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e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarter Ended September 30, 2002

Commission File No. 1-10403

TEPPCO Partners, L.P.

(Exact name of Registrant as specified in its charter)


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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Limited Partner Units outstanding as of October 31, 2002: 50,014,597

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF INCOME
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
		Forward-Looking Statements
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
PART II. OTHER INFORMATION
	Item 6. Exhibits and Reports on Form 8-K.
SIGNATURES
EXHIBIT INDEX
Computation of Ratio of Earnings to Fixed Charges

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION		Page

Item 1. Financial Statements
	Consolidated Balance Sheets as of September 30, 2002 (unaudited) and December 31, 2001		1
	Consolidated Statements of Income for the three months and nine months ended September 30, 2002 and 2001 (unaudited)		2
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2002 and 2001 (unaudited)		3
	Notes to the Consolidated Financial Statements (unaudited)		4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
	Forward-Looking Statements		44
Item 3. Quantitative and Qualitative Disclosures About Market Risk			44
Item 4. Controls and Procedures			46
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K			46

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)


					September 30,			December 31,
					2002			2001

					(Unaudited)
				ASSETS
Current assets:
	Cash and cash equivalents				$	32,137		$	25,479
	Accounts receivable, trade					293,044			221,541
	Accounts receivable, related party					6,023			4,310
	Inventories					21,693			17,243
	Other					25,245			14,907

		Total current assets				378,142			283,480

Property, plant and equipment, at cost (Net of accumulated depreciation and amortization of $324,627 and $290,248)						1,593,435			1,180,461
Equity investments						285,623			292,224
Intangible assets						450,448			251,487
Goodwill						16,944			16,669
Other assets						88,751			41,027

		Total assets			$	2,813,343		$	2,065,348

				LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
	Notes payable				$	72,000		$	360,000
	Accounts payable and accrued liabilities					276,742			228,075
	Accounts payable, related parties					5,511			22,680
	Accrued interest					13,387			15,649
	Other accrued taxes					11,871			8,888
	Other					50,016			33,550

		Total current liabilities				429,527			668,842

Senior Notes						949,456			375,184
Other long-term debt						500,000			340,658
Other liabilities and deferred credits						31,634			31,853
Redeemable Class B Units held by related party						103,883			105,630
Commitments and contingencies
Partners’ capital:
	Accumulated other comprehensive loss					(22,192	)		(20,324	)
	General partner’s interest					13,187			13,190
	Limited partners’ interests					807,848			550,315

			Total partners’ capital			798,843			543,181

		Total liabilities and partners’ capital			$	2,813,343		$	2,065,348

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except per Unit amounts)


			Three Months Ended						Nine Months Ended
			September 30,						September 30,

			2002			2001			2002			2001

Operating revenues:
	Sales of crude oil and petroleum products		$	766,502		$	915,296		$	2,111,817		$	2,601,580
	Transportation — Refined products			35,271			32,161			92,218			109,748
	Transportation — LPGs			12,515			15,669			46,688			54,174
	Transportation — Crude oil			6,809			6,862			20,032			18,929
	Transportation — NGLs			11,157			5,305			28,007			15,555
	Gathering — Natural gas			33,031			—			54,005			—
	Mont Belvieu operations			3,726			3,977			11,121			9,871
	Other			11,793			11,546			36,382			39,876

		Total operating revenues		880,804			990,816			2,400,270			2,849,733

Costs and expenses:
	Purchases of crude oil and petroleum products			753,577			902,126			2,074,719			2,566,621
	Operating, general and administrative			41,567			38,181			108,095			96,086
	Operating fuel and power			9,599			9,125			25,431			27,946
	Depreciation and amortization			24,551			10,411			58,191			31,175
	Taxes — other than income taxes			4,875			3,852			12,854			11,409

		Total costs and expenses		834,169			963,695			2,279,290			2,733,237

		Operating income		46,635			27,121			120,980			116,496
Interest expense				(19,763	)		(15,679	)		(53,379	)		(47,365	)
Interest capitalized				1,338			1,105			4,476			2,040
Equity earnings				3,147			5,645			9,133			15,270
Other income — net				736			997			2,068			2,224

		Income before minority interest		32,093			19,189			83,278			88,665
Minority interest				—			(97	)		—			(800	)

		Net income	$	32,093		$	19,092		$	83,278		$	87,865

Net Income Allocation:
Limited Partner Unitholders			$	22,139		$	12,113		$	57,200		$	62,035
Class B Unitholder				1,873			1,357			5,107			7,027
General Partner				8,081			5,622			20,971			18,803

		Total net income allocated	$	32,093		$	19,092		$	83,278		$	87,865

Basic net income per Limited Partner and Class B Unit			$	0.48		$	0.35		$	1.33		$	1.79

Diluted net income per Limited Partner and Class B Unit			$	0.48		$	0.35		$	1.32		$	1.79

Weighted average Limited Partner and Class B Units outstanding				50,007			38,867			46,991			38,544

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)


					Nine Months Ended
					September 30,

					2002			2001

Cash flows from operating activities:
	Net income				$	83,278		$	87,865
	Adjustments to reconcile net income to cash provided by operating activities:
			Depreciation and amortization			58,191			31,175
			Earnings in equity investments, net of distributions			14,322			6,090
			Non-cash portion of interest expense			4,018			2,175
			(Increase) decrease in accounts receivable			(71,503	)		9,292
			Increase in inventories			(4,450	)		(1,972	)
			Increase in other current assets			(10,337	)		(3,524	)
			Increase (decrease) in accounts payable and accrued expenses			45,046			(16,231	)
			Other			22,021			(1,412	)

				Net cash provided by operating activities		140,586			113,458

Cash flows from investing activities:
		Proceeds from cash investments				—			3,236
		Purchase of crude oil assets				—			(20,000	)
		Proceeds from the sale of assets				3,380			1,300
		Purchase of Val Verde Gathering System				(444,150	)		—
		Purchase of Chaparral NGL system				(132,372	)		—
		Purchase of Jonah Gas Gathering Company				(7,319	)		(359,834	)
		Investments in Centennial Pipeline LLC				(7,721	)		(34,335	)
		Capital expenditures				(98,363	)		(61,966	)

				Net cash used in investing activities		(686,545	)		(471,599	)

Cash flows from financing activities:
		Proceeds from term and revolving credit facilities				662,000			427,000
		Repayments on term and revolving credit facilities				(790,659	)		(41,000	)
		Issuance of Senior Notes				497,805			—
		Debt issuance costs				(7,025	)		(2,601	)
		Proceeds from termination of interest rate swaps				17,984			—
		Issuance of Limited Partner Units, net				275,264			54,588
		General Partner’s contributions				5,627			1,114
		Distributions				(108,379	)		(75,025	)

				Net cash provided by financing activities		552,617			364,076

Net increase in cash and cash equivalents						6,658			5,935
Cash and cash equivalents at beginning of period						25,479			27,096

Cash and cash equivalents at end of period					$	32,137		$	33,031

Supplemental disclosure of cash flows:
		Interest paid during the period (net of capitalized interest)			$	30,475		$	52,022

See accompanying Notes to Consolidated Financial Statements.

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, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner. The General Partner is a wholly-owned subsidiary of Duke Energy Field Services (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy holds an approximate 70% interest in DEFS, and ConocoPhillips holds the remaining 30%. The Company, as general partner, performs all management and operating functions required for us, except for the management and operations of certain of the TEPPCO Midstream assets. We have entered into agreements with DEFS in which DEFS manages certain of the TEPPCO Midstream assets on our behalf. We reimburse the General Partner for all reasonable direct and indirect expenses incurred in managing us.

On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly-owned by us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our general partner 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 us and the Operating Partnerships. As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.

As used in this Report, “we,” “us,” “our,” and the “Partnership” means TEPPCO Partners, L.P. and, where the context requires, includes our subsidiary operating partnerships.

The accompanying unaudited consolidated financial statements reflect all adjustments that are, in the opinion of the management of the Company, of a normal and recurring nature and necessary for a fair statement of our financial position as of September 30, 2002, and the results of our operations and cash flows for the periods presented. The results of operations for the three months and nine months ended September 30, 2002, are not necessarily indicative of results of our operations for the full year 2002. You should read the interim financial statements in conjunction with our consolidated financial statements and notes thereto presented in the TEPPCO Partners, L.P. Annual Report on Form 10-K, as amended, for the year ended December 31, 2001. We have reclassified certain amounts from prior periods to conform with the current presentation.

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

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

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

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 and Class B Units outstanding (a total of 50.0 million and 38.9 million Units for the three months ended September 30, 2002, and 2001, respectively, and 47.0 million and 38.5 million Units for the nine months ended September 30, 2002, and 2001, respectively). 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 10. Quarterly Distributions of Available Cash). The general partner was allocated $8.1 million (representing 25.18%) and $5.6 million (representing 29.45%) of net income for the three months ended September 30, 2002, and 2001, respectively, and $21.0 million (representing 25.18%) and $18.8 million (representing 21.40%) of net income for the nine months ended September 30, 2002, and 2001, respectively. The General Partner’s percentage interest in our net income increased for the nine months ended September 30, 2002, compared to the corresponding period in 2001, as a result of higher annualized distributions paid per Unit during 2002.

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 three months ended September 30, 2002, and 2001, the denominator was increased by 20,645 Units and 45,110 Units, respectively. For the nine months ended September 30, 2002, and 2001, the denominator was increased by 34,931 Units and 33,277 Units, respectively.

NOTE 2. NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. We are required to adopt SFAS 143 effective January 1, 2003. We are currently evaluating the impact of adopting SFAS 143.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. We adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on our financial position, results of operations or cash flows.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows.

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows.

In June 2002, the EITF reached a consensus on certain issues contained in Topic 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. We do not believe that this consensus, as currently interpreted by the EITF, applies to us, as we engage in the marketing of crude oil owned by us and third parties, rather than energy trading as contemplated by EITF No. 98-10. We do not engage in material energy trading activities. While certain accounting bodies have requested clarification from the EITF, the EITF has not expanded its definition of energy trading activities to include the marketing activities in which we engage. However, if the EITF does expand its definition of energy trading activities to include our marketing activities, we may be required to present sales of crude oil and petroleum products in the statement of income on a net margin basis. Any such change would significantly decrease our reported sales and purchases of crude oil and petroleum products, but would have no effect on our operating income or cash flow.

NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS

In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. 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.

Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment in Seaway Crude Pipeline Company (see Note 7. Equity Investments). Upon adoption of SFAS 142 effective January 1, 2002, we had not yet begun to amortize our excess investment in Centennial Pipeline LLC; therefore, no amortization expense has been recorded in any of the periods presented below related to this excess investment. The following table presents our results on a comparable basis, as if we had not recorded amortization expense of goodwill or amortization expense of our excess investment in Seaway Crude Pipeline Company for the three months and nine months ended September 30, 2001 (in thousands, except per Unit amounts):


			Three Months Ended				Nine Months Ended
			September 30,				September 30,

			2002		2001		2002		2001

Net income:
	Reported net income		$	32,093	$	19,092	$	83,278	$	87,865
	Amortization of goodwill and excess investment			—		566		—		1,829

		Adjusted net income	$	32,093	$	19,658	$	83,278	$	89,694

Net Income Allocation:
	Limited Partner Unitholders		$	22,139	$	12,472	$	57,200	$	63,327
	Class B Unitholder			1,873		1,397		5,107		7,173
	General Partner			8,081		5,789		20,971		19,194

		Total net income allocated	$	32,093	$	19,658	$	83,278	$	89,694

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


				Three Months Ended				Nine Months Ended
				September 30,				September 30,

				2002		2001		2002		2001

Basic net income per Limited
	Partner and Class B Unit:
		As reported		$	0.48	$	0.35	$	1.33	$	1.79
		Amortization of goodwill and excess investment			—		0.01		—		0.04

			Adjusted net income per Unit	$	0.48	$	0.36	$	1.33	$	1.83

Diluted net income per Limited
	Partner and Class B Unit:
		As reported		$	0.48	$	0.35	$	1.32	$	1.79
		Amortization of goodwill and excess investment			—		0.01		—		0.04

			Adjusted net income per Unit	$	0.48	$	0.36	$	1.32	$	1.83

Upon the adoption of SFAS 142, we were required to reassess the useful lives and residual values of all intangible assets acquired, and make necessary amortization period adjustments by the end of the first interim period after adoption. We completed this analysis during the first quarter of 2002, resulting in no change to the amortization period for our intangible assets. We will continue to reassess the useful lives and residual values of all intangible assets on an annual basis.

In connection with the transitional goodwill impairment evaluation required by SFAS 142, we were required to perform an assessment of whether there was an indication that goodwill was impaired as of the date of adoption. We accomplished this by identifying our reporting units and determining the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of adoption. We then determined the fair value of each reporting unit and compared it to the carrying value of the reporting unit. We completed this analysis during the second quarter of 2002, resulting in no transitional impairment loss. We will continue to compare the fair value of each reporting unit to the carrying value on an annual basis to determine if an impairment loss has occurred.

At September 30, 2002, we had $16.9 million of unamortized goodwill and $58.4 million of excess investment in our equity investments (equity method goodwill). We completed an impairment analysis of the excess investment in our equity investments during the nine months ended September 30, 2002, and we noted no indication of impairment. The excess investment is included in our equity investments account at September 30, 2002. The following table presents the carrying amount of goodwill and excess investments at September 30, 2002, by business segment (in thousands):


	Downstream		Midstream		Upstream		Segments
	Segment		Segment		Segment		Total

Goodwill	$	—	$	2,777	$	14,167	$	16,944
Equity method goodwill	$	32,935	$	—	$	25,502	$	58,437

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

The following table reflects the components of amortized intangible assets, excluding goodwill (in thousands):


			September 30, 2002					December 31, 2001

			Gross Carrying		Accumulated			Gross Carrying		Accumulated
			Amount		Amortization			Amount		Amortization

Amortized intangible assets:
	Fractionation agreement		$	38,000	$	(8,550	)	$	38,000	$	(7,125	)
	Natural gas transportation contracts			441,126		(21,019	)		222,800		(3,275	)
	Other			1,451		(560	)		1,458		(371	)

		Total	$	480,577	$	(30,129	)	$	262,258	$	(10,771	)

Excluding goodwill, amortization expense on intangible assets was $10.1 million and $0.5 million for the three months ended September 30, 2002 and 2001, respectively, and $19.4 million and $1.6 million for the nine months ended September 30, 2002 and 2001, respectively.

The following table sets forth the estimated amortization expense on intangible assets for the years ending December 31 (in thousands):


2002	$	29,463
2003		47,969
2004		49,525
2005		50,109
2006		44,894

NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS

We account for derivative financial instruments in accordance with 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 on the balance sheet at fair value as either 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.

We have utilized and expect to continue to utilize interest rate swap agreements to hedge a portion of our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floating interest rate mix of our total debt portfolio and overall cost of borrowing. The interest rate swap related to our cash flow risk is intended to reduce our exposure to increases in the benchmark interest rates underlying our variable rate revolving credit facility. The interest rate swaps related to our fair value risks are intended to reduce our exposure to changes in the fair value of our fixed rate Senior Notes. The interest rate swap agreements involve the periodic exchange of

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

payments without the exchange of the notional amount upon which the payments are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest.

By using interest rate swap agreements to hedge exposures to changes in interest rates and the fair value of fixed rate Senior Notes, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk for us. When the fair value of a derivative contract is negative, we owe the counterparty and, therefore, we do not possess credit risk. We minimize the credit risk in derivative instruments by entering into transactions with major financial institutions. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We manage market risk associated with interest rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that may be undertaken.

We have entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. The term of the interest rate swap matches the maturity of the credit facility. We designated this swap agreement, which hedges exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250.0 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, 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 months ended September 30, 2002, and 2001, we recognized $9.6 million and $4.0 million, respectively, in losses, included in interest expense, on the interest rate swap. During the quarter ended September 30, 2002, we measured the hedge effectiveness of this interest rate swap and noted that 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 $22.2 million and $20.3 million at September 30, 2002, and December 31, 2001, respectively. We anticipate that approximately $13.1 million of the fair value will be transferred into earnings over the next twelve months.

On October 4, 2001, our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the nine months ended September 30, 2002, we recognized a gain of $5.4 million, recorded as a reduction of interest expense, on the interest rate swap. During the quarter ended September 30, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap agreement was a gain of approximately $5.2 million at September 30, 2002, and a loss of approximately $14.6 million at December 31, 2001.

On February 20, 2002, we entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $25.8 million. From inception of the swap agreements on February 20, 2002, through the termination on July 16, 2002, $7.8 million had been recognized as a reduction to interest expense. The remaining gain of approximately $18.0 million has been deferred as an adjustment to the carrying value of the Senior Notes and is being amortized as a reduction to future interest expense over the remaining term of the original contract life of the terminated swap

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

agreements. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment.

Additionally, on July 16, 2002, we entered into new interest rate swap agreements to hedge our exposure to changes in the fair value of our $500.0 million principal amount of 7.625% fixed rate Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements have a combined notional amount of $500.0 million and mature in 2012 to match the principal and maturity of the Senior Notes. Under these swap agreements, we pay a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, which increased by approximately 50 basis points from the previous swap agreements, and receive a fixed rate of interest of 7.625%. During the quarter ended September 30, 2002, we recognized a gain of $4.0 million, recorded as a reduction of interest expense, on these interest rate swaps. During the quarter ended September 30, 2002, we measured the hedge effectiveness of these interest rate swaps and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of these interest rate swap agreements was a gain of approximately $39.0 million at September 30, 2002.

NOTE 5. ACQUISITIONS

On September 30, 2001, our subsidiaries completed the purchase of Jonah Gas Gathering Company (“Jonah”) from Alberta Energy Company for $359.8 million. The acquisition served as our entry into the natural gas gathering industry. We recognized goodwill on the purchase of approximately $2.8 million. We accounted for the acquisition under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from September 30, 2001. We paid an additional $7.3 million on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. Under a contractual arrangement, DEFS operates and manages Jonah on our behalf.

The following table allocates the estimated fair value of the Jonah assets acquired on September 30, 2001, and includes the additional purchase adjustment paid in February 2002 (in thousands):


Property, plant and equipment		$	141,835
Intangible assets (primarily gas transportation contracts)			222,800
Goodwill			2,777

	Total assets		367,412

Total liabilities assumed			(489	)

	Net assets acquired	$	366,923

The value assigned to intangible assets relates to contracts with customers that are either for a fixed term or which dedicate total future lease production. We are amortizing the value assigned to intangible assets over the expected lives of the contracts (approximately 16 years) in proportion to the timing of expected contractual volumes.

On March 1, 2002, we completed the purchase of the Chaparral NGL system (“Chaparral”) for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition costs of approximately $0.4 million. We funded the purchase by a drawdown of our $500.0 million revolving credit facility (see Note 8. Debt). Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu, Texas. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. Under a contractual arrangement, DEFS operates and manages these assets on our behalf. We accounted for the acquisition of the assets under the purchase method of accounting. We allocated the purchase price to property, plant and equipment.

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

On June 30, 2002, we completed the purchase of the Val Verde Gathering System (“Val Verde”) for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition costs of approximately $1.2 million. We funded the purchase by drawing down $168.0 million under our $500.0 million revolving credit facility, $72.0 million under our 364-day revolving credit facility, and $200.0 million under a six-month term loan with SunTrust Bank (see Note 8. Debt). The remaining purchase price was funded through working capital sources of cash. The Val Verde system gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico. The system is one of the largest coal seam gas gathering and treating facilities in the United States. Under a contractual arrangement, DEFS operates and manages Val Verde on our behalf. We accounted for the acquisition of the assets under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from June 30, 2002.

The following table allocates the estimated fair value of the Val Verde assets acquired on June 30, 2002 (in thousands):


Property, plant and equipment		$	226,469
Intangible assets (primarily gas transportation contracts)			218,326

	Total assets		444,795

Total liabilities assumed			(645	)

	Net assets acquired	$	444,150

The purchase price allocation for the Val Verde acquisition is based on our best estimate using information currently available. We are in the process of completing the final purchase price allocation for the Val Verde acquisition. Consequently, the final purchase price allocation may be different from the purchase price allocation shown above. However, we do not currently anticipate that the difference will be material to our financial position, results of operations or cash flows.

The value assigned to intangible assets relates to fixed-term contracts with customers. We are amortizing the value assigned to intangible assets over the lives of the contracts (averaging approximately 20 years) in proportion to the expected contractual volumes.

The following table presents our unaudited pro forma results as though the acquisitions of Jonah and Val Verde occurred at the beginning of 2001 or 2002 (in thousands, except per Unit amounts). The unaudited pro forma results give effect to certain pro forma adjustments including depreciation and amortization expense adjustments of property, plant and equipment and intangible assets based upon the purchase price allocations, interest expense related to financing the acquisitions, amortization of debt issue costs and the removal of income tax effects in historical results of operations. The pro forma results do not include operating efficiencies or revenue growth from historical results.

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,

	2002		2001		2002		2001

Revenues	$	880,804	$	1,017,914	$	2,438,055	$	2,934,586
Operating income		46,635		34,257		132,397		140,964
Net income		36,043		20,898		93,295		96,319
Basic and diluted net income per Limited Partner and Class B Unit	$	0.50	$	0.32	$	1.31	$	1.64

The summarized pro forma information has been prepared for comparative purposes only. It is not intended to be indicative of the actual operating results that would have occurred had the acquisitions been consummated at the beginning of 2001 or 2002, or the results which may be attained in the future.

NOTE 6. 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,
		2002		2001

Crude oil		$	6,897	$	3,783
Gasolines			855		3,670
Propane			—		1,096
Butanes			4,253		1,431
Other products			5,137		3,744
Materials and supplies			4,551		3,519

	Total	$	21,693	$	17,243

The costs of inventories did not exceed market values at September 30, 2002, and December 31, 2001.

NOTE 7. EQUITY INVESTMENTS

The acquisition of the ARCO Pipe Line Company (“ARCO”) assets in July 2000 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. Seaway is a partnership between TEPPCO Seaway, L.P. (“TEPPCO Seaway”), a subsidiary of TCTM, and ConocoPhillips. TCTM purchased the 50-percent ownership interest in Seaway on July 20, 2000, and transferred the investment to TEPPCO Seaway. 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, TEPPCO Seaway received 80% of revenue and expense of Seaway. From June 2002 through May 2006, TEPPCO Seaway receives 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and expense to TEPPCO Seaway. For the year ended December 31, 2002, our portion of equity earnings on a pro-rated basis will average approximately 67%.

In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial Pipeline LLC (“Centennial”). Centennial owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant owns a one-third interest in Centennial. CMS Energy Corporation has announced that it is exploring the sale of certain of its assets, including its investment

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

in Centennial. Through December 31, 2001, we contributed approximately $70.0 million for our investment in Centennial. During the nine months ended September 30, 2002, we contributed approximately $7.7 million for our investment in Centennial. These amounts are included in the equity investment balance at September 30, 2002.

We use the equity method of accounting to report our investments in Seaway and Centennial. Summarized combined income statement data for Seaway and Centennial for the nine months ended September 30, 2002, and 2001, is presented below (in thousands):


	Nine Months Ended
	September 30,

	2002		2001

Revenues	$	60,960	$	55,719
Net income		6,848		26,218

Summarized combined balance sheet data for Seaway and Centennial as of September 30, 2002, and December 31, 2001, is presented below (in thousands):


	September 30,		December 31,
	2002		2001

Current assets	$	35,016	$	57,368
Noncurrent assets		546,163		528,835
Current liabilities		22,194		31,308
Long-term debt		140,000		128,000
Noncurrent liabilities		14,730		—
Partners’ capital		404,255		426,895

Our investment in Seaway at September 30, 2002, and December 31, 2001, includes an excess net investment amount of $25.5 million. At September 30, 2002, our investment in Centennial includes an excess net investment amount of $32.9 million. Excess investment is the amount by which our investment balance exceeds our proportionate share of the net assets of the investment. Prior to January 1, 2002, and the adoption of SFAS 142, we were amortizing the excess investment in Seaway using the straight-line method over 20 years.

NOTE 8. DEBT

Senior Notes

On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). The 6.45% TE Products Senior Notes were issued at a discount and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at a premium.

The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank on a parity with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of September 30, 2002, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we received $494.6 million in net proceeds from the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% 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 our ability to incur additional indebtedness. As of September 30, 2002, we were in compliance with the covenants of these Senior Notes.

We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above. See Note 4. Derivative Financial Instruments.

Other Long Term Debt and Credit Facilities

On April 6, 2001, we entered into an Amended and Restated Credit Agreement (“Three Year Facility”) which provides for revolving borrowings of up to $500.0 million for a period of three years including the issuance of letters of credit of up to $20.0 million. The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contains restrictive financial covenants that require us 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. On February 20, 2002, we repaid $115.7 million of the then outstanding balance of the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes. On March 1, 2002, we borrowed $132.0 million under the Three Year Facility to finance the acquisition of Chaparral. On March 22, 2002, we repaid a portion of the Three Year Facility with proceeds we received from the issuance of additional Limited Partner Units (see Note 9. Partners’ Capital). To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Three Year Facility was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. We then drew down the existing capacity of the Three Year Facility. At September 30, 2002, $500.0 million was outstanding under the Three Year Facility at a weighted average interest rate of 2.9%. As of September 30, 2002, we were in compliance with the covenants contained in this credit agreement.

We have entered into an interest rate swap agreement to hedge our exposure to increases in interest rates on the Three Year Facility discussed above. See Note 4. Derivative Financial Instruments.

Short Term Credit Facilities

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

assets, on June 27, 2002, the Short-term Revolver was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. We then drew down $72.0 million under the Short-term Revolver. At September 30, 2002, $72.0 million was outstanding under the Short-term Revolver at an interest rate of 2.9%. As of September 30, 2002, we were in compliance with the covenants contained in this credit agreement.

On September 28, 2001, we entered into a $400.0 million credit facility with SunTrust Bank (“Bridge Facility”) payable in June 2002. We borrowed $360.0 million under the Bridge Facility to acquire the Jonah assets (see Note 5. Acquisitions). During the fourth quarter of 2001, we repaid $160.0 million of the outstanding principal from proceeds received from the issuance of Limited Partner Units in November 2001. On February 5, 2002, we drew down an additional $15.0 million under the Bridge Facility. On February 20, 2002, we repaid the outstanding balance of the Bridge Facility of $215.0 million, with proceeds from the issuance of the 7.625% Senior Notes and canceled the facility.

On June 27, 2002, we entered into a $200.0 million six-month term loan with SunTrust Bank (“Six-Month Term Loan”) payable in December 2002. We borrowed $200.0 million under the Six-Month Term Loan to acquire the Val Verde assets (see Note 5. Acquisitions). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained restrictive financial covenants that required us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal primarily from proceeds received from the issuance of Limited Partner Units in July 2002. On September 10, 2002, we repaid the remaining outstanding balance of $110.0 million with proceeds received from the issuance of Limited Partner Units in September 2002 (see Note 9. Partners’ Capital), and canceled the facility.

The following table summarizes the principal amounts outstanding under our credit facilities as of September 30, 2002, and December 31, 2001 (in thousands):


				September 30,		December 31,
				2002		2001

Short Term Credit Facilities:
		Short-term Revolver, due March 2003		$	72,000	$	160,000
		Bridge Facility, due June 2002			—		200,000

			Total Short Term Credit Facilities	$	72,000	$	360,000

Long Term Credit Facilities:
		Three Year Facility, due April 2004		$	500,000	$	340,658
		6.45% TE Products Senior Notes, due January 2008			179,837		179,814
		7.51% TE Products Senior Notes, due January 2028			210,000		210,000
		7.625% Senior Notes, due February 2012			497,940		—

			Total borrowings		1,387,777		730,472
	Adjustment to carrying value associated with hedges of fair value swaps				61,679		(14,630	)

			Total Long Term Credit Facilities	$	1,449,456	$	715,842

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

NOTE 9. PARTNERS’ CAPITAL

On March 22, 2002, we sold in an underwritten public offering 1.92 million Limited Partner Units at $31.18 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $57.3 million and were used to repay $50.0 million of the outstanding balance on the Three Year Facility, with the remaining amount being used for general purposes.

On July 11, 2002, we sold in an underwritten public offering 3.0 million Limited Partner Units at $30.15 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $86.6 million and were used to reduce borrowings under our Six-Month Term Loan. On August 14, 2002, 175,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on July 11, 2002. Proceeds from that sale totaled $5.1 million and were used for general purposes.

On September 6, 2002, we sold in an underwritten public offering 3.8 million Limited Partner Units at $29.72 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $108.1 million and were used to reduce borrowings under our Six-Month Term Loan. On September 19, 2002, 570,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on September 6, 2002. Proceeds from that sale totaled $16.2 million and were used to repay a portion of the Short-term Revolver.

NOTE 10. QUARTERLY DISTRIBUTONS OF AVAILABLE CASH

We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. According to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds as follows:


					General
		Unitholders			Partner

Quarterly Cash Distribution per Unit:
	Up to Minimum Quarterly Distribution ($0.275 per Unit)		98	%		2	%
	First Target — $0.276 per Unit up to $0.325 per Unit		85	%		15	%
	Second Target — $0.326 per Unit up to $0.45 per Unit		75	%		25	%
	Over Second Target — Cash distributions greater than $0.45 per Unit		50	%		50	%

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

The following table reflects the allocation of total distributions paid during the nine months ended September 30, 2002, and 2001 (in thousands, except per Unit amounts).


		Nine Months Ended
		September 30,

		2002		2001

Limited Partner Units		$	74,924	$	53,865
General Partner Ownership Interest			1,669		817
General Partner Incentive			24,933		13,674

	Total Partners’ Capital Cash Distributions		101,526		68,356
Class B Units			6,854		6,169
Minority Interest			—		500

	Total Cash Distributions Paid	$	108,380	$	75,025

Total Cash Distributions Paid Per Unit		$	1.750	$	1.575

On November 8, 2002, we will pay a cash distribution of $0.60 per Limited Partner Unit and Class B Unit for the quarter ended September 30, 2002. The third quarter 2002 cash distribution will total approximately $43.5 million.

NOTE 11. SEGMENT DATA

We have three reporting segments: transportation and storage of refined products, LPGs and petrochemicals, which operates as the Downstream Segment; gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals, which operates as the Upstream Segment; and gathering of natural gas, fractionation of NGLs and transportation of NGLs, which operates as the Midstream Segment. The amounts indicated below as “Partnership and Other” relate primarily to intercompany eliminations and assets that we hold that have not been allocated to any of our reporting segments.

Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which were previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation.

Our Downstream Segment includes the interstate transportation, storage and terminaling of petroleum products and LPGs and intrastate transportation of petrochemicals. Revenues are derived from transportation and storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Our Downstream Segment’s pipeline system extends from southeast Texas through the central and midwestern United States to the northeastern United States, and is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. Our Downstream Segment also includes our equity investment in Centennial.

Our Upstream Segment includes the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Our Upstream Segment also includes the equity earnings from our investment in Seaway. Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, Oklahoma, a central crude oil distribution point for the Central United States.

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Our Midstream Segment includes the fractionation of NGLs in Colorado; the ownership and operation of two trunkline NGL pipelines in South Texas and two NGL pipelines in East Texas; and the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, which was acquired by our subsidiaries on September 30, 2001. This segment also includes Chaparral, which we acquired on March 1, 2002. Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. On June 30, 2002, we acquired the Val Verde system, which gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico and is one of the largest coal seam gas gathering and treating facilities in the United States. The results of operations of the Jonah, Chaparral, and Val Verde acquisitions are included in periods subsequent to September 30, 2001, March 1, 2002, and June 30, 2002, respectively (See Note 5. Acquisitions).

The tables below include financial information by reporting segment for the three months and nine months ended September 30, 2002, and 2001 (in thousands):


		Three Months Ended September 30, 2002

		Downstream			Midstream		Upstream		Segments		Partnership
		Segment			Segment		Segment		Total		and Other			Consolidated

Revenues		$	58,754		$	46,210	$	776,036	$	881,000	$	(196	)	$	880,804
Operating expenses, including power			31,530			12,273		766,011		809,814		(196	)		809,618
Depreciation and amortization expense			7,496			14,938		2,117		24,551		—			24,551

	Operating income		19,728			18,999		7,908		46,635		—			46,635
Equity earnings (losses)			(2,019	)		—		5,166		3,147		—			3,147
Other income, net			77			40		985		1,102		(366	)		736

	Earnings before interest	$	17,786		$	19,039	$	14,059	$	50,884	$	(366	)	$	50,518


		Three Months Ended September 30, 2001

		Downstream			Midstream		Upstream		Segments		Partnership
		Segment			Segment		Segment		Total		and Other		Consolidated

Revenues		$	58,527		$	7,033	$	925,256	$	990,816	$	—	$	990,816
Operating expenses, including power			29,784			2,034		921,466		953,284		—		953,284
Depreciation and amortization expense			6,675			1,401		2,335		10,411		—		10,411

	Operating income		22,068			3,598		1,455		27,121		—		27,121
Equity earnings (losses)			(297	)		—		5,942		5,645		—		5,645
Other income, net			434			15		548		997		—		997

	Earnings before interest	$	22,205		$	3,613	$	7,945	$	33,763	$	—	$	33,763

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


		Nine Months Ended September 30, 2002

		Downstream			Midstream		Upstream		Segments		Partnership
		Segment			Segment		Segment		Total		and Other			Consolidated

Revenues		$	172,996		$	88,946	$	2,139,703	$	2,401,645	$	(1,375	)	$	2,400,270
Operating expenses, including power			89,352			20,269		2,112,853		2,222,474		(1,375	)		2,221,099
Depreciation and amortization expense			21,692			30,229		6,270		58,191		—			58,191

	Operating income		61,952			38,448		20,580		120,980		—			120,980
Equity earnings (losses)			(5,005	)		—		14,138		9,133		—			9,133
Other income, net			271			221		1,942		2,434		(366	)		2,068

	Earnings before interest	$	57,218		$	38,669	$	36,660	$	132,547	$	(366	)	$	132,181


		Nine Months Ended September 30, 2001

		Downstream			Midstream		Upstream		Segments		Partnership and
		Segment			Segment		Segment		Total		Other		Consolidated

Revenues		$	199,374		$	20,999	$	2,629,360	$	2,849,733	$	—	$	2,849,733
Operating expenses, including power			87,661			4,445		2,609,956		2,702,062		—		2,702,062
Depreciation and amortization expense			20,051			4,203		6,921		31,175		—		31,175

	Operating income		91,662			12,351		12,483		116,496		—		116,496
Equity earnings (losses)			(636	)		—		15,906		15,270		—		15,270
Other income, net			1,115			6		1,103		2,224		—		2,224

	Earnings before interest	$	92,141		$	12,357	$	29,492	$	133,990	$	—	$	133,990

The following table provides the total assets for each segment as of September 30, 2002, and December 31, 2001 (in thousands):


	Downstream		Midstream		Upstream		Segments		Partnership and
	Segment		Segment		Segment		Total		Other			Consolidated

2002	$	874,574	$	1,159,630	$	866,007	$	2,900,211	$	(86,868	)	$	2,813,343
2001	$	844,036	$	541,195	$	694,934	$	2,080,165	$	(14,817	)	$	2,065,348

The following table reconciles the segments total earnings before interest to consolidated net income (in thousands):


		Three Months Ended						Nine Months Ended
		September 30,						September 30,

		2002			2001			2002			2001

Earnings before interest		$	50,518		$	33,763		$	132,181		$	133,990
Interest expense			(19,763	)		(15,679	)		(53,379	)		(47,365	)
Interest capitalized			1,338			1,105			4,476			2,040
Minority interest			—			(97	)		—			(800	)

	Net income	$	32,093		$	19,092		$	83,278		$	87,865

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

NOTE 12. 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. (including the Company and Partnership). In both cases, the 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 not covered by insurance. Discovery is ongoing, and the Company is defending itself vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suit. We cannot estimate the loss, if any, associated with these pending lawsuits.

On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, in Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiff’s property, leaked toxic products onto the plaintiff’s property. The plaintiffs further contend that this leak caused damages to the plaintiffs. We have filed an answer to the plaintiff’s petition denying the allegations. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. We are defending ourself vigorously against the lawsuit. We cannot estimate the damages, if any, associated with this pending lawsuit, however; this case is covered by insurance.

On April 19, 2002, we, through our subsidiary, TEPPCO Crude Oil, L.P., filed a declaratory judgment action in the U.S. District Court for the Western District of Oklahoma against D.R.D. Environmental Services, Inc. (“D.R.D.”), seeking resolution of billing and other contractual disputes regarding potential overcharges for environmental remediation services provided by D.R.D. On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount of $2,243,525, and for unspecified damages for alleged tortious interference with D.R.D.’s contractual relations with DEFS. We have denied the counterclaims. Discovery is ongoing, and trial has been initially scheduled for May 2003. If D.R.D. should be successful, a substantial portion of the $2,243,525 breach of contract claim will be covered under an indemnity from DEFS. We cannot predict the outcome of the litigation against us, however, we are defending ourselves vigorously against the counterclaim. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

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

In February 2002, a producer on the Jonah system notified Alberta Energy Company that it may have a right to acquire all or a portion of the assets comprising the Jonah system. The producer’s inquiry is based upon an alleged right of first refusal contained in a gas gathering agreement between the producer and Jonah. Subsidiaries of Alberta Energy Company have agreed to indemnify us against losses resulting from the breach of representations concerning the absence of third party rights in connection with the acquisition of the entity that owns the Jonah system. We believe that we have adequate legal defenses if the producer should assert a claim and we also believe that no right of first refusal on any of the underlying Jonah system assets has been triggered.

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of injunctions delaying or prohibiting certain activities, and the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you 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 our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.

In 1994, we entered into an Agreed Order with the Indiana Department of Environmental Management (“IDEM”) that resulted in the implementation of a remediation program for groundwater contamination attributable to our operations at the Seymour, Indiana, terminal. In 1999, the IDEM approved a Feasibility Study, which includes our proposed remediation program. We expect the IDEM to issue a Record of Decision formally approving the remediation program. After the Record of Decision is issued, we will enter into a subsequent Agreed Order for the continued operation and maintenance of the remediation program. We have an accrued liability of $0.2 million at September 30, 2002, for future remediation costs at the Seymour terminal. We do not expect that the completion of the remediation program will have a future material adverse effect on our financial position, results of operations or cash flows.

In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. At September 30, 2002, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows.

At September 30, 2002, we have an accrued liability of $5.6 million and a receivable of $4.2 million related to various TCTM sites requiring environmental remediation activities (included in our Upstream Segment). The receivable is based on a contractual indemnity obligation for specified environmental liabilities that DEFS owes to us in connection with our acquisition of the Upstream Segment from DEFS in November 1998. Under this indemnity obligation, we are responsible for the first $3.0 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. The majority of the indemnified costs relate to remediation activities at the Velma crude oil site in Stephens County, Oklahoma, attributable to operations prior to our acquisition of the Upstream Segment. We do not expect that the completion of remediation programs associated with TCTM activities will have a future material adverse effect on our financial position, results of operations or cash flows.

Centennial entered into credit facilities totaling $150.0 million, and as of September 30, 2002, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. Each of the participants in Centennial originally guaranteed one-third of Centennial’s debt, which included TE Products, who had guaranteed one-third of the debt up to a maximum amount of $50.0 million. During the third quarter of 2002, PEPL, one of the participants in Centennial, was downgraded by Moody’s and Standard & Poors to below investment grade, which resulted in PEPL being in default under its portion of the

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Centennial guaranty. Effective September 27, 2002, the two remaining participants, TE Products and Marathon, increased their guaranteed amounts to one-half of the debt of Centennial, up to a maximum amount of $75.0 million each, to avoid a default on the Centennial debt. As compensation to TE Products and Marathon for providing their additional guarantees, PEPL is required to pay interest at a rate of 4% per annum to each of TE Products and Marathon on the portion of the additional guaranty that each has provided for PEPL.

In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus Plastics Corporation, now known as Louis Dreyfus Energy Services, L.P. (“Louis Dreyfus”), in which our Mont Belvieu LPGs storage and transportation shuttle system services are jointly marketed by Louis Dreyfus and us. The purpose of the alliance is to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. TE Products operates the facilities for the alliance. Under the alliance, Louis Dreyfus has invested $6.1 million for expansion projects at Mont Belvieu. The alliance is a service-oriented, fee-based venture with no commodity trading activity. The alliance is scheduled to terminate on December 31, 2002, at which time a partnership may be established between TE Products and Louis Dreyfus, if the terms of the joint development agreement are met. We anticipate that the terms in the joint development agreement will be met during the fourth quarter of 2002, and the partnership will be created effective January 1, 2003. Under the terms of the joint development agreement, we would contribute our Mont Belvieu assets to a newly formed partnership. The economic terms of the partnership will be the same as those under the joint development and marketing alliance.

NOTE 13. COMPREHENSIVE INCOME

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments, and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the nine months ended September 30, 2002, and 2001, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which is designated as a cash flow hedge. Changes in the fair value of the cash flow hedge, to the extent the hedge is effective, are recognized in other comprehensive income until the hedge interest costs are recognized in earnings. The table below reconciles reported net income to total comprehensive income (loss) for the three months and nine months ended September 30, 2002, and 2001 (in thousands).


		Three Months Ended						Nine Months Ended
		September 30,						September 30,

		2002			2001			2002			2001

Net income		$	32,093		$	19,092		$	83,278		$	87,865
Cumulative effect attributable to adoption of SFAS 133			—			—			—			(10,103	)
Net loss on cash flow hedge			(2,216	)		(22,274	)		(1,868	)		(16,889	)

	Total comprehensive income (loss)	$	29,877		$	(3,182	)	$	81,410		$	60,873

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

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 hedge		(10,221	)

Balance at December 31, 2001		$	(20,324	)
	Net loss on cash flow hedge		(1,868	)

Balance at September 30, 2002		$	(22,192	)

NOTE 14. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In connection with our issuance of Senior Notes on February 20, 2002, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, our significant operating subsidiaries, issued unconditional guarantees of our debt securities. Effective with the acquisition of the Val Verde assets on June 30, 2002, our subsidiary, Val Verde Gas Gathering Company, L.P. also became a significant operating subsidiary and issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting.

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


				September 30, 2002

														TEPPCO
				TEPPCO			Guarantor		Non-Guarantor		Consolidating			Partners, L.P.
				Partners, L.P.			Subsidiaries		Subsidiaries		Adjustments			Consolidated

									(in thousands)
Assets
		Current assets		$	(1,168	)	$	199,589	$	309,776	$	(130,055	)	$	378,142
		Property, plant and equipment — net			—			1,130,815		462,620		—			1,593,435
		Equity investments			923,067			754,107		213,498		(1,605,049	)		285,623
		Intercompany notes receivable			1,091,042			—		—		(1,091,042	)		—
		Intangible assets			—			420,107		30,341		—			450,448
		Other assets			46,031			25,266		34,398		—			105,695

			Total assets	$	2,058,972		$	2,529,884	$	1,050,633	$	(2,826,146	)	$	2,813,343

	Liabilities and partners’ capital
		Current liabilities		$	92,826		$	283,879	$	276,506	$	(223,684	)	$	429,527
		Long-term debt			1,054,374			395,082		—		—			1,449,456
		Intercompany notes payable			—			529,538		467,872		(997,410	)		—
		Other long term liabilities and minority interest			9,048			22,355		231		—			31,634
		Redeemable Class B Units held by related party			103,883			—		—		—			103,883
		Total partners’ capital			798,841			1,299,030		306,024		(1,605,052	)		798,843

			Total liabilities and partners’ capital	$	2,058,972		$	2,529,884	$	1,050,633	$	(2,826,146	)	$	2,813,343


			December 31, 2001

												TEPPCO
			TEPPCO		Guarantor		Non-Guarantor		Consolidating			Partners, L.P.
			Partners, L.P.		Subsidiaries		Subsidiaries		Adjustments			Consolidated

							(in thousands)
Assets
	Current assets		$	3,100	$	59,730	$	223,345	$	(2,695	)	$	283,480
	Property, plant and equipment — net			—		849,978		330,483		—			1,180,461
	Equity investments			669,370		309,080		222,815		(909,041	)		292,224
	Intercompany notes receivable			700,564		11,269		7,404		(719,237	)		—
	Intangible assets			—		219,525		31,962		—			251,487
	Other assets			3,853		24,923		33,424		(4,504	)		57,696

		Total assets	$	1,376,887	$	1,474,505	$	849,433	$	(1,635,477	)	$	2,065,348

Liabilities and partners’ capital
	Current liabilities		$	367,094	$	361,547	$	310,476	$	(370,275	)	$	668,842
	Long-term debt			340,658		375,184		—		—			715,842
	Intercompany notes payable			—		45,410		294,801		(340,211	)		—
	Other long term liabilities and minority interest			—		22,994		231		8,628			31,853
	Redeemable Class B Units held by related party			105,630		—		—		—			105,630
	Total partners’ capital			563,505		669,370		243,925		(933,619	)		543,181

		Total liabilities and partners’ capital	$	1,376,887	$	1,474,505	$	849,433	$	(1,635,477	)	$	2,065,348

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


		Three Months Ended September 30, 2002

		TEPPCO			Guarantor			Non-Guarantor			Consolidating			TEPPCO Partners, L.P.
		Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

								(in thousands)
Operating revenues		$	—		$	92,005		$	788,995		$	(196	)	$	880,804
Costs and expenses			—			60,027			774,338			(196	)		834,169

	Operating income		—			31,978			14,657			—			46,635

Interest expense — net			(15,184	)		(12,741	)		(6,050	)		15,550			(18,425	)
Equity earnings			32,093			19,615			5,166			(53,727	)		3,147
Other income — net			15,184			69			1,033			(15,550	)		736

	Net income	$	32,093		$	38,921		$	14,806		$	(53,727	)	$	32,093


		Three Months Ended September 30, 2001

		TEPPCO			Guarantor			Non-Guarantor			Consolidating			TEPPCO Partners, L.P.
		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


		Nine Months Ended September 30, 2002

		TEPPCO			Guarantor			Non-Guarantor			Consolidating			TEPPCO Partners, L.P.
		Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

								(in thousands)
Operating revenues		$	—		$	228,367		$	2,173,278		$	(1,375	)	$	2,400,270
Costs and expenses			—			146,663			2,134,002			(1,375	)		2,279,290

	Operating income		—			81,704			39,276			—			120,980

Interest expense — net			(38,323	)		(29,279	)		(19,990	)		38,689			(48,903	)
Equity earnings			83,278			40,165			14,138			(128,448	)		9,133
Other income — net			38,323			422			2,012			(38,689	)		2,068

	Net income	$	83,278		$	93,012		$	35,436		$	(128,448	)	$	83,278

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


		Nine Months Ended September 30, 2001

		TEPPCO			Guarantor			Non-Guarantor			Consolidating			TEPPCO Partners, L.P.
		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


				Nine Months Ended September 30, 2002

				TEPPCO			Guarantor			Non-Guarantor			Consolidating			TEPPCO Partners, L.P.
				Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

										(in thousands)
Cash flows from operating activities
	Net income			$	83,278		$	93,012		$	35,436		$	(128,448	)	$	83,278
		Adjustments to reconcile net income to net cash provided by (used in) operating activities:
			Depreciation and amortization		—			45,723			12,468			—			58,191
			Equity earnings, net of distributions		25,101			(2,185	)		9,317			(17,911	)		14,322
			Changes in assets and liabilities and other		(382,191	)		33,146			78,364			255,476			(15,205	)

Net cash provided by (used in) operating activities					(273,812	)		169,696			135,585			109,117			140,586

Cash flows from investing activities					(278,811	)		(964,960	)		(251,458	)		808,684			(686,545	)
Cash flows from financing activities					552,623			805,568			112,227			(917,801	)		552,617

Net increase (decrease) in cash and cash equivalents					—			10,304			(3,646	)		—			6,658
Cash and cash equivalents at beginning of period					—			3,655			21,824			—			25,479

Cash and cash equivalents at end of period				$	—		$	13,959		$	18,178		$	—		$	32,137

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


				Nine Months Ended September 30, 2001

				TEPPCO			Guarantor			Non-Guarantor			Consolidating			TEPPCO Partners, L.P.
				Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

										(in thousands)
Cash flows from operating activities
	Net income			$	87,865		$	88,665		$	18,683		$	(107,348	)	$	87,865
		Adjustments to reconcile net income to net cash provided by (used in) 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			(17,896	)		801			(11,672	)

Net cash provided by (used in) 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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

You should read the following review of our financial position and results of operations in conjunction with the Consolidated Financial Statements. 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. “Other Considerations” addresses certain trends, future plans or contingencies that could affect future liquidity or earnings. These Consolidated Financial Statements should be read in conjunction with the financial statements and related notes, together with our discussion and analysis of financial position and results of operations included in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2001.

We operate and report in three business segments:

	•		Downstream Segment — transportation and storage of refined products, LPGs and petrochemicals;

	•		Upstream Segment — gathering, transportation, marketing and storage of crude oil; and distribution of lubrication oils and specialty chemicals; and

	•		Midstream Segment — gathering of natural gas, fractionation of NGLs and transportation of NGLs.

Our reportable segments offer different products and services and are managed separately because each requires different business strategies. TEPPCO GP, our wholly-owned subsidiary, acts as managing general partner with a 0.001% general partner interest and manages our subsidiaries.

Our Downstream Segment revenues are derived from transportation and storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. 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. Our Downstream Segment also includes our equity investment in Centennial Pipeline LLC (“Centennial”).

The Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our 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. Our Upstream Segment also includes the equity earnings from our investment in Seaway Crude Pipeline Company (“Seaway”). Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, Oklahoma, a central crude oil distribution point for the Central United States.

The Midstream Segment revenues are earned from fractionation of NGLs in Colorado, transportation of NGLs and gathering of natural gas. The Midstream Segment includes the operations from the acquisition of Jonah on September 30, 2001, from Alberta Energy Company for $359.8 million. We paid an additional $7.3 million on

February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The results of operations of the acquisition are included in our consolidated financial statements beginning in the fourth quarter of 2001. The Jonah assets are managed and operated by DEFS under a contractual arrangement.

On March 1, 2002, we completed the purchase of the Chaparral NGL system (“Chaparral”) for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition costs of approximately $0.4 million. The Chaparral NGL system has an 800-mile pipeline that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. The Chaparral NGL system also has an approximately 170-mile NGL gathering system located in West Texas, which begins in Sutton County, Texas, and connects to the 800-mile pipeline near Midland. The pipelines are connected to 27 gas plants in West Texas and have approximately 28,000 horsepower of pumping capacity at 14 stations. The Chaparral NGL system is managed and operated by DEFS under a contractual arrangement. These assets are included in the Midstream Segment.

On June 30, 2002, we completed the purchase of the Val Verde Gathering System (“Val Verde”) for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition costs of approximately $1.2 million. The Val Verde Gathering System gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico. The system is one of the largest coal seam gas gathering and treating facilities in the United States, gathering coal seam gas from more than 544 separate wells throughout New Mexico. The system provides gathering and treating services pursuant to approximately 60 long-term contracts with approximately 40 different gas producers in the San Juan Basin. Gas gathered on the Val Verde Gathering System is delivered to several interstate pipeline systems serving the western United States and to local New Mexico markets. The Val Verde Gathering System consists of 360 miles of pipeline ranging in size from 4 inches to 36 inches in diameter, 14 compressor stations operating over 93,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet per day. The assets are managed and operated by DEFS under a contractual arrangement. These assets are included in the Midstream Segment.

Results of Operations

The following table summarizes financial data by business segment (in thousands):


				Three Months Ended						Nine Months Ended
				September 30,						September 30,

				2002			2001			2002			2001

Operating revenues:
	Downstream Segment			$	58,754		$	58,527		$	172,996		$	199,374
	Upstream Segment				776,036			925,256			2,139,703			2,629,360
	Midstream Segment				46,210			7,033			88,946			20,999
	Intercompany eliminations				(196	)		—			(1,375	)		—

		Total operating revenues			880,804			990,816			2,400,270			2,849,733


Operating income:
	Downstream Segment				19,728			22,068			61,952			91,662
	Upstream Segment				7,908			1,455			20,580			12,483
	Midstream Segment				18,999			3,598			38,448			12,351

		Total operating income			46,635			27,121			120,980			116,496


Earnings before interest:
	Downstream Segment				17,786			22,205			57,218			92,141
	Upstream Segment				14,059			7,945			36,660			29,492
	Midstream Segment				19,039			3,613			38,669			12,357
	Intercompany eliminations				(366	)		—			(366	)		—

			Total earnings before interest		50,518			33,763			132,181			133,990


Interest expense					(19,763	)		(15,679	)		(53,379	)		(47,365	)
Interest capitalized					1,338			1,105			4,476			2,040
Minority interest					—			(97	)		—			(800	)

			Net income	$	32,093		$	19,092		$	83,278		$	87,865

Below is a detailed analysis of the results of operations, including reasons for changes in results, by each of our operating segments.

Downstream Segment

The following table presents volume and average rate information for the three months and nine months ended September 30, 2002, and 2001:


			Three Months Ended							Nine Months Ended
			September 30,				Percentage			September 30,				Percentage
							Increase							Increase
			2002		2001		(Decrease)			2002		2001		(Decrease)

					(in thousands, except tariff information)
Volumes Delivered
	Refined products			40,065		32,387		24	%		101,174		92,935		9	%
	LPGs			8,689		8,864		(2	%)		27,780		27,422		1	%
	Mont Belvieu operations			6,128		5,352		15	%		21,385		16,188		32	%

		Total		54,882		46,603		18	%		150,339		136,545		10	%


Average Tariff per Barrel
	Refined products		$	0.88	$	0.99		(11	%)	$	0.91	$	0.98		(7	%)
	LPGs			1.44		1.77		(19	%)		1.68		1.98		(15	%)
	Mont Belvieu operations			0.14		0.18		(22	%)		0.14		0.18		(22	%)
		Average system tariff per barrel	$	0.89	$	1.05		(15	%)	$	0.94	$	1.08		(13	%)

Three Months ended September 30, 2002 Compared to Three Months ended September 30, 2001

Our Downstream Segment reported earnings before interest of $17.8 million for the three months ended September 30, 2002, compared with earnings before interest of $22.2 million for the three months ended September 30, 2001. Earnings before interest decreased $4.4 million primarily due to an increase of $2.6 million in costs and expenses, additional losses of $1.7 million from equity investments and a decrease of $0.3 million in other income -net, partially offset by an increase of $0.2 million in operating revenues. We discuss the factors influencing these variances below.

Revenues from refined products transportation increased $3.1 million for the three months ended September 30, 2002, compared with the three months ended September 30, 2001, due primarily to a 24% increase in refined products volumes delivered during the third quarter of 2002. This increase in refined products volumes delivered is primarily due to barrels received into our pipeline from Centennial at Creal Springs, Illinois. Centennial commenced refined products deliveries to us beginning in April 2002. The refined products average rate per barrel decreased 11% from the prior-year period due to the impact of the Midwest origin point for volumes received from Centennial.

Revenues from LPGs transportation decreased $3.2 million for the three months ended September 30, 2002, compared with the three months ended September 30, 2001, primarily due to decreased deliveries of propane in the upper Midwest and Northeast market areas caused by lower prices from competing Canadian and mid-continent propane supply as compared to propane originating from the Gulf Coast. Total LPGs volumes delivered decreased 2% as a result of increased short-haul deliveries to a petrochemical facility on the upper Texas Gulf Coast. The LPGs average rate per barrel decreased 19% from the prior-year period as a result of a decreased percentage of long-haul deliveries during the three months ended September 30, 2002.

Revenues generated from Mont Belvieu operations decreased $0.2 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001, as a result of increased contract shuttle deliveries. Mont Belvieu shuttle volumes delivered increased 15% during the three months ended September 30, 2002, compared with the three months ended September 30, 2001, due to increased petrochemical demand. The Mont Belvieu average rate per barrel decreased 22% during the three months ended September 30, 2002, as a result of increased contract shuttle deliveries, which generally carry lower rates.

Other operating revenues increased $0.5 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001, primarily due to increased refined products and LPGs loading fees. These increases were partially offset by lower propane deliveries at our Providence, Rhode Island, import facility and lower refined products storage revenues.

Costs and expenses increased $2.6 million for the three months ended September 30, 2002, compared with the three months ended September 30, 2001. The increase was comprised of a $1.1 million increase in operating, general and administrative expenses, a $0.8 million increase in depreciation and amortization expense, and a $1.4 million increase in taxes — other than income taxes, partially offset by a $0.7 million decrease in operating fuel and power expense. Operating, general and administrative expenses increased primarily due to increased consulting and contract services, increased rental charges and increased insurance costs. Depreciation expense increased from the prior-year period because of assets placed in service during 2001. Taxes — other than income taxes increased as a result of a higher property base in 2002. Operating fuel and power expense decreased as a result of decreased long-haul volumes delivered related to Midwest volumes received from Centennial and lower electric power costs.

Net losses from equity investments totaled $2.0 million during the three months ended September 30, 2002, due to start-up expenses of Centennial, which commenced operations in early April 2002.

Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001

Our Downstream Segment reported earnings before interest of $57.2 million for the nine months ended September 30, 2002, compared with earnings before interest of $92.1 million for the nine months ended September 30, 2001. Earnings before interest decreased $34.9 million primarily due to a decrease of $26.4 million in operating revenues, an increase of $3.3 million in costs and expenses, additional losses of $4.4 million from equity investments and a decrease of $0.8 million in other income — net. We discuss the factors influencing these variances below.

Revenues from refined products transportation decreased $17.5 million for the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, due primarily to $18.9 million of revenue recognized in the 2001 period from a cash settlement received from a 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 market-based-rates during the second quarter of 2001. These decreases were partially offset by a 9% increase in refined products volumes delivered during the nine months ended September 30, 2002, primarily due to barrels received into our pipeline from Centennial at Creal Springs, Illinois. Centennial commenced refined products deliveries to us beginning in April 2002. The overall increase in refined products deliveries was partially offset by a 1.3 million barrel decrease in methyl tertiary butyl ether (“MTBE”) deliveries as a result of the expiration of contract deliveries to our marine terminal near Beaumont, Texas, effective April 2001. As a result of the contract expiration, we no longer transport MTBE through our Products pipeline system. The refined products average rate per barrel decreased 7% from the prior-year period due to the impact of the Midwest origin point for volumes received from Centennial, which was partially offset by decreased short-haul MTBE volumes delivered and higher market-based tariff rates, which went into effect in July 2001.

Revenues from LPGs transportation decreased $7.5 million for the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, primarily due to decreased deliveries of propane in the upper Midwest and Northeast market areas attributable to warmer than normal weather. The decrease was also due to lower prices from competing Canadian and mid-continent propane supply as compared to propane originating from the Gulf Coast. Total LPGs volumes delivered increased 1% as a result of increased short-haul deliveries to a petrochemical facility on the upper Texas Gulf Coast. The LPGs average rate per barrel decreased 15% from the prior-year period as a result of a decreased percentage of long-haul deliveries during the nine months ended September 30, 2002.

Revenues generated from Mont Belvieu operations increased $1.2 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, as a result of increased storage revenue and receipt revenue. Mont Belvieu shuttle volumes delivered increased 32% during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, due to increased petrochemical demand. The Mont Belvieu average rate per barrel decreased 22% during the nine months ended September 30, 2002, as a result of increased contract shuttle deliveries, which generally carry lower rates.

Other operating revenues decreased $2.6 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, primarily due to lower propane deliveries at our Providence, Rhode Island, import facility, lower refined products storage revenue, lower margins on product inventory sales, and increased losses as a result of exchanging products at different geographic points of delivery to position product in the Midwest market area. These decreases were partially offset by increased refined products and LPGs loading fees.

Costs and expenses increased $3.3 million for the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001. The increase was made up of a $4.7 million increase in operating, general and administrative expenses, a $1.6 million increase in depreciation and amortization expense, and a $2.4 million increase in taxes — other than income taxes. These increases were partially offset by a $5.4 million decrease in operating fuel and power expense. Operating, general and administrative expenses increased, primarily due to higher pipeline maintenance and rehabilitation expenses, increased consulting and contract services and increased labor costs. Depreciation expense increased from the prior-year period because of assets placed in service during

2001. Taxes — other than income taxes increased as a result of a higher property base in 2002. Operating fuel and power expense decreased as a result of decreased long-haul volumes delivered related to Midwest volumes received from Centennial and lower power costs.

Net losses from equity investments totaled $5.0 million during the nine months ended September 30, 2002, due to pre-operating expenses and start-up costs of Centennial, which commenced operations in early April 2002.

Upstream Segment

We calculate the margin of the Upstream Segment as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil, 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 the three months and nine months ended September 30, 2002, and 2001 is presented below (in thousands, except per barrel and per gallon amounts):


			Three Months Ended							Nine Months Ended
			September 30,				Percentage			September 30,				Percentage
							Increase							Increase
			2002		2001		(Decrease)			2002		2001		(Decrease)

Margins:
	Crude oil transportation		$	9,517	$	9,119		4	%	$	28,211	$	26,165		8	%
	Crude oil marketing			6,249		6,945		(10	%)		16,319		16,772		(3	%)
	Crude oil terminaling			2,606		2,831		(8	%)		7,695		7,505		3	%
	Lubrication oil sales			1,166		1,030		13	%		3,531		3,148		12	%

		Total margin	$	19,538	$	19,925		(2	%)	$	55,756	$	53,590		4	%


Total barrels:
	Crude oil transportation			18,916		19,795		(4	%)		61,704		57,391		8	%
	Crude oil marketing			30,064		37,135		(19	%)		103,343		109,586		(6	%)
	Crude oil terminaling			31,361		30,130		4	%		93,700		87,252		7	%

Lubrication oil volume (total gallons)				2,079		2,257		(8	%)		6,971		6,646		5	%

Margin per barrel:
	Crude oil transportation		$	0.503	$	0.461		9	%	$	0.457	$	0.456		—
	Crude oil marketing			0.208		0.187		11	%		0.158		0.153		3	%
	Crude oil terminaling			0.083		0.094		(12	%)		0.082		0.086		(5	%)

Lubrication oil margin (per gallon)			$	0.561	$	0.456		23	%	$	0.507	$	0.474		7	%

Three Months ended September 30, 2002 Compared to Three Months ended September 30, 2001

Our Upstream Segment reported earnings before interest of $14.1 million for the three months ended September 30, 2002, compared with earnings before interest of $7.9 million for the three months ended September 30, 2001. Earnings before interest increased $6.2 million primarily due to a decrease of $7.4 million in costs and expenses (excluding purchases of crude oil and lubrication oil), an increase of $0.4 million in other income — net, partially offset by a decrease of $0.8 million in equity earnings of Seaway, a decrease of $0.4 million in margin and a decrease of $0.4 million in other revenue. We discuss the factors influencing these variances below.

Our margin decreased $0.4 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001. Crude oil marketing margin decreased $0.7 million primarily due to

reduced volumes marketed on Seaway by our marketing affiliate, partially offset by renegotiated supply contracts and lower trucking expenses. Crude oil terminaling margin decreased $0.2 million as a result of lower volumes at Midland, Texas, and Cushing, Oklahoma. Crude oil transportation margin increased $0.4 million primarily due to higher revenues on our Red River system. Lubrication oil sales margin increased $0.1 million due to increased volumes related to the acquisition of a lubrication oil distributor in Amarillo, Texas, in the fourth quarter of 2001.

Other operating revenues of the Upstream Segment decreased $0.4 million for the three months ended September 30, 2002, compared with the three months ended September 30, 2001, due to lower revenue from documentation and other services to support customers’ trading activity at Midland, Texas, and Cushing, Oklahoma.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, decreased $7.4 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001. Operating, general and administrative expenses decreased $6.1 million due to $4.3 million of environmental costs recognized in 2001, lower labor related costs and decreased general and administrative supplies and services expense during the 2002 period. Taxes — other than income taxes decreased by $1.0 million due to a reduction in estimated property taxes for the period. Depreciation and amortization expense decreased by $0.2 million due to the adoption of SFAS 142 effective January 1, 2002, (see Note 3. Goodwill and Other Intangible Assets), in which goodwill and excess investment are no longer being amortized. Operating fuel and power expense decreased by $0.1 million due to lower electric power costs.

Equity earnings in Seaway for the three months ended September 30, 2002, decreased $0.8 million from the three months ended September 30, 2001, due to our portion of equity earnings being reduced from 80 percent to 60 percent on a pro-rated basis in 2002 (averaging approximately 67 percent for the year ended December 31, 2002), coupled with lower third-party transportation volumes.

Nine Months ended September 30, 2002 Compared to Nine Months ended September 30, 2001

Our Upstream Segment reported earnings before interest of $36.7 million for the nine months ended September 30, 2002, compared with earnings before interest of $29.5 million for the nine months ended September 30, 2001. Earnings before interest increased $7.2 million primarily due to an increase of $2.1 million in margin, a decrease of $7.1 million in costs and expenses (excluding purchases of crude oil and lubrication oil) and an increase of $0.8 million in other income — net. These increases were partially offset by a decrease of $1.8 million in equity earnings of Seaway and a decrease of $1.0 million in other revenue. We discuss the factors influencing these variances below.

Our margin increased $2.1 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001. Crude oil transportation margin increased $2.0 million primarily due to volumes transported on the pipeline assets acquired from Valero Energy Corp. (“Valero”) in March 2001, and higher revenues on our Basin, Red River and West Texas systems. Crude oil terminaling margin increased $0.2 million as a result of higher volumes at Midland, Texas, and Cushing, Oklahoma. Lubrication oil sales margin increased $0.4 million due to increased volumes related to the acquisition of a lubrication oil distributor in Amarillo, Texas, in the fourth quarter of 2001. Crude oil marketing margin decreased $0.5 million primarily due to decreased volumes marketed, partially offset by renegotiated supply contracts and lower trucking expenses.

Other operating revenues of the Upstream Segment decreased $1.0 million for the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, due to lower revenue from documentation and other services to support customers’ trading activity at Midland, Texas, and Cushing, Oklahoma.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, decreased $7.1 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001. Operating, general and administrative expenses decreased from the prior year period due to $4.3 million of environmental costs recognized in 2001 and decreased labor related costs, partially offset by increased general and administrative supplies and services expense. Taxes — other than income taxes decreased $2.0

million due to reductions in property tax accruals. Depreciation and amortization expense decreased $0.7 million due to the adoption of SFAS 142 effective January 1, 2002, in which goodwill and excess investment are no longer being amortized, partially offset by increased depreciation expense on the assets acquired from Valero. These decreases were partially offset by a $0.3 million increase in operating fuel and power costs attributed to higher transportation volumes.

Equity earnings in Seaway for the nine months ended September 30, 2002, decreased $1.8 million from the nine months ended September 30, 2001, due to our portion of equity earnings being reduced from 80 percent to 60 percent on a pro rated basis in 2002 (averaging approximately 67 percent for the year ended December 31, 2002), coupled with lower third-party transportation volumes.

Midstream Segment

The following table presents volume and average rate information for the three months and nine months ended September 30, 2002, and 2001:


		Three Months Ended							Nine Months Ended
		September 30,				Percentage			September 30,				Percentage
						Increase							Increase
		2002		2001		(Decrease)			2002		2001		(Decrease)

Gathering — Natural Gas:
	Million cubic feet		111,197		—		—			221,173		—		—
	Million British thermal units (“MMBtu”)		110,571		—		—			232,792		—		—
	Average fee per MMBtu	$	0.299		—		—		$	0.232		—		—

Transportation — NGLs:
	Thousand barrels		15,568		5,828		167	%		39,039		16,026		144	%
	Average rate per barrel	$	0.717	$	0.929		(23	%)	$	0.717	$	0.989		(28	%)

Fractionation — NGLs:
	Thousand barrels		992		1,004		(1	%)		3,036		3,062		(1	%)
	Average rate per barrel	$	1.841	$	1.828		1	%	$	1.830	$	1.813		1	%

Sales — Condensate:
	Thousand barrels		7.0		—		—			57.7		—		—
	Average rate per barrel	$	27.78		—		—		$	24.46		—		—

Three Months ended September 30, 2002 Compared to Three Months ended September 30, 2001

Our Midstream Segment’s earnings before interest totaled $19.0 million for the three months ended September 30, 2002, compared with earnings before interest of $3.6 million for the three months ended September 30, 2001. Earnings before interest increased $15.4 million due to an increase of $39.2 million in operating revenues, partially offset by an increase of $23.8 million in costs and expenses. We discuss the factors influencing these variances below.

Operating revenues increased $39.2 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001. Natural gas gathering revenues from the Jonah system (acquired on September 30, 2001) totaled $13.1 million and volumes delivered totaled 63.0 billion cubic feet during the three months ended September 30, 2002. Natural gas gathering revenues from the Val Verde system (acquired on June 30, 2002) totaled $20.0 million and volumes delivered totaled 48.2 billion cubic feet during the three months ended September 30, 2002. Other revenues increased $0.2 million due to sales of gas condensate from the Jonah system. NGL transportation revenues increased $5.9 million, primarily due to the acquisition of Chaparral on March 1, 2002,

partially offset by lower revenues on a take-or-pay contract on the Dean system that was in effect until the bankruptcy of Enron Corp. in December 2001. The decrease in the NGL transportation average rate per barrel resulted from the cancellation of the Enron Corp. take-or-pay contract, and a lower average rate per barrel on volumes transported on Chaparral in 2002.

Costs and expenses increased $23.8 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001. The increase was comprised of an increase of $13.6 million in depreciation and amortization expense, an increase of $8.3 million in operating, general and administrative expense, an increase of $1.3 million in operating fuel and power costs and an increase of $0.6 million in taxes — other than income taxes. Of these increases, $22.8 million related to the Jonah, Chaparral and Val Verde assets acquired on September 30, 2001, March 1, 2002, and June 30, 2002, respectively, and an increase of $1.0 million in general and administrative labor and supplies expenses.

Nine Months ended September 30, 2002 Compared to Nine Months ended September 30, 2001

Our Midstream Segment’s earnings before interest totaled $38.7 million for the nine months ended September 30, 2002, compared with earnings before interest of $12.4 million for the nine months ended September 30, 2001. Earnings before interest increased $26.3 million due to an increase of $67.9 million in operating revenues and an increase of $0.2 million in other income - net, partially offset by an increase of $41.8 million in costs and expenses. We discuss the factors influencing these variances below.

Operating revenues increased $67.9 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001. Natural gas gathering revenues from the Jonah system totaled $34.0 million and volumes delivered totaled 173.0 billion cubic feet during the nine months ended September 30, 2002. Natural gas gathering revenues from the Val Verde system totaled $20.0 million and volumes delivered totaled 48.2 billion cubic feet during the nine months ended September 30, 2002. Other revenues increased $1.5 million primarily due to sales of gas condensate from the Jonah system. NGL transportation revenues increased $12.4 million, primarily due to the acquisition of Chaparral on March 1, 2002, partially offset by lower revenues on a take-or-pay contract on the Dean system that was in effect until the bankruptcy of Enron Corp. in December 2001. The decrease in the NGL transportation average rate per barrel resulted from the cancellation of the Enron Corp. take-or-pay contract, and a lower average rate per barrel on volumes transported on Chaparral.

Costs and expenses increased $41.8 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001. The increase was comprised of a $26.0 million increase in depreciation and amortization expense, a $12.1 million increase in operating, general and administrative expense, a $2.7 million increase in operating fuel and power costs and a $1.0 million increase in taxes — other than income taxes. Of these increases, $41.5 million related to the Jonah, Chaparral and Val Verde assets acquired on September 30, 2001, March 1, 2002, and June 30, 2002, respectively. The remaining $0.4 million increase was attributable to higher general and administrative labor and supplies expense, partially offset by decreased operating expenses.

Interest Expense and Capitalized Interest

Three Months ended September 30, 2002 Compared to Three Months ended September 30, 2001

Interest expense increased $4.1 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001, primarily due to higher outstanding debt, partially offset by lower LIBOR rates in effect during 2002.

Capitalized interest increased $0.2 million during the three months ended September 30, 2002, compared with the three months ended September 30, 2001, due to increased balances on construction work-in-progress during the third quarter of 2002.

Nine Months ended September 30, 2002 Compared to Nine Months ended September 30, 2001

Interest expense increased $6.0 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, primarily due to higher outstanding debt, partially offset by lower LIBOR rates in effect during 2002.

Capitalized interest increased $2.4 million during the nine months ended September 30, 2002, compared with the nine months ended September 30, 2001, due to interest capitalized on the investment during the construction of Centennial and increased balances during 2002 on construction work-in-progress.

Financial Condition and Liquidity

Net cash from operations totaled $140.6 million for the nine months ended September 30, 2002. This cash was made up of $141.5 million of income before charges for depreciation and amortization, partially offset by $0.9 million of cash used for working capital changes. This compares with net cash from operations of $113.5 million for the corresponding period in 2001, 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. Net cash from operations for the nine months ended September 30, 2002, and 2001, included interest payments of $30.5 million and $52.0 million, respectively.

Cash flows used in investing activities totaled $686.5 million during the nine months ended September 30, 2002, and were comprised of $7.3 million for the final purchase price adjustments on the acquisition of Jonah, $98.3 million of capital expenditures, $7.7 million of cash contributions for our interest in Centennial, $132.4 million for the purchase of Chaparral on March 1, 2002, and $444.2 million for the purchase of Val Verde on June 30, 2002. These uses of cash were partially offset by $3.4 million in cash proceeds from the sale of assets. Cash flows used in investing activities totaled $471.6 million during the nine months ended September 30, 2001, and were comprised of $359.8 million for the purchase of Jonah on September 30, 2001, $62.0 million of capital expenditures, $34.3 million of cash contributions for our interest in Centennial, and $20.0 million for the purchase of assets from Valero on March 1, 2001. These uses of cash were partially offset by $1.3 million of cash received from the sale of vehicles and $3.2 million received on matured cash investments.

Cash flows provided by financing activities totaled $552.6 million during the nine months ended September 30, 2002, and were comprised of $662.0 million in proceeds from term and revolving credit facilities; $497.8 million from the issuance of our 7.625% Senior Notes due 2012, partially offset by debt issuance costs of $7.0 million; $275.3 million from the issuance of 9.5 million Limited Partner Units in March, July, and September 2002, and $5.6 million of related general partner contributions; and $18.0 million of proceeds from the termination of our interest rate swaps on the 7.625% Senior Notes due 2012. These sources of cash in 2002 were partially offset by $790.7 million of repayments on our term and revolving credit facilities and $108.4 million of distributions to Limited Partner unitholders. Cash flows provided by financing activities totaled $364.1 million during the nine months ended September 30, 2001, and were comprised of $427.0 million of proceeds from term and revolving credit facilities, partially offset by debt issuance costs of $2.6 million; and $54.6 million from the issuance of 2.3 million Limited Partner Units in February 2001, and $1.1 million of related general partner contributions. These sources of cash in 2001 were partially offset by $41.0 million of repayments on our term and revolving credit facilities and $75.0 million in distributions to Limited Partner unitholders.

each, to avoid a default on the Centennial debt. As compensation to TE Products and Marathon for providing their additional guarantees, PEPL is required to pay interest at a rate of 4% per annum to each of TE Products and Marathon on the portion of the additional guaranty that each has provided for PEPL.

Credit Facilities and Interest Rate Swap Agreements

On April 6, 2001, we entered into a 364-day, $200.0 million revolving credit agreement (“Short-term Revolver”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Short-term Revolver was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. We then drew down $72.0 million under the Short-term Revolver. At September 30, 2002, $72.0 million was outstanding under the Short-term Revolver at an interest rate of 2.9%. As of September 30, 2002, we were in compliance with the covenants contained in this credit agreement.

On February 20, 2002, we received $494.6 million in net proceeds from the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, described above, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing the 7.625% 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 our ability to incur additional indebtedness. As of September 30, 2002, we were in compliance with the covenants of these Senior Notes.

On June 27, 2002, we entered into a $200.0 million six-month term loan with SunTrust Bank (“Six-Month Term Loan”) payable in December 2002. We borrowed $200.0 million under the Six-Month Term Loan to acquire the Val Verde assets (see Note 5. Acquisitions). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal from proceeds primarily received from the issuance of Limited Partner Units in July 2002. On September 10, 2002, we repaid the remaining outstanding balance of $110.0 million with proceeds received from the issuance of Limited Partner Units in September 2002 (see Note 9. Partners’ Capital), and canceled the facility.

We entered into interest rate swap agreements to hedge our exposure to cash flows and fair value changes. These agreements are more fully described in Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

The following table summarizes our credit facilities as of September 30, 2002 (in millions):

As of September 30, 2002

Available

Outstanding

Borrowing

Maturity

Description:

Principal

Capacity

Date

Short-term Revolver

72.0

128.0

March 2003

Three Year Facility

500.0

—

April 2004

6.45% Senior Notes

180.0

—

January 2008

7.625% Senior Notes

500.0

—

February 2012

7.51% Senior Notes

210.0

—

January 2028

Distributions and Issuance of Additional Limited Partner Units

We paid cash distributions of $108.4 million ($1.75 per Unit) and $75.0 million ($1.575 per Unit) for each of the nine months ended September 30, 2002, and 2001, respectively. Additionally, on October 16, 2002, we declared a cash distribution of $0.60 per Limited Partner Unit and Class B Unit for the quarter ended September 30, 2002. We will pay the distribution of approximately $43.5 million on November 8, 2002, to unitholders of record on October 31, 2002.

On February 6, 2001, we sold in an underwritten public offering 2.0 million Limited Partner Units at $25.50 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $48.7 million and

were used to reduce borrowings under the Three Year Facility. On March 6, 2001, 250,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on February 6, 2001. Proceeds from that sale totaled $6.1 million and were used for general purposes.

On November 14, 2001, we sold in an underwritten public offering 5.5 million Limited Partner Units at $34.25 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $180.3 million and were used to repay $160.0 million under the Bridge Facility that was used to fund the Jonah acquisition. The remaining proceeds were used to finance contributions to Centennial and for other capital expenditures.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions, for 2002 will be approximately $141.0 million (which includes $6.0 million of capitalized interest). We expect to use approximately $110.0 million for revenue generating projects, approximately $18.0 million for maintenance capital spending and approximately $7.0 million for system upgrade projects. Revenue generating projects will include approximately $45.0 million for Phase II expansion of the Jonah system, $17.0 million for expansion of other Midstream assets and $38.0 million to expand our service capabilities including the installation of a brine pond at our Mont Belvieu LPGs storage facility, the installation of improvements at our Princeton, Indiana, LPGs truck loading facilities, and the completion of facilities to support receipt and delivery locations with Centennial. We expect to use approximately $4.1 million of maintenance capital spending for pipeline rehabilitation projects to comply with regulations enacted by the United States Department of Transportation Office of Pipeline Safety. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business segments. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or the issuance of additional equity.

As of September 30, 2002, we had a working capital deficit of $51.4 million. Of this amount, $72.0 million was due to short-term borrowings outstanding under our Short-term Revolver, which is payable in March 2003. These borrowings were used to finance a portion of the purchase price of Val Verde. We anticipate that we will issue additional Limited Partner Units and additional long-term debt in the fourth quarter of 2002 and use the proceeds to repay balances outstanding under our short-term revolving credit facilities.

Our debt repayment obligations consist of payments for principal and interest on (i) outstanding principal amounts under the Short-term Revolver due in March 2003 ($72.0 million at September 30, 2002), (ii) outstanding principal amounts under the Three Year Facility due in April 2004 ($500.0 million at September 30, 2002), (iii) the TE Products Senior Notes, $180.0 million principal amount due January 15, 2008, and $210.0 million principal amount due January 15, 2028, and (iv) our $500.0 million 7.625% Senior Notes due February 15, 2012.

TE Products is contingently liable as guarantor for the lesser of one-half or $75.0 million principal amount (plus interest) of the borrowings of Centennial. We expect to contribute an additional $2.0 million to Centennial for the remaining three months of 2002 to provide for operating problems associated with the pipeline start-up, which have restricted the flexibility of Centennial's Creal Springs tank farm. We may make additional contributions to Centennial in 2003. We expect that if any contributions are made they would not have a material adverse effect on our consolidated financial position, results of operations or cash flows. We do not rely on off-balance sheet borrowings to fund our acquisitions. We have no off-balance sheet commitments for indebtedness other than the limited guaranty of Centennial debt and leases covering assets utilized in several areas of our operations.

The following table summarizes our debt repayment obligations and material contractual commitments as of September 30, 2002 (in millions).


		Amount of Commitment Expiration Per Period

				Less than						After
		Total		1 Year		2-3 Years		4-5 Years		5 Years

Short-term Revolver		$	72.0	$	72.0	$	—	$	—	$	—
Three Year Facility			500.0		—		500.0		—		—
6.45% Senior Notes due 2008 (1)			180.0		—		—		—		180.0
7.51% Senior Notes due 2028 (1)			210.0		—		—		—		210.0
7.625% Senior Notes due 2012			500.0		—		—		—		500.0
Centennial cash contributions			2.0		2.0		—		—		—
Operating leases			31.3		8.4		14.9		7.3		0.7

	Total	$	1,495.3	$	82.4	$	514.9	$	7.3	$	890.7

(1)

Obligations of TE Products.

We expect to repay the long-term, senior unsecured obligations and bank debt through the issuance of additional long-term senior unsecured debt at the time the 2008, 2012 and 2028 debt matures, issuance of additional equity, proceeds from dispositions of assets, or any combination of the above items.

Sources of Future Capital

Historically, we have funded our capital commitments from operating cash flow and borrowings under bank credit facilities or bridge loans. We repaid these loans in part by the issuance of long term debt in capital markets and the public offering of Limited Partner Units. We expect future capital needs to be similarly funded to the extent not otherwise available from cash flow from operations.

As of September 30, 2002, we had approximately $128.0 million in available borrowing capacity under the Short-term Revolver.

We expect cash flows from operating activities will be adequate to fund cash distributions and capital additions necessary to maintain existing operations. However, expansionary capital projects and acquisitions may require funding through proceeds from the sale of additional debt or equity capital markets offerings.

In connection with our acquisition of Val Verde, we amended our Short-term Revolver and Three Year Facility to increase the maximum permitted debt-to-EBITDA ratio. For the twelve month period ending September 30, 2002, the maximum permitted ratio is 5.0-to-1 on a pro forma basis. At September 30, 2002, we are in compliance with this covenant. At December 31, 2002, the maximum permitted debt-to-EBITDA ratio returns to its pre-amendment level of 4.5-to-1. This ratio is determined for each fiscal quarter based on the preceding twelve months on a pro forma basis. Although we expect to satisfy this additional requirement by reducing debt through sales of additional units or other possible alternatives or combinations thereof, we cannot assure you that we will be successful in these efforts. If we cannot obtain a waiver of these restrictions, we could be in default under our credit

facilities, which could result in the acceleration of the amount outstanding thereunder at the time. A default under our credit facilities could result in a default under our 7.625% Senior Notes and our guarantee of a portion of the indebtedness of Centennial.

On May 29, 2002, Moody’s Investors Service downgraded our senior unsecured debt rating to Baa3 from Baa2. Our subsidiary, TE Products was also included in this downgrade. These ratings were given with stable outlooks and followed our announcement of the acquisition of Val Verde. The downgrades reflect Moody’s concern that we have a high level of debt relative to many of our peers and that our debt may be continually higher than our long-term targets if we continue to make a series of acquisitions of increasingly larger size. Because of our high distribution rate, we are particularly reliant on external financing to finance our acquisitions. Moody’s indicated that our cash flows are becoming less predictable as a result of our acquisitions and expansion into the crude oil and natural gas gathering businesses. We are evaluating alternatives to lowering our debt-to-EBITDA ratio. Further reductions in our credit ratings could increase the debt financing costs or possibly reduce the availability of financing. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant such a change. On September 17, 2002, Moody’s reaffirmed the Baa3 ratings on us and our subsidiary, TE Products.

Other Considerations

the first $3.0 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. The majority of the indemnified costs relate to remediation activities at the Velma crude oil site in Stephens County, Oklahoma, attributable to operations prior to our acquisition of the Upstream Segment. We do not expect that the completion of remediation programs associated with TCTM activities will have a future material adverse effect on our financial position, results of operations or cash flows.

New Accounting Pronouncements

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. We are required to adopt SFAS 143 effective January 1, 2003. We are currently evaluating the impact of adopting SFAS 143.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows.

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows.

change would significantly decrease our reported sales and purchases of crude oil and petroleum products, but would have no effect on our operating income or cash flow.

Forward-Looking Statements

The matters discussed in this Report 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 we expect or anticipate will or may occur in the future, including such things as estimated future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our 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 based on our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our 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 us, competitive actions by other pipeline companies, changes in laws or regulations, and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations. For additional discussion of such risks and uncertainties, see our 2001 Annual Report on Form 10-K, as amended, and other filings we have made with the Securities and Exchange Commission.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

At September 30, 2002, we had $572.0 million outstanding under our variable interest rate revolving credit agreements. The interest rate is based, at our option, on either the lender’s base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semiannually. Utilizing the balances of variable interest rate debt outstanding at September 30, 2002, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $5.7 million.

We have utilized and expect to continue to utilize interest rate swap agreements to hedge a portion of our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floating interest rate mix of our total debt portfolio and overall cost of borrowing. The interest rate swap related to our cash flow risk is intended to reduce our exposure to increases in the benchmark interest rates underlying our variable rate revolving credit facility. The interest rate swaps related to our fair value risks are intended to reduce our exposure to changes in the fair value of the fixed rate Senior Notes. The interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional amount upon which the payments are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest.

At September 30, 2002, our subsidiary, TE Products had outstanding $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). At September 30, 2002, the estimated fair value of the TE Products Senior Notes was approximately $392.0 million. At September 30, 2002, $500.0 million principal amount of 7.625% Senior Notes due 2012 was outstanding. At September 30, 2002, the estimated fair value of the $500.0 million Senior Notes was approximately $527.0 million.

As of September 30, 2002, TE Products had an interest rate swap agreement in place to hedge its exposure to changes in the fair value of its fixed rate 7.51% TE Products Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the nine months ended September 30, 2002, we recognized a gain of $5.4 million, recorded as a reduction of interest expense, on the interest rate swap. During the quarter ended September 30, 2002, we measured the hedge effectiveness of this interest rate swap, and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap agreement was a gain of approximately $5.2 million at September 30, 2002, and a loss of approximately $14.6 million at December 31, 2001.

As of September 30, 2002, we had an interest rate swap agreement in place to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. The term of the interest rate swap matches the maturity of the credit facility. We designated this swap agreement, which hedges exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250.0 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, 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 months ended September 30, 2002, and 2001, we recognized $9.6 million and $4.0 million, respectively, in losses, included in interest expense, on the interest rate swap. During the quarter ended September 30, 2002, we measured the hedge effectiveness of this interest rate swap, and noted that 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 $22.2 million and $20.3 million at September 30, 2002, and December 31, 2001, respectively. We anticipate that approximately $13.1 million of the fair value will be transferred into earnings over the next twelve months.

On February 20, 2002, we entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $25.8 million. From inception of the swap agreements on February 20, 2002, through the termination on July 16, 2002, $7.8 million had been recognized as a reduction to interest expense. The remaining gain of approximately $18.0 million is being amortized as a reduction to future interest expense over the remaining term of the Senior Notes. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment.

Item 4. Controls and Procedures

Included in its recent Release No. 34-46427, effective August 29, 2002, the Securities and Exchange Commission adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the “Exchange Act”). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.

The principal executive officer and principal financial officer of our general partner have informed us that, based upon their evaluation as of October 29, 2002, of our disclosure controls and procedures (as defined in Rule 13a-14(c) and Rule 15d-14(c) under the Exchange Act), they have concluded that those disclosure controls and procedures are effective.

There have been no changes in our internal controls or in other factors known to us that could significantly affect those controls subsequent to their evaluation, nor any corrective actions with regard to significant deficiencies and material weaknesses.

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 TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
3.2		Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
4.1		Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
4.2		Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
4.3		Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
4.4		Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).


Exhibit
Number		Description

4.5		First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.6		Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.1+		Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.2+		Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.3+		Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.4+		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).
10.5+		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).
10.6		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).
10.7		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).
10.8		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).
10.9+		Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara A. Carroll (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).
10.10		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).


Exhibit
Number		Description

10.11		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).
10.12+		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).
10.13+		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).
10.14+		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).
10.15+		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).
10.16+		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).
10.17		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).
10.18+		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).
10.19+		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).
10.20+		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).
10.21		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).
10.22		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).
10.23		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. (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, 2001 and incorporated herein by reference).


Exhibit
Number		Description

10.24		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) (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, 2001 and incorporated herein by reference).
10.25		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) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.26		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) (Filed as Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.27		Amendment and Restatement, dated as of November 13, 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) (Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.28		Second Amendment and Restatement, dated as of November 13, 2001, to the Amended and Restated Credit Agreement amount 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 10.36 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.29		Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.30		Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.31		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).
10.32		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).
10.33		Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.34		Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.35		Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P.


Exhibit
Number		Description

		(Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.36		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and Certain Lenders, as Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
10.37		Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
10.38		Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.39		Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, as Lenders dated as of June 27, 2002 ($200,000,000 Term Facility) (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.40		Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.41		Amendment 1, dated as of June 27, 2002 to the Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.42		Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.43+		Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.49 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.
21		Subsidiaries of the Partnership (Filed as Exhibit 21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

*		Filed herewith.

+		A management contract or compensation plan or arrangement.


	(b) Reports on Form 8-K filed during the quarter ended September 30, 2002:


	Reports on Form 8-K were filed on July 2, 2002, July 15, 2002, August 12, 2002, September 3, 2002, and September 6, 2002.

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) (A Delaware Limited Partnership)

	By:	Texas Eastern Products Pipeline
	Company, LLC, as General Partner

	By:	/s/ BARRY R. PEARL Barry R. Pearl, President and Chief Executive Officer

Date: November 1, 2002	By:	/s/ CHARLES H. LEONARD Charles H. Leonard, Senior Vice President and Chief Financial Officer

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, BARRY R. PEARL, certify that:

I have reviewed this quarterly report on Form 10-Q of TEPPCO Partners, L.P.;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	b)		evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

November 1, 2002
Date

/s/ BARRY R. PEARL
Barry R. Pearl
President and Chief Executive Officer

CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, CHARLES H. LEONARD, certify that:

I have reviewed this quarterly report on Form 10-Q of TEPPCO Partners, L.P.;

	a)		designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	b)		evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

November 1, 2002
Date

/s/ CHARLES H. LEONARD
Charles H. Leonard
Senior Vice President and
Chief Financial Officer

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, being the Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC, the sole general partner of TEPPCO Partners, L.P. (the “Company”), hereby certifies that, to his knowledge, the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated, November 1, 2002

/s/ BARRY R. PEARL
Barry R. Pearl
President and Chief Executive Officer

CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, being the Chief Financial Officer of Texas Eastern Products Pipeline Company, LLC, the sole general partner of TEPPCO Partners, L.P. (the “Company”), hereby certifies that, to his knowledge, the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated, November 1, 2002

/s/ CHARLES H. LEONARD
Charles H. Leonard
Senior Vice President and Chief Financial Officer

EXHIBIT INDEX


Exhibit
Number		Description

3.1		Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
3.2		Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
4.1		Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
4.2		Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
4.3		Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
4.4		Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).


Exhibit
Number		Description

4.5		First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.6		Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.1+		Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.2+		Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.3+		Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.4+		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).
10.5+		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).
10.6		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).
10.7		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).
10.8		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).
10.9+		Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara A. Carroll (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).
10.10		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).


Exhibit
Number		Description

10.11		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).
10.12+		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).
10.13+		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).
10.14+		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).
10.15+		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).
10.16+		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).
10.17		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).
10.18+		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).
10.19+		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).
10.20+		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).
10.21		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).
10.22		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).
10.23		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. (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, 2001 and incorporated herein by reference).


Exhibit
Number		Description

10.24		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) (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, 2001 and incorporated herein by reference).
10.25		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) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.26		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) (Filed as Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.27		Amendment and Restatement, dated as of November 13, 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) (Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.28		Second Amendment and Restatement, dated as of November 13, 2001, to the Amended and Restated Credit Agreement amount 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 10.36 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.29		Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.30		Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.31		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).
10.32		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).
10.33		Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.34		Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.35		Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P.


Exhibit
Number		Description

		(Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.36		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and Certain Lenders, as Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
10.37		Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
10.38		Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.39		Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, as Lenders dated as of June 27, 2002 ($200,000,000 Term Facility) (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.40		Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.41		Amendment 1, dated as of June 27, 2002 to the Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.42		Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.43+		Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.49 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.
21		Subsidiaries of the Partnership (Filed as Exhibit 21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

*		Filed herewith.

+		A management contract or compensation plan or arrangement.

exv12w1

Exhibit 12.1

Statement of Computation of Ratio of Earnings to Fixed Charges


			Years Ended December 31,															Nine months
																		ended
			1997			1998			1999			2000			2001			September 30, 2002

			(in thousands)
Earnings
	Income From Continuing Operations *			61,925			53,885			72,856			65,951			92,533			74,145
	Fixed Charges			35,458			30,915			34,305			55,621			72,217			58,361
	Distributed Income of Equity Investment			—			—			—			—			40,800			24,038
	Capitalized Interest			(1,478	)		(795	)		(2,133	)		(4,559	)		(4,000	)		(4,476	)

		Total Earnings		95,905			84,005			105,028			117,013			201,550			152,068

Fixed Charges
	Interest Expense			33,707			29,784			31,563			48,982			66,057			53,379
	Capitalized Interest			1,478			795			2,133			4,559			4,000			4,476
	Rental Interest Factor			273			336			609			2,080			2,160			506

		Total Fixed Charges		35,458			30,915			34,305			55,621			72,217			58,361

Ratio: Earnings / Fixed Charges				2.70			2.72			3.06			2.10			2.79			2.61

• Excludes minority interest, extraordinary loss and undistributed equity earnings.