREE MONTHS ENDED SEPTEMBER 30, 2001 THREE MONTHS ENDED SEPTEMBER 30, 2000 ------------------------------------------ ----------------------------------------- DOWNSTREAM UPSTREAM DOWNSTREAM UPSTREAM SEGMENT SEGMENT CONSOLIDATED SEGMENT SEGMENT CONSOLIDATED ----------- ----------- ------------ ---------- ----------- ------------ Unaffiliated revenues ............ $ 60,362 $ 930,454 $ 990,816 $ 53,110 696,788 $ 749,898 Operating expenses, including power ......................... 30,000 923,284 953,284 29,495 689,342 718,837 Depreciation and amortization expense ....................... 7,179 3,232 10,411 6,908 2,246 9,154 ----------- ----------- ----------- ---------- ----------- ----------- Operating income .............. 23,183 3,938 27,121 16,707 5,200 21,907 Interest expense, net ............ (7,905) (6,669) (14,574) (7,899) (6,517) (14,416) Equity earnings .................. (296) 5,941 5,645 -- 9,325 9,325 Other income, net ................ 398 502 900 318 55 373 ----------- ----------- ----------- ---------- ----------- ----------- Net income ................. $ 15,380 $ 3,712 $ 19,092 $ 9,126 $ 8,063 $ 17,189 =========== =========== =========== ========== =========== ===========

NINE MONTHS ENDED SEPTEMBER 30, 2001 NINE MONTHS ENDED SEPTEMBER 30, 2000 ------------------------------------------ ----------------------------------------- DOWNSTREAM UPSTREAM DOWNSTREAM UPSTREAM SEGMENT SEGMENT CONSOLIDATED SEGMENT SEGMENT CONSOLIDATED ----------- ----------- ------------ ---------- ----------- ------------ Unaffiliated revenues ............ $ 204,925 $ 2,644,808 $ 2,849,733 $ 171,176 $ 2,077,118 $ 2,248,294 Operating expenses, including power ......................... 88,321 2,613,741 2,702,062 88,367 2,061,362 2,149,729 Depreciation and amortization expense ....................... 21,563 9,612 31,175 20,565 5,175 25,740 ----------- ----------- ----------- ---------- ----------- ----------- Operating income .............. 95,041 21,455 116,496 62,244 10,581 72,825 Interest expense, net ............ (24,267) (21,058) (45,325) (22,376) (6,757) (29,133) Equity earnings .................. (635) 15,905 15,270 -- 9,325 9,325 Other income, net ................ 567 857 1,424 1,284 339 1,623 ----------- ----------- ----------- ---------- ----------- ----------- Net income .................... $ 70,706 $ 17,159 $ 87,865 $ 41,152 $ 13,488 $ 54,640 =========== =========== =========== ========== =========== ===========

AS OF SEPTEMBER 30, 2001 ------------------------------------------------------------------------ DOWNSTREAM UPSTREAM MIDSTREAM PARTNERSHIP SEGMENT SEGMENT SEGMENT AND OTHER CONSOLIDATED ----------- ----------- --------- ----------- ------------ Total assets ..................... $ 809,106 $ 905,406 $ 360,860 $ (1,822) $ 2,073,550 Accounts receivable, trade ....... 20,772 272,667 -- -- 293,439 Accounts payable and accrued liabilities ................... $ 9,822 $ 284,542 $ -- $ -- $ 294,364

AS OF SEPTEMBER 30, 2000 ------------------------------------------------------------------------ DOWNSTREAM UPSTREAM MIDSTREAM PARTNERSHIP SEGMENT SEGMENT SEGMENT AND OTHER CONSOLIDATED ----------- ----------- --------- ----------- ------------ Total assets ..................... $ 743,838 $ 720,722 $ -- $ (1,592) $ 1,462,968 Accounts receivable, trade ....... 18,729 229,278 -- -- 248,007 Accounts payable and accrued liabilities ................... $ 10,380 $ 236,123 $ -- $ -- $ 246,503

13 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) NOTE 9. COMMITMENTS AND CONTINGENCIES In the fall of 1999 and on December 1, 2000, the Company and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, in Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the Company and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. In both cases plaintiffs contend, among other things, that the Company and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. The Company has filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are in the early stages of discovery and are not covered by insurance. The Company is defending itself vigorously against the lawsuits. The Partnership cannot estimate the loss, if any, associated with these pending lawsuits. The Partnership is involved in various other claims and legal proceedings incidental to its business. In the opinion of management, these claims and legal proceedings will not have a material adverse effect on the Partnership's consolidated financial position, results of operations or cash flows. The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. Although the Partnership believes its operations are in material compliance with applicable environmental regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations of the pipeline system, could result in substantial costs and liabilities to the Partnership. The Partnership does not anticipate that changes in environmental laws and regulations will have a material adverse effect on its financial condition, results of operations or cash flows in the near term. As of September 30, 2001, the Partnership had accrued approximately $8.3 million of costs to complete environmental remediation activity at certain sites owned by the Upstream Segment. Such amount includes $4.3 million of environmental remediation costs accrued during the third quarter of 2001. In connection with the acquisition of the Upstream Segment in November 1998, the Partnership received an indemnity from DEFS for environmental remediation costs that exceed $3.0 million, up to a maximum of $25.0 million, for certain sites that existed prior to the Partnership's operation of such properties. Approximately $2.6 million of the balance accrued as of September 30, 2001 is expected to be recovered under the indemnity. The majority of the indemnified costs relate to a crude oil site in Stephens County, Oklahoma, attributable to operations prior to the Partnership's acquisition of the Upstream Segment. The Partnership and the Indiana Department of Environmental Management ("IDEM") have entered into an Agreed Order that will ultimately result in a remediation program for any groundwater contamination attributable to the Partnership's operations at the Seymour, Indiana, terminal. A Feasibility Study, which includes the Partnership's proposed remediation program, has been approved by IDEM. IDEM is expected to issue a Record of Decision formally approving the remediation program. After the Record of Decision has been issued, the Partnership will enter into an Agreed Order for the continued operation and maintenance of the program. The Partnership has accrued $0.2 million at September 30, 2001 for future costs of the remediation program for the Seymour terminal. In the opinion of the Company, the completion of the remediation program will not have a material adverse impact on the Partnership's financial position, results of operations or liquidity. 14 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) The Partnership received a compliance order from the Louisiana Department of Environmental Quality ("DEQ") during 1994 relative to potential environmental contamination at the Partnership's Arcadia, Louisiana facility that may be attributable to the operations of the Partnership and adjacent petroleum terminals of other companies. The Partnership and all adjacent terminals have been assigned to the Groundwater Division of DEQ, in which a consolidated plan will be developed. The Partnership has finalized a negotiated Compliance Order with DEQ that will allow the Partnership to continue with a remediation plan similar to the one previously agreed to by DEQ and implemented by the Company. In the opinion of the General Partner, the completion of the remediation program being proposed by the Partnership will not have a future material adverse impact on the Partnership. Substantially all of the petroleum products transported and stored by the Partnership are owned by the Partnership's customers. At September 30, 2001, the Partnership had approximately 23.6 million barrels of products in its custody owned by customers. The Partnership is obligated for the transportation, storage and delivery of such products on behalf of its customers. The Partnership maintains insurance adequate to cover product losses through circumstances beyond its control. NOTE 10. COMPREHENSIVE INCOME The table below reconciles reported net income to total comprehensive income for the nine months ended September 30, 2001 (in thousands). Net income ..................................................... $ 87,865 Cumulative effect attributable to adoption of SFAS 133 (see Note 2. New Accounting Pronouncements) .................... (10,103) Hedge accounting for derivative instruments .................... (16,889) -------- Total comprehensive income ................................. $ 60,873 ======== The accumulated balance of other comprehensive loss related to cash flow hedges is as follows (in thousands): Balance at December 31, 2000 ........................... $ -- Cumulative effect of accounting change ................. (10,103) Net loss on cash flow hedges ........................... (20,928) Reclassification adjustments ........................... 4,039 -------- Balance at September 30, 2001 .......................... $(26,992) ======== NOTE 11. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION Under the Partnership's shelf registration statement on Form S-3 filed with the Securities and Exchange Commission on July 27, 2001, TE Products Pipeline Company, Limited Partnership and TCTM, L.P., the Partnership's sole first-tier operating subsidiaries (the "Guarantor Subsidiaries"), may issue unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time under the registration statement. If issued, the guarantees will be full, unconditional and joint and several. In July 2001, the Partnership restructured the ownership of the general partner interests in these first-tier operating subsidiaries to cause them to be wholly-owned by the Partnership. For purposes of the following consolidating information, the Partnership's and Guarantor Subsidiaries' investments in their respective subsidiaries are accounted for by the equity method of accounting. 15 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED)

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. SEPTEMBER 30, 2001 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ------------------ -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Assets Current assets ..................................... $ 3,127 $ 44,867 $ 323,141 $ (11,768) $ 359,367 Property, plant and equipment - net ................ -- 673,111 470,085 -- 1,143,196 Equity investments ................................. 493,468 285,553 230,632 (739,760) 269,893 Intercompany notes receivable ...................... 830,027 -- -- (830,027) -- Other assets ....................................... 5,732 19,651 280,626 (4,915) 301,094 ---------- ---------- ---------- ----------- ---------- Total assets .................................... $1,332,354 $1,023,182 $1,304,484 $(1,586,470) $2,073,550 ========== ========== ========== =========== ========== Liabilities and partners' capital Current liabilities ................................ $ 365,767 $ 46,933 $ 673,305 $ (356,734) $ 729,271 Long term debt ..................................... 472,000 389,807 -- -- 861,807 Intercompany notes payable ......................... -- 89,060 380,967 (470,027) -- Other long term liabilities and minority interest ......................................... -- 3,918 -- 12,038 15,956 Redeemable Class B Units held by related party ............................................ -- -- -- 106,270 106,270 Total partners' capital ............................ 494,587 493,464 250,212 (878,017) 360,246 ---------- ---------- ---------- ----------- ---------- Total liabilities and partners' capital ......... $1,332,354 $1,023,182 $1,304,484 $(1,586,470) $2,073,550 ========== ========== ========== =========== ==========

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. DECEMBER 31, 2000 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ----------------- -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Assets Current assets ................................... $ 6,083 $ 52,773 $ 315,488 $ (10,947) $ 363,397 Property, plant and equipment - net .............. -- 640,657 309,048 -- 949,705 Equity investments ............................... 420,433 202,811 236,232 (617,828) 241,648 Intercompany notes receivable .................... 441,836 -- -- (441,836) -- Other assets ..................................... 5,322 15,385 48,475 (1,122) 68,060 ---------- ---------- ---------- ----------- ---------- Total assets .................................. $ 873,674 $ 911,626 $ 909,243 $(1,071,733) $1,622,810 ========== ========== ========== =========== ========== Liabilities and partners' capital Current liabilities .............................. $ 7,206 $ 45,085 $ 318,049 $ (12,069) $ 358,271 Long term debt ................................... 446,000 389,784 -- -- 835,784 Intercompany notes payable ....................... -- 48,037 393,799 (441,836) -- Other long term liabilities and minority interest .............................. -- 3,991 -- 4,296 8,287 Redeemable Class B Units held by related party .................................. 105,411 -- -- -- 105,411 Total partners' capital .......................... 315,057 424,729 197,395 (622,124) 315,057 ---------- ---------- ---------- ----------- ---------- Total liabilities and partners' capital ....... $ 873,674 $ 911,626 $ 909,243 $(1,071,733) $1,622,810 ========== ========== ========== =========== ==========

16 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED)

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. THREE MONTHS ENDED SEPTEMBER 30, 2001 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ------------------------------------- -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Operating revenues ................... $ -- $ 58,527 $ 932,289 $ -- $ 990,816 Costs and expenses ................... -- 36,458 927,237 -- 963,695 ----------- ----------- ----------- ----------- ----------- Operating income ................... -- 22,069 5,052 -- 27,121 ----------- ----------- ----------- ----------- ----------- Interest expense - net ............... (8,774) (7,181) (7,393) 8,774 (14,574) Equity earnings ...................... 19,092 3,868 5,941 (23,256) 5,645 Other income - net ................... 8,774 433 564 (8,774) 997 ----------- ----------- ----------- ----------- ----------- Income before minority interest .... 19,092 19,189 4,164 (23,256) 19,189 Minority interest .................... -- -- -- (97) (97) ----------- ----------- ----------- ----------- ----------- Net income ......................... $ 19,092 $ 19,189 $ 4,164 $ (23,353) $ 19,092 =========== =========== =========== =========== ===========

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. THREE MONTHS ENDED SEPTEMBER 30, 2000 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ------------------------------------- -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Operating revenues ................... $ -- $ 51,203 $ 698,695 $ -- $ 749,898 Costs and expenses ................... -- 35,686 692,305 -- 727,991 ----------- ----------- ----------- ----------- ----------- Operating income ................... -- 15,517 6,390 -- 21,907 ----------- ----------- ----------- ----------- ----------- Interest expense - net ............... (8,261) (6,955) (7,461) 8,261 (14,416) Equity earnings ...................... 17,189 8,467 9,325 (25,656) 9,325 Other income - net ................... 8,261 335 213 (8,261) 548 ----------- ----------- ----------- ----------- ----------- Income before minority interest .... 17,189 17,364 8,467 (25,656) 17,364 Minority interest .................... -- -- -- (175) (175) ----------- ----------- ----------- ----------- ----------- Net income ......................... $ 17,189 $ 17,364 $ 8,467 $ (25,831) $ 17,189 =========== =========== =========== =========== ===========

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. NINE MONTHS ENDED SEPTEMBER 30, 2001 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ------------------------------------ -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Operating revenues ................... $ -- $ 199,374 $ 2,650,359 $ -- $ 2,849,733 Costs and expenses ................... -- 107,712 2,625,525 -- 2,733,237 ----------- ----------- ----------- ----------- ----------- Operating income ................... -- 91,662 24,834 -- 116,496 ----------- ----------- ----------- ----------- ----------- Interest expense - net ............... (26,577) (22,160) (23,165) 26,577 (45,325) Equity earnings ...................... 87,865 18,048 15,905 (106,548) 15,270 Other income - net ................... 26,577 1,115 1,109 (26,577) 2,224 ----------- ----------- ----------- ----------- ----------- Income before minority interest .... 87,865 88,665 18,683 (106,548) 88,665 Minority interest .................... -- -- -- (800) (800) ----------- ----------- ----------- ----------- ----------- Net income ......................... $ 87,865 $ 88,665 $ 18,683 $ (107,348) $ 87,865 =========== =========== =========== =========== ===========

17 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED)

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. NINE MONTHS ENDED SEPTEMBER 30, 2000 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ------------------------------------ -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Operating revenues ................... $ -- $ 165,526 $ 2,082,768 $ -- $ 2,248,294 Costs and expenses ................... -- 106,770 2,068,699 -- 2,175,469 ----------- ----------- ----------- ----------- ----------- Operating income ................... -- 58,756 14,069 -- 72,825 ----------- ----------- ----------- ----------- ----------- Interest expense - net ............... (8,261) (20,170) (8,963) 8,261 (29,133) Equity earnings ...................... 54,640 15,047 9,325 (69,687) 9,325 Other income - net ................... 8,261 1,564 616 (8,261) 2,180 ----------- ----------- ----------- ----------- ----------- Income before minority interest .... 54,640 55,197 15,047 (69,687) 55,197 Minority interest .................... -- -- -- (557) (557) ----------- ----------- ----------- ----------- ----------- Net income ......................... $ 54,640 $ 55,197 $ 15,047 $ (70,244) $ 54,640 =========== =========== =========== =========== ===========

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. NINE MONTHS ENDED SEPTEMBER 30, 2001 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ------------------------------------ -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Cash flows from operating activities Net Income ...................................... $ 87,865 $ 88,665 $ 18,681 $(107,346) $ 87,865 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ............... -- 20,051 11,124 -- 31,175 Equity earnings, net of distributions ....... (13,340) 3,375 5,600 10,455 6,090 Changes in assets and liabilities and other .................................... 2,601 2,822 (17,894) 799 (11,672) --------- --------- --------- --------- --------- Net cash provided by operating activities ......... 77,126 114,913 17,511 (96,092) 113,458 --------- --------- --------- --------- --------- Cash flows from investing activities .............. (446,301) (83,599) (388,000) 446,301 (471,599) Cash flows from financing activities .............. 369,175 (34,452) 379,562 (350,209) 364,076 --------- --------- --------- --------- --------- Net increase (decrease) in cash and cash equivalents ..................................... -- (3,138) 9,073 -- 5,935 Cash and cash equivalents at beginning of period .......................................... -- 9,167 17,929 -- 27,096 --------- --------- --------- --------- --------- Cash and cash equivalents at end of period ........ $ -- $ 6,029 $ 27,002 $ -- $ 33,031 ========= ========= ========= ========= =========

18 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED)

TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. NINE MONTHS ENDED SEPTEMBER 30, 2000 PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED ------------------------------------ -------------- ------------ ------------- ------------- -------------- (IN THOUSANDS) Cash flows from operating activities Net Income ...................................... $ 54,640 $ 55,197 $ 15,047 $ (70,244) $ 54,640 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ............... -- 19,053 6,687 -- 25,740 Equity earnings, net of distributions ....... 2,978 (3,233) (8,258) 143 (8,370) Changes in assets and liabilities and other ................................. -- 2,829 2,571 557 5,957 --------- --------- --------- --------- --------- Net cash provided by operating activities ......... 57,618 73,846 16,047 (69,544) 77,967 --------- --------- --------- --------- --------- Cash flows from investing activities .............. -- (49,792) (337,472) -- (387,264) Cash flows from financing activities .............. (57,618) (31,628) 321,421 69,544 301,719 --------- --------- --------- --------- --------- Net decrease in cash and cash equivalents ......... -- (7,574) (4) -- (7,578) Cash and cash equivalents at beginning of period .......................................... -- 16,284 16,309 -- 32,593 --------- --------- --------- --------- --------- Cash and cash equivalents at end of period ........ $ -- $ 8,710 $ 16,305 $ -- $ 25,015 ========= ========= ========= ========= =========

19 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL The following information is provided to facilitate increased understanding of the 2001 and 2000 interim consolidated financial statements and accompanying notes presented in Item 1. Material period-to-period variances in the consolidated statements of income are discussed under "Results of Operations." The "Financial Condition and Liquidity" section analyzes cash flows and financial position. Discussion included in "Other Matters" addresses key trends, future plans and contingencies. Throughout these discussions, management addresses items known to it that are reasonably likely to materially affect future liquidity or earnings. Through its ownership of the Downstream Segment, the Upstream Segment and the Midstream Segment, the Partnership operates in three segments: refined products, LPGs and petrochemical transportation; crude oil and NGLs transportation and marketing; and natural gas gathering. The Partnership's reportable segments offer different products and services and are managed separately because each requires different business strategies. On September 30, 2001, the Partnership completed the acquisition of Jonah (see Note 3. Acquisitions). The operations of Jonah include the gathering of natural gas. The Downstream Segment is involved in the interstate transportation, storage and terminaling of petroleum products and LPGs, intrastate transportation of petrochemicals and the fractionation of NGLs. Revenues are derived from the transportation of refined products and LPGs, the storage and short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex, sale of product inventory and other ancillary services. Labor and electric power costs comprise the two largest operating expense items of the Downstream Segment. Higher natural gas prices increase the cost of electricity used to power pump stations on the Pipeline System. Operations are somewhat seasonal with higher revenues generally realized during the first and fourth quarters of each year. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. The Upstream Segment is involved in the transportation, aggregation and marketing of crude oil and NGLs; and the distribution of lube oils and specialty chemicals. Revenues are earned from the gathering, storage, transportation and marketing of crude oil and NGLs; and the distribution of lube oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along its pipeline systems, or from third party pipeline systems, and arranging the necessary logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. The Midstream Segment gathers natural gas in the Green River Basin in southwest Wyoming. On September 30, 2001, the Partnership acquired Jonah Gas Gathering Company from Alberta Energy Corporation (see Note 3. Acquisitions). The acquisition was accounted for under the purchase method of accounting. The results of operations of the acquisition will be included in periods subsequent to September 30, 2001. On July 20, 2000, the Partnership completed an acquisition of assets from ARCO for $322.6 million, which included $4.1 million of acquisition related costs other than the purchase price. The purchased assets included ARCO's 50-percent voting interest in Seaway. The Partnership assumed ARCO's role as operator of this pipeline. The Company also acquired ARCO's crude oil terminal facilities in Cushing and Midland, Texas, including the line transfer and pumpover business at each location, an undivided ownership interest in both the Rancho Pipeline and the Basin Pipeline, both of which are operated by another joint owner, and the receipt and delivery pipelines known as the West Texas Trunk System, located around the Midland terminal. The transaction was accounted for under the purchase method for accounting purposes. The results of operations of assets acquired have been included in the Upstream Segment since the purchase on July 20, 2000. 20 RESULTS OF OPERATIONS In October 2000, the Partnership received a settlement notice from Atlantic Richfield Company for payment of a net aggregate amount of approximately $12.9 million in post-closing adjustments related to the purchase of ARCO. A large portion of the requested adjustment related to an indemnity for payment of accrued income taxes. In August 2001, the Partnership and Atlantic Richfield Company reached a settlement of $11.0 million for the post-closing adjustments. The Partnership recorded the settlement as an increase to the purchase price of ARCO. The Partnership paid the settlement amount to Atlantic Richfield Company on October 15, 2001. Summarized below is financial data by business segment (in thousands):

QUARTER ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, --------------------------- ------------------------------- 2001 2000 2001 2000 ---------- ---------- ---------- ---------- Operating revenues: Downstream Segment ............. $ 60,362 $ 53,110 $ 204,925 $ 171,176 Upstream Segment ............... 930,454 696,788 2,644,808 2,077,118 ---------- ---------- ---------- ---------- Total operating revenues .... 990,816 749,898 2,849,733 2,248,294 ---------- ---------- ---------- ---------- Operating income: Downstream Segment ............. 23,183 16,707 95,041 62,244 Upstream Segment ............... 3,938 5,200 21,455 10,581 ---------- ---------- ---------- ---------- Total operating income ...... 27,121 21,907 116,496 72,825 ---------- ---------- ---------- ---------- Net income: Downstream Segment ............. 15,380 9,126 70,706 41,152 Upstream Segment ............... 3,712 8,063 17,159 13,488 ---------- ---------- ---------- ---------- Total net income ............ $ 19,092 $ 17,189 $ 87,865 $ 54,640 ---------- ---------- ---------- ----------

For the quarter ended September 30, 2001, the Partnership reported net income of $19.1 million, compared with net income of $17.2 million for the 2000 third quarter. The $1.9 million increase in net income resulted from a $6.3 million increase in net income provided by the Downstream Segment, partially offset by a $4.4 million decrease in net income provided by the Upstream Segment. The increase in net income by the Downstream Segment was comprised primarily of a $7.3 million increase in operating revenues, partially offset by a $0.8 million increase in costs and expenses. The decrease in net income by the Upstream Segment was comprised of a $12.3 million increase in costs and expenses (excluding purchases of crude oil and petroleum products) and a $3.4 million decrease in equity earnings of Seaway, partially offset by a a $10.1 million increase in margin, a $0.9 million increase in other operating revenues, and a $0.4 million increase in other income - net. For the nine months ended September 30, 2001, the Partnership reported net income of $87.9 million, compared with net income of $54.6 million for the corresponding period in 2000. The $33.3 million increase in income resulted from a $29.5 million increase in net income provided by the Downstream Segment and a $3.7 million increase in net income provided by the Upstream Segment. The increase in net income by the Downstream Segment was primarily due to a $33.7 million increase in operating revenues, partially offset by a $1.9 million increase in interest expense (net of capitalized interest), a $1.0 million increase in costs and expenses, $0.6 million in losses from equity investments, and a $0.5 million decrease in other income - net. The increase in net income by the Upstream Segment was primarily due to a $34.2 million increase in margin, a $6.6 million increase in other operating revenues, a $6.6 million increase in equity earnings of Seaway, and a $0.6 million increase in other income - net, partially offset by a $30.0 million increase in costs and expenses (excluding purchases of crude oil and petroleum products) and a $14.3 million increase in interest expense (net of capitalized interest). 21 RESULTS OF OPERATIONS - (CONTINUED) DOWNSTREAM SEGMENT Volume and average rate information for 2001 and 2000 is presented below:

QUARTER ENDED NINE MONTHS ENDED SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE ------------------- INCREASE -------------------- INCREASE 2001 2000 (DECREASE) 2001 2000 (DECREASE) ------- ------- ---------- -------- -------- ----------- (IN THOUSANDS, EXCEPT AVERAGE RATE INFORMATION) VOLUMES DELIVERED Refined products ....................... 32,387 32,490 -- 92,935 97,216 (4)% LPGs ................................... 8,864 9,058 (2)% 27,422 27,385 -- Mont Belvieu operations ................ 5,352 5,506 (3)% 16,188 19,154 (15)% ------- ------- ------ -------- -------- ----- Total .............................. 46,603 47,054 (1)% 136,545 143,755 (5)% ======= ======= ====== ======== ======== ===== AVERAGE RATE PER BARREL Refined products ...................... $ 0.99 $ 0.91 9% $ 0.98(a) $ 0.93 5% LPGs .................................. 1.77 1.60 11% 1.98 1.75 13% Mont Belvieu operations ............... 0.18 .0.16 13% 0.18 0.15 20% Average system rate per barrel .... $ 1.05 $ 0.95 11% $ 1.08 $ 0.98 10% ======= ======= ====== ======== ======== =====

(a) Net of $18.9 million received from Pennzoil-Quaker State Company for canceled transportation agreement discussed below. Refined products transportation revenues increased $2.7 million for the quarter ended September 30, 2001, compared with the prior-year quarter, due primarily to a 9% increase in the refined products average rate per barrel. The increase in the refined products average rate per barrel from the prior-year quarter was due to the approval of market based rates in April 2001, and an increased percentage of long haul volumes delivered in the Midwest. Refined products volumes delivered during the third quarter of 2001 decreased slightly compared to the prior-year quarter, due primarily to lower deliveries of methyl tertiary butyl ether ("MTBE") at the Partnership's marine terminal near Beaumont, Texas, which were largely offset by increased long haul deliveries of motor fuel and distillate in the Midwest market area. LPGs transportation revenues increased $1.2 million for the quarter ended September 30, 2001, compared with the third quarter of 2000, due primarily to increased deliveries of propane in the upper Midwest and Northeast market areas attributable to favorable price differentials and higher demand from customers filling their storage facilities. These increases were partially offset by decreased butane deliveries in the Midwest and short-haul deliveries of propane along the upper Texas Gulf Coast. The LPGs average rate per barrel increased 11% from the prior-year quarter as a result of an increased percentage of long-haul deliveries during the third quarter of 2001. Revenues generated from Mont Belvieu operations increased $1.0 million during the quarter ended September 30, 2001, compared with the third quarter of 2000, as a result of increased storage revenue and brine service revenue. Mont Belvieu shuttle volumes delivered decreased 3% during the third quarter of 2001, compared with the third quarter of 2000, due to reduced petrochemical demand. The Mont Belvieu average rate per barrel increased during the third quarter of 2001 as a result of reduced contract shuttle deliveries, which generally carry lower rates. Other operating revenues increased $2.4 million during the quarter ended September 30, 2001, compared with the prior year quarter, due primarily to contract petrochemical delivery revenue, which started during the fourth quarter of 2000, and increased product sales. These increases were partially offset by decreased product exchange revenue. Costs and expenses increased $0.8 million for the quarter ended September 30, 2001, compared with the third quarter of 2000, primarily due to a $1.4 million increase in operating, general and administrative expenses, a 22 RESULTS OF OPERATIONS - (CONTINUED) $0.3 million increase in depreciation and amortization expense, and a $0.2 million increase in operating fuel and power expense. These increases were partially offset by a $1.1 million decrease in taxes - other than income taxes. Operating, general and administrative expenses increased primarily due to increased general and administrative consulting and contract labor and increased incentive compensation accruals. The increase in depreciation expense from the prior year third quarter resulted from assets placed in service during the fourth quarter of 2000. Operating fuel and power expense increased as a result of increased long-haul product deliveries. The decrease in taxes - other than income taxes resulted from actual property taxes being lower than previously estimated. Interest expense decreased $0.6 million for the quarter ended September 30, 2001, compared with the second quarter of 2000, as a result of reduced interest rates on borrowings under the variable-rate credit facilities. Interest capitalized decreased $0.6 million as a result of the completion of the petrochemical pipelines from Mont Belvieu, Texas, to Port Arthur, Texas, during the fourth quarter of 2000. Net loss from equity investments totaled $0.3 million during the quarter ended September 30, 2001 due to pre-operating expenses of Centennial Pipeline, LLC ("Centennial"). For the nine months ended September 30, 2001, refined products transportation revenues increased $19.6 million, due primarily to revenue recognized on the canceled transportation agreement with Pennzoil-Quaker State Company ("Pennzoil") and the recognition of $1.7 million of previously deferred revenue related to the approval of the market based rates during the second quarter of 2001, partially offset by a 4% decrease in refined products volumes delivered. The net revenue increase related to the settlement was approximately $14.8 million during the nine months ended September 30, 2001. Jet fuel volumes delivered to the Midwest market areas decreased 14% due to reduced air travel demand and an airline pilot strike during the second quarter of 2001. Deliveries of MTBE decreased as a result of the expiration of contract deliveries to the Partnership's marine terminal near Beaumont, Texas, in April 2001. The total refined products volume decrease was partially offset by increased distillate deliveries primarily due to increased demand in the south Central market areas and deliveries at a third-party terminal in Houston, Texas. The refined products average rate per barrel increased 5% from the prior-year period primarily due to an increased percentage of long-haul volumes delivered in 2001. LPGs transportation revenues increased $6.2 million for the nine months ended September 30, 2001, compared with the corresponding period in 2000, due primarily to increased deliveries of propane in the Midwest and Northeast market areas attributable to colder weather in the Northeast during the first quarter of 2001, favorable price differentials and higher demand from customers filling their storage facilities. Additionally, butane deliveries to the Chicago market area increased due to favorable price differentials. These increases were partially offset by decreased short-haul deliveries of propane as a result of operational problems at a petrochemical facility on the upper Texas Gulf Coast that is served by the Partnership. The LPGs average rate per barrel increased 13% from the prior-year period as a result of an increased percentage of long-haul deliveries to the upper Midwest and Northeast market areas. Revenues generated from Mont Belvieu operations decreased $0.5 million during the nine months ended September 30, 2001, compared with the nine months ended September 30, 2000, as a result of decreased contract storage revenue, partially offset by increased brine service revenue. Mont Belvieu shuttle deliveries decreased during the nine months ended September 30, 2001, compared with the corresponding period in 2000, due to reduced petrochemical demand. The Mont Belvieu average rate per barrel increased for the nine months as a result of reduced contract deliveries which generally carry lower rates. Other operating revenues increased $8.5 million during the nine months ended September 30, 2001, compared with the corresponding period in 2000, primarily due to contract petrochemical delivery revenue, which started during the fourth quarter of 2000, increased propane deliveries from the Partnership's Providence, Rhode Island, import facility in the first quarter of 2001, and increased product sales. 23 RESULTS OF OPERATIONS - (CONTINUED) Costs and expenses increased $1.0 million for the nine months ended September 30, 2001, compared with the corresponding period in 2000, primarily due to a $2.2 million increase in operating fuel and power expense and a $1.0 million increase in depreciation and amortization expense, partially offset by a $1.2 million decrease in operating, general and administrative expenses and a $1.0 decrease in taxes - other than income taxes. Operating fuel and power expense increased as a result of higher rates charged by electric utilities. The increase in depreciation expense from the prior year period resulted from assets placed in service during the fourth quarter of 2000. Operating, general and administrative expenses decreased primarily as a result of a March 2000 write-off of project evaluation costs related to the proposed pipeline construction from Beaumont, Texas, to Little Rock, Arkansas, decreased labor costs and decreased throughput-related rental expense on volumes received through the connection with Colonial Pipeline at Beaumont, Texas. The decrease in taxes - other than income taxes resulted from actual property taxes being lower than previously estimated. Interest expense decreased $0.1 million during the nine months ended September 30, 2001, compared with the nine months ended September 30, 2000, as a result of reduced interest rates on borrowings under the variable-rate credit facilities, largely offset by increased borrowings to fund investment in Centennial Pipeline. Interest capitalized decreased $2.0 million during the nine months ended September 30, 2001, compared with the corresponding prior year period, as a result of the completion of the petrochemical pipelines from Mont Belvieu, Texas, to Port Arthur, Texas, during the fourth quarter of 2000. Net loss from equity investments totaled $0.6 million during the nine months ended September 30, 2001 due to pre-operating expenses of Centennial. Other income - net decreased $0.5 million during the nine months ended September 30, 2001, compared with the first nine months of 2000, due primarily to lower interest income earned on cash investments. 24 RESULTS OF OPERATIONS - (CONTINUED) UPSTREAM SEGMENT Margin of the Upstream Segment is calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil and NGLs, less the costs of purchases of crude oil and lubrication oil. Margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices for products marketed. Margin and volume information for 2001 and 2000 is presented below (in thousands, except per barrel and per gallon amounts):

QUARTER ENDED NINE MONTHS ENDED SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE ----------------------- INCREASE ------------------------ INCREASE 2001 2000 (DECREASE) 2001 2000 (DECREASE) --------- --------- ----------- --------- --------- --------- (IN THOUSANDS, EXCEPT AVERAGE RATE INFORMATION) Margins: Crude oil transportation ........... $ 9,119 $ 6,769 35% $ 26,165 $ 16,496 59% Crude oil marketing ................ 3,625 3,863 (6)% 9,282 9,451 (2)% Crude oil terminaling .............. 2,831 1,849 53% 7,505 1,849 306% NGL transportation ................. 5,412 1,802 200% 15,853 5,142 208% Lubrication oil sales .............. 1,030 922 12% 3,148 2,293 37% Seaway Crude Intercompany .......... 3,320 -- -- 7,490 -- -- --------- --------- ------ --------- --------- ----- Total margin ..................... $ 25,337 $ 15,205 67% $ 69,443 $ 35,231 97% ========= ========= ====== ========= ========= ===== Total barrels: Crude oil transportation ........... 19,795 13,016 52% 57,391 30,952 85% Crude oil marketing ................ 37,135 23,424 59% 109,586 75,842 44% Crude oil terminaling .............. 30,130 22,000 37% 87,252 22,000 297% NGL transportation ................. 5,828 1,422 310% 16,026 3,859 315% Lubrication oil volume (total gallons) ... 2,257 1,999 13% 6,646 5,566 19% Margin per barrel: Crude oil transportation ........... $ 0.461 $ 0.520 (11)% $ 0.456 $ 0.533 (14)% Crude oil marketing ................ 0.098 0.165 (41)% 0.085 0.125 (32)% Crude oil terminaling .............. 0.094 0.084 12% 0.086 0.084 2% NGL transportation ................. 0.929 1.267 (27)% 0.989 1.332 (26)% Lubrication oil margin (per gallon) ...... 0.456 0.461 (1)% 0.474 0.412 15%

Margin increased $10.1 million during the third quarter of 2001, compared with the third quarter of 2000. NGL transportation margin increased $3.6 million primarily due to the Panola system acquired on December 31, 2000. Seaway Crude intercompany margin of $3.3 million was attributable to volumes transported on Seaway on behalf of the Upstream Segment. Crude oil transportation margin increased $2.4 million primarily due to volumes transported on the pipeline assets acquired from Ultramar Diamond Shamrock Corporation ("UDS") on March 1, 2001, and the full quarter impact of the assets acquired from ARCO. Crude oil terminaling margin increased $1.0 million as a result of higher pumpover volumes at Midland, Texas, and Cushing, Oklahoma. These increases were partially offset by a $0.2 million decrease in crude oil marketing margin compared with the prior quarter. Costs and expenses, excluding expenses associated with purchases of crude oil and petroleum products, increased $12.3 million during the quarter ended September 30, 2001, compared with the prior year quarter. The increase was comprised of a $9.0 million increase in operating, general and administrative expenses, a $2.2 million increase in taxes - other than income taxes, a $1.0 million increase in depreciation and amortization expense, and a 25 RESULTS OF OPERATIONS - (CONTINUED) $0.1 million increase in operating fuel and power expense. The increase in operating, general and administrative expenses was primarily attributable to a $4.3 million increase in environmental costs, increased labor related costs and increased general and administrative supplies and services expense. The increase in taxes - other than income taxes, depreciation expense, and operating fuel and power were primarily due to assets acquired from UDS. Equity earnings in Seaway Crude Pipeline Company for the quarter ended September 30, 2001, decreased $3.4 million from the quarter ended September 30, 2000, as a result of lower third-party transportation volumes. Margin increased $34.2 million during the nine months ended September 30, 2001, compared with the corresponding period in 2000. NGL transportation margin increased $10.7 million primarily due to the Panola system acquired on December 31, 2000, partially offset by decreased volumes on the Dean and Wilcox pipeline systems in South Texas. Crude oil transportation margin increased $9.7 million primarily due to a $5.6 million increase on the ARCO assets acquired in July 2000 and higher volume on the Red River and South Texas systems, which benefited from increased regional crude oil production and pipeline assets acquired from UDS. Seaway Crude intercompany margin of $7.5 million was attributable to volumes transported on Seaway on behalf of the Upstream Segment. Crude oil terminaling margin contributed $5.7 million as a result of pumpover volumes at Midland, Texas, and Cushing, Oklahoma, related to the ARCO assets acquired in July 2000. Margin contributed from lubrication oil sales increased $0.9 million primarily due to increased volumes and increased rates on the margin realized per gallon. These increases were partially offset by a $0.2 million decrease in crude oil marketing margin compared with the prior corresponding period. Costs and expenses, excluding expenses associated with purchases of crude oil and petroleum products, increased $30.0 million during the nine months ended September 30, 2001, compared with the corresponding prior year period, comprised of a $20.0 million increase in operating, general and administrative expenses, a $4.5 million increase in depreciation and amortization expense, a $4.5 million increase in taxes - other than income taxes, and a $1.0 million increase in operating fuel and power expense. The increase in operating, general and administrative expenses was primarily attributable to operating expenses of the acquired assets, $4.3 million of expense recorded in September 2001 for environmental remediation, increased labor related costs and increased general and administrative supplies and services expense. The increases in depreciation and amortization expense, taxes - other than income taxes, and operating fuel and power expense were primarily attributable to assets acquired. Net income of the Upstream Segment for the nine-month period ended September 30, 2001, included $15.9 million of equity earnings in Seaway Crude Pipeline Company, which was added to the Partnership's business on July 20, 2001, with the acquired ARCO assets. Other operating revenue of the Upstream Segment increased $0.9 million and $6.6 million for the three-month and nine-month periods ended September 30, 2001, respectively, compared with the prior year periods, attributable to revenue from documentation and other services to support customer's trading activity at Midland, Texas, and Cushing, Oklahoma. Such revenues were added to the Partnership's business on July 20, 2000, with the acquired ARCO assets. Interest expense increased $0.3 million and $14.5 million for the three-month and nine-month periods ended September 30, 2001, respectively, compared with the prior year periods, primarily due to interest expense on the term loan and revolving credit facilities used to finance the acquisition of acquired assets. 26 FINANCIAL CONDITION AND LIQUIDITY Net cash from operations for the nine months ended September 30, 2001, totaled $113.5 million, comprised of $119.0 million of income before charges for depreciation and amortization, partially offset by $5.5 million of cash used for working capital changes. This compares with cash flows from operations of $78.0 million for the corresponding period in 2000, comprised of $80.4 million of income before charges for depreciation and amortization, and $2.4 million of cash used for working capital changes. The decrease in cash from working capital changes during the nine-month period ended September 30, 2001, as compared to the corresponding period in 2000, resulted primarily from decreased accounts payable and accrued expenses at September 30, 2001. Net cash from operations for the nine months ended September 30, 2001 and 2000, included interest payments of $52.0 million and $27.7 million, respectively. Cash flows used in investing activities during the first nine months of 2001 was comprised of $359.8 million for the purchase of Jonah Gas Gathering Company on September 30, 2001, $62.0 million of capital expenditures, $34.3 million of cash contributions for the Partnership's interest in the Centennial joint venture, and $20.0 million for the purchase of crude oil assets from UDS on March 1, 2001. These uses of cash were partially offset by $3.2 million received on matured cash investments and $1.3 million of cash received from the sale of vehicles. Cash flows used in investing activities during the first nine months of 2000 was primarily comprised of $322.6 million for the purchase of assets from ARCO, $53.3 million of capital expenditures, $7.8 million for crude oil systems purchased in North Texas, and $3.0 million of cash contributions for the Partnership's initial interest in the Centennial joint venture. These decreases were partially offset by $1.5 million of proceeds from investment maturities. In August 2000, the Partnership announced the execution of definitive agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form Centennial. Centennial will own and operate an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant will own a one-third interest in Centennial. Centennial will build a 74-mile, 24-inch diameter pipeline connecting the Downstream Segment's facility in Beaumont, Texas, with the start of an existing 720-mile, 26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois. The pipeline will intersect the Downstream Segment's existing mainline near Creal Springs, Illinois, where a new two million barrel refined petroleum products storage terminal will be built. The Partnership expects to contribute approximately $70 million for its one-third interest in Centennial. The Partnership expects to fund its contribution through borrowings under its credit facilities. Centennial is anticipated to commence operations in the first quarter of 2002. The Partnership estimates that capital expenditures, excluding acquisitions, for 2001 will be approximately $97 million, which includes $3 million of capitalized interest. Approximately $49 million is expected to be used to expand the Partnership's capacity to support the receipt connection point with Centennial at Beaumont, Texas, and delivery location at Creal Springs, Illinois. Approximately one-half of the remaining amount is expected to be used for revenue-generating projects, with the remaining amount to be used for life-cycle replacements and upgrading current facilities. On July 14, 2000, the Partnership entered into a $75 million term loan and a $475 million revolving credit facility. On July 21, 2000, the Partnership borrowed $75 million under the term loan and $340 million under the revolving credit facility. The funds were used to finance the acquisition of the ARCO assets (see Note 3. Acquisitions) and to refinance existing credit facilities, other than the Senior Notes. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000. On April 6, 2001, the Partnership's $475 million revolving credit agreement was amended to permit borrowings up to $500 million and to allow for letters of credit up to $20 million. The term of the revised credit agreement was extended to April 6, 2004. Additionally, on April 6, 2001, the Partnership entered into a 364-day, $200 million revolving credit agreement. The interest rate is based on the Partnership's option of either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreements contain restrictive financial covenants that require the Partnership to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum 27 FINANCIAL CONDITION AND LIQUIDITY - (CONTINUED) fixed charge coverage ratios. At September 30, 2001, $472 million was outstanding under the revolving credit facility at a weighted average interest rate of 4.8%. On July 21, 2000, the Partnership entered into a three year swap agreement to hedge its exposure on the variable rate credit facilities. On April 6, 2001 the swap agreement was extended until April 6, 2004 to match the maturity of the variable rate credit facility above. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership pays a fixed rate of interest of 6.955% and receives a floating rate based on a three month USD LIBOR rate. During 2001, the Partnership executed treasury rate lock agreements with a combined notional amount of $400 million to hedge its exposure to increases in the treasury rate that will be used to establish the fixed interest rate for the debt offering that is probable to occur in the fourth quarter of 2001. Under the treasury rate lock agreements, the Partnership pays a fixed rate of interest, and receives a floating rate based on the three month treasury rate. The treasury rate locks are designated as cash flow hedges, therefore, the changes in fair value, to the extent the treasury rate locks are effective, are recognized in other comprehensive income until the actual debt offering occurs. Upon completion of the debt offering, the realized gain or loss on the treasury rate locks will be amortized out of accumulated other comprehensive income into interest expense over the life of the debt obligation. During April 2001, a treasury lock with a notional amount of $200 million was terminated with a realized gain of $1.1 million. The realized gain was recorded as a component of accumulated other comprehensive income. As of September 30, 2001, a notional amount of $200 million remained outstanding. The fair value of the outstanding treasury rate locks was a loss of approximately $6.0 million at September 30, 2001. On October 4, 2001, the Partnership entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its $210 million principal amount of 7.51% fixed rate Senior Notes. The swap agreement has a notional amount of $210 million and matures in January 2028 to match the principal and maturity of the Senior Notes. Under the swap agreement, the Partnership pays a floating rate based on a three month USD LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. The Partnership paid the second quarter 2001 cash distribution of $25.5 million ($0.525 per Limited Partner Unit and Class B Unit) on August 6, 2001. On October 17, 2001, the Partnership declared a cash distribution of $0.575 per Limited Partner Unit and Class B Unit for the quarter ended September 30, 2001. The distribution was paid on November 5, 2001 to Unitholders of record on October 31, 2001. OTHER MATTERS The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. Although the Partnership believes its operations are in material compliance with applicable environmental regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations of the pipeline system, could result in substantial costs and liabilities to the Partnership. The Partnership does not anticipate that changes in environmental laws and regulations will have a material adverse effect on its financial position, results of operations or cash flows in the near term. The Partnership and the Indiana Department of Environmental Management ("IDEM") have entered into an Agreed Order that will ultimately result in a remediation program for any groundwater contamination attributable to the Partnership's operations at the Seymour, Indiana, terminal. A Feasibility Study, which includes the Partnership's proposed remediation program, has been approved by IDEM. IDEM is expected to issue a Record of Decision formally approving the remediation program. After the Record of Decision has been issued, the Partnership will enter into an Agreed Order for the continued operation and maintenance of the program. The 28 OTHER MATTERS - (CONTINUED) Partnership has accrued $0.2 million at September 30, 2001 for future costs of the remediation program for the Seymour terminal. In the opinion of the Company, the completion of the remediation program will not have a material adverse impact on the Partnership's financial condition, results of operations or liquidity. The Partnership received a compliance order from the Louisiana Department of Environmental Quality ("DEQ") during 1994 relative to potential environmental contamination at the Partnership's Arcadia, Louisiana facility, which may be attributable to the operations of the Partnership and adjacent petroleum terminals of other companies. The Partnership and all adjacent terminals have been assigned to the Groundwater Division of DEQ, in which a consolidated plan will be developed. The Partnership has finalized a negotiated Compliance Order with DEQ that will allow the Partnership to continue with a remediation plan similar to the one previously agreed to by DEQ and implemented by the Company. In the opinion of the General Partner, the completion of the remediation program being proposed by the Partnership will not have a future material adverse impact on the Partnership. On May 11, 1999, the Downstream Segment filed an application with the FERC requesting permission to charge market-based rates for substantially all refined products transportation tariffs. Along with its application for market-based rates, the Downstream Segment filed a petition for waiver pending the FERC's determination on its application for market-based rates of the requirements that would otherwise have been imposed by the FERC's regulations requiring the Downstream Segment to reduce its rates in conformity with the PPI Index. On June 30, 1999, the FERC granted the waiver stating that the Downstream Segment would be required to make refunds, with interest, of all amounts collected under rates in excess of the PPI Index ceiling level after July 1, 1999, if the Downstream Segment's application for market-based rates was ultimately denied. On July 31, 2000, the FERC issued an order granting the Downstream Segment market-based rates in certain markets and set for hearing the Downstream Segment's application for market-based rates in the Little Rock, Arkansas; Shreveport-Arcadia, Louisiana; Cincinnati-Dayton, Ohio; and Memphis, Tennessee, destination markets and the Shreveport, Louisiana, origin market. After the matter was set for hearing, the Downstream Segment and the protesting shippers entered into a settlement agreement resolving their respective differences. On April 25, 2001, the FERC issued an order approving the offer of settlement. As a result of the settlement, the Downstream Segment recognized approximately $1.7 million of previously deferred transportation revenue in the second quarter of 2001. Also, the Downstream Segment withdrew the application for market-based rates to the Little Rock, Arkansas, destination market and the Arcadia, Louisiana, destination in the Shreveport-Arcadia, Louisiana, destination market. The Partnership has made appropriate refunds of approximately $1.0 million in the third quarter of 2001. In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS 141 requires that the purchase method of accounting be used for all business combinations and specifies that certain acquired intangible assets be reported apart from goodwill. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. The Partnership will adopt SFAS 141 immediately, and SFAS 142 effective January 1, 2002. At September 30, 2001, the Partnership had $24.8 million of unamortized goodwill. Amortization expense related to goodwill was $0.1 million and $0.8 million for the year ended December 31, 2000 and the nine months ended September 30, 2001, respectively. The Partnership has not determined the impact of adopting SFAS 142 at the date of this report, including whether any transitional impairment losses will be required to be recognized as the cumulative effect of a change in accounting principle. The matters discussed herein include "forward-looking statements" within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this document that address activities, events or developments that the Partnership expects or anticipates will or may occur in the future, including such things as estimated future capital 29 OTHER MATTERS - (CONTINUED) expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of the Partnership's business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by the Partnership in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. However, whether actual results and developments will conform with the Partnership's expectations and predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by the Partnership, competitive actions by other pipeline companies, changes in laws or regulations, and other factors, many of which are beyond the control of the Partnership. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and there can be no assurance that actual results or developments anticipated by the Partnership will be realized or, even if substantially realized, that they will have the expected consequences to or effect on the Partnership or its business or operations. For additional discussion of such risks and uncertainties, see TEPPCO Partners, L.P.'s 2000 Annual Report on Form 10-K and other filings made by the Partnership with the Securities and Exchange Commission. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Partnership may be exposed to market risk through changes in commodity prices and interest rates as discussed below. The Partnership has no foreign exchange risks. Risk management policies have been established by the Risk Management Committee to monitor and control these market risks. The Risk Management Committee is comprised of senior executives of the Company. At September 30, 2001, the Downstream Segment had outstanding $180 million principal amount of 6.45% Senior Notes due 2008, and $210 million principal amount of 7.51% Senior Notes due 2028 (collectively the "Senior Notes"). At September 30, 2001, the estimated fair value of the Senior Notes was approximately $377 million. From time to time, the Partnership has utilized and expects to continue to utilize derivative financial instruments with respect to a portion of its interest rate risks and its crude oil marketing activities to achieve a more predictable cash flow by reducing its exposure to interest rate and crude oil price fluctuations. These transactions generally are swaps and forwards and are entered into with major financial institutions or commodities trading institutions. Derivative financial instruments used in the Partnership's Upstream Segment are intended to reduce the Partnership's exposure to fluctuations in the market price of crude oil, while derivative financial instruments related to the Partnership's interest rate risks are intended to reduce the Partnership's exposure to increases in the benchmark interest rates underlying the Partnership's variable rate revolving credit facility. Through December 31, 2000, gains and losses from financial instruments used in the Partnership's Upstream Segment have been recognized in revenues for the periods to which the derivative financial instruments relate, and gains and losses from its interest rate financial instruments have been recognized in interest expense for the periods to which the derivative financial instrument relate. Adoption of SFAS 133 at January 1, 2001 resulted in the recognition of $10.1 million of derivative liabilities, $4.1 million of which are included in current liabilities and $6.0 million of which are included in other noncurrent liabilities on the Partnership's balance sheet, and $10.1 million of hedging losses included in accumulated other comprehensive loss, a component of Partners' capital, as the cumulative effect of the change in accounting principle. The hedging losses included in accumulated other comprehensive loss will be transferred to earnings as the forecasted transactions actually occur. Approximately $4.1 million of the loss included in accumulated other comprehensive loss as of January 1, 2001 is anticipated to be transferred into earnings over the next twelve months. The cumulative effect of the accounting change had no effect on the Partnership's net income or its earnings per Unit amounts for the nine months ended September 30, 2001. Amounts were determined as of 30 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS - (CONTINUED) January 1, 2001 based on quoted market values, the Partnership's portfolio of derivative instruments, and the Partnership's measurement of hedge effectiveness. As of September 30, 2001, the Upstream Segment had open positions on option contracts it had written for 100,000 barrels of crude oil and futures contracts for the sale of 50,000 barrels of crude oil. During the nine months ended September 30, 2001, a loss of $22,500 was recognized on such contracts. Also as of September 30, 2001, the Partnership had in place an interest rate swap agreement to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facilities. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership pays a fixed rate of interest of 6.955% and receives a floating rate based on a three month USD LIBOR rate. The interest rate swap is designated as a cash flow hedge, therefore, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. During the nine month period ended September 30, 2001, the Partnership recognized $4.0 million in losses, included in interest expense, on the interest rate swap attributable to interest costs occurring in 2001. No gain or loss from ineffectiveness was required to be recognized. The fair value of the interest rate swap agreement was a loss of approximately $22.1 million at September 30, 2001. Approximately $10.1 million (inclusive of the $4.1 million related to the cumulative effect of the accounting change not yet recognized) of such amount is anticipated to be transferred into earnings over the next twelve months. During 2001, the Partnership executed treasury rate lock agreements with a combined notional amount of $400 million to hedge its exposure to increases in the treasury rate that will be used to establish the fixed interest rate for the debt offering that is probable to occur in the fourth quarter of 2001. Under the treasury rate lock agreements, the Partnership pays a fixed rate of interest, and receives a floating rate based on the three month treasury rate. The treasury rate locks are designated as cash flow hedges, therefore, the changes in fair value, to the extent the treasury rate locks are effective, are recognized in other comprehensive income until the actual debt offering occurs. Upon completion of the debt offering, the realized gain or loss on the treasury rate locks will be amortized out of accumulated other comprehensive income into interest expense over the life of the debt obligation. During April 2001, a treasury lock with a notional amount of $200 million was terminated with a realized gain of $1.1 million. The realized gain was recorded as a component of accumulated other comprehensive income. As of September 30, 2001, a notional amount of $200 million remained outstanding. The fair value of the outstanding treasury rate locks was a loss of approximately $6.0 million at September 30, 2001. 31 PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits: Exhibit Number Description 3.1 Certificate of Limited Partnership of the Partnership (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 Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 3.3 Second Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated November 30, 1998 (Filed as Exhibit 3.3 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). 3.4 Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, effective July 21, 1998 (Filed as Exhibit 3.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1- 10403) dated July 21, 1998 and incorporated herein by reference). 3.5 Agreement of Limited Partnership of TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 3.5 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). 3.6 Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference). 3.7* Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001. 3.8* Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001. 3.9* Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001. 3.10* Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001. 4.1 Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). 4.2 Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership's Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference). 4.3 Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference). 32 EXHIBITS AND REPORTS ON FORM 8-K - (CONTINUED) 10.1+ Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference). 10.2+ Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992 and incorporated herein by reference). 10.3+ Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference). 10.4+ Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference). 10.5+ Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). 10.6+ Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). 10.7+ Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). 10.8+ Employment Agreement with William L. Thacker, Jr. (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1992 and incorporated herein by reference). 10.9+ Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference). 10.10+ Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference). 10.11 Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 10.12 Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 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). 10.13 Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 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). 10.14 Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 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). 33 EXHIBITS AND REPORTS ON FORM 8-K - (CONTINUED) 10.15+ Form of Employment Agreement between the Company and Ernest P. Hagan, Thomas R. Harper, David L. Langley, Charles H. Leonard and James C. Ruth, dated December 1, 1998 (Filed as Exhibit 10.20 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). 10.16 Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.17 Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.18 Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.19+ Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.20+ Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.21+ Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.22+ Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.23+ Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.24 Credit Agreement between TEPPCO Partners, L.P., SunTrust Bank, and Certain Lenders, dated July 14, 2000 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2000 and incorporated herein by reference). 10.25 Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipe Line Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference). 10.26+ Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference). 34 EXHIBITS AND REPORTS ON FORM 8-K - (CONTINUED) 10.27+ TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference). 10.28+ Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference). 10.29 Amended and Restated Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference). 10.30 Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference). 10.31* Purchase and Sale Agreement By and Among Green River Pipeline, LLC and McMurry Oil Company, Sellers, and TEPPCO Partners, L.P., Buyer, dated as of September 7, 2000. 10.32* Credit Agreement Among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of September 28, 2001 ($400,000,000 Term Facility). 10.33* Amendment 1, dated as of September 28, 2001, to the Amended and Restated Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility). 10.34* Amendment 1, dated as of September 28, 2001, to the Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility). 12.1* Statement of Computation of Ratio of Earnings to Fixed Charges. 22.1 Subsidiaries of the Partnership (Filed as Exhibit 22.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). ---------- * Filed herewith. + A management contract or compensation plan or arrangement. (b) Reports on Form 8-K filed during the quarter ended September 30, 2001: A report on Form 8-K was filed on July 27, 2001, pursuant to Item 5 and Item 7 of such form. 35 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrants have duly caused this report to be signed on its behalf by the undersigned duly authorized officer and principal financial officer. TEPPCO Partners, L.P. (Registrant) By: Texas Eastern Products Pipeline Company, LLC, as General Partner /s/ WILLIAM L. THACKER ---------------------- William L. Thacker Chief Executive Officer /s/ CHARLES H. LEONARD ---------------------- Charles H. Leonard Senior Vice President, Chief Financial Officer and Treasurer Date: November 8, 2001 36 INDEX TO EXHIBITS

EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 Certificate of Limited Partnership of the Partnership (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 Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 3.3 Second Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated November 30, 1998 (Filed as Exhibit 3.3 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). 3.4 Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, effective July 21, 1998 (Filed as Exhibit 3.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1- 10403) dated July 21, 1998 and incorporated herein by reference). 3.5 Agreement of Limited Partnership of TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 3.5 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). 3.6 Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference). 3.7* Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001. 3.8* Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001. 3.9* Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001. 3.10* Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001. 4.1 Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference). 4.2 Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership's Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference). 4.3 Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.1+ Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference). 10.2+ Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992 and incorporated herein by reference). 10.3+ Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference). 10.4+ Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference). 10.5+ Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). 10.6+ Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). 10.7+ Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to the Partnership's Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference). 10.8+ Employment Agreement with William L. Thacker, Jr. (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1992 and incorporated herein by reference). 10.9+ Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference). 10.10+ Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference). 10.11 Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference). 10.12 Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 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). 10.13 Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 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). 10.14 Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 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).

EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.15+ Form of Employment Agreement between the Company and Ernest P. Hagan, Thomas R. Harper, David L. Langley, Charles H. Leonard and James C. Ruth, dated December 1, 1998 (Filed as Exhibit 10.20 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). 10.16 Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.17 Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.18 Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.19+ Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference). 10.20+ Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.21+ Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.22+ Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.23+ Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference). 10.24 Credit Agreement between TEPPCO Partners, L.P., SunTrust Bank, and Certain Lenders, dated July 14, 2000 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2000 and incorporated herein by reference). 10.25 Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipe Line Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference). 10.26+ Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).

EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.27+ TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference). 10.28+ Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference). 10.29 Amended and Restated Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference). 10.30 Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference). 10.31* Purchase and Sale Agreement By and Among Green River Pipeline, LLC and McMurry Oil Company, Sellers, and TEPPCO Partners, L.P., Buyer, dated as of September 7, 2000. 10.32* Credit Agreement Among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of September 28, 2001 ($400,000,000 Term Facility). 10.33* Amendment 1, dated as of September 28, 2001, to the Amended and Restated Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility). 10.34* Amendment 1, dated as of September 28, 2001, to the Credit Agreement among TEPPCO Partners, L. P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility). 12.1* Statement of Computation of Ratio of Earnings to Fixed Charges. 22.1 Subsidiaries of the Partnership (Filed as Exhibit 22.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).

---------- * Filed herewith. + A management contract or compensation plan or arrangement.