TEPPCO PARTNERS LP - 10-Q Quarterly Report

Back to GetFilings.com

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2003

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

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 þ No o

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

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 July 29, 2003: 57,751,447

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF INCOME
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
		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 1. Legal Proceedings
	Item 6. Exhibits and Reports on Form 8-K.
SIGNATURES
INDEX TO EXHIBITS
Credit Agreement dated June 27, 2003
Statement of Computation of Ratio of Earnings
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS


		Page

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
	Consolidated Balance Sheets as of June 30, 2003 (unaudited) and December 31, 2002		1
	Consolidated Statements of Income for the three months and six months ended June 30, 2003 and 2002 (unaudited)		2
	Consolidated Statements of Cash Flows for the six months ended June 30, 2003 and 2002 (unaudited)		3
	Consolidated Statement of Partners’ Capital for the six months ended June 30, 2003 (unaudited)		4
	Notes to the Consolidated Financial Statements (unaudited)		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
	Forward-Looking Statements		46
Item 3. Quantitative and Qualitative Disclosures About Market Risk			46
Item 4. Controls and Procedures			48
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			48
Item 6. Exhibits and Reports on Form 8-K			48
Signatures			54

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)


				June 30,			December 31,
				2003			2002

				(Unaudited)
ASSETS
Current assets:
	Cash and cash equivalents			$	30,824		$	30,968
	Accounts receivable, trade (net of allowance for doubtful accounts of $5,395 and $4,537)				344,255			276,163
	Accounts receivable, related parties				3,153			4,313
	Inventories				20,225			17,166
	Other				28,722			31,670

		Total current assets			427,179			360,280

Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $315,231 and $338,746)					1,526,153			1,587,824
Equity investments					375,863			284,705
Intangible assets					445,633			465,374
Goodwill					16,944			16,944
Other assets					59,782			55,228

		Total assets		$	2,851,554		$	2,770,355

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
	Accounts payable and accrued liabilities			$	336,001		$	261,080
	Accounts payable, related parties				14,619			6,619
	Accrued interest				34,957			29,726
	Other accrued taxes				11,801			11,260
	Other				55,110			57,811

		Total current liabilities			452,488			366,496

Senior Notes					1,144,094			945,692
Other long-term debt					263,000			432,000
Other liabilities and deferred credits					15,524			30,962
Redeemable Class B Units held by related party					—			103,363
Commitments and contingencies
Partners’ capital:
	Accumulated other comprehensive loss				(11,351	)		(20,055	)
	General partner’s interest				5,849			12,770
	Limited partners’ interests				981,950			899,127

			Total partners’ capital		976,448			891,842

		Total liabilities and partners’ capital		$	2,851,554		$	2,770,355

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						Six Months Ended
			June 30,						June 30,

			2003			2002			2003			2002

Operating revenues:
	Sales of petroleum products		$	927,232		$	800,107		$	1,903,192		$	1,345,315
	Transportation – Refined products			37,802			31,803			64,696			56,947
	Transportation – LPGs			13,357			10,813			44,178			34,173
	Transportation – Crude oil			7,059			7,095			13,964			13,223
	Transportation – NGLs			9,440			10,544			19,339			16,850
	Gathering – Natural gas			32,264			11,454			66,546			20,974
	Mont Belvieu operations			—			2,889			—			7,395
	Other			13,646			13,624			28,124			24,589

		Total operating revenues		1,040,800			888,329			2,140,039			1,519,466

Costs and expenses:
	Purchases of petroleum products			912,344			787,574			1,875,188			1,320,545
	Operating, general and administrative			46,390			35,083			89,025			66,528
	Operating fuel and power			9,970			7,243			20,147			15,832
	Depreciation and amortization			23,487			17,599			50,800			33,640
	Taxes – other than income taxes			4,571			3,474			9,499			7,979
	Gain on sale of assets			(3,948	)		—			(3,948	)		—

		Total costs and expenses		992,814			850,973			2,040,711			1,444,524

		Operating income		47,986			37,356			99,328			74,942
Interest expense				(23,513	)		(16,829	)		(45,420	)		(33,616	)
Interest capitalized				963			1,029			1,559			3,138
Equity earnings				8,250			2,414			11,960			5,986
Other income – net				258			407			442			735

		Net income	$	33,944		$	24,377		$	67,869		$	51,185

Net Income Allocation:
Limited Partner Unitholders			$	24,654		$	16,467		$	47,741		$	35,061
Class B Unitholder				126			1,441			1,806			3,234
General Partner				9,164			6,469			18,322			12,890

		Total net income allocated	$	33,944		$	24,377		$	67,869		$	51,185

Basic and diluted net income per Limited Partner and Class B Unit			$	0.43		$	0.39		$	0.86		$	0.84

Weighted average Limited Partner and Class B Units outstanding				57,749			46,346			57,739			45,457

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

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


					Six Months Ended
					June 30,

					2003			2002

Cash flows from operating activities:
	Net income				$	67,869		$	51,185
	Adjustments to reconcile net income to cash provided by operating activities:
			Depreciation and amortization			50,800			33,640
			Earnings in equity investments, net of distributions			(1,220	)		7,444
			Gain on sale of assets			(3,948	)		—
			Non-cash portion of interest expense			3,075			2,284
			Increase in accounts receivable			(68,092	)		(56,270	)
			(Increase) decrease in inventories			(3,059	)		3,568
			(Increase) decrease in other current assets			2,948			(11,557	)
			Increase in accounts payable and accrued expenses			80,174			74,716
			Other			3,994			(7,552	)

				Net cash provided by operating activities		132,541			97,458

Cash flows from investing activities:
		Acquisition of additional interest in Centennial Pipeline LLC				(20,000	)		—
		Acquisition of crude oil assets				(5,459	)		—
		Proceeds from the sale of assets				8,531			3,380
		Purchase of Val Verde Gas Gathering System				—			(444,150	)
		Purchase of Chaparral NGL System				—			(132,140	)
		Purchase of Jonah Gas Gathering Company				—			(7,315	)
		Investment in Centennial Pipeline LLC				(1,000	)		(7,726	)
		Capital expenditures				(45,919	)		(63,560	)

				Net cash used in investing activities		(63,847	)		(651,511	)

Cash flows from financing activities:
		Proceeds from term and revolving credit facilities				335,000			642,000
		Repayments on term and revolving credit facilities				(504,000	)		(570,660	)
		Issuance of Senior Notes				198,570			497,805
		Debt issuance costs				(3,079	)		(7,043	)
		Issuance of Limited Partner Units, net				114,457			59,234
		Repurchase and retirement of Class B Units				(113,814	)		—
		General Partner’s contributions				2			1,217
		Distributions paid				(95,974	)		(68,575	)

				Net cash provided by (used in) financing activities		(68,838	)		553,978

Net decrease in cash and cash equivalents						(144	)		(75	)
Cash and cash equivalents at beginning of period						30,968			25,479

Cash and cash equivalents at end of period					$	30,824		$	25,404

Non-cash investing activities:
		Net assets transferred to Mont Belvieu Storage Partners, L.P.			$	69,459		$	—

Supplemental disclosure of cash flows:
		Cash paid for interest (net of amounts capitalized)			$	39,567		$	19,499

See accompanying Notes to Consolidated Financial Statements.

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(Unaudited)
(in thousands, except Unit amounts)


		Outstanding								Accumulated
		Limited		General			Limited			Other
		Partner		Partner’s			Partners’			Comprehensive
		Units		Interest			Interests			Loss			Total

Partners’ capital at December 31, 2002			53,809,597	$	12,770		$	899,127		$	(20,055	)	$	891,842
	Issuance of Limited Partner Units, net		3,938,750		—			114,422			—			114,422
	Retirement of Class B Units		—		—			(10,993	)		—			(10,993	)
	Net gain on cash flow hedges		—		—						8,704			8,704
	Net income allocation		—		18,322			47,741			—			66,063
	Cash distributions		—		(25,245	)		(68,382	)		—			(93,627	)
	Issuance of Limited Partner Units upon exercise of options		3,100		2			35			—			37

Partners’ capital at June 30, 2003			57,751,447	$	5,849		$	981,950		$	(11,351	)	$	976,448

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 and owns a 2% general partner interest in us. The General Partner is a wholly owned subsidiary of Duke Energy Field Services, LLC (“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 that are managed by DEFS on our behalf. We reimburse the General Partner for all reasonable direct and indirect expenses incurred in managing us.

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

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 June 30, 2003, and the results of our operations and cash flows for the periods presented. The results of operations for the three months and six months ended June 30, 2003, are not necessarily indicative of results of our operations for the full year 2003. 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 for the year ended December 31, 2002. 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.”

Net Income Per Unit

Basic net income per Limited Partner and Class B Unit (collectively, “Units”) is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 57.7 million and 45.5 million Units for the six months ended June 30, 2003, and 2002, respectively, and 57.7 million and 46.3 million Units for the three months ended June 30, 2003, and 2002, respectively). The General Partner’s percentage interest in our 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 $18.3 million (representing 26.99%) and $12.9 million (representing 25.18%) of net income for the six months ended June 30, 2003, and 2002, respectively. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, pursuant to our limited partnership agreement.

TEPPCO PARTNERS, L.P.

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

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 June 30, 2003, and 2002, the denominator was increased by 25,115 Units and 39,958 Units, respectively. For the six months ended June 30, 2003, and 2002, the denominator was increased by 23,414 Units and 45,036 Units, respectively.

New Accounting Pronouncements

In December 2002, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. We have not granted options for any periods presented. For options outstanding under our 1994 Long Term Incentive Plan, we followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, we record no compensation expense for unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Units on the date of the grant. Assuming we had used the fair value method of accounting for our unit option plan, pro forma net income for the six months ended June 30, 2002, would be lower than reported net income by an immaterial amount. Pro forma net income would equal reported net income for the three months ended June 30, 2003, and 2002, and for the six months ended June 30, 2003. Pro forma net income per Unit would equal reported net income per Unit for the periods presented. The adoption of SFAS 148 did not affect our financial position, results of operations or cash flows.

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. We are required to apply FIN 46 to all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, we are required to apply FIN 46 on July 1, 2003. In connection with the adoption of FIN 46, we evaluated our investments in Centennial Pipeline LLC, Seaway Crude Pipeline Company and Mont Belvieu Storage Partners, L.P. and determined that these entities are not variable interest entities as defined by FIN 46, and thus we have accounted for them as equity method investments (see Note 7. Equity Investments). We do not believe that the adoption of FIN 46 will have an effect on our financial position, results of operations or cash flows.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends SFAS 133 to conform and incorporate derivative implementation issues and subsequently issued accounting guidance. SFAS 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others and amends certain other existing pronouncements. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively. However, certain SFAS 133 implementation issues that were effective for all fiscal quarters prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. We are required to adopt SFAS 149 effective July 1, 2003. We

TEPPCO PARTNERS, L.P.

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

do not believe that the adoption of SFAS 149 will have a material effect on our financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS 150 establishes standards for how an issuer classifies and measures certain freestanding financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We are required to adopt SFAS 150 effective July 1, 2003. We do not believe that the adoption of SFAS 150 will have a material effect on our financial position, results of operations or cash flows.

In May 2003, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-04, Accounting for “Cash Balance” Pension Plans, to specifically address the accounting for certain cash balance pension plans. The consensus reached in EITF 03-04 requires certain cash balance pension plans to be accounted for as defined benefit plans. For cash balance plans described in the consensus, the consensus also requires the use of the traditional unit credit method for purposes of measuring the benefit obligation and annual cost of benefits earned as opposed to the projected unit credit method. We have historically accounted for our cash balance plans as defined benefit plans; however, we are required to adopt the measurement provisions of EITF 03-04 in our cash balance plans’ next measurement date of December 31, 2003. Any differences in the measurement of the obligation as a result of applying the consensus will be reported as a component of actuarial gain or loss. We do not believe that the adoption of EITF 03-04 will have a material effect on our financial position, results of operations or cash flows.

In May 2003, the EITF reached consensus in EITF 01-08, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, Accounting For Leases. We have historically leased storage capacity to outside parties as well as entered into pipeline capacity lease agreements both as the lessee and as a lessor. Upon application of EITF 01-08, the accounting requirements under the consensus could affect the timing of revenue and expense recognition, and revenues reported as transportation and storage services might have to be reported as rental or leasing income. Should capital-lease treatment be necessary, purchasers of transportation and storage services in the arrangements would have to recognize new assets on their balance sheets. The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning after May 28, 2003. Previous arrangements that would be leases or would contain a lease according to the consensus will continue to be accounted for as transportation and storage purchases or sales arrangements. We do not believe the adoption of EITF 01-08 will have a material effect on our financial position, results of operations or cash flows.

NOTE 2. ASSET RETIREMENT OBLIGATIONS

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 liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. Determination of any amounts recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.

TEPPCO PARTNERS, L.P.

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

The Downstream Segment assets consist primarily of a pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from wells owned by producers and transports natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionator facilities in Colorado.

We have completed our assessment of SFAS 143, and we have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the asset retirement obligations for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate.

In order to determine a removal date for our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil and natural gas, we are not a producer of the field reserves and as such, we do not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which we gather crude oil and natural gas. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates of our gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.

We will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. The adoption of SFAS 143 did not have an effect on our financial position, results of operations or cash flows.

NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001. SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually.

To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred.

TEPPCO PARTNERS, L.P.

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

At June 30, 2003, we had $16.9 million of unamortized goodwill and $25.5 million of excess investment in our equity investment in Seaway Crude Pipeline Company (equity method goodwill). The excess investment is included in our equity investments account at June 30, 2003. The following table presents the carrying amount of goodwill and equity method goodwill at June 30, 2003, by business segment (in thousands):


	Downstream		Midstream		Upstream		Segments
	Segment		Segment		Segment		Total

Goodwill	$	—	$	2,777	$	14,167	$	16,944
Equity method goodwill		—		—		25,502		25,502

Other Intangible Assets

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


			June 30, 2003					December 31, 2002

			Gross Carrying		Accumulated			Gross Carrying		Accumulated
			Amount		Amortization			Amount		Amortization

Amortized intangible assets:
	Fractionation agreement		$	38,000	$	(9,975	)	$	38,000	$	(9,025	)
	Natural gas gathering contracts			462,449		(47,178	)		462,449		(28,710	)
	Other			3,745		(1,408	)		3,745		(1,085	)

		Total	$	504,194	$	(58,561	)	$	504,194	$	(38,820	)

At June 30, 2003, we had $33.4 million of excess investment in our equity investment in Centennial Pipeline LLC, which was created upon formation of the company (see Note 7. Equity Investments). The excess investment is included in our equity investments account at June 30, 2003. This excess investment is accounted for as an intangible asset with an indefinite life. We will assess the intangible asset for impairment on an annual basis.

SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. With respect to our natural gas gathering contracts, we update throughput estimates and evaluate the remaining expected useful life of the contract assets on a quarterly basis based on the best available information. Amortization expense on intangible assets was $8.3 million and $4.7 million for the three months ended June 30, 2003 and 2002, respectively, and $19.7 million and $9.3 million for the six months ended June 30, 2003 and 2002, respectively.

The value assigned to our intangible assets for natural gas gathering contracts is amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. Due to our recent expansions on the gathering systems at Jonah Gas Gathering Company (“Jonah”) and because of certain limited production forecasts obtained from producers on the Jonah system related to the expansions, we have increased, in the second quarter of 2003, our best estimate of future throughput on the Jonah system. This increase in the estimate of future throughput will extend the amortization period of Jonah’s natural gas gathering contracts by an estimated 9 years, increasing from approximately 16 years to 25 years. Further revisions to this estimate may occur as additional information becomes available.

TEPPCO PARTNERS, L.P.

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

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


2003	$	42,455
2004		40,167
2005		39,534
2006		36,834
2007		33,990

NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS

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. This interest rate swap matures on April 6, 2004. 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 six months ended June 30, 2003, and 2002, we recognized increases in interest expense of $7.0 million and $6.3 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended June 30, 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. On June 27, 2003, we repaid the amounts outstanding under the revolving credit facility with borrowings under a new three year revolving credit facility and canceled the old facility (see Note 9. Debt). We redesignated the interest rate swap as a hedge of our exposure to increases in the benchmark interest rate underlying the new variable rate revolving credit facility. The fair value of the interest rate swap was a loss of approximately $11.4 million and $20.1 million at June 30, 2003, and December 31, 2002, respectively. The remaining fair value of the interest rate swap will be transferred into earnings over the remaining term of the interest rate swap.

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 six months ended June 30, 2003, and 2002, we recognized reductions in interest expense of $4.9 million and $3.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended June 30, 2003, 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 was a gain of approximately $15.1 million and $13.6 million at June 30, 2003, and December 31, 2002, respectively.

On February 20, 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional 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 of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, the swap agreements were terminated resulting in a gain of approximately $18.0 million. Concurrent with the swap terminations, we entered into new interest rate swap agreements, with identical terms as the previous swap agreements; however, the

TEPPCO PARTNERS, L.P.

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

floating rate was based upon a spread of an additional 50 basis points. In December 2002, the swap agreements entered into on July 16, 2002, were terminated, resulting in a gain of approximately $26.9 million. The gains realized from the July 2002 and December 2002 swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At June 30, 2003, the unamortized balance of the deferred gains was $42.4 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

NOTE 5. ACQUISITIONS AND DISPOSITIONS

Jonah Gas Gathering Company

On September 30, 2001, our subsidiaries completed the purchase of Jonah from Alberta Energy Company for $359.8 million. The acquisition served as our entry into the natural gas gathering industry. 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.

Chaparral NGL System

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 related costs of approximately $0.4 million. We funded the purchase by a borrowing under our $500.0 million revolving credit facility (see Note 9. Debt). 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. Under a contractual agreement, DEFS manages and operates Chaparral on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting, and we allocated the purchase price to property, plant and equipment. Accordingly, the results of the acquisition are included in the consolidated financial statements from March 1, 2002.

Val Verde Gas Gathering Company

On June 30, 2002, we completed the purchase of Val Verde Gas Gathering Company (“Val Verde”) for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. We funded the purchase by borrowings of $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 9. Debt). The remaining purchase price was funded through working capital sources of cash. The Val Verde system gathers coal bed methane (“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from June 30, 2002.

TEPPCO PARTNERS, L.P.

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

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


Property, plant and equipment		$	205,146
Intangible assets (primarily gas gathering contracts)			239,649

	Total assets		444,795

Total liabilities assumed			(645	)

	Net assets acquired	$	444,150

The value assigned to intangible assets relates to fixed-term contracts with customers. We are amortizing the value assigned to intangible assets on a units-of-production basis, based upon the actual throughput of the system over the expected total throughput for the contracts. The period of amortization is expected to be approximately 20 years from the date of acquisition.

The following table presents our unaudited pro forma results as though the acquisition of Val Verde occurred at the beginning of 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 acquisition, 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.


	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2002		2002

Revenues	$	908,010	$	1,557,251
Operating income		43,909		86,412
Net income		29,652		60,327
Basic and diluted net income per Limited Partner and Class B Unit	$	0.38	$	0.79

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 acquisition been consummated at the beginning of 2002, or the results which may be attained in the future.

Rancho Pipeline

We owned an approximate 25% undivided joint interest in the Rancho Pipeline, which was a pipeline system acquired in connection with our acquisition of crude oil assets in 2000. Under the terms of the Rancho Pipeline operating agreement, the operating agreement terminated in March 2003, and the Rancho Pipeline ceased operations in crude oil service from West Texas to Houston, Texas. The Rancho Pipeline was divided into segments, and these segments were sold to certain of the current owners of the Rancho Pipeline. We acquired approximately 230 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold portions of the segment acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions, which is included in the gain on sale of assets in our consolidated statements of income.

TEPPCO PARTNERS, L.P.

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

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):


		June 30,		December 31,
		2003		2002

Crude oil		$	214	$	—
Gasolines			3,305		4,700
Butanes			3,846		1,991
Transmix			1,712		2,526
Other products			4,326		3,836
Materials and supplies			6,822		4,113

	Total	$	20,225	$	17,166

The costs of inventories did not exceed market values at June 30, 2003, and December 31, 2002.

NOTE 7. EQUITY INVESTMENTS

Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway Crude Pipeline Company (“Seaway”). The remaining 50% interest is owned by ConocoPhillips. Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston areas. The 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, we received 80% of revenue and expense of Seaway. From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and expense to us. For the year ended December 31, 2002, our portion of equity earnings on a pro-rated basis averaged approximately 67%.

In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial Pipeline LLC (“Centennial”). Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Through February 9, 2003, each participant owned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired an additional interest in Centennial from PEPL for $20.0 million each, increasing their percentage ownerships in Centennial to 50% each. During the six months ended June 30, 2003, excluding the amount paid for the acquisition of the additional ownership interest, TE Products contributed approximately $1.0 million for its investment in Centennial, which is included in the equity investment balance at June 30, 2003.

As of January 1, 2003, TE Products and Louis Dreyfus Energy Services, L.P. (“Louis Dreyfus”) effectively formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership interest in MB Storage. The purpose of MB Storage 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. MB Storage is a service-oriented, fee-based venture with no commodity trading activity. TE Products continues to operate the facilities for MB Storage. Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $75.5 million to MB Storage. Additionally, as of the contribution date, Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was

TEPPCO PARTNERS, L.P.

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

terminated by either party. This deferred liability was also contributed and converted to the capital account of Louis Dreyfus in MB Storage.

We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway and Centennial for the six months ended June 30, 2003 and 2002, and MB Storage for the six months ended June 30, 2003, is presented below (in thousands):


	Six Months Ended
	June 30,

	2003		2002

Revenues	$	59,759	$	35,847
Net income		18,301		5,256

Summarized combined balance sheet data for Seaway and Centennial as of June 30, 2003, and December 31, 2002, and for MB Storage as of June 30, 2003, is presented below (in thousands):


	June 30,		December 31,
	2003		2002

Current assets	$	52,362	$	32,528
Noncurrent assets		619,450		551,324
Current liabilities		39,936		28,681
Long-term debt		140,000		140,000
Noncurrent liabilities		13,831		14,875
Partners’ capital		478,045		400,296

Our investments in Seaway and Centennial include excess net investment amounts of $25.5 million and $33.4 million, respectively. 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. PARTNERS’ CAPITAL

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3,916,547 previously outstanding Class B Units held by Duke Energy Transport and Trading Company, LLC (“DETTCO”), an affiliate of Duke Energy. We received approximately $0.7 million in proceeds from the offering in excess of the amount needed to repurchase and retire the Class B Units.

NOTE 9. 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 of $0.3 million and are

TEPPCO PARTNERS, L.P.

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

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 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 June 30, 2003, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million 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 June 30, 2003, we were in compliance with the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on our $500.0 million revolving credit facility to $250.0 million. The balance of the net proceeds received was used for general purposes. 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 6.125% 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 June 30, 2003, 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 a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”). 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 for the Three Year Facility contained certain restrictive financial covenant ratios. During 2002, borrowings under the Three Year Facility were used to finance the acquisitions of Chaparral on March 1, 2002, and Val Verde on June 30, 2002, and for general purposes. During 2002, repayments were made on the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes, proceeds from the issuance of additional Units and proceeds from the termination of interest rate swaps (see Note 4. Derivative Financial Instruments). During the

TEPPCO PARTNERS, L.P.

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

first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.

On June 27, 2003, we entered into a $550.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”) with a three year term. 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 Revolving Credit Facility contains certain restrictive financial covenant ratios. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On June 30, 2003, $263.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate, before the effects of hedging activities, of 1.8%. At June 30, 2003, 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 a portion of the credit facilities discussed above. See Note 4. Derivative Financial Instruments.

Short Term Credit Facilities

On April 6, 2001, we entered into a 364-day, $200.0 million revolving credit agreement (“Short-term Revolver”). 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 certain restrictive financial covenant ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. During 2002, borrowings under the Short-term Revolver were used to finance the acquisition of the Val Verde assets and for other purposes. During 2002, we repaid the existing amounts outstanding under the Short-term Revolver with proceeds we received from the issuance of Units in 2002. The Short-term Revolver expired on March 27, 2003.

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 and Dispositions). 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 certain restrictive financial covenant ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal from proceeds primarily received from the issuance of 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 Units in September 2002, and canceled the facility.

TEPPCO PARTNERS, L.P.

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

The following table summarizes the principal outstanding under our credit facilities as of June 30, 2003, and December 31, 2002 (in thousands):


			June 30,		December 31,
			2003		2002

Long Term Credit Facilities:
	Three Year Facility, due April 2004		$	—	$	432,000
	Revolving Credit Facility, due June 2006			263,000		—
	6.45% TE Products Senior Notes, due January 2008			179,860		179,845
	7.625% Senior Notes, due February 2012			498,136		497,995
	6.125% Senior Notes, due February 2013			198,630		—
	7.51% TE Products Senior Notes, due January 2028			210,000		210,000

		Total borrowings		1,349,626		1,319,840
	Adjustment to carrying value associated with hedges of fair value			57,468		57,852

		Total Long Term Credit Facilities	$	1,407,094	$	1,377,692

NOTE 10. QUARTERLY DISTRIBUTIONS 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. Pursuant 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	%

The following table reflects the allocation of total distributions paid during the six months ended June 30, 2003, and 2002 (in thousands, except per Unit amounts).


		Six Months Ended June 30,

		2003		2002

Limited Partner Units		$	68,382	$	47,646
General Partner Ownership Interest			1,444		1,064
General Partner Incentive			23,801		15,361

	Total Partners’ Capital Cash Distributions		93,627		64,071
Class B Units			2,347		4,504

	Total Cash Distributions Paid	$	95,974	$	68,575

Total Cash Distributions Paid Per Unit		$	1.225	$	1.150

On August 8, 2003, we will pay a cash distribution of $0.625 per Unit for the quarter ended June 30, 2003. The second quarter 2003 cash distribution will total $49.4 million.

TEPPCO PARTNERS, L.P.

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

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 intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.

Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, 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 the results of operations of the northern portion of the Dean Pipeline. Beginning in January 2003, the northern portion of the Dean Pipeline was converted to transport refinery grade propylene (“RGPs”) from Mont Belvieu to Point Comfort, Texas. As a result, the revenues and expenses of the northern portion of the Dean Pipeline are included in the Downstream Segment. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 7. Equity Investments).

Our 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. Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the Central United States, and to refineries in the Texas City and Houston areas.

Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah and the gathering of CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, through Val Verde. DEFS manages and operates the Val Verde, Jonah and Chaparral assets for us under contractual agreements. The results of operations of the Chaparral and Val Verde acquisitions are included in periods subsequent to their respective acquisition dates (see Note 5. Acquisitions and Dispositions).

TEPPCO PARTNERS, L.P.

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

The table below includes interim financial information by reporting segment for the interim periods ended June 30, 2003 and 2002 (in thousands):


		Three Months Ended June 30, 2003

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

Revenues		$	60,058	$	936,698		$	44,462	$	1,041,218		$	(418	)	$	1,040,800
Purchases of petroleum products			—		912,762			—		912,762			(418	)		912,344
Operating expenses, including power			36,268		13,755			10,908		60,931			—			60,931
Depreciation and amortization expense			7,067		2,466			13,954		23,487			—			23,487
Gain on sale of assets			—		(3,948	)		—		(3,948	)		—			(3,948	)

	Operating income		16,723		11,663			19,600		47,986			—			47,986
Equity earnings			64		8,186			—		8,250			—			8,250
Other income, net			55		213			27		295			(37	)		258

	Earnings before interest	$	16,842	$	20,062		$	19,627	$	56,531		$	(37	)	$	56,494


		Three Months Ended June 30, 2002

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

Revenues		$	54,656		$	809,779	$	24,366	$	888,801	$	(472	)	$	888,329
Purchases of petroleum products			—			788,046		—		788,046		(472	)		787,574
Operating expenses, including power			28,715			12,582		4,503		45,800		—			45,800
Depreciation and amortization expense			7,364			2,089		8,146		17,599		—			17,599

	Operating income		18,577			7,062		11,717		37,356		—			37,356
Equity earnings			(2,190	)		4,604		—		2,414		—			2,414
Other income, net			70			175		162		407		—			407

	Earnings before interest	$	16,457		$	11,841	$	11,879	$	40,177	$	—		$	40,177

TEPPCO PARTNERS, L.P.

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


		Six Months Ended June 30, 2003

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

Revenues		$	128,023		$	1,922,078		$	91,366	$	2,141,467		$	(1,428	)	$	2,140,039
Purchases of petroleum products			—			1,876,616			—		1,876,616			(1,428	)		1,875,188
Operating expenses, including power			67,817			28,592			22,262		118,671			—			118,671
Depreciation and amortization expense			14,214			5,531			31,055		50,800			—			50,800
Gain on sale of assets			—			(3,948	)		—		(3,948	)		—			(3,948	)

	Operating income		45,992			15,287			38,049		99,328			—			99,328
Equity earnings			(1,195	)		13,155			—		11,960			—			11,960
Other income, net			49			402			64		515			(73	)		442

	Earnings before interest	$	44,846		$	28,844		$	38,113	$	111,803		$	(73	)	$	111,730


		Six Months Ended June 30, 2002

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

Revenues		$	114,242		$	1,363,667	$	42,736	$	1,520,645	$	(1,179	)	$	1,519,466
Purchases of petroleum products			—			1,321,724		—		1,321,724		(1,179	)		1,320,545
Operating expenses, including power			57,822			24,521		7,996		90,339		—			90,339
Depreciation and amortization expense			14,196			4,153		15,291		33,640		—			33,640

	Operating income		42,224			13,269		19,449		74,942		—			74,942
Equity earnings			(2,986	)		8,972		—		5,986		—			5,986
Other income, net			194			360		181		735		—			735

	Earnings before interest	$	39,432		$	22,601	$	19,630	$	81,663	$	—		$	81,663

The following table provides the total assets, capital expenditures and significant non-cash investing activities for each segment as of and for the periods ended June 30, 2003, and December 31, 2002 (in thousands):


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

June 30, 2003:
	Total assets	$	935,657	$	794,164	$	1,155,173	$	2,884,994	$	(33,440	)	$	2,851,554
	Capital expenditures		25,376		6,226		14,317		45,919		—			45,919
	Non-cash investing activities		69,459		—		—		69,459		—			69,459
December 31, 2002:
	Total assets		883,163		724,860		1,174,010		2,782,033		(11,678	)		2,770,355
	Capital expenditures		60,900		10,212		62,260		133,372		—			133,372

TEPPCO PARTNERS, L.P.

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

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


		Three Months Ended June 30,						Six Months Ended June 30,

		2003			2002			2003			2002

Earnings before interest		$	56,494		$	40,177		$	111,730		$	81,663
Interest expense			(23,513	)		(16,829	)		(45,420	)		(33,616	)
Interest capitalized			963			1,029			1,559			3,138

	Net income	$	33,944		$	24,377		$	67,869		$	51,185

NOTE 12. COMMITMENTS AND CONTINGENCIES

In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we 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. We have 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 we are defending ourselves 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, styled 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 ourselves 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. On July 16, 2003, the parties entered into a Settlement Agreement and Mutual Release, dismissing all claims and counterclaims against each other. The terms of the Settlement Agreement and Mutual Release will not have a material adverse effect on our financial position, results of operations or cash flows.

In May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as the result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary

TEPPCO PARTNERS, L.P.

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

investigation, the General Partner believes that the only claim asserted against it results from one individual for the period of July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period is a relatively minor period with respect to the total alleged exposure period for this individual from January 1964 through December 2001. The individual’s claims involve numerous employers and alleged job sites. Currently, the General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is currently uncertain whether this case is covered by insurance. Discovery is planned and, if the General Partner is unable to obtain early voluntary dismissal, the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. 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.

On April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The plaintiffs allege personal injuries ranging from headaches and allergies to birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 and January 2002. The plaintiffs have made a global settlement offer of $198.5 million. The defendants have made a global settlement counteroffer of $20.0 million, which is based on a per capita payment of $80,000 per party. Marathon is handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. Based upon Centennial’s limited involvement with the disposal site, we do not believe that the outcome of this matter 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.

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, 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 June 30, 2003, we have an accrued liability of $0.1 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.

TEPPCO PARTNERS, L.P.

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

On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Preliminary Injunction and Order (“Agreed Order”) with the State of Illinois. The Agreed Order requires us, in part, to complete a site investigation plan to delineate the scope of any potential contamination resulting from the release and to remediate any contamination. The Agreed Order does not contain any provision for any fines or penalties; however, it does not preclude the State of Illinois from assessing these at a later date. 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.

At June 30, 2003, we have an accrued liability of $6.6 million related to various TCTM sites requiring environmental remediation activities. We have a contractual indemnity obligation from DETTCO, an affiliate of Duke Energy, that we received in connection with our acquisition of assets from DETTCO in November 1998. The indemnity relates to future environmental remediation activities attributable to operations of these assets prior to our acquisition. Under this indemnity obligation, we are responsible for the first $3.0 million in specified environmental liabilities, and DETTCO is responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. At December 31, 2002, we had a receivable balance from DETTCO of $4.2 million, the majority of which related to remediation activities at the Velma crude oil site in Stephens County, Oklahoma. On March 31, 2003, we received $2.4 million under the indemnity obligation with DETTCO. The remaining $1.8 million due was subsequently written off as a result of final settlement discussions with DETTCO on this matter. The accrued liability balance at June 30, 2003, also includes an accrual of $2.3 million related to a crude oil site. We are currently in discussions with DETTCO regarding various matters relative to DETTCO’s indemnifications. 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 June 30, 2003, $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, including TE Products, originally guaranteed one-third of Centennial’s 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 Centennial guaranty. Effective September 27, 2002, 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 was 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 had provided for PEPL. In connection with the acquisition of the additional interest in Centennial on February 10, 2003, the guaranty agreement between TE Products, Marathon, and PEPL was terminated. TE Products’ guaranty of up to a maximum of $75.0 million of Centennial’s debt remains in effect.

In May 2003, we entered into an agreement with Williams Gas Processing Company (“Williams”) that requires Williams to build, own, and operate a central dehydration facility to be used as a bulk water removal plant for gas gathered on the Jonah system. The cost of building this facility was estimated at $4.5 million. Under the agreement, Williams will supply the land for the facility, and we are required to deposit $4.5 million into an escrow account to be used by Williams to cover costs of construction of the facility. Williams will retain ultimate title to the facility, and we will be reimbursed for the escrowed amounts used by Williams through surcharges paid to us by the producers on the Jonah system. In accordance with the agreement, we funded $1.0 million of the $4.5 million required escrow amount in the second quarter of 2003, and we are obligated to fund the remaining $3.5 million by August 31, 2003.

TEPPCO PARTNERS, L.P.

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

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 six months ended June 30, 2003, and 2002, 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 for the three months and six months ended June 30, 2003, and 2002 (in thousands).


		Three Months Ended June 30,					Six Months Ended June 30,

		2003		2002			2003		2002

Net income		$	33,944	$	24,377		$	67,869	$	51,185
Net income (loss) on cash flow hedges			3,235		(2,952	)		8,704		348

	Total comprehensive income	$	37,179	$	21,425		$	76,573	$	51,533

The accumulated balance of other comprehensive loss related to cash flow hedges is as follows (in thousands):


Balance at December 31, 2001		$	(20,324	)
	Net income on cash flow hedges		269

Balance at December 31, 2002		$	(20,055	)
	Net income on cash flow hedges		8,704

Balance at June 30, 2003		$	(11,351	)

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 Guarantor Subsidiaries have also issued guarantees of our 6.125% Senior Notes issued in January 2003.

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)


			June 30, 2003

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

							(in thousands)
Assets
	Current assets		$	21,836	$	100,260	$	354,522	$	(49,439	)	$	427,179
	Property, plant and equipment – net			—		1,068,212		457,941		—			1,526,153
	Equity investments			987,830		935,581		213,702		(1,761,250	)		375,863
	Intercompany notes receivable			996,372		—		—		(996,372	)		—
	Intangible assets			—		416,438		29,195		—			445,633
	Other assets			6,420		33,102		37,204		—			76,726

		Total assets	$	2,012,458	$	2,553,593	$	1,092,564	$	(2,807,061	)	$	2,851,554

Liabilities and partners’ capital
	Current liabilities		$	22,444	$	113,289	$	354,137	$	(37,382	)	$	452,488
	Long-term debt			1,002,214		404,880		—		—			1,407,094
	Intercompany notes payable			—		578,832		418,249		(997,081	)		—
	Other long term liabilities			—		15,315		209		—			15,524
	Total partners’ capital			987,800		1,441,277		319,969		(1,772,598	)		976,448

		Total liabilities and partners’ capital	$	2,012,458	$	2,553,593	$	1,092,564	$	(2,807,061	)	$	2,851,554


			December 31, 2002

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

							(in thousands)
Assets
	Current assets		$	241	$	92,511	$	286,379	$	(18,851	)	$	360,280
	Property, plant and equipment – net			—		1,128,803		459,021		—			1,587,824
	Equity investments			1,011,935		846,991		211,229		(1,785,450	)		284,705
	Intercompany notes receivable			986,852		—		—		(986,852	)		—
	Intangible assets			—		434,941		30,433		—			465,374
	Other assets			6,200		31,135		34,837		—			72,172

		Total assets	$	2,005,228	$	2,534,381	$	1,021,899	$	(2,791,153	)	$	2,770,355

Liabilities and partners’ capital
	Current liabilities		$	30,715	$	122,882	$	272,538	$	(59,639	)	$	366,496
	Long-term debt			974,264		403,428		—		—			1,377,692
	Intercompany notes payable			—		508,652		437,411		(946,063	)		—
	Other long term liabilities			6,523		24,230		209		—			30,962
	Redeemable Class B Units held by related party			103,363		—		—		—			103,363
	Total partners’ capital			890,363		1,475,189		311,741		(1,785,451	)		891,842

		Total liabilities and partners’ capital	$	2,005,228	$	2,534,381	$	1,021,899	$	(2,791,153	)	$	2,770,355

TEPPCO PARTNERS, L.P.

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


		Three Months Ended June 30, 2003

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

								(in thousands)
Operating revenues		$	—		$	91,812		$	949,406		$	(418	)	$	1,040,800
Costs and expenses			—			62,363			934,817			(418	)		996,762
Gain on sale of assets			—			—			(3,948	)		—			(3,948	)

	Operating income		—			29,449			18,537			—			47,986

Interest expense – net			(19,007	)		(14,472	)		(8,115	)		19,044			(22,550	)
Equity earnings			33,944			26,550			8,186			(60,430	)		8,250
Other income – net			19,007			49			246			(19,044	)		258

	Net income	$	33,944		$	41,576		$	18,854		$	(60,430	)	$	33,944


			Three Months Ended June 30, 2002

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

									(in thousands)
Operating revenues			$	—		$	66,574		$	822,227		$	(472	)	$	888,329
Costs and expenses				—			43,612			807,833			(472	)		850,973

	Operating income			—			22,962			14,394			—			37,356

Interest expense – net				(11,706	)		(8,888	)		(6,912	)		11,706			(15,800	)
Equity earnings				24,377			12,442			4,604			(39,009	)		2,414
Other income – net				11,706			220			187			(11,706	)		407

		Net income	$	24,377		$	26,736		$	12,273		$	(39,009	)	$	24,377


		Six Months Ended June 30, 2003

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

								(in thousands)
Operating revenues		$	—		$	193,891		$	1,947,576		$	(1,428	)	$	2,140,039
Costs and expenses			—			123,240			1,922,847			(1,428	)		2,044,659
Gain on sale of assets			—			—			(3,948	)		—			(3,948	)

	Operating income		—			70,651			28,677			—			99,328

Interest expense – net			(36,416	)		(27,991	)		(15,943	)		36,489			(43,861	)
Equity earnings			67,869			40,104			13,155			(109,168	)		11,960
Other income – net			36,416			38			477			(36,489	)		442

	Net income	$	67,869		$	82,802		$	26,366		$	(109,168	)	$	67,869

TEPPCO PARTNERS, L.P.

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


		Six Months Ended June 30, 2002

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

								(in thousands)
Operating revenues		$	—		$	136,362		$	1,384,283		$	(1,179	)	$	1,519,466
Costs and expenses			—			86,636			1,359,067			(1,179	)		1,444,524

	Operating income		—			49,726			25,216			—			74,942

Interest expense – net			(23,139	)		(16,538	)		(13,940	)		23,139			(30,478	)
Equity earnings			51,185			20,550			8,972			(74,721	)		5,986
Other income – net			23,139			353			382			(23,139	)		735

	Net income	$	51,185		$	54,091		$	20,630		$	(74,721	)	$	51,185


			Six Months Ended June 30, 2003

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

									(in thousands)
Cash flows from operating activities
Net income			$	67,869		$	82,802		$	26,366		$	(109,168	)	$	67,869
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization		—			40,590			10,210			—			50,800
		Equity earnings, net of distributions		28,105			4,670			(2,415	)		(31,580	)		(1,220	)
		Changes in assets and liabilities and other		(24,615	)		17,259			(1,154	)		23,602			15,092

Net cash provided by operating activities				71,359			145,321			33,007			(117,146	)		132,541

Cash flows from investing activities				(2,519	)		(59,883	)		(3,964	)		2,519			(63,847	)
Cash flows from financing activities				(68,840	)		(79,927	)		(34,698	)		114,627			(68,838	)

Net increase (decrease) in cash and cash equivalents				—			5,511			(5,655	)		—			(144	)
Cash and cash equivalents at beginning of period				—			8,247			22,721			—			30,968

Cash and cash equivalents at end of period			$	—		$	13,758		$	17,066		$	—		$	30,824

TEPPCO PARTNERS, L.P.

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


			Six Months Ended June 30, 2002

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

									(in thousands)
Cash flows from operating activities
Net income			$	51,185		$	54,091		$	20,630		$	(74,721	)	$	51,185
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization		—			25,021			8,619			—			33,640
		Equity earnings, net of distributions		17,391			2,142			4,458			(16,547	)		7,444
		Changes in assets and liabilities and other		(564,188	)		25,389			(17,880	)		561,868			5,189

Net cash provided by (used in) operating activities				(495,612	)		106,643			15,827			470,600			97,458

Cash flows from investing activities				(58,406	)		(511,431	)		(140,080	)		58,406			(651,511	)
Cash flows from financing activities				554,018			408,499			120,467			(529,006	)		553,978

Net increase (decrease) in cash and cash equivalents				—			3,711			(3,786	)		—			(75	)
Cash and cash equivalents at beginning of period				—			3,655			21,824			—			25,479

Cash and cash equivalents at end of period			$	—		$	7,366		$	18,038		$	—		$	25,404

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 trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings. The 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 for the year ended December 31, 2002.

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, Inc., our wholly owned subsidiary, acts as managing general partner of our Operating Partnerships, with a 0.001% general partner interest and manages our subsidiaries.

Our 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 consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the Central United States, and to refineries in the Texas City and Houston areas.

the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, through Val Verde Gas Gathering Company (“Val Verde”). DEFS manages and operates the Val Verde, Jonah and Chaparral assets for us under contractual agreements. The results of operations of the Chaparral and Val Verde acquisitions are included in periods subsequent to their respective acquisition dates (see Note 5. Acquisitions and Dispositions).

Results of Operations

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


			Three Months Ended June 30,						Six Months Ended June 30,

			2003			2002			2003			2002

Operating revenues:
	Downstream Segment		$	60,058		$	54,656		$	128,023		$	114,242
	Upstream Segment			936,698			809,779			1,922,078			1,363,667
	Midstream Segment			44,462			24,366			91,366			42,736
	Intersegment eliminations			(418	)		(472	)		(1,428	)		(1,179	)

		Total operating revenues		1,040,800			888,329			2,140,039			1,519,466

Operating income:
	Downstream Segment			16,723			18,577			45,992			42,224
	Upstream Segment			11,663			7,062			15,287			13,269
	Midstream Segment			19,600			11,717			38,049			19,449

		Total operating income		47,986			37,356			99,328			74,942

Earnings before interest:
	Downstream Segment			16,842			16,457			44,846			39,432
	Upstream Segment			20,062			11,841			28,844			22,601
	Midstream Segment			19,627			11,879			38,113			19,630
	Intersegment eliminations			(37	)		—			(73	)		—

		Total earnings before interest		56,494			40,177			111,730			81,663

Interest expense				(23,513	)		(16,829	)		(45,420	)		(33,616	)
Interest capitalized				963			1,029			1,559			3,138

		Net income	$	33,944		$	24,377		$	67,869		$	51,185

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 volumes delivered in barrels and average tariff per barrel for the three months and six months ended June 30, 2003, and 2002:


			Three Months Ended							Six Months Ended
			June 30,				Percentage			June 30,				Percentage
							Increase							Increase
			2003		2002		(Decrease)			2003		2002		(Decrease)

					(in thousands, except tariff information)
Volumes Delivered
	Refined products			42,256		35,344		20	%		72,488		61,109		19	%
	LPGs			6,832		7,056		(3	%)		20,532		19,091		8	%

		Total		49,088		42,400		16	%		93,020		80,200		16	%

Average Tariff per Barrel
	Refined products		$	0.89	$	0.90		(1	%)	$	0.89	$	0.93		(4	%)
	LPGs			1.96		1.53		28	%		2.15		1.79		20	%
		Average system tariff per barrel	$	1.04	$	1.01		3	%	$	1.17	$	1.14		3	%

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

Our Downstream Segment reported earnings before interest of $16.8 million for the three months ended June 30, 2003, compared with earnings before interest of $16.4 million for the three months ended June 30, 2002. Earnings before interest increased $0.4 million primarily due to an increase of $5.4 million in operating revenues and increased income of $2.3 million from equity investments, partially offset by an increase of $7.3 million in costs and expenses. We discuss the factors influencing these variances below.

Revenues from refined products transportation increased $6.0 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002, due to an overall increase of 20% in the refined products volumes delivered. This increase was primarily due to deliveries of product received into our pipeline from Centennial at Creal Springs, Illinois. Centennial, which commenced refined products deliveries to us in April 2002, has provided our system with additional pipeline capacity for product originating in the U.S. Gulf Coast area. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs. The 20% increase in our overall refined products deliveries was composed of a 19% increase in motor fuel deliveries, a 29% increase in distillate volume deliveries, a 6% increase in jet fuel deliveries and a 25% increase in natural gasoline deliveries from the prior year period. Volume increases were due to increased demand for product supplied by the U.S. Gulf Coast into Midwest markets resulting from colder weather during the second quarter of 2003, which both increased demand for and caused higher prices of natural gas. As a result of high natural gas prices, utilities use distillates as a substitute for natural gas for their facilities. The refined products average rate per barrel decreased 1% from the prior year period primarily due to the impact of the Midwest origin point for volumes received from Centennial, which resulted in an increase in short-haul volumes transported on our system.

Revenues from LPGs transportation increased $2.5 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002, primarily due to increased deliveries of propane in the upper Midwest and Northeast market areas attributable to colder weather during the second quarter of 2003 and the impact of lower inventories at competing supply locations. Butane deliveries also increased in the Midwest as a result of increased isobutane deliveries to refineries in the Chicago area. The decrease in total volumes of LPGs delivered was due primarily to decreased short-haul deliveries of LPGs to Gulf Coast petrochemical facilities attributable to higher prices of propane relative to other feedstocks. The LPGs average rate per barrel increased 28% from the prior year period as a result of an increased percentage of long-haul deliveries during the three months ended June 30, 2003.

Effective January 1, 2003, TE Products’ 50% ownership interest in MB Storage is accounted for as an equity investment. Revenues generated from Mont Belvieu operations totaled $2.9 million during the three months ended June 30, 2002. As a result of the formation of MB Storage, revenues and expenses related to Mont Belvieu operations are now recorded within equity earnings. See discussion regarding changes in equity earnings/losses below. The purpose of MB Storage 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.

Other operating revenues decreased $0.2 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002, primarily due to lower volume of product inventory sales and lower revenues from product location exchanges which are used to position product in the Midwest market area, partially offset by higher propane deliveries at our Providence, Rhode Island import facility and higher refined product rental charges and loading fees. Other operating revenues also increased $1.3 million due to the addition of the northern portion of the Dean Pipeline to the Downstream Segment in January 2003, which began transporting RGPs in January 2003.

Costs and expenses increased $7.3 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002. The increase was made up of an increase of $5.7 million in operating, general and administrative expenses and an increase of $2.2 million in operating fuel and power, partially offset by a decrease of $0.3 million in depreciation and amortization expense and a decrease of $0.3 million in taxes – other than income taxes. Operating, general and administrative expenses increased primarily due to higher pipeline maintenance expenses, increased consulting and contract services, increased labor costs and increased general and administrative supplies expense, increased insurance expense and expense from the Centennial lease agreement that we entered into in 2003. The addition of the northern portion of the Dean Pipeline to the Downstream Segment increased operating, general and administrative expense by $0.2 million. Operating fuel and power expense increased as a result of increased mainline throughput and higher power costs due to an increase in the price of natural gas. Depreciation expense decreased from the prior year period because of assets retired during the three months ended June 30, 2003, which reduced the asset base, and due to the assets transferred to MB Storage, which also reduced depreciation expense. Taxes – other than income taxes decreased as a result of actual property taxes being lower than previously estimated and due to the transfer of assets to MB Storage.

Net losses from equity investments decreased $2.3 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002. Centennial, which commenced operations in April 2002, accounted for $1.8 million of the equity losses during the three months ended June 30, 2003. On February 10, 2003, TE Products acquired an additional 16.7% interest in Centennial, bringing its ownership interest to 50%. The losses from Centennial are offset by equity earnings of $1.9 million from our 50% ownership interest in MB Storage, which was formed effective January 1, 2003. Amounts in the prior year period related to Mont Belvieu operations recorded to revenues and costs and expenses are now being recorded within equity earnings based upon our 50% ownership interest in MB Storage, effective with its formation on January 1, 2003. If the 2002 revenues and costs and expenses from the Mont Belvieu operations had been accounted for under the same method as 2003, equity earnings would have increased $0.4 million in 2003, compared with the prior year, due to increased contract shuttle deliveries and increased storage revenue.

Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

Our Downstream Segment reported earnings before interest of $44.8 million for the six months ended June 30, 2003, compared with earnings before interest of $39.4 million for the six months ended June 30, 2002. Earnings before interest increased $5.4 million primarily due to an increase of $13.8 million in operating revenues and increased income of $1.8 million from equity investments, partially offset by an increase of $10.0 million in costs and expenses and a decrease of $0.2 million in other income – net. We discuss the factors influencing these variances below.

Revenues from refined products transportation increased $7.7 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002, due to an overall increase of 19% in the refined products volumes delivered. This increase was primarily due to deliveries of product received into our pipeline from

Centennial at Creal Springs, Illinois. Centennial, which commenced refined products deliveries to us in April 2002, has provided our system with additional pipeline capacity for product originating in the U.S. Gulf Coast area. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs. The 19% increase in our overall refined products deliveries was composed of an 18% increase in motor fuel deliveries, a 28% increase in distillate volume deliveries, a 4% increase in jet fuel deliveries and a 33% increase in natural gasoline deliveries from the prior year period. Volume increases were due to increased demand for product supplied by the U.S. Gulf Coast into Midwest markets resulting from colder weather during the second quarter of 2003, which both increased demand for and caused higher prices of natural gas. As a result of high natural gas prices, utilities use distillates as a substitute for natural gas for their facilities. The refined products average rate per barrel decreased 4% from the prior year period primarily due to the impact of the Midwest origin point for volumes received from Centennial, which resulted in an increase in short-haul volumes transported on our system.

Revenues from LPGs transportation increased $10.0 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002, primarily due to increased deliveries of propane in the upper Midwest and Northeast market areas attributable to colder than normal weather during the first quarter of 2003 and due to low inventories at competing supply locations. Butane deliveries also increased due to the increased demand by refineries for normal butane for use in gasoline blending and increased isobutane deliveries to Chicago area refineries. The LPGs average rate per barrel increased 20% from the prior year period as a result of an increased percentage of long-haul deliveries during the six months ended June 30, 2003.

Effective January 1, 2003, TE Products’ 50% ownership interest in MB Storage is accounted for as an equity investment. Revenues generated from Mont Belvieu operations totaled $7.4 million during the six months ended June 30, 2002. As a result of the formation of MB Storage, revenues and expenses related to Mont Belvieu operations are now recorded within equity earnings. See discussion regarding changes in equity earnings/losses below. The purpose of MB Storage 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.

Other operating revenues increased $3.5 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002, primarily due to higher propane deliveries at our Providence, Rhode Island import facility, higher refined product rental charges and loading fees and higher revenues from product loans. Other operating revenues also increased $2.2 million due to the addition of the northern portion of the Dean Pipeline to the Downstream Segment in January 2003, which began transporting RGPs in January 2003. These increases were partially offset by lower revenues from product location exchanges which are used to position product in the Midwest market area and lower volume of product inventory sales.

Costs and expenses increased $10.0 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002. The increase was made up of an increase of $7.4 million in operating, general and administrative expenses and an increase of $3.3 million in operating fuel and power, partially offset by a decrease of $0.7 million in taxes – other than income taxes. Operating, general and administrative expenses increased primarily due to higher pipeline maintenance expenses, increased consulting and contract services, increased labor costs and increased general and administrative supplies expense, increased insurance expense, expense from the Centennial lease agreement that we entered into in 2003 and the write off of receivables of $0.4 million related to customer bankruptcies. The addition of the northern portion of the Dean Pipeline to the Downstream Segment increased operating, general and administrative expense by $0.4 million. Operating fuel and power expense increased as a result of increased mainline throughput and higher power costs due to an increase in the price of natural gas. Taxes – other than income taxes decreased as a result of actual property taxes being lower than previously estimated and the transfer of assets to MB Storage.

Net losses from equity investments decreased $1.8 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002. Centennial, which commenced operations in April 2002, accounted for $5.0 million of the equity losses during the six months ended June 30, 2003. On February 10, 2003,

TE Products acquired an additional 16.7% interest in Centennial, bringing its ownership interest to 50%. The losses from Centennial are partially offset by equity earnings of $3.8 million from our 50% ownership interest in MB Storage, which was formed effective January 1, 2003. Amounts in the prior year period related to Mont Belvieu operations recorded to revenues and costs and expenses are now being recorded within equity earnings based upon our 50% ownership interest in MB Storage, effective with its formation on January 1, 2003. If the 2002 revenues and costs and expenses from the Mont Belvieu operations had been accounted for under the same method as 2003, equity earnings from MB Storage would have remained unchanged between years.

Other – net decreased $0.2 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002, primarily due to lower interest income received on short-term investments.

Upstream Segment

Information presented in the following table includes the margin of the Upstream Segment, which may be viewed as a non-GAAP (Generally Accepted Accounting Principles) financial measure under the rules of the Securities and Exchange Commission. 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 six months ended June 30, 2003, and 2002, is presented below (in thousands, except per barrel and per gallon amounts):


			Three Months Ended							Six Months Ended
			June 30,				Percentage			June 30,				Percentage
							Increase							Increase
			2003		2002		(Decrease)			2003		2002		(Decrease)

Margins:
	Crude oil transportation		$	11,129	$	9,622		16	%	$	21,785	$	18,693		17	%
	Crude oil marketing			6,632		5,664		17	%		11,515		10,667		8	%
	Crude oil terminaling			2,429		2,640		(8	%)		4,549		5,089		(11	%)
	Lubrication oil sales			1,339		1,230		9	%		2,691		2,365		14	%

		Total margin	$	21,529	$	19,156		12	%	$	40,540	$	36,814		10	%

Total barrels:
	Crude oil transportation			25,931		21,672		20	%		48,556		42,788		13	%
	Crude oil marketing			36,903		42,927		(14	%)		74,575		73,279		2	%
	Crude oil terminaling			28,193		33,064		(15	%)		55,562		62,339		(11	%)
Lubrication oil volume (total gallons)				2,310		2,698		(14	%)		5,153		4,892		5	%
Margin per barrel:
	Crude oil transportation		$	0.429	$	0.444		(3	%)	$	0.449	$	0.437		3	%
	Crude oil marketing			0.180		0.132		36	%		0.154		0.146		5	%
	Crude oil terminaling			0.086		0.080		8	%		0.082		0.082		—
Lubrication oil margin (per gallon)				0.580		0.456		27	%		0.522		0.483		8	%

The following table reconciles the Upstream Segment margin to the consolidated statements of income using the information presented in the consolidated statements of income and the statements of income in Note 11. Segment Data (in thousands):


		Three Months Ended June 30,						Six Months Ended June 30,

		2003			2002			2003			2002

Sales of petroleum products		$	927,232		$	800,107		$	1,903,192		$	1,345,315
Transportation – Crude oil			7,059			7,095			13,964			13,223
Less: Purchases of petroleum products			(912,762	)		(788,046	)		(1,876,616	)		(1,321,724	)

	Total margin	$	21,529		$	19,156		$	40,540		$	36,814

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

Our Upstream Segment reported earnings before interest of $20.0 million for the three months ended June 30, 2003, compared with earnings before interest of $11.8 million for the three months ended June 30, 2002. Earnings before interest increased $8.2 million primarily due to an increase of $2.4 million in margin, an increase of $3.6 million in equity earnings of Seaway and a gain of $3.9 million from the sale of assets, partially offset by an increase of $1.5 million in costs and expenses (excluding purchases of crude oil and lubrication oil) and a decrease of $0.2 million in other operating revenues. We discuss factors influencing these variances below.

Our margin increased $2.4 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002. Crude oil transportation margin increased $1.5 million primarily due to increased revenues on our Red River, Basin, South Texas and West Texas systems resulting from an increase of 20% in transportation volumes, slightly offset by a decrease in the margin per barrel. Crude oil marketing margin increased $1.0 million primarily from more favorable crude oil price differentials, renegotiated supply contracts and lower trucking expenses, partially offset by decreased volumes marketed. Lubrication oil sales margin increased $0.1 million due to higher margins on lubrication sales. Crude oil terminaling margin decreased $0.2 million as a result of lower pumpover volumes at Midland, Texas, and Cushing, Oklahoma.

Other operating revenue of the Upstream Segment decreased $0.2 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002, due to lower revenues from documentation and other services to support customers’ trading activity at Midland and Cushing.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $1.5 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002. Operating, general and administrative expenses increased $0.4 million from the prior year period. The increase includes $2.3 million for environmental remediation and assessment activities in the three months ended June 30, 2003, partially offset by lower labor costs and lower general and administrative supplies expense. Taxes – other than income taxes increased $0.7 million due to increases in property tax accruals. Depreciation and amortization expense increased $0.4 million due to assets placed in service in 2002. Operating fuel and power remained constant during the period due to efficient use of transportation assets in 2003.

Equity earnings in Seaway for the three months ended June 30, 2003, increased $3.6 million from the three months ended June 30, 2002, due to higher long-haul transportation volumes and lower general and administrative expenses, partially offset by our portion of equity earnings decreasing from 80% to 60% on a pro-rated basis in 2002 (averaging approximately 67% for the year ended December 31, 2002), to 60% in 2003.

In June 2003, we recorded a net gain of $3.9 million on the sale of certain of the assets of the Rancho Pipeline. We owned an approximate 25% undivided joint interest in the Rancho Pipeline, which was a pipeline system acquired in connection with our acquisition of crude oil assets in 2000. Under the terms of the Rancho Pipeline operating agreement, the operating agreement terminated in March 2003, and the Rancho Pipeline ceased operations in crude oil service from West Texas to Houston, Texas. The Rancho Pipeline was divided into

segments, and these segments were sold to certain of the current owners of the Rancho Pipeline. We acquired approximately 230 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold portions of the segment acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions, which is included in the gain on sale of assets in our consolidated statements of income.

Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

Our Upstream Segment reported earnings before interest of $28.8 million for the six months ended June 30, 2003, compared with earnings before interest of $22.6 million for the six months ended June 30, 2002. Earnings before interest increased $6.2 million primarily due to an increase of $3.7 million in margin, an increase of $4.2 million in equity earnings of Seaway and a gain of $3.9 million from the sale of assets, partially offset by an increase of $5.5 million in costs and expenses (excluding purchases of crude oil and lubrication oil) and a decrease of $0.1 million in other operating revenues. We discuss factors influencing these variances below.

Our margin increased $3.7 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002. Crude oil transportation margin increased $3.1 million primarily due to increased revenues on our Red River, Basin, South Texas and West Texas systems resulting from an increase of 20% in transportation volumes on these systems. Crude oil marketing margin increased $0.8 million primarily due to increased volumes marketed, renegotiated supply contracts, lower trucking expenses and more favorable crude oil price differentials, partially offset by a pricing settlement on a marketing contract in the first quarter of 2003. Lubrication oil sales margin increased $0.3 million due to increased sales of chemical volumes and higher margins on lubrication sales. Crude oil terminaling margin decreased $0.5 million as a result of an 11% decrease in pumpover volumes at Midland, Texas, and Cushing, Oklahoma.

Other operating revenue of the Upstream Segment decreased $0.1 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002, due to lower revenues from documentation and other services to support customers’ trading activity at Midland and Cushing.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $5.5 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002. Operating, general and administrative expenses increased $3.6 million from the prior year period. The increase includes $3.9 million for environmental assessment and remediation costs in 2003, higher legal costs related to the litigation with D.R.D. (see Note 12. Commitments and Contingencies) and $1.7 million from the net settlement of crude oil imbalances with customers, partially offset by lower labor costs and lower general and administrative supplies expenses during the period. Depreciation and amortization expense increased $1.4 million due to assets placed in service in 2002. Taxes – other than income taxes increased $0.6 million due to increases in property tax accruals. These increases were partially offset by a decrease of $0.1 million in operating fuel and power attributable to a more efficient use of transportation assets in 2003.

Equity earnings in Seaway for the six months ended June 30, 2003, increased $4.2 million from the six months ended June 30, 2002, due to the settlement of crude oil imbalances with customers, lower general and administrative expenses and higher long-haul transportation volumes, partially offset by our portion of equity earnings decreasing from 80% to 60% on a pro-rated basis in 2002 (averaging approximately 67% for the year ended December 31, 2002), to 60% in 2003.

Rancho Pipeline. We sold portions of the segment acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions, which is included in the gain on sale of assets in our consolidated statements of income.

Midstream Segment

The following table presents volume and average rate information for the three months and six months ended June 30, 2003, and 2002:


		Three Months Ended							Six Months Ended
		June 30,				Percentage			June 30,				Percentage
						Increase							Increase
		2003		2002		(Decrease)			2003		2002		(Decrease)

Gathering – Natural Gas:
	Million cubic feet		110,455		59,805		85	%		226,429		109,976		106	%
	Million British thermal units (“MMBtu”)		112,001		66,493		68	%		229,212		122,221		88	%
	Average fee per MMBtu	$	0.288	$	0.173		66	%	$	0.290	$	0.172		69	%
Transportation – NGLs:
	Thousand barrels		13,953		15,557		(10	%)		28,221		23,471		20	%
	Average rate per barrel	$	0.677	$	0.678		—		$	0.685	$	0.718		(5	%)
Fractionation – NGLs:
	Thousand barrels		1,007		1,032		(2	%)		2,078		2,043		2	%
	Average rate per barrel	$	1.846	$	1.840		—		$	1.788	$	1.827		(2	%)
Sales – Condensate:
	Thousand barrels		15.2		18.3		(17	%)		46.0		50.6		(9	%)
	Average rate per barrel	$	27.43	$	28.37		(3	%)	$	31.05	$	23.99		29	%

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

Our Midstream Segment reported earnings before interest of $19.6 million for the three months ended June 30, 2003, compared with earnings before interest of $11.9 million for the three months ended June 30, 2002. Earnings before interest increased $7.7 million due to an increase of $20.1 million in operating revenues, partially offset by an increase of $12.2 million in costs and expenses and a decrease of $0.2 million in other income – net. We discuss factors influencing these variances below.

Operating revenues increased $20.1 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002, due to an increase of $20.8 million in natural gas gathering revenues and an increase of $0.4 million in other revenues, partially offset by a decrease of $1.1 million in NGL transportation revenues. Natural gas gathering revenues from the Jonah system increased $3.6 million and volumes delivered increased 10.7 billion cubic feet during the three months ended June 30, 2003, due to the expansions of the Jonah system during 2002. The first expansion, which was completed in March 2002, increased the capacity of the Jonah system by 62%, from approximately 450 million cubic feet per day (“MMcf/day”) to approximately 730 MMcf/day. In October 2002, additional expansion projects were completed, which increased the capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day. Natural gas gathering revenues from the Val Verde system, which was acquired on June 30, 2002, totaled $17.2 million and volumes delivered totaled 39.9 billion cubic feet during the three months ended June 30, 2003. NGL transportation revenues decreased primarily due to a decrease of $0.4 million in revenues on the Dean Pipeline as a result of lower transportation volumes in 2003. Lower transportation volumes resulted from the conversion of the northern portion of the pipeline to transport RGPs and

subsequent classification as a part of the Downstream Segment. NGL transportation revenues also decreased $0.6 million due to lower transportation volumes on the Panola Pipeline.

Costs and expenses increased $12.2 million for the three months ended June 30, 2003, compared with the three months ended June 30, 2002, due to an increase of $5.8 million in depreciation and amortization expense, an increase of $5.2 million in operating, general and administrative expense, an increase of $0.7 million in taxes – other than income taxes and an increase of $0.5 million in operating fuel and power. Depreciation and amortization expense increased $7.2 million due to the acquisition of the Val Verde assets on June 30, 2002, and $0.7 million due to assets placed in service in 2002 related primarily to the expansion of the Jonah system. These increases were partially offset by a decrease of $1.5 million in the amortization expense of the Jonah gas gathering contract intangible assets under units-of-production due to an adjustment in estimated total throughput of the system which extended the expected amortization period from 16 years to 25 years (see Note 3. Goodwill and Other Intangible Assets). Operating, general and administrative expense increased $4.3 million from the Val Verde assets acquired, and $1.1 million due to higher general and administrative labor and supplies expense. Operating fuel and power costs increased $0.5 million due to increased transportation volumes on Chaparral. Taxes – other than income taxes increased $0.2 million due to the acquisition of Val Verde, $0.2 million due to a higher property tax base on Jonah as a result of the expansions and $0.3 million due to adjustments to the estimated property taxes for the period.

Other income – net decreased $0.2 million during the three months ended June 30, 2003, compared with the three months ended June 30, 2003, due to a reduction in interest income. During the three months ended June 30, 2002, we recognized interest income on the timing of the debt borrowings related to the Val Verde transaction.

Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

Our Midstream Segment reported earnings before interest of $38.1 million for the six months ended June 30, 2003, compared with earnings before interest of $19.6 million for the six months ended June 30, 2002. Earnings before interest increased $18.5 million due to an increase of $48.6 million in operating revenues, partially offset by an increase of $30.0 million in costs and expenses and a decrease of $0.1 million in other income – net. We discuss factors influencing these variances below.

Operating revenues increased $48.6 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002, due to an increase of $45.6 million in natural gas gathering revenues, an increase of $2.5 million in NGL transportation revenues and an increase of $0.5 million in other revenues. Natural gas gathering revenues from the Jonah system increased $9.7 million and volumes delivered increased 34.8 billion cubic feet during the six months ended June 30, 2003, due to the expansions of the Jonah system during 2002. Natural gas gathering revenues from the Val Verde system, which was acquired on June 30, 2002, totaled $35.9 million and volumes delivered totaled 81.6 billion cubic feet during the six months ended June 30, 2003. Other revenues increased $0.5 million primarily due to sales of gas condensate from the Jonah system. NGL transportation revenues increased $2.5 million, primarily due to an increase of $4.3 million related to the acquisition of Chaparral on March 1, 2002. This increase was partially offset by a decrease of $0.8 million on the Dean Pipeline due to decreased transportation volumes. Lower transportation volumes resulted from the conversion of the northern portion of the pipeline to transport RGPs and subsequent classification as a part of the Downstream Segment. NGL transportation revenues also decreased $1.0 million due to lower transportation volumes on the Panola Pipeline. The decrease in the NGL transportation average rate per barrel resulted from a lower average rate per barrel on volumes transported on Chaparral.

Costs and expenses increased $30.0 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002, due to an increase of $15.8 million in depreciation and amortization expense, an increase of $11.5 million in operating, general and administrative expense, an increase of $1.6 million in taxes – other than income taxes and an increase of $1.1 million in operating fuel and power. Depreciation and amortization expense increased $14.0 million due to the acquisitions of the Chaparral and Val Verde assets acquired on March 1, 2002, and June 30, 2002, respectively, and $1.8 million due to assets placed in service in 2002 related primarily to the expansions of the Jonah system. Operating, general and administrative expense increased $9.7 million from the

assets acquired, and due to higher general and administrative labor and supplies expense. Operating fuel and power costs increased $1.1 million due to the assets acquired and due to increased volumes transported on Chaparral. Taxes – other than income taxes increased $1.1 million due to the assets acquired and $0.4 million due to a higher property tax base on Jonah as a result of the expansions.

Interest Expense and Capitalized Interest

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

Interest expense increased $6.7 million during the three months ended June 30, 2003, compared with the three months ended June 30, 2002, primarily due to higher outstanding debt balances used for capital expenditures and to finance the acquisition of assets acquired through the Midstream Segment, an increased percentage of fixed-rate debt in 2003 and $1.3 million of debt issuance costs written off during the three months ended June 30, 2003, related to the refinancing of our revolving credit facility.

Capitalized interest decreased $0.1 million during the three months ended June 30, 2003, compared with the three months ended June 30, 2002, due to interest capitalized on capital expenditures during the construction of the Jonah expansions in 2002 and decreased balances during 2003 on overall construction work-in-progress.

Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

Interest expense increased $11.8 million during the six months ended June 30, 2003, compared with the six months ended June 30, 2002, primarily due to higher outstanding debt balances used for capital expenditures and to finance the acquisition of assets acquired through the Midstream Segment, an increased percentage of fixed-rate debt in 2003 and $1.3 million of debt issuance costs written off during the six months ended June 30, 2003, related to the refinancing of our revolving credit facility.

Capitalized interest decreased $1.6 million during the six months ended June 30, 2003, compared with the six months ended June 30, 2002, due to interest capitalized on capital expenditures during the construction of the Jonah expansions in 2002, interest capitalized on our investment in Centennial during the first quarter of 2002, and decreased balances during 2003 on overall construction work-in-progress.

Financial Condition and Liquidity

Net cash from operating activities totaled $132.5 million for the six months ended June 30, 2003. This cash was made up of $118.7 million of income before charges for depreciation and amortization and $13.8 million of cash provided by working capital. This compares with net cash from operating activities of $97.5 million for the corresponding period in 2002, comprised of $84.8 million of income before charges for depreciation and amortization and $12.7 million of cash provided by working capital. Net cash from operating activities for the six months ended June 30, 2003, and 2002, included interest payments of $39.6 million and $19.5 million, respectively.

Cash flows used in investing activities totaled $63.9 million for the six months ended June 30, 2003, and were comprised of $45.9 million of capital expenditures, $20.0 million for TE Products’ acquisition of an additional ownership interest in Centennial, $1.0 million of cash contributions for TE Products’ ownership interest in Centennial, and $5.5 million for the purchase of crude oil assets as part of the Rancho transaction. These uses of cash were partially offset by $8.5 million in cash proceeds from the sale of the Rancho assets. Cash flows used in investing activities totaled $651.5 million for the six months ended June 30, 2002, and were comprised of $7.3 million for the final purchase price adjustments on the acquisition of Jonah, $63.6 million of capital expenditures, $7.7 million of cash contributions for TE Products’ ownership interest in Centennial, $132.1 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 financing activities totaled $68.8 million for the six months ended June 30, 2003, and were comprised of $335.0 million in proceeds from term and revolving credit facilities; $198.6 million from the issuance in January 2003 of our 6.125% Senior Notes due 2013, partially offset by debt issuance costs of $3.1 million; and $114.5 million from the issuance of 3.9 million Units in April 2003. These sources of cash for the six months ended June 30, 2003, were partially offset by $504.0 million of repayments on our term and revolving credit facilities; $113.8 million to repurchase and retire the outstanding Class B Units, and $96.0 million of distributions to unitholders. Cash flows provided by financing activities totaled $554.0 million for the six months ended June 30, 2002, and were comprised of $642.0 million of proceeds from term and revolving credit facilities; $497.8 million from the issuance in February 2002 of our 7.625% Senior Notes due 2012, partially offset by debt issuance costs of $7.0 million; and $59.3 million from the issuance of 2.0 million Units and $1.2 million of related General Partner contributions. These sources of cash for the six months ended June 30, 2002, were partially offset by $570.7 million of repayments on our term and revolving credit facilities and $68.6 million of distributions to unitholders.

In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”) and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Through February 9, 2003, each original participant owned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired an additional 16.7% interest in Centennial, bringing their ownership interest to 50% each. Excluding TE Products’ purchase of its additional ownership interest of 16.7% on February 10, 2003, we expect to contribute an additional $5.0 million to Centennial in 2003.

Centennial entered into credit facilities totaling $150.0 million, and as of June 30, 2003, $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, including TE Products, originally guaranteed one-third of Centennial’s 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 Centennial guaranty. Effective September 27, 2002, 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 was 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 had provided for PEPL. In connection with the acquisition of the additional interest in Centennial on February 10, 2003, the guaranty agreement between TE Products, Marathon and PEPL was terminated. TE Products’ guaranty of up to a maximum of $75.0 million of Centennial’s debt remains in effect.

Credit Facilities and Interest Rate Swap Agreements

The credit agreement for the Revolving Credit Facility contains certain restrictive financial covenant ratios. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On June 30, 2003, $263.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate, before the effects of hedging activities, of 1.8%. At June 30, 2003, we were in compliance with the covenants contained in this credit agreement.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million 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 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 June 30, 2003, we were in compliance with the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on the Three Year Facility to $250.0 million. The balance of the net proceeds received was used for general purposes. 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 6.125% 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 June 30, 2003, we were in compliance with the covenants of these Senior Notes.

We have 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 June 30, 2003 (in millions):


	As of June 30, 2003

			Available
	Outstanding		Borrowing		Maturity
Description:	Principal		Capacity		Date

Revolving Credit Facility	$	263.0	$	287.0	June 2006
6.45% Senior Notes (1)		180.0		—	January 2008
7.625% Senior Notes (1)		500.0		—	February 2012
6.125% Senior Notes (1)		200.0		—	February 2013
7.51% Senior Notes (1)		210.0		—	January 2028

Total	$	1,353.0	$	287.0

(1) Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At June 30, 2003, the 15.1% Senior Notes include an adjustment to increase the fair value of the debt by $15.1 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At June 30, 2003, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $42.4 million. At June 30, 2003, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $3.4 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and the unamortized debt discounts are excluded from this table.

Distributions and Issuance of Additional Limited Partner Units

We paid cash distributions of $96.0 million ($1.225 per Unit) and $68.6 million ($1.15 per Unit) for each of the six months ended June 30, 2003 and 2002, respectively. Additionally, we declared a cash distribution of $0.625 per Unit for the quarter ended June 30, 2003. We will pay the distribution of $49.4 million on August 8, 2003, to unitholders of record on July 31, 2003.

On March 22, 2002, we sold in an underwritten public offering 1.92 million 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 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 5, 2002, we sold in an underwritten public offering 3.8 million 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 5, 2002. Proceeds from that sale totaled $16.2 million and were used to reduce borrowings under our Short-term Revolver.

On November 7, 2002, we sold in an underwritten public offering 3.3 million Units at $26.83 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $84.8 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility. On December 4, 2002, 495,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on

November 7, 2002. Proceeds from that sale totaled $12.7 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions, for 2003 will be approximately $150.4 million (which includes $4.1 million of capitalized interest). Of this amount, we expect to spend approximately $104.7 million for revenue generating projects. Capital spending on Downstream Segment revenue generating projects will total approximately $16.8 million, including $7.5 million for the expansion of our pumping capacity of LPGs into the Northeast markets, $6.0 million for the expansion of our Bossier City, Louisiana facilities and $3.3 million for expansion of delivery capacity at various locations. For the Midstream Segment, revenue generating capital expenditures will total approximately $74.9 million, principally for the upgrade of the Jonah system, and for additional well connections on both the Jonah and Val Verde systems. Upstream Segment revenue generating expenditures will be approximately $13.0 million, including $7.0 million for the expansion of our South Texas system and $6.0 million for connections to various other production facilities and pipelines. We expect to spend approximately $29.9 million to sustain existing operations, of which $23.2 million will be for various Downstream Segment pipeline projects, $4.8 million for Upstream Segment facilities and $1.9 million for the Midstream Segment. An additional $15.8 million will be expended on system upgrade projects among all of our business segments. 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 June 30, 2003, we had a working capital deficit of $25.3 million. In the event of any working capital shortfalls, we have approximately $287.0 million in available borrowing capacity under our Revolving Credit Facility to cover these items.

Our debt repayment obligations consist of payments for principal and interest on (i) outstanding principal amounts under the Revolving Credit Facility due in June 2006 ($263.0 million outstanding at June 30, 2003), (ii) the TE Products $180.0 million 6.45% Senior Notes due January 15, 2008, (iii) our $500.0 million 7.625% Senior Notes due February 15, 2012, (iv) our $200.0 million 6.125% Senior Notes due February 1, 2013, and (v) the TE Products $210.0 million 7.51% Senior Notes due January 15, 2028.

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 $5.0 million to Centennial in 2003 to provide for its working capital needs. In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum capacity requirement. On February 10, 2003, TE Products acquired an additional 16.7% ownership interest in Centennial, bringing its ownership percentage to 50%.

required escrow amount in the second quarter of 2003, and we are obligated to fund the remaining $3.5 million by August 31, 2003.

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, the remaining escrow commitment to Williams 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 June 30, 2003 (in millions):


		Amount of Commitment Expiration Per Period

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

Revolving Credit Facility		$	263.0	$	—	$	263.0	$	—	$	—
6.45% Senior Notes due 2008 (1) (2)			180.0		—		—		180.0		—
7.625% Senior Notes due 2012 (2)			500.0		—		—		—		500.0
7.51% Senior Notes due 2028 (1) (2)			210.0		—		—		—		210.0
6.125% Senior Notes due 2013 (2)			200.0		—		—		—		200.0

	Debt subtotal		1,353.0		—		263.0		180.0		910.0
Estimated Centennial cash contributions			5.0		5.0		—		—		—
Williams escrow commitments			3.5		3.5		—		—		—
Operating leases			58.0		15.4		27.8		14.2		0.6

	Contractual commitments subtotal		66.5		23.9		27.8		14.2		0.6

	Total	$	1,419.5	$	23.9	$	290.8	$	194.2	$	910.6

(1) Obligations of TE Products.

(2) Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At June 30, 2003, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $15.1 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At June 30, 2003, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $42.4 million. At June 30, 2003, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $3.4 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustments and the unamortized debt discounts are excluded from this table.

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, 2013 and 2028 debt matures, issuance of additional equity, proceeds from dispositions of assets, cash flow from operations 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 Units. We expect future capital needs would be similarly funded to the extent not otherwise available from cash flow from operations.

As of June 30, 2003, we had approximately $287.0 million in available borrowing capacity under the Revolving Credit Facility.

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

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. 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 determines that the circumstances warrant such a change. In May 2003, Moody’s reaffirmed the Baa3 ratings for us and our subsidiary, TE Products.

Other Considerations

indemnity relates to future environmental remediation activities attributable to operations of these assets prior to our acquisition. Under this indemnity obligation, we are responsible for the first $3.0 million in specified environmental liabilities, and DETTCO is responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. At December 31, 2002, we had a receivable balance from DETTCO of $4.2 million, the majority of which related to remediation activities at the Velma crude oil site in Stephens County, Oklahoma. On March 31, 2003, we received $2.4 million under the indemnity obligation with DETTCO. The remaining $1.8 million due was subsequently written off as a result of final settlement discussions with DETTCO on this matter. The accrued liability balance at June 30, 2003, also includes an accrual of $2.3 million related to a crude oil site. We are currently in discussions with DETTCO regarding various matters relative to DETTCO’s indemnifications. 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.

Recent Accounting Pronouncements

See discussion of new accounting pronouncements in Note 1. Organization and Basis of Presentation – New Accounting Pronouncements in the accompanying consolidated financial statements.

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 made by us in light of 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 Annual Report on Form 10-K, for the year ended December 31, 2002, 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 June 30, 2003, we had $263.0 million outstanding under our variable interest rate revolving credit agreement. 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 June 30, 2003, including the effects of hedging activities discussed below, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $0.1 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 June 30, 2003, 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 June 30, 2003, the estimated fair value of the TE Products Senior Notes was approximately $427.1 million. At June 30, 2003, we had outstanding $500.0 million principal amount of 7.625% Senior Notes due 2012 and $200.0 million principal amount of 6.125% Senior Notes due 2013. At June 30, 2003, the estimated fair value of the $500.0 million 7.625% Senior Notes and the $200.0 million 6.125% Senior Notes was approximately $604.0 million and $212.5 million, respectively.

As of June 30, 2003, 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 six months ended June 30, 2003, and 2002, we recognized reductions in interest expense of $4.9 million and $3.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended June 30, 2003, 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 was a gain of approximately $15.1 million and $13.6 million at June 30, 2003, and December 31, 2002, respectively. Utilizing the balance of the 7.51% TE Products Senior Notes outstanding at June 30, 2003, and including the effects of hedging activities, assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $2.1 million.

As of June 30, 2003, 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. This interest rate swap matures on April 6, 2004. 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 six months ended June 30, 2003, and 2002, we recognized increases in interest expense of $7.0 million and $6.3 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended June 30, 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. On June 27, 2003, we repaid the amounts outstanding under the revolving credit facility with borrowings under a new three year revolving credit facility and canceled the old facility (see Note 9. Debt). We redesignated the interest rate swap as a hedge of our exposure to increases in the benchmark interest rate underlying the new variable rate revolving credit facility. The fair value of the interest rate swap was a loss of approximately $11.4 million and $20.1 million at June 30, 2003, and December 31, 2002, respectively. The remaining fair value of the interest rate swap will be transferred into earnings over the remaining term of the interest rate swap.

LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, the swap agreements were terminated resulting in a gain of approximately $18.0 million. Concurrent with the swap terminations, we entered into new interest rate swap agreements, with identical terms as the previous swap agreements; however, the floating rate was based upon a spread of an additional 50 basis points. In December 2002, the swap agreements entered into on July 16, 2002, were terminated, resulting in a gain of approximately $26.9 million. The gains realized from the July 2002 and December 2002 swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At June 30, 2003, the unamortized balance of the deferred gains was $42.4 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains 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”).

The principal executive officer and principal financial officer of our general partner, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-14(c) and Rule 15d-14(c)) as of a date within 90 days before the filing date of this Report, have concluded that, as of such date, our disclosure controls and procedures are adequate and effective to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities.

There have been no changes in our internal controls or in other factors known to us that could significantly affect those internal controls subsequent to the date of the evaluation, nor were there any significant deficiencies or material weaknesses in our internal controls. As a result, no corrective actions were required or undertaken.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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. See discussion of legal proceedings in Note 12. Commitments and Contingencies in the accompanying consolidated financial statements.

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).


Exhibit
Number		Description

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).

4.5		First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).

4.6		Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

4.7		Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.1+		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.


Exhibit
Number		Description

		(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).

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


Exhibit
Number		Description

		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).

10.24		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).

10.25		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).

10.26		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).

10.27		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).

10.28		Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8


Exhibit
Number		Description

		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).

10.29		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).

10.30		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).

10.31		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).

10.32		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).

10.33		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).

10.34		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. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.35		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).

10.36		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).

10.37		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).

10.38		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).

10.39		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).

10.40		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
Number		Description

		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).

10.41		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).

10.42+		Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43 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+		Amended and Restated TEPPCO Supplemental Benefit Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.44+		Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Second Amendment and Restatement, effective January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.45+		Amended and Restated Texas Eastern Products Pipeline Company, LLC Management Incentive Compensation Plan, effective January 1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.46+		Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.47		Formation Agreement between Panhandle Eastern Pipe Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.48		Amended and Restated Limited Liability Company Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.49		Guaranty Agreement, dated as of September 27, 2002, between TE Products Pipeline Company, Limited Partnership and Marathon Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.50		LLC Membership Interest Purchase Agreement By and Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.51		Joint Development Agreement between TE Products Pipeline Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and incorporated herein by reference).

10.52*		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000 Revolving Facility).

12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.


Exhibit
Number		Description

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).

31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

* Filed herewith.

+ A management contract or compensation plan or arrangement.

(b) Reports on Form 8-K filed with or furnished to the Securities and Exchange Commission during the quarter ended June 30, 2003:

A current report on Form 8-K was filed on April 8, 2003, including as an exhibit an underwriting agreement with underwriters named therein in connection with respect to the issue and sale of up to 3,938,750 units of the Partnership.

A current report on Form 8-K was furnished on April 30, 2003, in connection with disclosure of first quarter estimates and earnings guidance.

A current report on Form 8-K was furnished on June 12, 2003, in connection with a presentation to investors.

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

		By:		/s/ CHARLES H. LEONARD

				Charles H. Leonard,
				Senior Vice President and Chief
				Financial Officer

Date: July 30, 2003

INDEX TO 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).

4.5		First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).

4.6		Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

4.7		Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.1+		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.


Exhibit
Number		Description

		(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).

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


Exhibit
Number		Description

		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).

10.24		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).

10.25		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).

10.26		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).

10.27		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).

10.28		Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8


Exhibit
Number		Description

		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).

10.29		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).

10.30		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).

10.31		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).

10.32		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).

10.33		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).

10.34		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. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.35		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).

10.36		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).

10.37		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).

10.38		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).

10.39		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).

10.40		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
Number		Description

		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).

10.41		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).

10.42+		Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43 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+		Amended and Restated TEPPCO Supplemental Benefit Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.44+		Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Second Amendment and Restatement, effective January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.45+		Amended and Restated Texas Eastern Products Pipeline Company, LLC Management Incentive Compensation Plan, effective January 1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.46+		Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.47		Formation Agreement between Panhandle Eastern Pipe Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.48		Amended and Restated Limited Liability Company Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.49		Guaranty Agreement, dated as of September 27, 2002, between TE Products Pipeline Company, Limited Partnership and Marathon Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.50		LLC Membership Interest Purchase Agreement By and Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.51		Joint Development Agreement between TE Products Pipeline Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and incorporated herein by reference).

10.52*		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000 Revolving Facility).

12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.


Exhibit
Number		Description

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).

31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

* Filed herewith.

+ A management contract or compensation plan or arrangement.

	•		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.

(1)		Obligations of TE Products.

(2)		Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At June 30, 2003, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $15.1 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At June 30, 2003, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $42.4 million. At June 30, 2003, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $3.4 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustments and the unamortized debt discounts are excluded from this table.

*		Filed herewith.

+		A management contract or compensation plan or arrangement.