tppform10q_033108.htm

10-Q 1 tppform10q_033108.htm FORM 10-Q tppform10q_033108.htm

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 March 31, 2008

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____.

Commission File No. 1-10403

____________________

TEPPCO Partners, L.P.

(Exact name of Registrant as specified in its charter)

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

1100 Louisiana Street, Suite 1600

Houston, Texas 77002

(Address of principal executive offices, including zip code)

(713) 381-3636

(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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ	Accelerated Filer o
Non-accelerated Filer o (Do not check if a smaller reporting company)	Smaller reporting company o

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

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 May 1, 2008: 94,839,660

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TEPPCO PARTNERS, L.P.

TABLE OF CONTENTS

	Page No.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets	1

Unaudited Condensed Statements of Consolidated Income	2

Unaudited Condensed Statements of Comprehensive Income	3

Unaudited Condensed Statements of Consolidated Cash Flows	4

Unaudited Condensed Statements of Consolidated Partners’ Capital	5

Notes to Unaudited Condensed Consolidated Financial Statements	6
Note 1. Partnership Organization and Basis of Presentation	6
Note 2. General Accounting Policies and Related Matters	7
Note 3. Accounting for Unit-Based Awards	10
Note 4. Employee Benefit Plans	13
Note 5. Financial Instruments	13
Note 6. Inventories	17
Note 7. Property, Plant and Equipment	18
Note 8. Investments in Unconsolidated Affiliates	19
Note 9. Acquisitions and Dispositions	21
Note 10. Intangible Assets and Goodwill	26
Note 11. Debt Obligations	28
Note 12. Partners’ Capital and Distributions	32
Note 13. Business Segments	35
Note 14. Related Party Transactions	39
Note 15. Earnings per Unit	42
Note 16. Commitments and Contingencies	43
Note 17. Supplemental Cash Flow Information	48
Note 18. Supplemental Condensed Consolidating Financial Information	48
Note 19. Subsequent Events	52

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	53

Cautionary Note Regarding Forward-Looking Statements	54

Item 3. Quantitative and Qualitative Disclosures About Market Risk	74

Item 4. Controls and Procedures	77
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	77

Item 1A. Risk Factors	77

Item 5. Other Information	79

Item 6. Exhibits	79

Signatures	82

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	March 31,		December 31,
	2008		2007

ASSETS

Current assets:
Cash and cash equivalents	$	32	$	23
Accounts receivable, trade (net of allowance for doubtful accounts of
$128 and $125)		1,571,049		1,381,871
Accounts receivable, related parties		5,003		6,525
Inventories		87,526		80,299
Other		50,628		47,271
Total current assets		1,714,238		1,515,989
Property, plant and equipment, at cost (net of accumulated
depreciation of $604,021 and $582,225)		2,252,377		1,793,634
Equity investments		1,164,337		1,146,995
Intangible assets		218,214		164,681
Goodwill		120,237		15,506
Other assets		134,449		113,252
Total assets	$	5,603,852	$	4,750,057

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Senior notes	$	--		$	353,976
Accounts payable and accrued liabilities		1,591,428			1,413,447
Accounts payable, related parties		29,695			38,980
Accrued interest		15,193			35,491
Other accrued taxes		20,719			20,483
Other		48,071			84,848
Total current liabilities		1,705,106			1,947,225
Long-term debt:
Senior notes		1,716,748			721,545
Junior subordinated notes		299,547			299,538
Other long-term debt		429,200			490,000
Total long-term debt		2,445,495			1,511,083
Other liabilities and deferred credits		29,944			27,122
Commitments and contingencies
Partners’ capital:
Limited partners’ interests:
Limited partner units (94,777,260 and 89,849,132 units outstanding)		1,575,111			1,394,812
Restricted limited partner units (62,400 and 62,400 units outstanding)		478			338
General partner’s interest		(89,614	)		(87,966	)
Accumulated other comprehensive loss		(62,668	)		(42,557	)
Total partners’ capital		1,423,307			1,264,627
Total liabilities and partners’ capital	$	5,603,852		$	4,750,057

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Dollars in thousands, except per Unit amounts)

	For the Three Months Ended
	March 31,
	2008			2007
Operating revenues:
Sales of petroleum products	$	2,644,578		$	1,850,128
Transportation – Refined products		37,283			37,135
Transportation – LPGs		36,191			36,053
Transportation – Crude oil		15,300			10,790
Transportation – NGLs		12,957			10,941
Transportation – Marine		25,536			--
Gathering – Natural gas		13,413			15,408
Other		23,230			17,974
Total operating revenues		2,808,488			1,978,429

Costs and expenses:
Purchases of petroleum products		2,606,607			1,813,994
Operating expense		53,777			45,166
Operating fuel and power		21,374			15,274
General and administrative		8,748			8,598
Depreciation and amortization		28,344			25,369
Taxes – other than income taxes		6,119			5,243
Gains on sales of assets		--			(18,649	)
Total costs and expenses		2,724,969			1,894,995

Operating income		83,519			83,434

Other income (expense):
Interest expense – net		(38,571	)		(22,211	)
Gain on sale of ownership interest in Mont Belvieu Storage Partners, L.P.		--			59,837
Equity earnings		19,662			16,563
Interest income		308			342
Other income – net		40			244

Income before provision for income taxes		64,958			138,209

Provision for income taxes		819			18

Net income	$	64,139		$	138,191

Net Income Allocation:
Limited Partner’s interest in net income	$	53,403		$	115,524
General Partner interest in net income		10,736			22,667
Total net income allocated	$	64,139		$	138,191

Basic and diluted net income per Limited Partner Unit	$	0.57		$	1.29

Weighted average Limited Partner Units outstanding		93,156			89,805

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

	For the Three Months Ended
	March 31,
	2008			2007

Net income	$	64,139		$	138,191
Other comprehensive income (loss):
Cash flow hedges:
Change in fair values of interest rate cash flow hedges and treasury locks		(23,200	)		217
Changes in fair values of crude oil cash flow hedges		3,089			360
Total cash flow hedges		(20,111	)		577
Pension benefit SFAS No. 158 adjustment		--			(34	)
Total other comprehensive income (loss)		(20,111	)		543
Comprehensive income	$	44,028		$	138,734

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

	For the Three Months Ended
	March 31,
	2008			2007
Operating activities:
Net income	$	64,139		$	138,191
Adjustments to reconcile net income to cash provided by operating activities:
Deferred income taxes		(5	)		(642	)
Depreciation and amortization		28,344			25,369
Amortization of deferred compensation		291			--
Amortization in interest expense		2,777			(189	)
Earnings in equity investments		(19,662	)		(16,563	)
Distributions from equity investments		37,234			40,304
Gains on sales of assets		--			(18,649	)
Gain on sale of ownership interest in Mont Belvieu Storage Partners, L.P.		--			(59,837	)
Loss on early extinguishment of debt		8,689			--
Net effect of changes in operating accounts		(63,126	)		(39,253	)
Net cash provided by operating activities		58,681			68,731

Investing activities:
Proceeds from sales of assets		--			26,537
Proceeds from sale of ownership interest		--			138,729
Cash used for business combinations		(338,485	)		--
Investment in Centennial Pipeline LLC		--			(6,081	)
Investment in Jonah Gas Gathering Company		(31,773	)		(30,942	)
Capitalized costs incurred to develop identifiable intangible assets		(300	)		--
Cash paid for linefill on assets owned		(14,282	)		--
Capital expenditures		(51,601	)		(34,084	)
Net cash provided by (used in) investing activities		(436,441	)		94,159

Financing activities:
Proceeds from term credit facility		1,000,000			--
Repayments on term credit facility		(1,000,000	)		--
Proceeds from revolving credit facility		516,250			235,000
Repayments on revolving credit facility		(577,050	)		(325,500	)
Repayment of debt assumed in Cenac acquisition		(63,157	)		--
Redemption of 7.51% TE Products Senior Notes		(181,571	)		--
Repayment of 6.45% TE Products Senior Notes		(180,000	)		--
Issuance of Limited Partner Units, net		2,666			--
Issuance of senior notes		996,349			--
Debt issuance costs		(8,747	)		--
Settlement of treasury lock agreements		(52,098	)		--
Distributions paid		(74,873	)		(72,389	)
Net cash provided by (used in) financing activities		377,769			(162,889	)

Net change in cash and cash equivalents		9			1

Cash and cash equivalents, January 1		23			70
Cash and cash equivalents, March 31	$	32		$	71

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ CAPITAL

(Dollars in thousands, except Unit amounts)

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

Balance, December 31, 2007		89,911,532	$	(87,966	)	$	1,395,150		$	(42,557	)	$	1,264,627
Net income allocation		--		10,736			53,403			--			64,139
Issuance of units in connection with Cenac acquisition on February 1, 2008		4,854,899		--			186,558			--			186,558
Limited Partner Units issued in connection with Distribution Reinvestment Plan		69,319		--			2,518			--			2,518
Units issued in connection with Employee Unit Purchase Plan		3,910		--			148			--			148
Cash distributions		--		(12,384	)		(62,489	)		--			(74,873	)
Non-cash contribution		--		--			125			--			125
Amortization of equity awards		--		--			176			--			176
Changes in fair values of crude oil cash flow hedges		--		--			--			3,089			3,089
Changes in fair values of treasury locks		--		--			--			(23,200	)		(23,200	)

Balance, March 31, 2008		94,839,660	$	(89,614	)	$	1,575,589		$	(62,668	)	$	1,423,307

See Notes to Unaudited Condensed Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION AND BASIS OF PRESENTATION

Partnership Organization

TEPPCO Partners, L.P. (the “Partnership”), is a publicly traded Delaware limited partnership and our limited partner units are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. As used in this Report, “we,” “us,” “our,” the “Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries. At formation in March 1990, we completed an initial public offering of 26,500,000 units representing limited partner interests (“Units”) at $10.00 per Unit.

Through June 29, 2007, we operated through TE Products Pipeline Company, Limited Partnership, TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. On June 30, 2007, each of TE Products Pipeline Company, Limited Partnership and TEPPCO Midstream Companies, L.P. separately converted into Texas limited partnerships and immediately thereafter each merged into separate newly-formed Texas limited liability companies that had no business operations prior to the merger. The resulting limited liability companies are called TE Products Pipeline Company, LLC (“TE Products”) and TEPPCO Midstream Companies, LLC (“TEPPCO Midstream”). Beginning June 30, 2007 and through January 31, 2008, we operated through TE Products, TCTM and TEPPCO Midstream. As of February 1, 2008, we operate through TE Products, TCTM, TEPPCO Midstream and TEPPCO Marine Services, LLC (“TEPPCO Marine Services”). Texas Eastern Products Pipeline Company, LLC (the “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. We hold a 99.999% limited partner interest in TCTM, 99.999% membership interests in each of TE Products and TEPPCO Midstream and a 100% membership interest in TEPPCO Marine Services. TEPPCO GP, Inc. (“TEPPCO GP”) holds a 0.001% general partner interest in TCTM and a 0.001% managing member interest in each of TE Products and TEPPCO Midstream.

Through May 6, 2007, our General Partner was owned by DFI GP Holdings L.P. (“DFIGP”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan. On May 7, 2007, DFIGP sold all of the membership interests in our General Partner, together with 4,400,000 of our Units, to Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded partnership, also controlled indirectly by Dan L. Duncan. Mr. Duncan and certain of his affiliates, including Enterprise GP Holdings and Dan Duncan LLC, a privately held company controlled by him, control us, our General Partner and Enterprise Products Partners L.P. (“Enterprise Products Partners”) and its affiliates, including Duncan Energy Partners L.P. As of May 7, 2007, Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest. Enterprise GP Holdings, DFIGP and other entities controlled by Mr. Duncan own 16,691,550 of our Units. Under an amended and restated administrative services agreement (“ASA”), EPCO performs management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements reflect all adjustments that are, in the opinion of our management, of a normal and recurring nature and necessary for a fair statement of our financial position as of March 31, 2008, and the results of our operations and cash flows for the periods presented. The results of operations for the three months ended March 31, 2008, are not necessarily indicative of results of our operations for the full year 2008. The unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principals (“GAAP”) have been condensed or omitted pursuant to those rules and regulations.

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

You should read these 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, 2007.

Except per Unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands.

NOTE 2. GENERAL ACCOUNTING POLICIES AND RELATED MATTERS

Business Segments

We operate and report in four business segments:

pipeline transportation, marketing and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”);
gathering, pipeline transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals (“Upstream Segment”);
gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and pipeline transportation of NGLs (“Midstream Segment”); and
marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges (“Marine Services Segment”).

Our reportable segments offer different products and services and are managed separately because each requires different business strategies (see Note 13).

Our interstate pipeline 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, lubrication oils and specialty chemicals, NGLs, natural gas, asphalt, heavy fuel oil and other heated oil products in this Report, collectively, as “petroleum products” or “products.”

Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Income Taxes

We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. We are subject to the Revised Texas Franchise Tax, enacted by the State of Texas in May 2006. At March 31, 2008 and December 31, 2007, we had current tax liabilities of $2.0 million and $1.2 million, respectively, and deferred tax assets of less than $0.1 million and less than $0.1 million, respectively. During the three months ended March 31, 2008 and 2007, we recorded increases in current income tax liabilities of $0.8 million and $0.7 million, respectively. During the three months ended March 31, 2007, we recorded a $0.6 million reduction to deferred tax liability. The offsetting net charges to deferred tax expense and income tax expense are shown on our statements of consolidated income as provision for income taxes.

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Net Income Per Unit

Basic net income per Unit is computed by dividing net income or loss, after deduction of the General Partner’s interest, by the weighted average number of distribution-bearing Units outstanding during a period. 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 12). Diluted net income per Unit is computed by dividing net income or loss, after deduction of the General Partner’s interest, by the sum of (i) the weighted average number of distribution-bearing Units outstanding during a period (as used in determining basic earnings per Unit); and (ii) the number of incremental Units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”) (see Note 15).

In a period of net operating losses, restricted units and incremental option units are excluded from the calculation of diluted earnings per Unit due to their anti-dilutive effect. The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase Units at an average market value during the period. The amount of Units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase above specified levels, in accordance with our Partnership Agreement.

Recent Accounting Developments

Certain provisions of Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements, became effective for us on January 1, 2008. See Note 5 for information regarding new fair value related disclosures required in connection with SFAS 157.

In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities an – amendment of FASB Statement No. 133. SFAS 161 requires enhanced disclosures regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 requires disclosure of (i) the fair values of derivative instruments and their gains and losses in a tabular format, (ii) derivative features that are credit risk-related and (iii) cross-referencing within financial statement footnotes to locate important information about derivative instruments. SFAS 161 is effective for us on January 1, 2009. Management is currently evaluating the impact that SFAS 161 will have on our financial statement disclosures. At present, we do not believe that this standard will impact how we record financial instruments.

In March 2008, the Emerging Issues Task Force (“EITF”), reached consensus on EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships. This guidance prescribes the manner in which a master limited partnership (“MLP”) should allocate and present earnings per unit using the two-class method set forth in SFAS No. 128, Earnings per Share. Under the two-class method, current period earnings are allocated to the general partner (including any embedded incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. EITF 07-4 is effective for us on January 1, 2009. Management is currently evaluating the impact that EITF 07-4 will have on our earnings per unit computations and disclosures.

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Revenue Recognition

Our Downstream Segment revenues are earned from pipeline transportation, marketing and storage of refined products and LPGs, intrastate pipeline transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold. Our refined products marketing activities generate revenues by purchasing refined products from our throughput partners and establishing a margin by selling refined products for physical delivery through spot sales at the Aberdeen truck rack to independent wholesalers and retailers of refined products. These purchases and sales are generally contracted to occur on the same day.

Our Upstream Segment revenues are earned from gathering, transporting, marketing and storing crude oil, and distributing lubrication oils and specialty chemicals principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Revenues are also generated from trade documentation and terminaling services, primarily at Cushing, Oklahoma, and Midland, Texas. Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, LLC (“TCO”), which typically occurs upon our receipt of the product. Revenues related to trade documentation and terminaling services are recognized as services are completed.

Except for crude oil purchased from time to time as inventory required for operations, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, commodity price risks cannot be completely hedged.

Our Midstream Segment revenues are earned from the gathering of natural gas, pipeline transportation of NGLs and fractionation of NGLs. Gathering revenues are recognized as natural gas is received from the customer. Transportation revenues are recognized as NGLs are delivered. Fractionation revenues are recognized ratably over the contract year as products are delivered. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances. Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.

Our Marine Services Segment revenues are earned from inland and offshore transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges. We also provide offshore well-testing and other offshore services. Our transportation services are generally

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

provided under term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from within designated operating areas at set day rates or a set fee per cargo movement. Most of the inland term contracts have one-year terms with the remainder having terms of up to two years. Substantially all of the inland contracts have renewal options, which are exercisable subject to agreement on rates applicable to the option terms. Most of the offshore service and transportation contracts have up to one-year terms with renewal options, which are exercisable subject to agreement on rates applicable to the option terms, or are spot contracts. A spot contract is an agreement with a customer to move cargo within designated operating areas for a rate negotiated at the time the cargo movement takes place. We do not assume ownership of the products we transport in this segment. As is typical for inland and offshore affreightment contracts, the term contracts establish set day rates but do not include revenue or volume guarantees. Most of the contracts include escalation provisions to recover specific increased operating costs such as incremental increases in labor. The costs of fuel and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts.

NOTE 3. ACCOUNTING FOR UNIT-BASED AWARDS

The following table summarizes compensation expense by plan for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended March 31,
	2008			2007
Phantom Unit Plans: (1) (2)
1999 Phantom Unit Retention Plan	$	(8	)	$	440
2000 Long Term Incentive Plan		(227	)		180
2005 Phantom Unit Plan		57			213
EPCO, Inc. 2006 TPP Long-Term Incentive Plan:
Unit options		27			--
Restricted units (3)		139			--
Unit appreciation rights (“UARs”) (1) (2)		(3	)		--
Phantom units (1)		4			--
Compensation expense allocated under ASA (4)		339			90
Total compensation expense	$	328		$	923

_________________________________

(1)	These awards are accounted for as liability awards under the provisions of SFAS 123(R). Accruals for plan award payouts are based on the Unit price.

(2)	The decrease in compensation expense for the three months ended March 31, 2008, is primarily due to a decrease in the Unit price at March 31, 2008 as compared to the Unit price at December 31, 2007.

(3)	As used in the context of the EPCO, Inc. 2006 Long-Term Incentive Plan, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.

(4)	Represents compensation expense under equity awards allocated to us from EPCO under the ASA in connection with shared service employees working on our behalf.

1999 Plan

The Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 Plan”) provides for the issuance of phantom unit awards as incentives to key employees. A total of 31,600 phantom units were outstanding under the 1999 Plan at March 31, 2008. In April 2008, 13,000 phantom units vested resulting in a cash payment of $0.4 million. The remaining awards cliff vest as follows: 13,000 in April 2009 and 5,600 in January 2010. At March 31, 2008 and December 31, 2007, we had accrued liability balances of $1.0 million and $1.0 million, respectively, for compensation related to the 1999 Plan.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2000 LTIP

The Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) provides key employees incentives to achieve improvements in our financial performance. On December 31, 2007, 8,400 phantom units vested and $0.5 million was paid out to participants in the first quarter of 2008. At March 31, 2008, there were a total of 11,300 phantom units outstanding under the 2000 LTIP that cliff vest on December 31, 2008 and will be paid out to participants in 2009. At March 31, 2008 and December 31, 2007, we had accrued liability balances of $0.2 million and $0.9 million, respectively, related to the 2000 LTIP.

2005 Phantom Unit Plan

The Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 Phantom Unit Plan”) provides key employees incentives to achieve improvements in our financial performance. On December 31, 2007, 36,200 phantom units vested and $1.6 million was paid out to participants in the first quarter of 2008. At March 31, 2008, there were a total of 38,200 phantom units outstanding under the 2005 Phantom Unit Plan that cliff vest on December 31, 2008 and will be paid out to participants in 2009. At March 31, 2008 and December 31, 2007, we had accrued liability balances of $1.0 million and $2.6 million, respectively, for compensation related to the 2005 Phantom Unit Plan.

2006 LTIP

The EPCO, Inc. 2006 TPP Long-Term Incentive Plan (“2006 LTIP”) provides for awards of our Units and other rights to our non-employee directors and to certain employees of EPCO and its affiliates providing services to us. Awards granted under the 2006 LTIP may be in the form of restricted units, phantom units, unit options, UARs and distribution equivalent rights. Subject to adjustment as provided in the 2006 LTIP, awards with respect to up to an aggregate of 5,000,000 Units may be granted under the 2006 LTIP. We reimburse EPCO for the costs allocable to 2006 LTIP awards made to employees who work in our business. The 2006 LTIP is effective until December 8, 2016 or, if earlier, the time which all available Units under the 2006 LTIP have been delivered to participants or the time of termination of the 2006 LTIP by EPCO or the Audit, Conflicts and Governance Committee of the Board of Directors of our General Partner (“ACG Committee”). After giving effect to outstanding unit options and restricted units at March 31, 2008, and the forfeiture of restricted units through March 31, 2008, a total of 4,782,600 additional Units could be issued under the 2006 LTIP in the future.

Unit Options

The information in the following table presents unit option activity under the 2006 LTIP for the periods indicated:

					Weighted-
			Weighted-		Average
			Average		Remaining
	Number		Strike Price		Contractual
	of Units		(dollars/Unit)		Term (in years)
Unit Options:
Outstanding at December 31, 2007		155,000	$	45.35		--
Granted		--		--		--
Outstanding at March 31, 2008		155,000	$	45.35		9.15
Options exercisable at:
March 31, 2008		--	$	--		--

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

At March 31, 2008, total unrecognized compensation cost related to nonvested unit options granted under the 2006 LTIP was an estimated $0.4 million. We expect to recognize this cost over a weighted-average period of 3.14 years.

Restricted Units

The following table summarizes information regarding our restricted units for the periods indicated:

			Weighted-
			Average Grant
	Number		Date Fair Value
	of Units		per Unit (1)
Restricted Units at December 31, 2007		62,400
Granted		--	$	--
Restricted Units at March 31, 2008		62,400	$	37.64

____________________________

(1)	Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued.

None of our restricted units vested during the three months ended March 31, 2008. At March 31, 2008, total unrecognized compensation cost related to restricted units was $1.9 million, and these costs are expected to be recognized over a weighted-average period of 3.14 years.

Phantom Units and UARs

At March 31, 2008, a total of 1,647 phantom units were outstanding, which have been awarded under the 2006 LTIP to the non-executive members of the board of directors. Each phantom unit will pay out in cash on April 30, 2011 or, if earlier, the date the director is no longer serving on the board of directors, whether by voluntarily resignation or otherwise. Phantom unit awards to non-executive directors are accounted for similar to SFAS 123(R) liability awards.

At March 31, 2008, a total of 66,225 UARs were outstanding, which have been awarded under the 2006 LTIP at an exercise price of $45.30 per Unit to the non-executive members of the board of directors. The UARs will be subject to five year cliff vesting and will vest earlier if the director dies or is removed from, or not re-elected or appointed to, the board of directors for reasons other than his voluntary resignation or unwillingness to serve. When the UARs become payable, the director will receive a payment in cash equal to the fair market value of the Units subject to the UARs on the payment date over the fair market value of the Units subject to the UARs on the date of grant. UARs awarded to non-executive directors are accounted for similar to SFAS 123(R) liability awards.

At March 31, 2008, a total of 335,723 UARs were outstanding, which have been awarded under the 2006 LTIP at an exercise price of $45.35 per Unit to certain employees providing services directly to us. The UARs are subject to five year cliff vesting and are subject to forfeiture. When the UARs become payable, the awards will be redeemed in cash (or, in the sole discretion of the ACG Committee, Units or a combination of cash and Units) equal to the fair market value of the Units subject to the UARs on the payment date over the fair market value of the Units subject to the UARs on the date of grant. In addition, for each calendar quarter from the grant date until the UARs become payable, each holder will receive a cash payment equal to the product of (i) the per Unit cash distribution paid to our unitholders during such calendar quarter less the quarterly distribution amount in effect at the time of grant multiplied by (ii) the number of Units subject to the UAR. UARs awarded to employees are accounted for as liability awards under SFAS 123(R) since the current intent is to settle the awards in cash.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 4. EMPLOYEE BENEFIT PLANS

Retirement Plan

The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan. The benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age and service. We used a December 31 measurement date for this plan.

Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date. Effective June 1, 2005, EPCO adopted the TEPPCO RCBP for the benefit of its employees providing services to us. Effective December 31, 2005, all plan benefits accrued were frozen, participants received no additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, and plan participants had the option to receive their benefits either through a lump sum payment in 2006 or through an annuity. In April 2006, we received a determination letter from the Internal Revenue Service (“IRS”) providing IRS approval of the plan termination. For those plan participants who elected to receive an annuity, we purchased an annuity contract from an insurance company in which the plan participants own the annuity, absolving us of any future obligation to the participants.

As of December 31, 2007, all benefit obligations to plan participants have been settled. During the first quarter of 2008, the remaining balance of the TEPPCO RCBP was transferred to an EPCO benefit plan.

EPCO maintains defined contribution plans for the benefit of employees providing services to us, and we reimburse EPCO for the cost of maintaining these plans in accordance with the ASA (see Note 14).

NOTE 5. FINANCIAL INSTRUMENTS

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Interest Rate Swaps

In January 2006, we entered into interest rate swap agreements with a total notional value of $200.0 million to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. Under the swap agreements, we paid a fixed rate of interest ranging from 4.67% to 4.695% and received a floating rate based on the three-month U.S. Dollar LIBOR rate. At December 31, 2007, the fair value of these interest rate swaps was an asset of $0.3 million. These interest rate swaps expired in January 2008.

In October 2001, TE Products 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. This swap agreement, designated as a fair value hedge, had a notional value of $210.0 million and was set to mature in January 2028 to match the principal and maturity of the TE Products Senior Notes. During the three months ended March 31, 2007, we recognized a reduction in interest expense of $0.3 million related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. In September 2007, we terminated this swap agreement resulting in a loss of $1.2 million. This loss was deferred as an adjustment to the carrying value of the 7.51% Senior Notes, and approximately $0.2 million of the loss was amortized to interest expense in 2007, with the remaining $1.0 million recognized in interest expense in January 2008 at the time the 7.51% Senior Notes were redeemed (see Note 11).

During 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 value of $500.0 million and were set to mature in 2012 to match the principal and maturity of the underlying debt. These swap agreements were terminated in 2002 resulting in deferred gains of $44.9 million, which are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the 7.625% Senior Notes. At March 31, 2008 and December 31, 2007, the unamortized balance of the deferred gains was $21.9 million and $23.2 million, respectively. In the event of early extinguishment of the 7.625% Senior Notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.

Treasury Locks

In October 2006 and February 2007, we entered into treasury lock agreements, accounted for as cash flow hedges, that extended through June 2007 for a notional value totaling $300.0 million. In May 2007, these treasury locks were terminated concurrent with the issuance of junior subordinated notes (see Note 11). The termination of the treasury locks resulted in gains of $1.4 million, and these gains were recorded in accumulated other comprehensive income. These gains are being amortized using the effective interest method as reductions to future interest expense over the term of the forecasted fixed rate interest payments, which is ten years. Over the next twelve months, we expect to reclassify $0.1 million of accumulated other comprehensive income that was generated by these treasury locks as a reduction to interest expense. In the event of early extinguishment of the junior subordinated notes, any remaining unamortized gains would be recognized in the statement of consolidated income at the time of extinguishment.

In 2007, we entered into treasury locks, accounted for as cash flow hedges, that extended through January 31, 2008 for a notional value totaling $600.0 million. At December 31, 2007, the fair value of the treasury locks was a liability of $25.3 million. In January 2008, these treasury locks were extended through April 30, 2008. In March 2008, these treasury locks were settled concurrently with the issuance of senior notes (see Note 11). The settlement of the treasury locks resulted in losses of $52.1 million, and these losses were recorded in accumulated other comprehensive income. We recognized approximately $3.6 million of this loss in interest expense as a result of interest payments hedged under the treasury locks not occurring as forecasted. The remaining losses are being amortized using the effective interest method as increases to future interest expense over the terms of the forecasted interest payments, which range from five to ten years. Over the next twelve months, we expect to reclassify $2.8 million of accumulated other comprehensive loss that was generated by these treasury locks as an increase to interest expense. In the event of early extinguishment of these senior notes, any remaining unamortized losses would be recognized in the statement of consolidated income at the time of extinguishment.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Commodity Risk Hedging Program

We seek to maintain a position that is substantially balanced between crude oil purchases and related sales and future delivery obligations. As part of our crude oil marketing business, we enter into financial instruments such as swaps and other hedging instruments. The purpose of such hedging activity is to either balance our inventory position or to lock in a profit margin.

At March 31, 2008 and December 31, 2007, we had a limited number of commodity derivatives that were accounted for as cash flow hedges. These contracts will expire during 2008, and any amounts remaining in accumulated other comprehensive income will be recorded in net income. Gains and losses on these derivatives are offset against corresponding gains or losses of the hedged item and are deferred through other comprehensive income, thus minimizing exposure to cash flow risk. No ineffectiveness was recognized as of March 31, 2008. In addition, we had some commodity derivatives that did not qualify for hedge accounting. These financial instruments had a minimal impact on our earnings. The fair values of these open positions at March 31, 2008 and December 31, 2007 were liabilities of $15.4 million and $18.9 million, respectively.

Adoption of SFAS 157 – Fair Value Measurements

On January 1, 2008, we adopted the provisions of SFAS No. 157, Fair Value Measurements, that apply to financial assets and liabilities. We will adopt the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability. These assumptions include estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data, or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur in sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYSE or New York Mercantile Exchange). Level 1 primarily consists of financial assets and liabilities such as exchange-traded financial instruments, publicly-traded equity securities and U.S. government treasury securities.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors for stocks, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are validated by inputs other than quoted prices (e.g., interest rates and yield curves at commonly quoted intervals). Level 2 includes non-exchange-traded instruments such as over-the-counter forward contracts, options, and repurchase agreements.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally-developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities measured on a recurring basis at March 31, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. At March 31, 2008, there were no level 1 financial assets and liabilities.

	Level 2		Level 3		Total

Financial assets:
Commodity financial instruments	$	10,545	$	758	$	11,303
Total	$	10,545	$	758	$	11,303

Financial liabilities:
Commodity financial instruments	$	25,960	$	734	$	26,694
Total	$	25,960	$	734	$	26,694

The determination of fair values above associated with our commodity financial instrument portfolios are developed using available market information and appropriate valuation techniques in accordance with SFAS 157.

The following table sets forth a reconciliation of changes in the fair value of our net financial assets and liabilities classified as level 3 in the fair value hierarchy:

	Net
	Commodity
	Financial
	Instruments

Beginning balance, January 1, 2008	$	(394	)
Total gains (losses) included in:
Net income (1)		418
Other comprehensive income		--
Purchases, issuances, settlements		--
Transfer in/out of Level 3		--

Ending balance, March 31, 2008	$	24

Net unrealized gains (losses) included in net income for
quarter relating to instruments still held at March 31, 2008 (1)	$	418

_________________________________

(1)	At March 31, 2008, total commodity financial instrument gains included in net income were $0.4 million, which were unrealized. This amount was recognized in revenues on our statement of consolidated income for the three months ended March 31, 2008.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 6. INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at March 31, 2008 and December 31, 2007. The major components of inventories were as follows:

	March 31, 2008		December 31, 2007
Crude oil (1)	$	36,529	$	44,542
Refined products and LPGs (2)		31,916		18,616
Lubrication oils and specialty chemicals		9,332		9,160
Materials and supplies		7,858		7,178
NGLs		1,891		803
Total	$	87,526	$	80,299

_________________________________

(1)	At March 31, 2008 and December 31, 2007, $21.4 million and $16.5 million, respectively, of our crude oil inventory was subject to forward sales contracts.

(2)	Refined products and LPGs inventory is managed on a combined basis.

Due to fluctuating commodity prices in the crude oil, refined products and LPG industries, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value. These non-cash charges are a component of costs and expenses in the period they are recognized. For the three months ended March 31, 2008 and 2007, we recognized LCM adjustments of approximately $12 thousand and $0.6 million, respectively.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 7. PROPERTY, PLANT AND EQUIPMENT

Major categories of property, plant and equipment at March 31, 2008 and December 31, 2007, were as follows:

	Estimated
	Useful Life			March 31,		December 31,
	In Years			2008		2007
Plants and pipelines (1)		5-40	(4)	$	1,801,600	$	1,810,195
Underground and other storage facilities (2)		5-40	(5)		256,082		254,677
Transportation equipment (3)		5-10			8,484		7,780
Marine vessels		20-30			422,045		--
Land and right of way					138,593		117,628
Construction work in progress					229,594		185,579
Total property, plant and equipment				$	2,856,398	$	2,375,859
Less accumulated depreciation					604,021		582,225
Property, plant and equipment, net				$	2,252,377	$	1,793,634

______________________________________________

(1)	Plants and pipelines include refined products, LPGs, NGL, petrochemical, crude oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings, laboratory and shop equipment; and related assets.

(2)	Underground and other storage facilities include underground product storage caverns; storage tanks; and other related assets.

(3)	Transportation equipment includes vehicles and similar assets used in our operations.

(4)	The estimated useful lives of major components of this category are as follows: pipelines, 20-40 years (with some equipment at 5 years); terminal facilities, 10-40 years; office furniture and equipment, 5-10 years; buildings 20-40 years; and laboratory and shop equipment, 5-40 years.

(5)	The estimated useful lives of major components of this category are as follows: underground storage facilities, 20-40 years (with some components at 5 years) and storage tanks, 20-30 years.

The following table summarizes our depreciation expense and capitalized interest amounts for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended March 31,
	2008		2007

Depreciation expense (1)	$	21,906	$	19,424
Capitalized interest (2)		4,408		3,728

________________________________________________________

(1)	Depreciation expense is a component of depreciation and amortization expense as presented in our statements of consolidated income.

(2)	Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.

Asset Retirement Obligations

We have conditional asset retirement obligations (“AROs”) related to the retirement of the Val Verde Gas Gathering Company, L.P. (“Val Verde”) natural gas gathering system and to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination. At March 31, 2008, we have a $1.3 million liability, which represents the fair values of these conditional AROs. We assigned probabilities for settlement dates and settlement methods for use in an expected present value measurement of fair value and recorded conditional AROs.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents information regarding our AROs:

ARO liability balance, December 31, 2007	$	1,346
Liabilities incurred		--
Liabilities settled		--
Accretion expense		31
ARO liability balance, March 31, 2008	$	1,377

Property, plant and equipment at March 31, 2008, includes $0.5 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

NOTE 8. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

We own interests in related businesses that are accounted for using the equity method of accounting. These investments are identified below by reporting business segment (see Note 13 for a general discussion of our business segments). The following table presents our investments in unconsolidated affiliates as of March 31, 2008 and December 31, 2007:

	Ownership Percentage at			Investments in unconsolidated affiliates at
	March 31, 2008			March 31, 2008		December 31, 2007

Downstream Segment:
Centennial Pipeline LLC (“Centennial”)		50.0	%	$	77,069	$	78,962
Other		25.0	%		373		362
Upstream Segment:
Seaway Crude Pipeline Company (“Seaway”)		50.0	%		192,047		188,650
Midstream Segment:
Jonah Gas Gathering Company (“Jonah”)		80.64	%		894,848		879,021
Total				$	1,164,337	$	1,146,995

The following table summarizes equity earnings by business segment for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended March 31,
	2008			2007

Equity earnings (losses):
Downstream Segment	$	(4,132	)	$	(1,487	)
Upstream Segment		3,000			1,789
Midstream Segment		23,695			18,629
Intersegment eliminations		(2,901	)		(2,368	)
Total equity earnings	$	19,662		$	16,563

Seaway

Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway. The remaining 50% interest is owned by ConocoPhillips. We operate and commercially manage the Seaway assets. Seaway owns pipelines and terminals that carry imported, offshore and domestic onshore crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, from a marine terminal at Texas City, Texas, to refineries in the

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Texas City and Houston, Texas, areas. Seaway also has a connection to our South Texas system that allows it to receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway. Our sharing ratio (including the amount of distributions we receive) of Seaway for each of the three months ended March 31, 2008 and 2007 was 40% of revenue and expense (and distributions) and will remain at that level in the future. During the three months ended March 31, 2007, we received distributions from Seaway of $3.8 million. During the three months ended March 31, 2008, Seaway paid no distributions due to its operating cash requirements. During the three months ended March 31, 2008 and 2007, we did not invest any funds in Seaway.

Centennial

TE Products owns a 50% ownership interest in Centennial, and Marathon Petroleum Company LLC (“Marathon”) owns the remaining 50% interest. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Marathon operates the mainline Centennial pipeline, and TE Products operates the Beaumont origination point and the Creal Springs terminal. During the three months ended March 31, 2008, we did not invest any funds in Centennial. During the three months ended March 31, 2007, we contributed $6.1 million to Centennial for contractual obligations that were created upon formation of Centennial. TE Products has received no cash distributions from Centennial since its formation.

Jonah

Enterprise Products Partners, through its affiliate, Enterprise Gas Processing, LLC, is our joint venture partner in Jonah, the partnership through which we have owned our interest in the system serving the Jonah and Pinedale fields. The joint venture is governed by a management committee comprised of two representatives approved by Enterprise Products Partners and two representatives approved by us, each with equal voting power. Enterprise Products Partners serves as operator. In connection with the joint venture arrangement, Jonah is nearing the completion of the Phase V expansion, which is expected to increase the combined system capacity of the Jonah and Pinedale fields from 1.5 billion cubic feet (“Bcf”) per day to approximately 2.35 Bcf per day and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The expansion is expected to be completed in the second quarter of 2008. Enterprise Products Partners manages the Phase V construction project.

From August 1, 2006 through July 2007, we and Enterprise Products Partners equally shared the costs of the Phase V expansion, and Enterprise Products Partners shared in the incremental cash flow resulting from the operation of those new facilities. During August 2007, with the completion of the first portion of the expansion, we and Enterprise Products Partners began sharing joint venture cash distributions and earnings based on a formula that takes into account the capital contributions of the parties, including expenditures by us prior to the expansion. Based on this formula in the partnership agreement, at March 31, 2008, our ownership interest in Jonah was approximately 80.64%, and Enterprise Products Partners’ ownership interest in Jonah was approximately 19.36%. Amounts exceeding an agreed upon base cost estimate of $415.2 million are shared 19.36% by Enterprise Products Partners and 80.64% by us. Our ownership interest in Jonah is currently anticipated to remain at 80.64%. Through March 31, 2008, we have reimbursed Enterprise Products Partners $281.1 million ($19.5 million in 2008, $152.2 million in 2007 and $109.4 million in 2006) for our share of the Phase V cost incurred by it (including its cost of capital incurred prior to the formation of the joint venture of $1.3 million). At March 31, 2008 and December 31, 2007, we had payables to Enterprise Products Partners for costs incurred of $7.4 million and $9.9 million, respectively.

In early 2008, Jonah began an expansion of the portion of its system serving the Pinedale field, which is expected to increase the combined system capacity of the Jonah and Pinedale fields from 2.35 Bcf per day (upon completion of the Phase V expansion as described above) to approximately 2.55 Bcf per day. This project will include an additional 17,000 horsepower of compression at the Paradise and Bird Canyon stations in Sublette County, Wyoming and involve construction of approximately 52 miles of 24-inch and 30-inch diameter pipelines. This expansion is expected to be completed in phases, with final completion expected in early 2009. The total anticipated cost of this system expansion is expected to be approximately $125.0 million. Our share of the costs of the construction is expected to be 80.64%, and Enterprise Products Partners’ share is expected to be 19.36%.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During the three months ended March 31, 2008 and 2007, we received distributions from Jonah of $37.2 million and $26.1 million, respectively. The 2007 amount included $11.6 million of distributions declared in 2006 and paid during the first quarter of 2007. During the three months ended March 31, 2008 and 2007, we invested $31.8 million and $30.9 million, respectively, in Jonah.

Summarized Financial Information of Unconsolidated Affiliates

Summarized combined income statement data by reporting segment for the three months ended March 31, 2008 and 2007, is presented below (on a 100% basis):

	For the Three Months Ended
	March 31, 2008							March 31, 2007
	Revenues		Operating Income		Net Income (Loss)			Revenues		Operating Income		Net Income (Loss)

Downstream Segment (1)	$	9,643	$	871	$	(1,837	)	$	15,863	$	1,027	$	(1,724	)
Upstream Segment		20,573		10,354		10,370			18,170		7,835		7,934
Midstream Segment		58,203		29,279		29,424			56,524		20,012		20,169

______________

(1)	On March 1, 2007, we sold our ownership interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”) to Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) (see Note 10).

Summarized combined balance sheet information by reporting segment as of March 31, 2008 and December 31, 2007, is presented below:

	March 31, 2008
	Current Assets		Noncurrent Assets		Current Liabilities		Long-term Debt		Noncurrent Liabilities		Partners’ Capital

Downstream Segment	$	12,905	$	246,410	$	17,294	$	127,350	$	827	$	113,844
Upstream Segment		25,714		250,236		3,978		33		--		271,939
Midstream Segment		49,567		1,093,225		27,305		--		262		1,115,225

	December 31, 2007
	Current Assets		Noncurrent Assets		Current Liabilities		Long-term Debt		Noncurrent Liabilities		Partners’ Capital

Downstream Segment	$	20,864	$	248,896	$	23,814	$	129,900	$	365	$	115,681
Upstream Segment		16,429		251,635		6,457		--		38		261,569
Midstream Segment		55,396		1,065,304		22,545		--		264		1,097,891

NOTE 9. ACQUISITIONS AND DISPOSITIONS

Acquisitions

Cenac

On February 1, 2008, we, through our subsidiary, TEPPCO Marine Services, entered the marine transportation business for refined products, crude oil and condensate. We acquired transportation assets and certain intangible assets that comprised the marine transportation business of Cenac Towing Co., Inc. ("Cenac Towing"), Cenac Offshore, L.L.C. and Mr.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”). The aggregate value of total consideration we paid or issued to complete the Cenac acquisition was $444.3 million, which consisted of $256.6 million in cash and 4,854,899 newly issued Units. Additionally, we assumed $63.2 million of Cenac’s long-term debt in this transaction. On February 1, 2008, we repaid the $63.2 million of assumed debt in full with borrowings under our term credit agreement (see Note 11).

The following table summarizes the components of total consideration paid or issued in this transaction.

Cash payment for Cenac acquisition	$	256,593
Fair value of our 4,854,899 Units		186,558
Other cash acquisition costs paid to third-parties		1,117
Total consideration	$	444,268

We financed the cash portion of the consideration with borrowings under our term credit agreement (see Note 11). In accordance with purchase accounting, the value of our Units issued in connection with the Cenac acquisition was based on the average closing price of such Units immediately prior to and on the day of February 1, 2008. For the purpose of this calculation, the average closing price was $38.43 per Unit.

We acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements. This business serves refineries and storage terminals along the Mississippi, Illinois and Ohio rivers, as well as the Intracoastal Waterway between Texas and Florida. These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast and in the Gulf of Mexico. This acquisition is a natural extension of our existing assets and complements two of our core franchise businesses: the transportation and storage of refined products and the gathering, transportation and storage of crude oil.

The results of operations for the Cenac acquisition are included in our consolidated financial statements beginning at the date of acquisition, in a newly created business segment, Marine Services Segment. Our fleet of acquired tow boats and tank barges will continue to be operated by employees of Cenac under a transitional operating agreement with TEPPCO Marine Services for a period of up to two years following the acquisition. These operations will remain headquartered in Houma, Louisiana during such time.

The purchase agreement gives us the right to repurchase the approximately 4.9 million Units issued in the transaction in connection with proposed sales thereof by Cenac and specified related persons for 10 years. If Cenac or related persons sell Units during a specified 30-day window for a per unit price that is less than the market value of such Units (as determined under the purchase agreement) on February 1, 2008, we are obligated to pay the difference in such values to Cenac or such related persons. In addition, if we or any of our affiliates sell any of the assets acquired from Cenac Towing prior to June 30, 2018 and recognize certain “built-in gains” for federal income tax purposes that are allocable to Cenac Towing, we have indemnification obligations under the purchase agreement to pay Cenac Towing an amount generally intended to compensate for the incremental level of double taxation imposed on Cenac Towing as a result of the sale. The purchase agreement prohibits Cenac from competing with our marine services business for two years or from soliciting employees and service providers of TEPPCO Marine Services and its affiliates for four years. The purchase agreement contains other customary representations, warranties, covenants and indemnification provisions.

This acquisition was accounted for using the purchase method of accounting and, accordingly, the cost has been allocated to assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary fair values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocation for this transaction during 2008.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

Property, plant and equipment	$	359,956
Intangible assets		52,850
Total assets acquired		412,806

Long-term debt		(63,157	)
Total liabilities assumed		(63,157	)
Total assets acquired less liabilities assumed		349,649
Total consideration given		444,268
Goodwill	$	94,619

The $52.9 million preliminary fair value of acquired intangible assets represents customer relationships and non-compete agreements. Customer relationship intangible assets represent the estimated economic value attributable to certain relationships acquired in connection with the Cenac acquisition whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. In this context, customer relationships arise from contractual arrangements (such as transportation contracts) and through means other than contracts, such as regular contact by sales or service representative. The values assigned to these intangible assets are amortized to earnings on a straight-line basis over the expected period of economic benefit, which ranges from 2 to 20 years.

Of the $444.3 million in consideration we paid or issued to complete the Cenac acquisition, $94.6 million has been assigned to goodwill. Management attributes the value of this goodwill to potential future benefits we expect to realize as a result of acquiring these assets.

Since the closing date of the Cenac acquisition was February 1, 2008, our statements of consolidated income do not include any earnings from these assets prior to this date. The following table presents selected pro forma earnings information for the three months ended March 31, 2008 and 2007 as if the Cenac acquisition had been completed on January 1, 2008 and 2007, respectively, instead of February 1, 2008. This information was prepared based on financial data available to us and reflects certain estimates and assumptions made by our management. Our pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had the Cenac acquisition actually occurred on January 1, 2007 or 2008.

	For the Three Months Ended March 30,
	2008		2007

Pro forma earnings data:
Revenues	$	2,820,039	$	2,000,862
Costs and expenses		2,733,916		1,916,753
Operating income		86,123		84,109
Net income		65,681		135,677

Basic and diluted earnings per unit:
Units outstanding, as reported		93,156		89,805
Units outstanding, pro forma		94,747		94,660
Basic and diluted earnings per unit, as reported	$	0.57	$	1.29
Basic and diluted earnings per unit, pro forma	$	0.58	$	1.20

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Horizon

On February 29, 2008, we expanded our Marine Services Segment with the acquisition of marine assets from Horizon Maritime, L.L.C., a privately-held Houston-based company and an affiliate of Mr. Cenac (“Horizon”) for $80.8 million in cash. We acquired 7 tow boats, 17 tank barges, rights to two tow boats under construction and certain related commercial and other agreements (or the associated economic benefits). In April 2008, we paid $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and we expect to pay $3.8 million upon delivery of the second tow boat (see Note 19). The acquired vessels transport asphalt, heavy fuel oil and other heated oil products to storage facilities and refineries along the Mississippi, Illinois and Ohio Rivers, as well as the Intracoastal Waterway. We financed the acquisition with borrowings under our term credit agreement.

The results of operations for the Horizon acquisition are included in our consolidated financial statements beginning at the date of acquisition, in our Marine Services Segment. This acquisition was accounted for using the purchase method of accounting and, accordingly, the cost has been allocated to assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary fair values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocation for this transaction during 2008. The following table summarizes estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

Property, plant and equipment	$	63,872
Intangible assets		6,790
Total assets acquired		70,662

Total consideration given		80,774
Goodwill	$	10,112

The $6.8 million preliminary fair value of acquired intangible assets represents customer relationships and non-compete agreements. Customer relationship intangible assets represent the estimated economic value attributable to certain relationships acquired in connection with the Horizon acquisition whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. In this context, customer relationships arise from contractual arrangements (such as transportation contracts) and through means other than contracts, such as regular contact by sales or service representative. The values assigned to these intangible assets are amortized to earnings on a straight-line basis over the expected period of economic benefit, which ranges from 2 to 9 years.

Of the $80.8 million in consideration we paid to complete the acquisition of the Horizon business, $10.1 million has been assigned to goodwill. Management attributes the value of this goodwill to potential future benefits we expect to realize as a result of acquiring this business and further expanding our Marine Services Segment and complementing two of our core businesses.

Dispositions

MB Storage and Other Related Assets

On March 1, 2007, TE Products sold its 49.5% ownership interest in MB Storage, its 50% ownership interest in Mont Belvieu Venture, LLC (the general partner of MB Storage) and other related assets to Louis Dreyfus for a total of approximately $157.2 million in cash, which includes approximately $18.5 million for other TE Products assets. This sale was in compliance with the October 2006 order and consent agreement with the Bureau of Competition of the Federal Trade Commission (“FTC”) and was completed in accordance with the terms and

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

conditions approved by the FTC in February 2007. We used the proceeds from the transaction to partially fund our 2007 portion of the Jonah Phase V expansion and other organic growth projects. We recognized gains of approximately $59.8 million and $13.2 million related to the sale of our equity interests and other related assets of TE Products, respectively, which are included in gain on sale of ownership interest in MB Storage and gain on the sale of assets, respectively, in our statements of consolidated income.

In accordance with a transition services agreement between TE Products and Louis Dreyfus effective as of March 1, 2007, TE Products will provide certain administrative services to MB Storage for a period of up to two years after the sale, for a fee equal to 110% of the direct costs and expenses TE Products and its affiliates incur to provide the transition services to MB Storage. Payments for these services will be made according to the terms specified in the transition services agreement.

Other Refined Products Assets

On January 23, 2007, we sold a 10-mile, 18-inch segment of pipeline to an affiliate of Enterprise Products Partners for approximately $8.0 million in cash. These assets were part of our Downstream Segment and had a net book value of approximately $2.5 million. The sales proceeds were used to fund construction of a replacement pipeline in the area, in which the new pipeline provides greater operational capability and flexibility. We recognized a gain of approximately $5.5 million on this transaction, which is included in gain on sale of assets in our statements of consolidated income.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 10. INTANGIBLE ASSETS AND GOODWILL

Intangible Assets

The following table summarizes our intangible assets, including excess investments, being amortized at March 31, 2008 and December 31, 2007:

	March 31, 2008					December 31, 2007
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Intangible assets:
Downstream Segment:
Transportation agreements	$	1,000	$	(371	)	$	1,000	$	(358	)
Other		5,227		(434	)		4,927		(325	)
Subtotal		6,227		(805	)		5,927		(683	)
Upstream Segment:
Transportation agreements		888		(350	)		888		(335	)
Other		10,005		(3,179	)		10,005		(3,046	)
Subtotal		10,893		(3,529	)		10,893		(3,381	)
Midstream Segment:
Gathering agreements		239,649		(111,828	)		239,649		(107,356	)
Fractionation agreement		38,000		(19,000	)		38,000		(18,525	)
Other		306		(153	)		306		(149	)
Subtotal		277,955		(130,981	)		277,955		(126,030	)
Marine Services Segment:
Customer relationship intangibles		40,900		(448	)		--		--
Other		18,740		(738	)		--		--
Subtotal		59,640		(1,186	)		--		--
Total intangible assets		354,715		(136,501	)		294,775		(130,094	)

Excess investments: (1)
Downstream Segment (2)		33,390		(22,782	)		33,390		(21,861	)
Upstream Segment (3)		26,908		(5,306	)		26,908		(5,135	)
Midstream Segment (4)		7,469		(128	)		6,988		(95	)
Subtotal		67,767		(28,216	)		67,286		(27,091	)

Total intangible assets, including excess investments	$	422,482	$	(164,717	)	$	362,061	$	(157,185	)

__________________________________________

(1)	Excess investments are included in “Equity Investments” in our consolidated balance sheets.

(2)	Relates to our investment in Centennial.

(3)	Relates to our investment in Seaway.

(4)	Relates to our investment in Jonah.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the amortization expense of our intangible assets by segment for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended March 31,
	2008		2007
Intangible assets:
Downstream Segment	$	122	$	129
Upstream Segment		148		175
Midstream Segment		4,951		5,607
Marine Services Segment		1,186		--
Subtotal		6,407		5,911

Excess investments: (1)
Downstream Segment		921		617
Upstream Segment		171		171
Midstream Segment		33		19
Subtotal		1,125		807

Total amortization expense	$	7,532	$	6,718

___________________________________________

(1)	Amortization of excess investments is included in equity earnings.

The following table sets forth the estimated amortization expense of intangible assets and the estimated amortization expense allocated to equity earnings for the years ending December 31:

	Intangible Assets		Excess Investments
2008	$	28,438	$	5,958
2009		27,278		3,483
2010		25,116		2,349
2011		23,405		1,036
2012		17,665		1,036
2013		16,343		1,036

Goodwill

The following table presents the carrying amount of goodwill at March 31, 2008 and December 31, 2007, by business segment:

	Downstream Segment		Midstream Segment		Upstream Segment		Marine Services Segment		Segments Total

Goodwill:
March 31, 2008	$	1,339	$	--	$	14,167	$	104,731	$	120,237
December 31, 2007		1,339		--		14,167		--		15,506

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 11. DEBT OBLIGATIONS

The following table summarizes the principal amounts outstanding under all of our debt instruments at March 31, 2008 and December 31, 2007:

	March 31,		December 31,
	2008		2007

Short-term senior debt obligations:
6.45% TE Products Senior Notes, due January 2008 (1)	$	--	$	180,000
7.51% TE Products Senior Notes, due January 2028 (1)		--		175,000
Total principal amount of short-term senior debt obligations		--		355,000
Adjustment to carrying value associated with hedges of
fair value and unamortized discounts (2)		--		(1,024	)
Total short-term senior debt obligations	$	--	$	353,976

Long-term:
Senior debt obligations: (3)
Revolving Credit Facility, due December 2012	$	429,200	$	490,000
7.625% Senior Notes, due February 2012		500,000		500,000
6.125% Senior Notes, due February 2013		200,000		200,000
5.90% Senior Notes, due April 2013		250,000		--
6.65% Senior Notes, due April 2018		350,000		--
7.55% Senior Notes, due April 2038		400,000		--
Total principal amount of long-term senior debt obligations		2,129,200		1,190,000

7.000% Junior Subordinated Notes, due June 2067 (3)		300,000		300,000
Total principal amount of long-term debt obligations		2,429,200		1,490,000
Adjustment to carrying value associated with hedges of fair value and unamortized discounts (4)		16,295		21,083
Total long-term debt obligations		2,445,495		1,511,083
Total Debt Instruments (4)	$	2,445,495	$	1,865,059
Standby letter of credit outstanding (5)	$	23,086	$	23,494

_________________

(1)

In January 2008, TE Products retired all of its outstanding long-term debt by repaying at maturity $180.0 million principal amount of its 6.45% TE Products Senior Notes due 2008 and redeeming the remaining $175.0 million principal amount of its 7.51% TE Products Senior Notes due 2028. The redemption price for the 7.51% TE Products Senior Notes due 2028 was 103.755% (or $181.6 million, which includes a $6.6 million make-whole premium) of the principal amount plus accrued and unpaid interest to January 28, 2008, the date of redemption, of $0.5 million.

(2)	Includes $1.0 million related to fair value hedges and $2 thousand in unamortized discount. In January 2008, with the redemption of the 7.51% TE Products Senior Notes, the remaining unamortized loss was recognized in the statement of consolidated income.

(3)	TE Products, TCTM, TEPPCO Midstream and Val Verde (collectively, the “Subsidiary Guarantors”) have issued full, unconditional, joint and several guarantees of our senior notes, junior subordinated notes and revolving credit facility.

(4)

We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the debt obligations presented above (see Note 5). At March 31, 2008 and December 31, 2007, amount includes $5.6 million and $2.1 million of unamortized discounts, respectively, and $21.9 million and $23.2 million related to fair value hedges, respectively.

(5)	Letters of credit were issued in connection with crude oil purchased during the respective quarter. Payables related to these purchases of crude oil are generally paid during the following quarter.

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Revolving Credit Facility

We have in place a $700.0 million unsecured revolving credit facility, including the issuance of letters of credit (“Revolving Credit Facility”), which matures on December 12, 2012. The Revolving Credit Facility allows us to request unlimited one-year extensions of the maturity date, subject to lender approval and satisfaction of certain other conditions and contains an accordion feature whereby the total amount of the bank commitments may be increased, with lender approval and the satisfaction of certain other conditions, from $700.0 million up to a maximum amount of $1.0 billion. The aggregate outstanding principal amount of swing line loans or same day borrowings permitted under the Revolving Credit Facility is $40.0 million. The interest rate is based, at our option, on either the lender’s base rate, or LIBOR rate, plus a margin, in effect at the time of the borrowings. The applicable margin with respect to LIBOR rate borrowings is based on our senior unsecured non-credit enhanced long-term debt rating issued by Standard & Poor’s Rating Services and Moody’s Investors Service, Inc. The Revolving Credit Facility contains a term-out option in which we may, on the maturity date, convert the principal balance of all revolving loans then outstanding into a non-revolving one-year term loan. Upon the conversion of the revolving loans to term loans pursuant to the term-out option, the applicable LIBOR spread will increase by 0.125% per year, and if immediately prior to such borrowing the total outstanding revolver borrowings then outstanding exceeds 50% of the total lender commitments, the applicable LIBOR spread with respect to borrowings will increase by an additional 10 basis points.

The Revolving Credit Facility contains financial covenants that require us to maintain a ratio of Consolidated Funded Debt to Pro Forma EBITDA (as defined and calculated in the facility) of less than 5.00 to 1.00 (and, if after giving effect to a permitted acquisition the ratio exceeds 5.00 to 1.00, the threshold ratio will be increased to 5.50 to 1.00 for the fiscal quarter in which such acquisition occurs and the first full fiscal quarter following such acquisition). Other restrictive covenants in the Revolving Credit Facility limit our ability, and the ability of certain of our subsidiaries, to, among other things, incur certain additional indebtedness, make distributions in excess of Available Cash (see Note 12), incur certain liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets. The credit agreement restricts the amount of outstanding debt of the Jonah joint venture to debt owing to the owners of its partnership interests and other third-party debt in the aggregate principal amount of $50.0 million and allows for the issuance of certain hybrid securities of up to 15% of our Consolidated Total Capitalization (as defined therein). At March 31, 2008, $429.2 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 3.16%. At March 31, 2008, we were in compliance with the covenants of the Revolving Credit Facility.

Senior Notes

On January 27, 1998, TE Products issued $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”). Interest on the TE Products Senior Notes was payable semiannually in arrears on January 15 and July 15 of each year. The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and were being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 were redeemed at maturity on January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, became redeemable at any time after January 15, 2008, at the option of TE Products, in whole or in part, at varying fixed annual redemption prices. In October 2007, TE Products repurchased $35.0 million principal amount of the 7.51% TE Products Senior Notes for $36.1 million and accrued interest. On January 28, 2008, TE Products redeemed the remaining $175.0 million of 7.51% TE Products Senior Notes at a redemption price of 103.755% of the principal amount plus accrued and unpaid interest at the date of redemption. We funded the retirement of both series of senior notes with borrowings under our term credit agreement.

On February 20, 2002 and January 30, 2003, we issued $500.0 million principal amount of 7.625% Senior Notes due 2012 (“7.625% Senior Notes”) and $200.0 million principal amount of 6.125% Senior Notes due 2013

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(“6.125% Senior Notes”), respectively. The 7.625% Senior Notes and the 6.125% Senior Notes were issued at discounts of $2.2 million and $1.4 million, respectively, and are being accreted to their face value over the applicable term of the senior notes. 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.

On March 27, 2008, we issued (i) $250.0 million principal amount of 5.90% Senior Notes due 2013, (ii) $350.0 million principal amount of 6.65% Senior Notes due 2018, and (iii) $400.0 million principal amount of 7.55% Senior Notes due 2038. The senior notes were issued at discounts of $0.2 million, $1.3 million and $2.2 million, respectively, and are being accreted to their face value over the applicable terms of the senior notes. 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 50 basis points.

The indentures governing our senior notes contain covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indentures do not limit our ability to incur additional indebtedness. At March 31, 2008, we were in compliance with the covenants of our senior notes.

Junior Subordinated Notes

In May 2007, we issued and sold $300.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due June 1, 2067 (“Junior Subordinated Notes”). Our payment obligations under the Junior Subordinated Notes are subordinated to all of our current and future senior indebtedness (as defined in the related indenture). The Subsidiary Guarantors have issued full, unconditional, and joint and several guarantees, on a junior subordinated basis, of payment of the principal of, premium, if any, and interest on the Junior Subordinated Notes.

The indenture governing the Junior Subordinated Notes does not limit our ability to incur additional debt, including debt that ranks senior to or equally with the Junior Subordinated Notes. The indenture allows us to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture also provides that during any period in which we defer interest payments on the Junior Subordinated Notes, subject to certain exceptions, (i) we cannot declare or make any distributions with respect to, or redeem, purchase or make a liquidation payment with respect to, any of our equity securities; (ii) neither we nor the Subsidiary Guarantors will make, and we and the Subsidiary Guarantors will cause our respective majority-owned subsidiaries not to make, any payment of interest, principal or premium, if any, on or repay, purchase or redeem any of our or the Subsidiary Guarantors’ debt securities (including securities similar to the Junior Subordinated Notes) that contractually rank equally with or junior to the Junior Subordinated Notes or the guarantees, as applicable; and (iii) neither we nor the Subsidiary Guarantors will make, and we and the Subsidiary Guarantors will cause our respective majority-owned subsidiaries not to make, any payments under a guarantee of debt securities (including under a guarantee of debt securities that are similar to the Junior Subordinated Notes) that contractually ranks equally with or junior to the Junior Subordinated Notes or the guarantees, as applicable.

The Junior Subordinated Notes bear interest at a fixed annual rate of 7.000% from May 2007 to June 1, 2017, payable semi-annually in arrears on June 1 and December 1 of each year, commencing December 1, 2007. After June 1, 2017, the Junior Subordinated Notes will bear interest at a variable annual rate equal to the 3-month LIBOR rate for the related interest period plus 2.7775%, payable quarterly in arrears on March 1, June 1, September 1 and December 1 of each year commencing September 1, 2017. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to certain provisions. Deferred interest will accumulate additional interest at the then-prevailing interest rate on the Junior Subordinated Notes. The Junior Subordinated Notes mature

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

in June 2067. The Junior Subordinated Notes are redeemable in whole or in part prior to June 1, 2017 for a “make-whole” redemption price and thereafter at a redemption price equal to 100% of their principal amount plus accrued interest. The Junior Subordinated Notes are also redeemable prior to June 1, 2017 in whole (but not in part) upon the occurrence of certain tax or rating agency events at specified redemption prices. At March 31, 2008, we were in compliance with the covenants of the Junior Subordinated Notes.

In connection with the issuance of the Junior Subordinated Notes, we and our Subsidiary Guarantors entered into a replacement capital covenant in favor of holders of a designated series of senior long-term indebtedness (as provided in the underlying documents) pursuant to which we and our Subsidiary Guarantors agreed for the benefit of such debt holders that we would not redeem or repurchase or otherwise satisfy, discharge or defease any of the Junior Subordinated Notes on or before June 1, 2037, unless, subject to certain limitations, during the 180 days prior to the date of that redemption, repurchase, defeasance or purchase, we have or one of our subsidiaries has received a specified amount of proceeds from the sale of qualifying securities that have characteristics that are the same as, or more equity-like than, the applicable characteristics of the Junior Subordinated Notes. The replacement capital covenant is not a term of the indenture or the Junior Subordinated Notes.

Fair Values

The following table summarizes the estimated fair values of the Senior Notes and Junior Subordinated Notes at March 31, 2008 and December 31, 2007:

			Fair Value
			March 31,		December 31,
	Face Value		2008		2007

6.45% TE Products Senior Notes, due January 2008 (1)	$	180,000	$	--	$	179,982
7.625% Senior Notes, due February 2012		500,000		533,188		536,765
6.125% Senior Notes, due February 2013		200,000		202,368		202,027
5.90% Senior Notes, due April 2013		250,000		251,960		--
6.65% Senior Notes, due April 2018		350,000		353,531		--
7.51% TE Products Senior Notes, due January 2028 (1)		175,000		--		181,571
7.55% Senior Notes, due April 2038		400,000		404,031		--
7.000% Junior Subordinated Notes, due June 2067		300,000		253,724		270,485

_________________

(1)

On January 28, 2008, TE Products redeemed the $175.0 million of 7.51% TE Products Senior Notes at a redemption price of 103.755% of the principal amount plus accrued and unpaid interest at the date of redemption. Additionally, the $180.0 million principal amount of 6.45% TE Products Senior Notes matured and was repaid on January 15, 2008. We funded the retirement of both series with borrowings under our term credit agreement.

Term Credit Agreement

We had in place a senior unsecured term credit agreement (“Term Credit Agreement”), with a borrowing capacity of $1.0 billion and a maturity date of December 19, 2008. Term loans could have been drawn in up to five separate drawings, each in a minimum amount of $75.0 million. Amounts repaid could not be re-borrowed, and the principal amounts of all term loans were due and payable in full on the maturity date. We were required to make mandatory principal repayments on the outstanding term loans from 100% of the net cash proceeds we received from (i) any asset sale excluding asset sales made in the ordinary course of business and sales to the extent aggregate proceeds are less than $25.0 million, and (ii) subject to specified exceptions, issuances of debt or equity. The interest rate was based, at our option, on either the lender’s base rate, or LIBOR rate, plus a margin, in effect at the time of the borrowings. The applicable margin with respect to LIBOR rate borrowings was based on our senior unsecured non-credit enhanced long-term debt rating issued by Standard & Poor’s Rating Services and Moody’s Investors Service, Inc. Financial covenants in the Term Credit Agreement required us to maintain a ratio of

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Consolidated Funded Debt to Pro Forma EBTIDA (as defined and calculated in the facility) of less than 5.00 to 1.00 (subject to adjustment for specified acquisitions, as described above with respect to our Revolving Credit Facility). Other restrictive covenants in the Term Credit Agreement limited our ability, and the ability of certain of our subsidiaries, to, among other things, incur certain indebtedness, make distributions in excess of Available Cash (see Note 12), incur certain liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets. Our obligations under the Term Credit Agreement were guaranteed by the Subsidiary Guarantors. During the first quarter of 2008, we borrowed $1.0 billion to finance the retirement of TE Products’ senior notes and the Cenac and Horizon acquisitions and for other partnership purposes. In March 2008, we repaid the outstanding balance with proceeds from the issuance of senior notes and other cash on hand and terminated the agreement.

Debt Obligations of Unconsolidated Affiliates

We have one unconsolidated affiliate, Centennial, with long-term debt obligations. The following table shows the total debt of Centennial at March 31, 2008 (on a 100% basis) and the corresponding scheduled maturities of such debt.

	Scheduled Maturities of Debt
2008	$	10,100
2009		9,900
2010		9,100
2011		9,000
2012		8,900
After 2012		93,000
Total scheduled maturities of debt	$	140,000

At March 31, 2008 and December 31, 2007, Centennial’s debt obligations consisted of $140.0 million borrowed under a master shelf loan agreement. Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial’s assets and severally guaranteed by Centennial’s owners. In January 2008, we entered into an amended and restated guaranty agreement (“Amended Guaranty”) in which we, TCTM, TEPPCO Midstream and TE Products (collectively, “TEPPCO Guarantors”) are required, on a joint and several basis, to pay 50% of any past-due amount under Centennial’s master shelf loan agreement not paid by Centennial (see Note 16).

NOTE 12. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Our Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Partnership Agreement. We are managed by our General Partner.

In accordance with the Partnership Agreement, capital accounts are maintained for our General Partner and limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements. In connection with the amendment of our Partnership Agreement in December 2006, the General Partner’s obligation to make capital contributions to maintain its 2% capital account was eliminated.

Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and General Partner will receive. Net income is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General

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Partner and the limited partners during the period. This is generally consistent with the manner of allocating net income under our Partnership Agreement. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under GAAP in our financial statements.

Equity Offerings and Registration Statements

In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by our General Partner in its sole discretion (subject, under certain circumstances, to the approval of our unitholders).

We have a universal shelf registration statement on file with the SEC that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $2.0 billion of equity securities, debt securities or a combination thereof. In March 2008, we sold $1.0 billion principal amount of senior notes under our universal shelf registration statement (see Note 11). After taking into account past issuances of securities under this registration statement, as of March 31, 2008, we have the ability to issue approximately $205.1 million of additional securities under this registration statement, subject to customary marketing terms and conditions.

Quarterly Distributions of Available Cash

We make quarterly cash distributions of all of our available cash, generally defined in our Partnership Agreement as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its reasonable discretion (“Available Cash”). Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds as shown in the following table:

				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	%
Over First Target – Cash distributions greater than $0.325 per Unit		75	%		25	%

The following table reflects the allocation of total distributions paid during the three months ended March 31, 2008 and 2007.

	For the Three Months Ended March 31,
	2008		2007
Limited Partner Units	$	62,489	$	60,618
General Partner Ownership Interest		1,275		1,237
General Partner Incentive		11,109		10,534
Total Cash Distributions Paid	$	74,873	$	72,389

Total Cash Distributions Paid Per Unit	$	0.695	$	0.675

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Our quarterly cash distributions for 2008 are presented in the following table:

	Cash Distribution History
	Distribution per Unit		Record Date	Payment Date

1st Quarter 2008	$	0.7100	Apr. 30, 2008	May 7, 2008

______________________

(1)	The first quarter 2008 cash distribution totaled approximately $80.9 million.

EPCO, Inc. TPP Employee Unit Purchase Plan

The EPCO, Inc. TPP Employee Unit Purchase Plan (the “Unit Purchase Plan”) provides for discounted purchases of our Units by employees of EPCO and its affiliates. A maximum of 1,000,000 Units may be delivered under the Unit Purchase Plan (subject to adjustment as provided in the plan). The Unit Purchase Plan is effective until December 8, 2016, or, if earlier, at the time that all available Units under the plan have been purchased on behalf of the participants or the time of termination of the plan by EPCO or the Chairman or Vice Chairman of EPCO. As of March 31, 2008, 8,417 Units have been issued to employees under this plan.

Distribution Reinvestment Plan

Our distribution reinvestment plan (“DRIP”) provides for the issuance of up to 10,000,000 Units. Units purchased through the DRIP may be acquired at a discount rating from 0% to 5% (currently set at 5%), which will be set from time to time by us. As of March 31, 2008, 109,115 Units have been issued in connection with the DRIP.

General Partner’s Interest

At March 31, 2008 and December 31, 2007, we had deficit balances of $89.6 million and $88.0 million, respectively, in our General Partner’s equity account. These negative balances do not represent assets to us and do not represent obligations of the General Partner to contribute cash or other property to us. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Statement of Consolidated Partners’ Capital for a detail of the General Partner’s equity account). For the three months ended March 31, 2008, our General Partner was allocated $10.7 million (representing 16.74%) of our net income and received $12.4 million in cash distributions.

Cash distributions that we make during a period may exceed our net income for the period. 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 reasonable discretion. Cash distributions in excess of net income allocations and capital contributions during previous years, resulted in a deficit in the General Partner’s equity account at December 31, 2007 and March 31, 2008. Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.

According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the Partnership. If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Accumulated Other Comprehensive Income (Loss)

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, gains or losses associated with pension or other postretirement benefits, prior service costs or credits associated with pension or other postretirement benefits, transition assets or obligations associated with pension or other postretirement benefits and unrealized gains and losses on certain investments in debt and equity securities to be reported in a financial statement. As of and for the three months ended March 31, 2008, the components of accumulated other comprehensive income (loss) reflected on our consolidated balance sheets were composed of crude oil hedges and treasury locks. The series of crude oil hedges have forward positions throughout 2008. While the crude oil hedges are in effect, changes in their fair values, to the extent the hedges are effective, are recognized in accumulated other comprehensive income until they are recognized in net income in future periods. The amounts related to settlements of treasury lock agreements are being amortized into earnings over the terms of the respective debt (see Note 5).

The accumulated balance of other comprehensive income (loss) is as follows:

Balance at December 31, 2007	$	(42,557	)
Changes in fair values of crude oil cash flow hedges		3,089
Settlement of treasury locks		(52,098	)
Amortization of treasury lock proceeds into earnings		(26	)
Changes in fair values of treasury locks		25,296
Ineffectiveness of treasury locks		42
Transfer portion of interest payment hedged under treasury locks
not occurring as forecasted to earnings		3,586
Balance at March 31, 2008	$	(62,668	)

NOTE 13. BUSINESS SEGMENTS

We have four reporting segments:

Our Downstream Segment, which is engaged in the pipeline transportation, marketing and storage of refined products, LPGs and petrochemicals;
Our Upstream Segment, which is engaged in the gathering, pipeline transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals;
Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and pipeline transportation of NGLs; and
Our Marine Services Segment, which is engaged in the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges.

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 pipeline transportation, marketing and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. We generally realize higher revenues in the Downstream Segment during the first and fourth quarters of each year since LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating. 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. The two

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

largest operating expense items of the Downstream Segment are labor and electric power. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investment in Centennial (see Note 8).

Our Upstream Segment revenues are earned from gathering, pipeline transporting, marketing and storing crude oil and distributing lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating crude oil purchased at the lease along our pipeline systems, and from third party pipeline systems, and arranging the necessary transportation logistics for the ultimate sale or delivery of the crude oil to local refineries, marketers or other end users. Revenues are also generated from trade documentation and terminaling services, primarily at Cushing, Oklahoma, and Midland, Texas. Our Upstream Segment also includes our equity investment in Seaway (see Note 8). 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. Seaway also has a connection to our South Texas system that allows it to receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing.

Our Midstream Segment revenues are earned from the gathering of coal bed methane and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde; transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; and the fractionation of NGLs in Colorado. Our Midstream Segment also includes our equity investment in Jonah (see Note 8). Jonah, which is a joint venture between us and an affiliate of Enterprise Products Partners, owns a natural gas gathering system in the Green River Basin in southwestern Wyoming.

Our Marine Services Segment revenues are earned from the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges. We entered the marine transportation business in February 2008 with the acquisition of assets and certain intangible assets from Cenac and Horizon on February 1, 2008 and February 29, 2008, respectively (see Note 10). These businesses service refineries and storage terminals along the Mississippi, Illinois and Ohio rivers, as well as the Intracoastal Waterway between Texas and Florida. These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast and in the Gulf of Mexico.

The following table presents our measurement of earnings before interest expense for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended March 31,
	2008		2007

Total operating revenues	$	2,808,488	$	1,978,429
Less: Total costs and expenses		2,724,969		1,894,995
Operating income		83,519		83,434
Add:Gain on sale of ownership interest in MB Storage		--		59,837
Equity earnings		19,662		16,563
Interest income		308		342
Other income – net		40		244
Earnings before interest expense and provision for income taxes	$	103,529	$	160,420

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A reconciliation of our earnings before interest expense and provision for income taxes to net income for the three months ended March 31, 2008 and 2007 is as follows:

	For the Three Months Ended March 31,
	2008			2007

Earnings before interest expense and provision for income taxes	$	103,529		$	160,420
Interest expense – net		(38,571	)		(22,211	)
Income before provision for income taxes		64,958			138,209
Provision for income taxes		819			18
Net income	$	64,139		$	138,191

The table below includes information by segment, together with reconciliations to our consolidated totals for the periods indicated:

	Downstream Segment		Upstream Segment		Midstream Segment		Marine Services Segment		Partnership and Other			Consolidated

Revenues from third parties:
Three months ended March 31, 2008	$	94,502	$	2,655,068	$	26,577	$	25,536	$	--		$	2,801,683
Three months ended March 31, 2007		92,952		1,854,082		26,563		--		--			1,973,597

Revenues from related parties:
Three months ended March 31, 2008	$	3,130	$	235	$	3,504	$	--	$	(64	)	$	6,805
Three months ended March 31, 2007		1,966		254		2,810		--		(198	)		4,832

Intersegment and intrasegment revenues:
Three months ended March 31, 2008	$	--	$	--	$	--	$	--	$	--		$	--
Three months ended March 31, 2007		--		--		81		--		(81	)		--

Total revenues:
Three months ended March 31, 2008	$	97,632	$	2,655,303	$	30,081	$	25,536	$	(64	)	$	2,808,488
Three months ended March 31, 2007		94,918		1,854,417		29,373		--		(279	)		1,978,429

Depreciation and amortization:
Three months ended March 31, 2008	$	10,236	$	4,777	$	9,597	$	3,734	$	--		$	28,344
Three months ended March 31, 2007		11,136		4,068		10,165		--		--			25,369

Operating income:
Three months ended March 31, 2008	$	36,329	$	29,335	$	8,386	$	6,568	$	2,901		$	83,519
Three months ended March 31, 2007		53,941		22,315		4,810		--		2,368			83,434


Equity earnings (losses):
Three months ended March 31, 2008	$	(4,132	)	$	3,000	$	23,695	$	--	$	(2,901	)	$	19,662
Three months ended March 31, 2007		(1,487	)		1,789		18,629		--		(2,368	)		16,563

Earnings before interest expense and provision for income taxes:
Three months ended March 31, 2008	$	32,415		$	32,341	$	32,201	$	6,572	$	--		$	103,529
Three months ended March 31, 2007		112,722			24,147		23,551		--		--			160,420

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Downstream Segment		Upstream Segment		Midstream Segment		Marine Services Segment		Partnership and Other			Consolidated

Segment assets:
At March 31, 2008	$	1,216,875	$	2,403,701	$	1,609,762	$	606,415	$	(232,901	)	$	5,603,852
At December 31, 2007		1,221,316		2,084,830		1,512,621		--		(68,710	)		4,750,057

Capital expenditures:
At March 31, 2008	$	45,747	$	5,510	$	387	$	110	$	(153	)	$	51,601
At December 31, 2007		165,353		54,583		7,412		--		924			228,272

Investments in unconsolidated affiliates:
At March 31, 2008	$	68,052	$	192,047	$	904,238	$	--	$	--		$	1,164,337
At December 31, 2007		79,324		188,650		879,021		--		--			1,146,995

Intangible assets:
At March 31, 2008	$	5,422	$	7,364	$	146,974	$	58,454	$	--		$	218,214
At December 31, 2007		5,244		7,512		151,925		--		--			164,681

Goodwill:
At March 31, 2008	$	1,339	$	14,167	$	--	$	104,731	$	--		$	120,237
At December 31, 2007		1,339		14,167		--		--		--			15,506

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 14. RELATED PARTY TRANSACTIONS

The following table summarizes the related party transactions for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended
	March 31,
	2008		2007
Revenues from EPCO and affiliates:
Sales of petroleum products (1)	$	646	$	76
Transportation – NGLs (2)		3,403		2,810
Transportation – LPGs (3)		2,287		1,606
Other operating revenues (4)		433		306
Revenues from unconsolidated affiliates:
Other operating revenues (5)		36		34
Costs and Expenses from EPCO and affiliates:
Purchases of petroleum products (6)		19,693		12,147
Operating expense (7)		26,112		24,297
General and administrative (8)		8,525		6,538
Costs and Expenses from unconsolidated affiliates:
Purchases of petroleum products (9)		1,592		--
Operating expense (10)		2,272		670
Costs and Expenses from Cenac and affiliates: (11)
Operating expense (12)		7,867		--

_______________________________________

(1)	Includes sales from TE Products and Lubrication Services, LLC (“LSI”) to Enterprise Products Partners and certain of its subsidiaries.

(2)	Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines from Enterprise Products Partners and certain of its subsidiaries.

(3)	Represents revenues from LPG transportation on the TE Products pipeline from Enterprise Products Partners and certain of its subsidiaries.

(4)	Includes other operating revenues on the TE Products pipeline and the Val Verde system from Enterprise Products Partners and certain of its subsidiaries.

(5)	Includes sales of petroleum products, management fees and rental revenues.

(6)	Includes TCO purchases of condensate of $15.6 million and $8.8 million for the three months ended March 31, 2008 and 2007, respectively, and expenses related to TCO’s and LSI’s use of an affiliate of EPCO as a transporter.

(7)

Includes operating payroll, payroll related expenses and other operating expenses, including reimbursements related to employee benefits and employee benefit plans, incurred by EPCO in managing us and our subsidiaries in accordance with the ASA. Also includes insurance expense for the three months ended March 31, 2008 and 2007, of $2.9 million and $5.1 million, respectively, related to premiums paid by EPCO on our behalf. The majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, is obtained through EPCO.

(8)	Includes administrative payroll, payroll related expenses and other administrative expenses, including reimbursements related to employee benefits and employee benefit plans, incurred by EPCO in managing and operating us and our subsidiaries in accordance with the ASA.

(9)	Includes TCO purchases of petroleum products from Jonah and Seaway and pipeline transportation expense from Seaway.

(10)	Includes rental expense and other operating expense.

(11)	We entered into a transitional operating agreement with Cenac in which our fleet of acquired tow boats and tank barges (including those acquired from Horizon) are operated by employees of Cenac for a period of up to two years following the acquisition.

(12)

Includes reimbursement for operating payroll, payroll related expenses, certain repairs and maintenance expenses and insurance premiums on our equipment, as well as payment of a $42 thousand monthly service fee and a 5% overhead fee charged on direct costs incurred by Cenac to operate the marine assets in accordance with the transitional operating agreement with Cenac.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes the related party balances at March 31, 2008 and December 31, 2007:

	March 31, 2008		December 31, 2007

Accounts receivable, related parties (1)	$	5,003	$	6,525
Accounts payable, related parties (2)		29,695		38,980

________________________________________________

(1)	Relates to sales and transportation services provided to Enterprise Products Partners and certain of its subsidiaries and EPCO and certain of its affiliates and direct payroll, payroll related costs and other operational expenses charged to unconsolidated affiliates.

(2)

Relates to direct payroll, payroll related costs and other operational related charges from Enterprise Products Partners and certain of its subsidiaries and EPCO and certain of its affiliates, transportation and other services provided by unconsolidated affiliates and advances from Seaway for operating expenses.

Relationship with EPCO and Affiliates

We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities:

EPCO and its consolidated private company subsidiaries;
Texas Eastern Products Pipeline Company, LLC, our General Partner;
Enterprise GP Holdings, which owns and controls our General Partner;
Enterprise Products Partners, which is controlled by affiliates of EPCO, including Enterprise GP Holdings;
Duncan Energy Partners L.P., which is controlled by affiliates of EPCO; and
Enterprise Gas Processing LLC, which is controlled by affiliates of EPCO and is our joint venture partner in Jonah.

Dan L. Duncan directly owns and controls EPCO and through Dan Duncan LLC, owns and controls EPE Holdings, the general partner of Enterprise GP Holdings. Enterprise GP Holdings owns all of the membership interests of our General Partner. The principal business activity of our General Partner is to act as our managing partner. The executive officers of our General Partner are employees of EPCO (see Note 1).

We and our General Partner are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO and its consolidated private company subsidiaries and affiliates depend on the cash distributions they receive from our General Partner and other investments to fund their operations and to meet their debt obligations. We paid cash distributions to our General Partner of $12.4 million and $11.8 million during the three months ended March 31, 2008 and 2007, respectively.

The limited partner interests in us that are owned or controlled by EPCO and certain of its affiliates, other than those interests owned by Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of an affiliate of EPCO. All of the membership interests in our General Partner and the limited partner interests in us that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. If Enterprise GP Holdings were to default under its credit facility, its lender banks could own our General Partner.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Unless noted otherwise, our transactions and agreements with EPCO or its affiliates are not on an arm’s length basis. As a result, we cannot provide assurance that the terms and provisions of such transactions or agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

We do not have any employees. We are managed by our General Partner, and all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to the ASA or by other service providers. We reimburse EPCO for the allocated costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees (see Note 1).

Jonah Joint Venture

Enterprise Products Partners (through an affiliate) is our joint venture partner in Jonah, the partnership through which we have owned our interest in the system serving the Jonah and Pinedale fields. Through March 31, 2008, we have reimbursed Enterprise Products Partners $281.1 million ($19.5 million in 2008, $152.2 million in 2007 and $109.4 million in 2006) for our share of the Phase V cost incurred by it (including its cost of capital incurred prior to the formation of the joint venture of $1.3 million). At March 31, 2008 and December 31, 2007, we had payables to Enterprise Products Partners for costs incurred of $7.4 million and $9.9 million, respectively (see Note 8). At March 31, 2008 and December 31, 2007, we had receivables from Jonah of $4.3 million and $6.0 million, respectively, for distributions and operating expenses. During the three months ended March 31, 2008 and 2007, we received distributions from Jonah of $37.2 million and $26.1 million, respectively. The 2007 amount included $11.6 million of distributions declared in 2006 and paid during the first quarter of 2007. During the three months ended March 31, 2008 and 2007, Jonah paid distributions of $8.9 million and $0.4 million, respectively, to the affiliate of Enterprise Products Partners that is our joint venture partner.

We have agreed to indemnify Enterprise Products Partners from any and all losses, claims, demands, suits, liability, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the formation of the Jonah joint venture, Jonah’s ownership or operation of the Jonah-Pinedale system prior to the effective date of the joint venture, and any environmental activity, or violation of or liability under environmental laws arising from or related to the condition of the Jonah-Pinedale system prior to the effective date of the joint venture. In general, a claim for indemnification cannot be filed until the losses suffered by Enterprise Products Partners exceed $1.0 million, and the maximum potential amount of future payments under the indemnity is limited to $100.0 million. However, if certain representations or warranties are breached, the maximum potential amount of future payments under the indemnity is capped at $207.6 million. All indemnity payments are net of insurance recoveries that Enterprise Products Partners may receive from third-party insurers. We carry insurance coverage that may offset any payments required under the indemnity. We do not expect that these indemnities will have a material adverse effect on our financial position, results of operations or cash flows.

Sale of General Partner to Enterprise GP Holdings; Relationship with Energy Transfer Equity

On May 7, 2007, all of the membership interests in our General Partner, together with 4,400,000 of our Units, were sold by DFIGP to Enterprise GP Holdings, a publicly traded partnership also controlled indirectly by Dan L. Duncan. As of May 7, 2007, Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest. Enterprise GP Holdings, DFIGP and other entities controlled by Mr. Duncan own 16,691,550 of our Units.

Concurrently with the acquisition of our General Partner, Enterprise GP Holdings acquired non-controlling ownership interests in Energy Transfer Equity, L.P. (“Energy Transfer Equity”) and LE GP, LLC (“ETE GP”), the general partner of Energy Transfer Equity. Following the transaction, Enterprise GP Holdings owns approximately

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34.9% of the membership interests in ETE GP and 38,976,090 common units of Energy Transfer Equity representing approximately 17.6% of the outstanding limited partner interests in Energy Transfer Equity.

Other Transactions

Relationship with Unconsolidated Affiliates

Our significant related party revenues and expense transactions with unconsolidated affiliates consist of management, rental and other revenues, transportation expense related to movements on Centennial and Seaway and rental expense related to the lease of pipeline capacity on Centennial. For additional information regarding our unconsolidated affiliates, see Note 8.

NOTE 15. EARNINGS PER UNIT

Basic earnings per Unit is computed by dividing net income or loss allocated to limited partner interests by the weighted average number of distribution-bearing Units outstanding during a period. The amount of net income allocated to limited partner interests is derived by subtracting our General Partner’s share of the net income from net income. Diluted earnings per Unit is computed by dividing net income or loss allocated to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing Units outstanding during a period (as used in determining basic earnings per Unit); and (ii) the number of incremental Units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).

In May 2007, we granted 155,000 unit options to employees providing services to us (see Note 3). These unit options were excluded from the computation of diluted earnings per Unit due to their anti-dilutive effect as they represent unit options with an exercise price greater than the average market price of a Unit for the period.

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The following table shows the computation of basic and diluted earnings per Unit for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended March 31,
	2008			2007

Net income	$	64,139		$	138,191
General Partner interest in net income		16.74	%		16.40	%
Earnings allocated to General Partner	$	10,736		$	22,667

BASIC AND DILUTED EARNINGS PER UNIT:
Numerator:
Limited partners’ interest in net income	$	53,403		$	115,524

Denominator:
Units		93,094			89,805
Time-vested restricted Units		62			--
Total Weighted average Units outstanding		93,156			89,805

Basic and diluted earnings per Unit:
Limited partners’ interest in net income	$	0.57		$	1.29

Our General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our Partnership Agreement. At March 31, 2008 and 2007, we had outstanding 94,839,660 and 89,804,829 Units, respectively.

NOTE 16. COMMITMENTS AND CONTINGENCIES

Litigation

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 plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs assert damages attributable to the remediation of the property of approximately $1.4 million. This case has been stayed pending the completion of remediation pursuant to the Louisiana Department of Environmental Quality (“LDEQ”) requirements. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants. The former refinery is located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property. The plaintiffs have pursued certification as a class and have significantly increased their demand to approximately $175.0 million. We have never owned any interest in the refinery property made the basis of this action, and we do not believe that we contributed to any alleged contamination of this property. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

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On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of our other unitholders, and derivatively on our behalf, concerning proposals made to our unitholders in our definitive proxy statement filed with the SEC on September 11, 2006 (“Proxy Statement”) and other transactions involving us and Enterprise Products Partners or its affiliates. Mr. Brinckerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants the General Partner; the Board of Directors of the General Partner; EPCO; Enterprise Products Partners and certain of its affiliates and Dan L. Duncan. We are named as a nominal defendant.

The amended complaint alleges, among other things, that certain of the transactions adopted at a special meeting of our unitholders on December 8, 2006, including a reduction of the General Partner’s maximum percentage interest in our distributions in exchange for Units (the “Issuance Proposal”), were unfair to our unitholders and constituted a breach by the defendants of fiduciary duties owed to our unitholders and that the Proxy Statement failed to provide our unitholders with all material facts necessary for them to make an informed decision whether to vote in favor of or against the proposals. The amended complaint further alleges that, since Mr. Duncan acquired control of the General Partner in 2005, the defendants, in breach of their fiduciary duties to us and our unitholders, have caused us to enter into certain transactions with Enterprise Products Partners or its affiliates that were unfair to us or otherwise unfairly favored Enterprise Products Partners or its affiliates over us. The amended complaint alleges that such transactions include the Jonah joint venture entered into by us and an Enterprise Products Partners affiliate in August 2006 (citing the fact that our ACG Committee did not obtain a fairness opinion from an independent investment banking firm in approving the transaction), and the sale by us to an Enterprise Products Partners’ affiliate of the Pioneer plant in March 2006. As more fully described in the Proxy Statement, the ACG Committee recommended the Issuance Proposal for approval by the Board of Directors of the General Partner. The amended complaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting the three members of the ACG Committee at the time, cannot be considered independent because of their alleged ownership of securities in Enterprise Products Partners and its affiliates and/or their relationships with Mr. Duncan.

The amended complaint seeks relief (i) awarding damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; (ii) rescinding all actions taken pursuant to the Proxy vote and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts.

In addition to the proceedings 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 other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.

Regulatory Matters

Our pipelines and other facilities are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations. These include, without limitation: the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the Clean Water Act; the Oil Pollution Act; and analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation,

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remedial and clean-up costs. Likewise, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. Any or all of this could materially affect our results of operations and cash flows.

We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial position. We cannot ensure, however, that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. At March 31, 2008 and December 31, 2007, we had accrued liabilities of $7.8 million and $4.0 million, respectively, related to sites requiring environmental remediation activities.

In 1999, our Arcadia, Louisiana, facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of environmental contamination. Effective March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. At March 31, 2008, we have an accrued liability of $0.6 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.

We are in negotiations with the U.S. Department of Transportation with respect to a notice of probable violation that we received on April 25, 2005, for alleged violations of pipeline safety regulations at our Todhunter facility, with a proposed $0.4 million civil penalty. We responded on June 30, 2005, by admitting certain of the alleged violations, contesting others and requesting a reduction in the proposed civil penalty. We do not expect any settlement, fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.

The FERC, pursuant to the Interstate Commerce Act of 1887, as amended, the Energy Policy Act of 1992 and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier pipeline operations. To be lawful under that Act, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with the FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected with interest pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties can also challenge tariff rates that have become final and effective. Because of the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rates for transporting crude oil and refined products. Our interstate tariff rates are either market-based or derived in accordance with the FERC’s indexing methodology, which currently allows a pipeline to increase its rates by a percentage linked to the producer price index for finished goods. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC’s approved methodology for approving

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rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.

The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.

Although our natural gas gathering systems are generally exempt from FERC regulation under the Natural Gas Act of 1938, FERC regulation still significantly affects our natural gas gathering business. In recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue this approach, it could have an adverse effect on the rates we are able to charge in the future. In addition, our natural gas gathering operations could be adversely affected in the future should they become subject to the application of federal regulation of rates and services or if the states in which we operate adopt policies imposing more onerous regulation on gathering. Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

Contractual Obligations

Total rental expense included in operating costs and expenses was $5.2 million and $6.3 million for the three months ended March 31, 2008 and 2007, respectively. There have been no material changes in our operating lease commitments since December 31, 2007.

In March 2008, we issued $1.0 billion of senior notes due 2013, 2018 and 2038 (see Note 11). Other than the issuance of these senior notes, there have been no significant changes in our schedule of maturities of long-term debt or other contractual obligations since the year ended December 31, 2007.

The following table summarizes our maturities of long-term debt obligations at March 31, 2008:

	Payment or Settlement due by Period
	Total		2008		2009		2010		2011		2012		Thereafter

Maturities of long-term debt (1)	$	2,429,200	$	--	$	--	$	--	$	500,000	$	629,200	$	1,300,000
Interest payments (2)	$	2,772,485	$	152,900	$	152,900	$	152,900	$	152,900	$	110,896	$	2,049,989

__________________

(1)

We have long-term payment obligations under our Revolving Credit Facility, our Senior Notes and our Junior Subordinated Notes. Amounts shown in the table represent our scheduled future maturities of long-term debt principal for the periods indicated (see Note 11 for additional information regarding our consolidated debt obligations).

(2)

Includes interest payments due on our Senior Notes and junior subordinated notes and interest payments and commitment fees due on our Revolving Credit Facility. The interest amount calculated on the Revolving Credit Facility and the junior subordinated notes is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels.

Other

At March 31, 2008 and December 31, 2007, Centennial’s debt obligations consisted of $140.0 million borrowed under a master shelf loan agreement. In January 2008, we entered into an Amended Guaranty agreement with Centennial’s lenders, in which the TEPPCO Guarantors are required, on a joint and several basis, to pay 50% of any past-due amount under Centennial’s master shelf loan agreement not paid by Centennial. The Amended

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Guaranty also has a credit maintenance requirement whereby we may be required to provide additional credit support in the form of a letter of credit or pay certain fees if either of our credit ratings from Standard & Poor’s Ratings Group and Moody’s Investors Service, Inc. fall below investment grade levels as specified in the Amended Guaranty. If Centennial defaults on its debt obligations, the estimated maximum potential amount of future payments for the TEPPCO Guarantors and Marathon is $70.0 million each at March 31, 2008. At March 31, 2008, we have a liability of $9.4 million, which represents the present value of the estimated amount we would have to pay under the guaranty.

TE Products, Marathon and Centennial have also entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event. There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each. As a result of the catastrophic event guarantee, at March 31, 2008, TE Products has a liability of $4.1 million, which represents the present value of the estimated amount, based on a probability estimate, we would have to pay under the guarantee. If a catastrophic event were to occur and we were required to contribute cash to Centennial, such contributions might be covered by our insurance (net of deductible), depending upon the nature of the catastrophic event.

One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various equipment. Lease expense related to this equipment is approximately $5.2 million per year. We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements. Generally, events of default would trigger our performance under the guarantee. The maximum potential amount of future payments under the guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments. We carry insurance coverage that may offset any payments required under the guarantees. We do not believe that any performance under the guarantee would have a material effect on our financial condition, results of operations or cash flows.

In December 2006, we signed an agreement with Motiva Enterprises, LLC (“Motiva”) for us to construct and operate a new refined products storage facility to support the expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms of the agreement, we are constructing a 5.4 million barrel refined products storage facility for gasoline and distillates. The agreement also provides for a 15-year throughput and dedication of volume, which will commence upon completion of the refinery expansion. The project includes the construction of 20 storage tanks, five 5.4-mile product pipelines connecting the storage facility to Motiva’s refinery, 21,000 horsepower of pumping capacity, and distribution pipeline connections to the Colonial, Explorer and Magtex pipelines. The storage and pipeline project is expected to be completed by January 1, 2010. As a part of a separate but complementary initiative, we are constructing an 11-mile, 20-inch pipeline to connect the new storage facility in Port Arthur to our refined products terminal in Beaumont, Texas, which is the primary origination facility for our mainline system. These projects will facilitate connections to additional markets through the Colonial, Explorer and Magtex pipeline systems and provide the Motiva refinery with access to our pipeline system. The total cost of the project is expected to be approximately $310.0 million, which includes $20.0 million for the 11-mile, 20-inch pipeline, $30.0 million of capitalized interest and $17.0 million of scope changes requested by Motiva. Through March 31, 2008, we have spent approximately $70.0 million on this construction project. Under the terms of the agreement, if Motiva cancels the agreement prior to the commencement date of the project, Motiva will reimburse us the actual reasonable expenses we have incurred after the effective date of the agreement, including both internal and external costs that would be capitalized as a part of the project, plus a ten percent cancellation fee.

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NOTE 17. SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities, (ii) non-cash investing and financing activities and (iii) cash payments for interest for the three months ended March 31, 2008 and 2007:

	For the Three Months Ended March 31,
	2008			2007
Decrease (increase) in:
Accounts receivable, trade	$	(189,177	)	$	76,246
Accounts receivable, related parties		1,531			(10,774	)
Inventories		(7,227	)		8,359
Other current assets		(2,778	)		778
Other		(5,184	)		(4,181	)
Increase (decrease) in:
Accounts payable and accrued expenses		157,684			(111,763	)
Accounts payable, related parties		(6,879	)		4,789
Other		(11,096	)		(2,707	)

Net effect of changes in operating accounts	$	(63,126	)	$	(39,253	)

Non-cash investing activities:
Payable to Enterprise Gas Processing, LLC for spending for Phase V expansion of Jonah Gas Gathering Company (see Note 8)	$	7,437		$	14,935

Non-cash financing activities:
Issuance of Units in Cenac acquisition (see Note 9)	$	186,558		$	--

Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	47,388		$	42,947

NOTE 18. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

TE Products, TCTM, TEPPCO Midstream and Val Verde have issued full, unconditional, and joint and several guarantees of our Senior Notes, our Junior Subordinated Notes (collectively “the Guaranteed Debt”), our Revolving Credit Facility and prior to its termination, our Term Credit Facility. TE Products, TCTM, TEPPCO Midstream and Val Verde are collectively referred to as the “Guarantor Subsidiaries.”

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

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	March 31, 2008
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated

Assets
Current assets	$	7,347	$	120,097	$	1,833,034	$	(246,240	)	$	1,714,238
Property, plant and equipment – net		--		1,175,317		1,077,060		--			2,252,377
Equity investments		1,474,324		1,389,675		192,068		(1,891,730	)		1,164,337
Intercompany notes receivable		2,438,582		--		--		(2,438,582	)		--
Intangible assets		--		131,790		86,424		--			218,214
Other assets		16,278		34,867		203,541		--			254,686
Total assets	$	3,936,531	$	2,851,746	$	3,392,127	$	(4,576,552	)	$	5,603,852
Liabilities and partners’ capital
Current liabilities	$	58,510	$	263,517	$	1,629,319	$	(246,240	)	$	1,705,106
Long-term debt		2,445,495		--		--		--			2,445,495
Intercompany notes payable		--		1,338,395		1,100,187		(2,438,582	)		--
Other long-term liabilities		9,219		18,597		2,128		--			29,944
Total partners’ capital		1,423,307		1,231,237		660,493		(1,891,730	)		1,423,307
Total liabilities and partners’ capital	$	3,936,531	$	2,851,746	$	3,392,127	$	(4,576,552	)	$	5,603,852

	December 31, 2007
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated

Assets
Current assets	$	32,302	$	77,083	$	1,499,653	$	(93,049	)	$	1,515,989
Property, plant and equipment – net		--		1,142,630		651,004		--			1,793,634
Equity investments		1,286,021		1,347,313		188,669		(1,675,008	)		1,146,995
Intercompany notes receivable		1,511,168		--		--		(1,511,168	)		--
Intangible assets		--		136,050		28,631		--			164,681
Other assets		8,580		34,839		85,401		(62	)		128,758
Total assets	$	2,838,071	$	2,737,915	$	2,453,358	$	(3,279,287	)	$	4,750,057
Liabilities and partners’ capital
Current liabilities	$	61,926	$	493,184	$	1,485,164	$	(93,049	)	$	1,947,225
Long-term debt		1,511,083		--		--		--			1,511,083
Intercompany notes payable		--		1,006,801		504,367		(1,511,168	)		--
Other long term liabilities		435		24,466		2,283		(62	)		27,122
Total partners’ capital		1,264,627		1,213,464		461,544		(1,675,008	)		1,264,627
Total liabilities and partners’ capital	$	2,838,071	$	2,737,915	$	2,453,358	$	(3,279,287	)	$	4,750,057

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	For the Three Months Ended March 31, 2008
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated

Operating revenues	$	--	$	102,934		$	2,705,618		$	(64	)	$	2,808,488
Costs and expenses		--		67,931			2,660,003			(2,965	)		2,724,969
Operating income		--		35,003			45,615			2,901			83,519
Interest expense – net		--		(26,752	)		(11,819	)		--			(38,571	)
Equity earnings		64,139		52,958			3,000			(100,435	)		19,662
Other income – net		--		250			98			--			348
Income before provision for income taxes		64,139		61,459			36,894			(97,534	)		64,958
Provision for income taxes		--		178			641			--			819
Net income	$	64,139	$	61,281		$	36,253		$	(97,534	)	$	64,139

	For the Three Months Ended March 31, 2007
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated

Operating revenues	$	--	$	98,918		$	1,879,790		$	(279	)	$	1,978,429
Costs and expenses		--		66,167			1,850,124			(2,647	)		1,913,644
Gains on sales of assets		--		(18,651	)		2			--			(18,649	)
Operating income		--		51,402			29,664			2,368			83,434
Interest expense – net		--		(15,962	)		(6,249	)		--			(22,211	)
Gain on sale of ownership interest in MB Storage		--		59,837			--			--			59,837
Equity earnings		138,191		41,935			1,789			(165,352	)		16,563
Other income – net		--		489			97			--			586
Income before provision for income taxes		138,191		137,701			25,301			(162,984	)		138,209
Provision for income taxes		--		(490	)		508			--			18
Net income	$	138,191	$	138,191		$	24,793		$	(162,984	)	$	138,191

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	For the Three Months Ended March 31, 2008
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated

Operating activities:
Net income	$	64,139		$	61,281		$	36,253		$	(97,534	)	$	64,139
Adjustments to reconcile net income to net cash from operating activities:
Deferred income taxes		--			31			(36	)		--			(5	)
Depreciation and amortization		--			16,900			11,444			--			28,344
Earnings in equity investments, net of distributions		10,734			11,230			(3,000	)		(1,392	)		17,572
Changes in assets and liabilities and other		(504,850	)		89,288			(188,657	)		552,850			(51,369	)
Net cash from operating activities		(429,977	)		178,730			(143,996	)		453,924			58,681

Cash flows from investing activities		--			(74,462	)		(361,979	)		--			(436,441	)
Cash flows from financing activities		427,210			(104,268	)		505,985			(451,158	)		377,769
Net change in cash and cash equivalents		(2,767	)		--			10			2,766			9
Cash and cash equivalents, January 1		8,147			70			22			(8,216	)		23
Cash and cash equivalents, March 31	$	5,380		$	70		$	32		$	(5,450	)	$	32

	For the Three Months Ended March 31, 2007
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated

Operating activities:
Net income	$	138,191		$	138,191		$	24,793		$	(162,984	)	$	138,191
Adjustments to reconcile net income to net cash from operating activities:		--
Deferred income taxes		--			(638	)		(4	)		--			(642	)
Depreciation and amortization		--			18,380			6,989			--			25,369
Earnings in equity investments, net of distributions		(65,802	)		20,564			2,011			66,968			23,741
Gains on sales of assets and ownership interest		--			(78,488	)		2			--			(78,486	)
Changes in assets and liabilities and other		85,031			38,365			(87,101	)		(75,737	)		(39,442	)
Net cash from operating activities		157,420			136,374			(53,310	)		(171,753	)		68,731

Cash flows from investing activities		--			55,360			68,119			(29,320	)		94,159
Cash flows from financing activities		(162,889	)		(191,510	)		(14,808	)		206,318			(162,889	)
Net change in cash and cash equivalents		(5,469	)		224			1			5,245			1
Cash and cash equivalents, January 1		10,975			--			70			(10,975	)		70
Cash and cash equivalents, March 31	$	5,506		$	224		$	71		$	(5,730	)	$	71

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TEPPCO PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 19. SUBSEQUENT EVENTS

Marine Asset Acquisitions

On April 18, 2008, we paid $3.0 million of the $6.8 million consideration held back at closing to Horizon Maritime, L.L.C., in connection with the completion of construction and delivery of one of the two tow boats that had been under construction at the time of closing of the acquisition.

Additionally, on April 7, 2008, we further expanded our Marine Services Segment by purchasing four new 30,000 barrel inland tank barges from Cenac Towing Co., Inc. for approximately $11.4 million. These tank barges will be used in conjunction with incremental revenue producing services and to maintain fleet utilization.

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

For the three months ended March 31, 2008 and 2007

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this report. The following information and such unaudited condensed 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, 2007. Our discussion and analysis includes the following:

Key References Used in this Quarterly Report.
Cautionary Note Regarding Forward-Looking Statements.
Overview of Critical Accounting Policies and Estimates.
Overview of Business.
Recent Developments – Discusses recent developments during the quarter ended March 31, 2008.
Results of Operations – Discusses material period-to-period variances in the statements of consolidated income.
Financial Condition and Liquidity – Analyzes cash flows and financial position.
Other Considerations – Addresses available sources of liquidity, trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.
Recent Accounting Pronouncements.

As generally used in the energy industry and in this discussion, the identified terms have the following meanings:

/d	= per day
BBtus	= billion British Thermal units
Bcf	= billion cubic feet
MMBtus	= million British Thermal units
MMcf	= million cubic feet
Mcf	= thousand cubic feet
MMBbls	= million barrels

Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”).

Key References Used in this Quarterly Report

Unless the context requires otherwise, references to “we,” “us,” “our” or “TEPPCO” are intended to mean the business and operations of TEPPCO Partners, L.P. and its consolidated subsidiaries.

References to “TE Products,” “TCTM,” “TEPPCO Midstream” and “TEPPCO Marine Services” mean TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and TEPPCO Marine Services, LLC, our subsidiaries.

References to “General Partner” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and owned by Enterprise GP Holdings L.P., a publicly traded partnership, controlled indirectly by EPCO, Inc.

References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded partnership that owns our General Partner and Enterprise Products GP, LLC, the general partner of Enterprise Products Partners L.P.

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References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., and its consolidated subsidiaries, a publicly traded Delaware limited partnership, which is an affiliate of ours.

References to “EPCO” mean EPCO, Inc., a privately-held company that is affiliated with our General Partner. Dan L. Duncan is the Chairman and controlling shareholder of EPCO.

Cautionary Note Regarding Forward-Looking Statements

The matters discussed in this Quarterly Report on Form 10-Q (this “Report”) include “forward-looking statements.” All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical facts are forward-looking statements. The words “proposed”, “anticipate”, “potential”, “may”, “will”, “could”, “should”, “expect”, “estimate”, “believe”, “intend”, “plan”, “seek” and similar expressions are intended to identify forward-looking statements. Without limiting the broader description of forward-looking statements above, we specifically note that statements 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 future distributions, 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. While we believe our expectations reflected in these forward-looking statements are reasonable, 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 or energy transportation companies, changes in laws or regulations and other factors, many of which are beyond our control. For example, the demand for refined products is dependent upon the price, prevailing economic conditions and demographic changes in the markets served, trucking and railroad freight, agricultural usage and military usage; the demand for propane is sensitive to the weather and prevailing economic conditions; the demand for petrochemicals is dependent upon prices for products produced from petrochemicals; the demand for crude oil and petroleum products is dependent upon the price of crude oil and the products produced from the refining of crude oil; and the demand for natural gas is dependent upon the price of natural gas and the locations in which natural gas is drilled. Further, the success of our new marine services business is dependent upon, among other things, our ability to effectively assimilate and provide for the operation of that business and maintain key personnel and customer relationships. We are also subject to regulatory factors such as the amounts we are allowed to charge our customers for the services we provide on our regulated pipeline systems and the cost and ability of complying with government regulations of the marine transportation industry. 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. Also note that we provide additional cautionary discussion of risks and uncertainties under the captions “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Report and in our Annual Report on Form 10-K for the year ended December 31, 2007.

The forward-looking statements contained in this Report speak only as of the date hereof. Except as required by the federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Report and in our future periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.

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Overview of Critical Accounting Policies and Estimates

A summary of the significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included in our Annual Report on Form 10-K for the year ended December 31, 2007. Certain of these accounting policies require the use of estimates. As more fully described therein, the following estimates, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: revenue and expense accruals, including accruals for power costs, property taxes and crude oil margins; reserves for environmental matters; depreciation methods and estimated useful lives of property, plant and equipment; and goodwill and intangible assets. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial position, results of operations and cash flows.

Overview of Business

Certain factors are key to our operations. These include the safe, reliable and efficient operation of the pipelines and facilities that we own or operate while meeting the regulations that govern the operation of our assets and the costs associated with such regulations. We operate and report in four business segments:

Our Downstream Segment, which is engaged in the pipeline transportation, marketing and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals;
Our Upstream Segment, which is engaged in the gathering, pipeline transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals;
Our Midstream Segment, which is engaged in the gathering of natural gas, pipeline transportation of natural gas liquids (“NGLs”) and fractionation of NGLs; and
Our Marine Services Segment, which is engaged in the marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via tow boats and tank barges.

Please refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview of Business in our Annual Report on Form 10-K for the year ended December 31, 2007 for an overview of how revenues are earned in each segment and other factors affecting the results and financial position of our businesses.

Consistent with our business strategy, we are focused on our continued growth through expansion of the assets that we own and through the construction and acquisition of assets. We continuously evaluate possible acquisitions of assets that would complement our current operations, including assets which, if acquired, would have a material effect on our financial position, results of operations or cash flows.

Recent Developments

Acquisitions

On February 1, 2008, we, through our subsidiary, TEPPCO Marine Services, entered the marine transportation business for refined products, crude oil and condensate. We acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements that comprised the marine transportation business of Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”). The aggregate value of total consideration we paid or issued to complete the Cenac acquisition was $444.3 million, which consisted of $256.6 million in cash and 4,854,899 newly issued limited partner units (“Units”). Additionally, we assumed $63.2 million of Cenac’s long-term debt in this transaction. We financed the cash portion of the total consideration with borrowings under our term credit agreement (see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements). This business serves refineries and storage terminals along the Mississippi, Illinois and Ohio rivers, as well as the Intracoastal Waterway between Texas and Florida. These assets also gather crude oil from production facilities and platforms

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along the U.S. Gulf Coast and in the Gulf of Mexico. We entered into a transitional operating agreement with the sellers under which they will continue to operate the acquired assets and the assets we acquired from Horizon Maritime L.L.C., described below, for up to two years following the acquisition.

On February 29, 2008, we expanded our Marine Services Segment with the acquisition of marine assets from Horizon Maritime, L.L.C., a privately-held Houston-based company and an affiliate of Mr. Cenac (“Horizon”) for $80.8 million in cash. We acquired 7 tow boats, 17 tank barges, rights to two tow boats under construction and certain related commercial and other agreements (or the associated economic benefits). In April 2008, we paid $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and we expect to pay $3.8 million upon delivery of the second tow boat. The acquired vessels transport asphalt, heavy fuel oil and other heated oil products to storage facilities and refineries along the Mississippi, Illinois and Ohio Rivers, as well as the Intracoastal Waterway. We financed the acquisition with borrowings under our term credit agreement.

The Cenac and Horizon acquisitions are a natural extension of our existing assets and complement two of our core franchise businesses: the transportation and storage of refined products and the gathering, transportation and storage of crude oil.

Most of the commercial and other agreements acquired as part of the Cenac and Horizon acquisitions require consents of third parties to assign the agreements from Cenac and Horizon to TEPPCO Marine Services, which TEPPCO Marine Services, Cenac and Horizon began seeking promptly after the closing of the acquisitions. Under the purchase agreements with Cenac and Horizon, TEPPCO Marine Services is entitled to the economic benefit of these unassigned agreements, and Cenac and Horizon continue to be obligated to use reasonable efforts to obtain those consents.

Debt Retirements and Issuances

In January 2008, TE Products retired all of its outstanding long-term debt by repaying at maturity $180.0 million principal amount of its 6.45% TE Products Senior Notes due 2008 and redeeming the remaining $175.0 million principal amount of its 7.51% TE Products Senior Notes due 2028. The redemption price for the 7.51% TE Products Senior Notes due 2028 was 103.755% (or $181.6 million, which included a $6.6 million make-whole premium) of the principal amount plus accrued and unpaid interest to January 28, 2008, the date of redemption, of $0.5 million. We funded the retirement of the TE Products debt with borrowings under our term credit agreement.

Jonah Expansion

Jonah Gas Gathering Company ("Jonah") is nearing completion of its Phase V expansion which is expected to increase the combined system capacity of the Jonah and Pindale fields from 1.5 Bcf per day to approximately 2.35 Bcf per day and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The expansion is expected to be completed in the second quarter of 2008.

In 2008, Jonah began an expansion of the portion of its system serving the Pinedale field, which is expected to increase the combined system capacity of the Jonah and Pinedale fields from 2.35 Bcf per day (the expected capacity upon completion of the Phase V expansion) to approximately 2.55 Bcf per day. This project will include an additional 17,000 horsepower of compression at the Paradise and Bird Canyon stations in Sublette County, Wyoming and involve construction of approximately 52 miles of 24-inch and 30-inch diameter pipelines. This expansion is expected to be completed in phases, with final completion in early 2009. The total anticipated cost of this system expansion is expected to be approximately $125.0 million. Our share of the costs of the construction is expected to be 80.64%, and Enterprise Products Partners’ share is expected to be 19.36%.

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Results of Operations

The following table summarizes financial information by business segment for the three months ended March 31, 2008 and 2007 (in thousands):

	For the Three Months Ended March 31,
	2008			2007
Operating revenues:
Downstream Segment	$	97,632		$	94,918
Upstream Segment		2,655,303			1,854,417
Midstream Segment		30,081			29,373
Marine Services Segment		25,536			--
Intersegment eliminations		(64	)		(279	)
Total operating revenues		2,808,488			1,978,429

Operating income:
Downstream Segment		36,329			53,941
Upstream Segment		29,335			22,315
Midstream Segment		8,386			4,810
Marine Services Segment		6,568			--
Intersegment eliminations		2,901			2,368
Total operating income		83,519			83,434

Equity earnings (losses):
Downstream Segment		(4,132	)		(1,487	)
Upstream Segment		3,000			1,789
Midstream Segment		23,695			18,629
Intersegment eliminations		(2,901	)		(2,368	)
Total equity earnings		19,662			16,563

Earnings before interest:(1)
Downstream Segment		32,415			112,722
Upstream Segment		32,341			24,147
Midstream Segment		32,201			23,551
Marine Services Segment		6,572			--

Interest expense		(42,979	)		(25,939	)
Interest capitalized		4,408			3,728
Income before provision for income taxes		64,958			138,209
Provision for income taxes		819			18
Net income	$	64,139		$	138,191

___________________________

(1)	See Note 13 in the Notes to Unaudited Condensed Consolidated Financial Statements for a reconciliation of earnings before interest to net income.

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

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Downstream Segment

The following table provides financial information for the Downstream Segment for the three months ended March 31, 2008 and 2007 (in thousands):

	For the Three Months Ended
	March 31,						Increase
	2008			2007			(Decrease)
Operating revenues:
Sales of petroleum products	$	6,989		$	9,376		$	(2,387	)
Transportation – Refined products		37,283			37,135			148
Transportation – LPGs		36,191			36,053			138
Other		17,169			12,354			4,815
Total operating revenues		97,632			94,918			2,714

Costs and expenses:
Purchases of petroleum products		6,910			9,394			(2,484	)
Operating expense		26,870			21,520			5,350
Operating fuel and power		10,526			10,413			113
General and administrative		3,533			4,075			(542	)
Depreciation and amortization		10,236			11,136			(900	)
Taxes – other than income taxes		3,228			3,090			138
Gains on sales of assets		--			(18,651	)		18,651
Total costs and expenses		61,303			40,977			20,326

Operating income		36,329			53,941			(17,612	)

Gain on sale of ownership interest in Mont Belvieu Storage
Partners, L.P. (“MB Storage”)		--			59,837			(59,837	)
Equity losses		(4,132	)		(1,487	)		(2,645	)
Interest income		168			202			(34	)
Other income – net		50			229			(179	)

Earnings before interest	$	32,415		$	112,722		$	(80,307	)

The following table presents volumes delivered in barrels and average tariff per barrel for the three months ended March 31, 2008 and 2007 (in thousands, except tariff information):

	For the Three Months Ended				Percentage
	March 31,				Increase
	2008		2007		(Decrease)
Volumes Delivered:
Refined products (1)		38,520		35,754		8	%
LPGs		12,886		15,523		(17	%)
Total		51,406		51,277		--

Average Tariff per Barrel:
Refined products	$	0.97	$	1.04		(7	%)
LPGs		2.81		2.29		23	%
Average system tariff per barrel		1.43		1.26		13	%

_________________________________

(1)	Includes 6,111 and 5,281 barrels delivered via the Centennial Pipeline during the three months ended March 31, 2008 and 2007, respectively.

We generally realize higher revenues in the Downstream Segment during the first and fourth quarters of each year since LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating, and due to the demand for normal butane, which is used for the

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blending of gasoline. 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. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene from Mont Belvieu to Point Comfort, Texas.

Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007

At our Aberdeen, Mississippi, terminal, we conduct distribution and marketing operations and terminaling services for our throughput and exchange partners. We also purchase petroleum products from our throughput partners that we in turn sell through spot sales at the Aberdeen truck rack to independent wholesalers and retailers of refined products. Sales and purchase related to these petroleum products marketing activities decreased $2.4 million and $2.5 million, respectively, for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. The decreases in purchases and sales were primarily a result of unplanned maintenance on storage tanks during the first quarter of 2008. This maintenance is expected to continue into the second quarter of 2008.

Revenues from refined products transportation increased $0.1 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to an 8% increase in the refined products volumes delivered, partially offset by a 7% decrease in the average tariff per barrel. Volume increases were primarily due to increases in motor fuel deliveries as compared to the prior year period due to higher demand in the Midwest markets in the 2008 period resulting from Midwest refineries undergoing maintenance, increased jet fuel demand into the Chicago market and higher short-haul deliveries in the Houston, Texas area. These short-haul deliveries commenced operations in the first quarter of 2007 following the integration of assets acquired from Texas Genco LLC in 2005. The refined products average tariff per barrel decreased primarily due to the impact of Centennial on the average rates and increased short haul movements, partially offset by increases in system tariffs, which went into effect in February 2007 and July 2007. Movements during the three months ended March 31, 2008 on Centennial were a larger percentage of the total refined products deliveries when compared to the prior year period. When the proportion of refined products deliveries from a Centennial origin increases, the average TEPPCO tariff declines (even if the actual volume transported on Centennial increases). Conversely, if the proportion of the refined products deliveries from a Centennial origin decrease, TEPPCO’s average tariff increases (even if the actual volume transported on Centennial decreases).

Revenues from LPGs transportation increased $0.1 million for the three months ended March 31, 2008, compared to the three months ended March 31, 2007, primarily due to increases in system tariffs, which went into effect in July 2007, partially offset by a 17% decrease in transportation volumes delivered. Propane transportation volumes were lower in the 2008 period compared to the prior year period due to warmer weather in the 2008 period. Additionally, LPG transportation volumes in the 2007 period include approximately 2.2 million barrels related to short-haul propane movements on a pipeline that was sold on March 1, 2007 to Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”). The LPGs average rate per barrel increased 23% from the prior year period primarily as a result of decreased short-haul deliveries due to the pipeline sale.

Other operating revenues increased $4.8 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to a $2.6 million increase in refined products excess inventory fees, a $1.1 million increase in refined products terminaling revenue and a $0.8 million reduction in upsystem product exchange costs.

Costs and expenses increased $20.3 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. Purchases of petroleum products, discussed above, decreased $2.5 million, compared with the period year period. Operating expenses increased $5.4 million primarily due to a $4.8 million increase in pipeline operating and maintenance costs related to periodic tank maintenance requirements in the 2008 period, a $0.7 million increase in environmental assessments and remediation costs, a $0.7 million increase in product measurement losses and a $0.6 million increase in transportation expense related to movements on Centennial. These increases in operating expenses were partially offset by a $0.5 million decrease in pipeline inspection and repair costs associated with our integrity management program, a $0.5 million decrease in labor and benefits expense associated with our incentive

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compensation plans and a $0.6 million decrease in insurance premiums. Operating fuel and power increased $0.1 million primarily due to increased mainline throughput and higher power rates as a result of the increased cost of fuel. General and administrative expenses decreased $0.6 million primarily due to a decrease in consulting and contract services. Depreciation and amortization expense decreased $0.9 million primarily due to asset retirements in 2007, partially offset by assets placed into service in the 2008 period. Taxes – other than income taxes increased $0.1 million primarily due to true-ups of property tax accruals. During the three months ended March 31, 2007, we recognized a net gain of $18.7 million from the sales of various assets in the Downstream Segment to Enterprise Products Partners and Louis Dreyfus (see Note 9 in the Notes to Unaudited Condensed Consolidated Financial Statements).

Net losses from equity investments increased for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, as shown below (in thousands):

	For the Three Months
	Ended March 31,						Increase
	2008			2007			(Decrease)

Centennial	$	(4,143	)	$	(3,987	)	$	(156	)
MB Storage		--			2,491			(2,491	)
Other		11			9			2
Total equity losses	$	(4,132	)	$	(1,487	)	$	(2,645	)

Equity losses in Centennial increased $0.2 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to higher amortization expense related to our excess investment in Centennial as a result of higher volumes, partially offset by higher transportation revenues. Equity earnings in MB Storage decreased $2.5 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, due to the sale of MB Storage on March 1, 2007 to Louis Dreyfus (see Note 9 in the Notes to Unaudited Condensed Consolidated Financial Statements).

On March 1, 2007, TE Products sold its 49.5% ownership interest in MB Storage and its 50% ownership interest in Mont Belvieu Venture, LLC (the general partner of MB Storage) to Louis Dreyfus for approximately $138.7 million in cash (see Note 9 in the Notes to Unaudited Condensed Consolidated Financial Statements). We recognized a gain of approximately $59.8 million related to the sale of our equity interests, which is included in gain on sale of ownership interest in MB Storage in our statements of consolidated income.

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Upstream Segment

The following table provides financial information for the Upstream Segment for the three months ended March 31, 2008 and 2007 (in thousands):

	For the Three Months Ended
	March 31,					Increase
	2008			2007		(Decrease)
Operating revenues: (1)
Sales of petroleum products (2)	$	2,637,652		$	1,841,031	$	796,621
Transportation – Crude oil		15,300			10,790		4,510
Other		2,351			2,596		(245	)
Total operating revenues		2,655,303			1,854,417		800,886

Costs and expenses: (1)
Purchases of petroleum products (2)		2,602,662			1,807,166		795,496
Operating expense		13,348			15,473		(2,125	)
Operating fuel and power		1,648			2,058		(410	)
General and administrative		1,840			1,828		12
Depreciation and amortization		4,777			4,068		709
Taxes – other than income taxes.		1,693			1,507		186
Gains on sales of assets.		--			2		(2	)
Total costs and expenses		2,625,968			1,832,102		793,866

Operating income		29,335			22,315		7,020

Equity earnings		3,000			1,789		1,211
Interest income		16			29		(13	)
Other income (expense) – net		(10	)		14		(24	)

Earnings before interest	$	32,341		$	24,147	$	8,194

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(1)	Amounts in this table are presented after elimination of intercompany transactions, including sales and purchases of petroleum products.

(2)	Petroleum products include crude oil, lubrication oils and specialty chemicals.

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 SEC. 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, in each case, prior to the elimination of intercompany sales, revenues and purchases between wholly-owned subsidiaries. We believe that margin is a more meaningful measure of financial performance than sales and purchases of crude oil and lubrication oil due to the significant fluctuations in sales and purchases caused by variations in the level of volumes marketed and prices for products marketed. Additionally, we use margin internally to evaluate the financial performance of the Upstream Segment because it excludes expenses that are not directly related to the marketing and sales activities being evaluated. Margin and volume information for the three months ended March 31, 2008 and 2007 is presented below (in thousands, except per barrel and per gallon amounts):

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	For the Three Months Ended				Percentage
	March 31,				Increase
	2008		2007		(Decrease)
Margins: (1)
Crude oil marketing	$	20,314	$	21,531		(6	%)
Lubrication oil sales		2,732		2,154		27	%
Revenues: (1)
Crude oil transportation		23,411		17,220		36	%
Crude oil terminaling		3,833		3,750		2	%
Total margins/revenues	$	50,290	$	44,655		13	%

Total barrels/gallons:
Crude oil marketing (barrels) (1)		57,558		55,946		3	%
Lubrication oil volume (gallons)		3,931		3,831		3	%

Crude oil transportation (barrels)		27,806		24,133		15	%
Crude oil terminaling (barrels)		33,136		40,143		(17	%)

Margin per barrel or gallon:
Crude oil marketing (per barrel) (1)	$	0.353	$	0.385		(8	%)
Lubrication oil margin (per gallon)		0.695		0.562		24	%

Average tariff per barrel:
Crude oil transportation	$	0.842	$	0.714		18	%
Crude oil terminaling		0.116		0.093		24	%

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(1)

Amounts in this table are presented prior to the eliminations of intercompany sales, revenues and purchases between TEPPCO Crude Oil, LLC (“TCO”) and TEPPCO Crude Pipeline, LLC (“TCPL”), both of which are our wholly-owned subsidiaries. TCO is a significant shipper on TCPL. Crude oil marketing volumes also include inter-region transfers, which are transfers among TCO’s various geographically managed regions.

The following table reconciles the Upstream Segment margin to operating income using the information presented in the statements of consolidated income and the Upstream Segment financial information on the preceding page (in thousands):

	For the Three Months Ended
	March 31,
	2008			2007
Sales of petroleum products	$	2,637,652		$	1,841,031
Transportation – Crude oil		15,300			10,790
Less: Purchases of petroleum products		(2,602,662	)		(1,807,166	)
Total margins/revenues		50,290			44,655
Other operating revenues		2,351			2,596
Net operating revenues		52,641			47,251
Operating expense		13,348			15,473
Operating fuel and power		1,648			2,058
General and administrative expense		1,840			1,828
Depreciation and amortization		4,777			4,068
Taxes – other than income taxes		1,693			1,507
Gains on sales of assets		--			2
Operating income	$	29,335		$	22,315

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Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007

Sales of petroleum products and purchases of petroleum products increased $796.6 million and $795.5 million, respectively, for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. Operating income increased $7.0 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. The increases in sales and purchases were primarily a result of increased volumes marketed and increases in the price of crude oil. The average New York Mercantile Exchange (“NYMEX”) price of crude oil was $97.82 per barrel for the three months ended March 31, 2008, compared with $58.27 per barrel for the three months ended March 31, 2007. Increased volumes transported and marketed, partially offset by increased costs and expenses discussed below, were the primary factors resulting in an increase in operating income.

Crude oil transportation revenues (prior to intercompany eliminations) increased $6.2 million primarily due to higher transportation volumes on most of our crude oil gathering systems and increases in the tariff rates in the second and third quarters of 2007. Increased transportation revenues on our Red River, South Texas and Basin systems resulted from movements on higher tariff segments. Additionally, the completion of organic growth projects on our West Texas and South Texas systems increased transportation revenues and volumes on those systems. Lubrication oil sales margin increased $0.5 million primarily due to increased volumes of higher margin specialty chemicals. Crude oil terminaling revenues increased $0.1 million as a result of increased pumpover volumes at Midland, Texas, partially offset by decreased pumpover volumes at Cushing, Oklahoma, due to crude oil market conditions. Crude oil marketing margin decreased $1.2 million, primarily due to increased transportation costs, partially offset by increased volumes marketed.

Costs and expenses increased $793.9 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. Purchases of petroleum products, discussed above, increased $795.5 million compared with the prior year period. Operating expenses decreased $2.1 million from the prior year period, primarily due to a $1.7 million decrease in product measurement losses, a $1.4 million decrease in labor and benefits expense associated with our incentive compensation plans and a $0.6 million decrease in insurance premiums, partially offset by a $1.5 million increase in pipeline operating and maintenance expenses. Operating fuel and power decreased $0.4 million primarily as a result of true-ups of the power accrual, partially offset by higher transportation volumes. General and administrative expenses remained relatively unchanged between periods. Depreciation and amortization expense increased $0.7 million primarily due to assets placed into service in 2007. Taxes – other than income taxes increased $0.2 million due to increases in property tax accruals and a higher property asset base in 2008.

Equity earnings from our investment in Seaway increased $1.2 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. Our sharing ratio of the revenue and expense of Seaway for 2008 and 2007 is 40% (see Note 8 in the Notes to Unaudited Condensed Consolidated Financial Statements). Equity earnings from our investment in Seaway increased primarily due to increased transportation revenues from volumes transported on a spot basis, which are transported at higher tariff rates compared with higher volumes moved in the 2007 period at the lowest tier of an incentive tariff, partially offset by overall decreased transportation volumes resulting from the impact of higher Canadian crude volumes coming into the Cushing market. Lower product measurement losses were offset by increased pipeline operating and maintenance expenses. Long-haul volumes on Seaway averaged 166,000 barrels per day during the three months ended March 31, 2008, compared with 193,000 barrels per day during the three months ended March 31, 2007. For further information on distributions from Seaway, see Note 8 in the Notes to Unaudited Condensed Consolidated Financial Statements.

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Midstream Segment

The following table provides financial information for the Midstream Segment for the three months ended March 31, 2008 and 2007 (in thousands):

	For the Three Months Ended
	March 31,				Increase
	2008		2007		(Decrease)
Operating revenues:
Gathering – Natural gas – Val Verde	$	13,413	$	15,408	$	(1,995	)
Transportation – NGLs (1)		12,957		10,941		2,016
Other		3,711		3,024		687
Total operating revenues		30,081		29,373		708

Costs and expenses:
Operating expense		4,980		8,254		(3,274	)
Operating fuel and power		3,711		2,803		908
General and administrative expense		2,639		2,695		(56	)
Depreciation and amortization		9,597		10,165		(568	)
Taxes – other than income taxes		768		646		122
Total costs and expenses		21,695		24,563		(2,868	)

Operating income		8,386		4,810		3,576

Equity earnings – Jonah		23,695		18,629		5,066
Interest income		120		111		9
Other income – net		--		1		(1	)

Earnings before interest	$	32,201	$	23,551	$	8,650

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(1)	Includes transportation revenue from Enterprise Products Partners of $3.4 million and $2.8 million for the three months ended March 31, 2008 and 2007, respectively.

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The following table presents volume and average rate information for the three months ended March 31, 2008 and 2007 (in thousands, except average fee and average rate amounts and as otherwise indicated):

	For the Three Months Ended				Percentage
	March 31,				Increase
	2008		2007		(Decrease)
Gathering – Natural Gas – Jonah: (1)
MMcf		167,094		131,543		27	%
BBtu		184,628		145,159		27	%
Average fee per MMcf	$	0.258	$	0.226		14	%
Average fee per MMBtu	$	0.234	$	0.205		14	%

Gathering – Natural Gas – Val Verde: (1)
MMcf		38,240		43,567		(12	%)
BBtu		34,178		38,582		(11	%)
Average fee per MMcf	$	0.351	$	0.354		(1	%)
Average fee per MMBtu	$	0.392	$	0.399		(2	%)

Transportation and movements – NGLs:
Transportation barrels		16,549		15,503		7	%
Lease barrels (2)		3,041		2,061		48	%
Average rate per barrel	$	0.736	$	0.689		7	%

Natural Gas Sales – Jonah:
BBtu		1,679		3,546		(53	%)
Average fee per MMBtu	$	6.806	$	7.059		(4	%)

Fractionation – NGLs:
Barrels		1,095		978		12	%
Average rate per barrel	$	1.661	$	1.721		(4	%)

Sales – Condensate – Jonah: (3)
Barrels		47.9		48.6		(1	%)
Average rate per barrel	$	76.72	$	52.85		45	%

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(1)	The majority of volumes in Val Verde’s contracts are measured in MMcf, while the majority of volumes in Jonah’s contracts are measured in MMBtu. Both measures are shown for each asset for comparability purposes.

(2)	Revenues associated with capacity leases are classified as other operating revenues in our statements of consolidated income.

(3)	All of Jonah’s condensate volumes are sold to TCO.

Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007

Natural gas gathering revenues from the Val Verde system decreased $2.0 million, and volumes gathered decreased 5.3 Bcf for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to lower production as a result of winter weather during the first quarter of 2008 and the natural decline of coal bed methane production in the fields in which the Val Verde gathering system operates. For the three months ended March 31, 2008, Val Verde’s gathering volumes averaged 420 MMcf per day, compared with 484 MMcf per day for the three months ended March 31, 2007. Val Verde’s average natural gas gathering fee per MMBtu decreased 2% primarily due to higher volumes from a third party natural gas connection that utilizes fewer services provided by Val Verde and therefore is charged a lower rate.

Revenues from the transportation of NGLs increased $2.0 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to increases in volumes transported on the Chaparral and Dean Pipelines and an increase in the average rates on the Chaparral, Dean and Panola Pipelines.

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Other operating revenues increased $0.7 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to a $0.3 million increase on the Panola Pipeline as a result of increased revenues and volumes from a pipeline capacity lease, and a $0.3 million increase on the Val Verde system as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage. Val Verde retains a portion of its producers’ gas to compensate for fuel used in operations. Under certain contracts, efficient fuel usage benefits us and is recognized as other operating revenues. In addition, revenues from the fractionation of NGLs increased $0.1 million as a result of a 12% increase in the volumes fractionated, partially offset by a 4% decrease in the average rate per barrel fractionated, primarily due to the rate structure in the agreement, under which higher volumes of NGLs are fractionated at lower rates.

Costs and expenses decreased $2.9 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. Operating expenses decreased $3.3 million from the prior year period, primarily due to a $2.9 million decrease as a result of lower product measurement losses, a $1.2 million decrease in insurance premiums and a $0.7 million decrease in labor and benefits expense associated with our incentive compensation plans, partially offset by a $1.1 million increase in pipeline operating and maintenance expenses and a $0.4 million increase in pipeline inspection and repair costs associated with our integrity management program. Operating fuel and power increased $0.9 million primarily due to higher fuel costs on the Chaparral and Panola Pipelines and increased transportation volumes on the Chaparral Pipeline. General and administrative expenses decreased $0.1 million due to lower professional services costs, partially offset by higher labor and benefits expense. Depreciation and amortization expense decreased $0.6 million primarily due to a decrease in amortization expense on Val Verde as a result of a decrease in volumes on contracts which are included in intangible assets and amortized under the units-of production method. Taxes – other than income taxes increased $0.1 million primarily due to true-ups of property tax accruals.

Equity earnings from our investment in Jonah increased $5.1 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007. These earnings increased primarily due to a $13.4 million increase in natural gas gathering revenues and an increase in volumes from the completion of a portion of the Phase V expansion project in July 2007, partially offset by a $2.5 million increase in operating expenses and a $2.7 million increase in depreciation and amortization expense primarily relating to the Phase V expansion. The decreases in Jonah’s natural gas sales volumes and average fee per MMBtu for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, were primarily a result of certain shippers selling gas themselves, rather than through Jonah. The increase in the average condensate rate per barrel for the three months ended March 31, 2008 was primarily a result of higher market prices compared with the three months ended March 31, 2007.

For the three months ended March 31, 2008, compared with the three months ended March 31, 2007, Jonah’s gathering volumes averaged approximately 1.8 Bcf per day and 1.5 Bcf per day, respectively, and total gathering volumes gathered increased 35.6 Bcf. For the three months ended March 31, 2008, our sharing in the earnings of Jonah was 80.64%, compared with 95.2% in the prior year period, as a result of certain milestones provided for in the joint venture agreement being reached in the construction of the Phase V expansion (see Note 8 in the Notes to Unaudited Condensed Consolidated Financial Statements).

Marine Services Segment

We conduct business in our Marine Services Segment through TEPPCO Marine Services. Demand for our marine transportation services is driven primarily by demand for refined products, crude oil and other hydrocarbon-based products in the areas in which we operate. We generate revenue in this segment primarily by charging customers for the inland and offshore transportation and distribution of their products utilizing our 110 tank barges and 51 tow boats. We also provide offshore well-testing and other offshore services. Approximately 6 of our tow boats and 8 of our tank barges are dedicated to offshore activities. We do not assume ownership of the products we transport in this segment.

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Our transportation services are generally provided under term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from within designated operating areas at set day rates or a set fee per cargo movement. Most of the inland term contracts have one-year terms with the remainder having terms of up to two years. Substantially all of the inland contracts have renewal options, which are exercisable subject to agreement on rates applicable to the option terms. Most of the offshore service and transportation contracts have up to one-year terms with renewal options, which are exercisable subject to agreement on rates applicable to the option terms, or are spot contracts. A spot contract is an agreement with a customer to move cargo within designated operating areas for a rate negotiated at the time the cargo movement takes place.

As is typical for inland and offshore affreightment contracts, the term contracts establish set day rates but do not include revenue or volume guarantees. Most of the contracts include escalation provisions to recover specific increased operating costs such as incremental increases in labor. The costs of fuel and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts. We are responsible for the remaining operating costs, such as equipment maintenance costs, various inspection costs, the cost of maintaining insurance coverage on the vessels under these contracts, and for other operating costs under our other contracts that do not contain such reimbursement or escalation provisions.

The following table provides financial information for the Marine Services Segment for the three months ended March 31, 2008 and 2007 (in thousands):

	For the Three Months Ended
	March 31,				Increase
	2008		2007		(Decrease)
Operating revenues:
Transportation – Marine	$	25,536	$	--	$	25,536
Total operating revenues		25,536		--		25,536

Costs and expenses:
Operating expense		8,579		--		8,579
Operating fuel and power		5,489		--		5,489
General and administrative		736		--		736
Depreciation and amortization		3,734		--		3,734
Taxes – other than income taxes		430		--		430
Total costs and expenses		18,968		--		18,968

Operating income		6,568		--		6,568

Interest income		4		--		4

Earnings before interest	$	6,572	$	--	$	6,572

Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007

Revenues from marine transportation were $25.5 million for the three months ended March 31, 2008, of which $21.5 million related to inland transportation services and $4.0 million related to offshore transportation services, including well-testing service activities and other offshore services. Revenues were primarily influenced by rates on term contracts along with industry demand, high use of tank barges and reimbursements of costs of fuel that are recovered under most of the transportation contracts.

Costs and expenses were $19.0 million for the three months ended March 31, 2008. Operating expenses were $8.6 million consisting primarily of $5.0 million of reimbursements under the transitional operating agreement for vessel personnel salaries and related employee benefits and other expenses, $1.4 million for contract business fees and $0.4 million of towboat and tank barge maintenance expenses. Under the transitional operating agreement, we reimburse Cenac for personnel salaries and related employee benefit expenses, certain repairs and maintenance expenses and insurance premiums on our equipment, as well as payment of a monthly service fee. Operating fuel and power was $5.5 million relating to diesel fuel consumed under the term contracts, in which substantially all fuel costs are directly reimbursed by the customer to recover the cost of fuel. General and administrative expenses were

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$0.7 million primarily related to the monthly service fee and overhead fees that we paid to Cenac under the transitional operating agreement. Depreciation and amortization expense was $3.7 million, consisting of $2.5 million of depreciation expense on tow boats and tank barges and $1.2 million of amortization expense related to customer relationship intangibles, non-compete agreements and other intangibles acquired in the Cenac and Horizon acquisitions (see Note 9 in the Notes to Unaudited Condensed Consolidated Financial Statements). Taxes – other than income taxes was $0.4 million and related primarily to the waterway user tax.

Interest Expense and Capitalized Interest

Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007

Interest expense increased $17.1 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to $8.7 million recognized in interest expense upon the redemption of the 7.51% TE Products Senior Notes on January 28, 2008. Of the $8.7 million of expense, $6.6 million related to a make-whole premium paid with the redemption of the senior notes (see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements), $1.0 million related to the remaining unamortized interest rate swap loss that had been deferred as an adjustment to the carrying value of the senior notes (see Note 5 in the Notes to Unaudited Condensed Consolidated Financial Statements) and $1.1 million related to unamortized debt issuance costs on the senior notes. Additionally, the increase in interest expense was due to $3.6 million of interest expense in the 2008 period resulting from interest payments hedged under treasury locks not occurring as forecasted (see Note 5 in the Notes to Unaudited Condensed Consolidated Financial Statements) and higher outstanding borrowings in the 2008 period, partially offset by lower short-term floating interest rates in the 2008 period.

Capitalized interest (included in interest expense, net in our statements of consolidated income) increased $0.7 million for the three months ended March 31, 2008, compared with the three months ended March 31, 2007, primarily due to higher construction work-in-progress balances in the 2008 period as compared to the 2007 period.

Income Taxes – Revised Texas Franchise Tax

Provision for income taxes is applicable to our state tax obligations under the Revised Texas Franchise Tax enacted in May 2006. At March 31, 2008 and December 31, 2007, we had current tax liabilities of $2.0 million and $1.2 million, respectively, and deferred tax assets of less than $0.1 million and less than $0.1 million, respectively. During the three months ended March 31, 2008 and 2007, we recorded increases in current income tax liabilities of $0.8 million and $0.7 million, respectively. During the three months ended March 31, 2007, we recorded a $0.6 million reduction to deferred tax liability. The offsetting net charges to deferred tax expense and income tax expense are shown on our statements of consolidated income as provision for income taxes.

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Financial Condition and Liquidity

Cash generated from operations, credit facilities and debt and equity offerings are our primary sources of liquidity. At March 31, 2008, we had a working capital surplus of $9.1 million, while at December 31, 2007, we had a working capital deficit of $431.2 million. Of the $431.2 million deficit at December 31, 2007, $354.0 million related to the classification of the TE Products’ Senior Notes as short-term (see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements and Credit Facilities below). At March 31, 2008, we had approximately $247.7 million in available borrowing capacity under our revolving credit facility to cover any working capital needs. Cash flows for the three months ended March 31, 2008 and 2007 were as follows (in thousands):

	For the Three Months Ended
	March 31,
	2008			2007

Cash provided by (used in):
Operating activities	$	58,681		$	68,731
Investing activities		(436,441	)		94,159
Financing activities		377,769			(162,889	)

Operating Activities

Net cash flow provided by operating activities was $58.7 million for the three months ended March 31, 2008 compared to $68.7 million for the three months ended March 31, 2007. The following were the principal factors resulting in the $10.0 million decrease in net cash flows provided by operating activities:

Cash flow from operating activities decreased due to the timing of cash disbursements and cash receipts related to working capital components.

Cash distributions received from unconsolidated affiliates decreased $3.1 million. Distributions received from our equity investment in MB Storage decreased $10.4 million due to the sale of our investment in MB Storage on March 1, 2007. Distributions received from our equity investment in Seaway decreased $3.8 million primarily due to its operating cash requirements. Distribution from our equity investment in Jonah increased $11.1 million primarily due to increased revenues and volumes generated from completion of a portion of the Phase V expansion project in July 2007.

Cash paid for interest, net of amounts capitalized, increased $4.4 million period-to-period primarily due to higher outstanding balances on our variable rate revolving credit facility. Excluding the effects of hedging activities and interest capitalized during the year ended December 31, 2008, we expect interest payments on our fixed rate senior notes and junior subordinated notes for 2008 to be approximately $137.6 million. We expect to make our interest payments with cash flows from operating activities.

Investing Activities

Net cash flows used in investing activities was $436.4 million for the three months ended March 31, 2008 compared to net cash flows provided by investing activities of $94.2 million for the three months ended March 31, 2007. The following were the principal factors resulting in the $530.6 million increase in net cash flows used in investing activities:

Cash used for business combinations was $338.5 million during the three months ended March 31, 2008, of which $257.7 million was for the Cenac acquisition and $80.8 million was for the Horizon acquisition.

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Capital expenditures increased $17.5 million primarily due to an increase in organic growth projects period-to-period and higher spending to sustain existing operations, including pipeline integrity (see “Other Considerations – Future Capital Needs and Commitments” below). Cash paid for linefill on assets owned increased $14.3 million period-to-period primarily due to the completion of organic growth projects in our Upstream Segment.

Proceeds from the sales of assets and ownership interests during the three months ended March 31, 2007 were $165.3 million, which includes $138.8 million from the sale of TE Products’ ownership interests in MB Storage and its general partner and $18.5 million for the sale of other Downstream Segment assets, all to Louis Dreyfus on March 1, 2007; and $8.0 million for the sale of Downstream Segment assets to Enterprise Products Partners in January 2007 (see Note 10 in the Notes to Unaudited Condensed Consolidated Financial Statements).

Investments in unconsolidated affiliates decreased $5.3 million, which includes a $6.1 million decrease in contributions to Centennial, partially offset by a $0.8 million increase in contributions to Jonah primarily for capital expenditures on its Phase V expansion. Contributions to Centennial during the three months ended March 31, 2007 were for contractual obligations that were created upon formation of Centennial.

During the three months ended March 31, 2008, we paid $0.3 million related to customer reimbursable commitments.

Financing Activities

Cash flows provided by financing activities totaled $377.8 million for the three months ended March 31, 2008, compared to cash flows used in financing activities of $162.9 million for the three months ended March 31, 2007. The following were the principal factors resulting in the $540.7 million increase in cash provided by financing activities:

During the three months ended March 31, 2008, we used $1.0 billion of proceeds from our term credit agreement (i) to fund the cash portion of our Cenac and Horizon acquisitions, (ii) to fund the redemption of our 7.51% TE Products Senior Notes in January 2008, and the repayment of our 6.45% TE Products Senior Notes, which matured in January 2008, (iii) to repay $63.2 million of debt assumed in the Cenac acquisition, and (iv) for other general partnership purposes. We used the proceeds from the issuance of senior notes in March 2008 to repay the outstanding balance of $1.0 billion under the term credit agreement (see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements). Debt issuance costs paid during the three months ended March 31, 2008 were $8.7 million.

Net repayments under our revolving credit facility decreased $29.7 million.

We paid $52.1 million to settle treasury locks in March 2008 (see Note 5 in the Notes to Unaudited Condensed Consolidated Financial Statements) upon the issuance of senior notes.

Cash distributions to our partners increased $2.5 million period-to-period due to an increase in the number of Units outstanding and our quarterly cash distribution rates. We paid cash distributions of $74.9 million ($0.695 per Unit) and $72.4 million ($0.675 per Unit) during the three months ended March 31, 2008 and 2007, respectively. Additionally, we declared a cash distribution of $0.71 per Unit for the quarter ended March 31, 2008. We paid the distribution of $80.9 million on May 7, 2008 to unitholders of record on April 30, 2008.

Net proceeds from the issuance of Units was $2.7 million during the three months ended March 31, 2008 from the issuance of Units to employees under the employee unit purchase plan and the issuance of Units in connection with our distribution reinvestment plan (see Note 12 in the Notes to Unaudited Condensed Consolidated Financial Statements).

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Other Considerations

Registration Statements

We have a universal shelf registration statement on file with the SEC that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $2.0 billion of equity securities, debt securities or a combination thereof. In March 2008, we sold $1.0 billion principal amount of senior notes (see "Senior Notes" below) under our universal shelf registration statement. After taking into account past issuances of securities under this registration statement, as of March 31, 2008, we have the ability to issue approximately $205.1 million of additional securities under this registration statement, subject to customary marketing terms and conditions.

Credit Facilities

We had in place a senior unsecured term credit agreement (“Term Credit Agreement”), with a borrowing capacity of $1.0 billion and a maturity date of December 19, 2008. During the first quarter of 2008, we borrowed $1.0 billion to finance the retirement of TE Products’s senior notes, the cash portion of our Cenac and Horizon acquisitions and other partnership purposes. In March 2008, we repaid the oustanding balance with proceeds from the issuance of senior notes and other cash on hand and terminated the credit agreement.

See Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements for further information on these credit facilities.

Senior Notes

On March 27, 2008, we issued and sold in an underwritten public offering (i) $250.0 million principal amount of 5.90% Senior Notes due 2013, (ii) $350.0 million principal amount of 6.65% Senior Notes due 2018, and (iii) $400.0 million principal amount of 7.55% Senior Notes due 2038. The proceeds of this offering were used to repay borrowings oustanding under our Term Credit Agreement, which was terminated in March 2008 (see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements). The Senior Notes were issued at discounts of $0.2 million, $1.3 million and $2.2 million, respectively, and are being accreted to their face value over the applicable terms of the senior notes. 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 50 basis points. The indentures governing our senior notes contain covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions.

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However, the indentures do not limit our ability to incur additional indebtedness. At March 31, 2008, we were in compliance with the covenants of these senior notes.

Retirement of TE Products Senior Notes

In January 2008, TE Products retired all of its outstanding long-term debt by repaying at maturity $180.0 million principal amount of its 6.45% TE Products Senior Notes due 2008 and redeeming the remaining $175.0 million principal amount of its 7.51% TE Products Senior Notes due 2028. The redemption price for the 7.51% TE Products Senior Notes due 2028 was 103.755% of the principal amount plus accrued and unpaid interest to January 28, 2008, the date of redemption. We funded the retirement of the TE Products debt with borrowings under our Term Credit Agreement. For further information, please see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions and joint venture contributions, for 2008 will be in the range of $380.0 million to $405.0 million (including approximately $14.0 million of capitalized interest). We expect to spend in the range of $313.0 million to $338.0 million for revenue generating projects, which includes $184.0 million for our expected spending on the Motiva project. We expect to spend approximately $55.0 million to sustain existing operations (including $17.0 million for pipeline integrity) including life-cycle replacements for equipment at various facilities and pipeline and tank replacements among all of our business segments. We expect to spend approximately $12.0 million to improve operational efficiencies and reduce costs among all of our business segments. Additionally, we expect to invest approximately $137.0 million (including approximately $4.0 million of capitalized interest) in our Jonah joint venture during 2008 for the completion of the Phase V expansion and additional facilities to expand the Pinedale field production.

During 2008, TE Products may be required to contribute cash to Centennial to cover capital expenditures, debt service requirements or other operating needs. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business operations. 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.

Liquidity Outlook

We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and to complete the Jonah expansion, revenue generating expenditures, interest payments on our senior notes, junior subordinated notes and Revolving Credit Facility, distributions to our unitholders and General Partner and acquisitions of new assets or businesses. Our operating cash requirements and capital expenditures to sustain existing operations for 2008 are expected to be funded through our cash flows from operating activities. Long-term cash requirements for expansion projects, acquisitions and debt repayments are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities, joint venture distributions and possibly the issuance of additional equity and debt securities. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

We expect to repay the long-term, senior and junior unsecured obligations through the issuance of additional long-term senior or junior unsecured debt, issuance of additional equity, with proceeds from dispositions of assets, cash flow from operations or any combination of the above items.

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Off-Balance Sheet Arrangements

We do not rely on off-balance sheet borrowings to fund our acquisitions. We have no material off-balance sheet commitments for indebtedness other than the limited guaranty of Centennial debt and the limited guarantee of Centennial catastrophic events as discussed below. In addition, we have entered into various operating leases covering assets utilized in several areas of our operations.

At March 31, 2008 and December 31, 2007, Centennial’s debt obligations consisted of $140.0 million borrowed under a master shelf loan agreement. In January 2008, we entered into an amended and restated guaranty agreement (“Amended Guaranty”) with Centennial’s lenders, in which we, TE Products, TEPPCO Midstream and TCTM (collectively, the “TEPPCO Guarantors”) are required, on a joint and several basis, to pay 50% of any past-due amount under Centennial’s master shelf loan agreement not paid by Centennial. The Amended Guaranty also has a credit maintenance requirement whereby we may be required to provide additional credit support in the form of a letter of credit or pay certain fees if either of our credit ratings from Standard & Poor’s Ratings Group (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”) fall below investment grade levels as specified in the Amended Guaranty. If Centennial defaults on its debt obligations, the estimated maximum potential amount of future payments for the TEPPCO Guarantors and Marathon Petroleum Company LLC ("Marathon") is $70.0 million each at March 31, 2008. At March 31, 2008, we have a liability of $9.4 million, which represents the present value of the estimated amount we would have to pay under the guaranty.

Contractual Obligations

In March 2008, we issued $1.0 billion of senior notes due in 2013, 2018 and 2038 (see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements). Other than the issuance of these senior notes, there have been no significant changes in our schedule of maturities of long-term debt or other contractual obligations since the year ended December 31, 2007.

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The following table summarizes our debt repayment obligations as of March 31, 2008 (in thousands):

			Amount of Commitment Expiration Per Period
	Total			Less than 1 Year		1-3 Years		4-5 Years		After 5 Years

Revolving Credit Facility, due 2012	$	429,200		$	--	$	--	$	429,200	$	--
7.625% Senior Notes due 2012 (1)		500,000			--		--		500,000		--
6.125% Senior Notes due 2013 (1)		200,000			--		--		200,000		--
5.90% Senior Notes, due 2013 (1)		250,000			--		--		--		250,000
6.65% Senior Notes, due 2018 (1)		350,000			--		--		--		350,000
7.55% Senior Notes, due 2038 (1)		400,000			--		--		--		400,000
7.00% Junior Subordinated Notes due 2067 (1)		300,000			--		--		--		300,000
Interest payments (2)		2,772,485			152,900		305,800		263,796		2,049,989
Debt and interest total	$	5,201,685		$	152,900	$	305,800	$	1,392,996	$	3,349,989

___________________________

(1)

At March 31, 2008, the 7.625% Senior Notes includes a deferred gain of $21.9 million, net of amortization, from interest rate swap terminations (see Note 5 in the Notes to Unaudited Condensed Consolidated Financial Statements). At March 31, 2008, our 7.625% Senior Notes, our 6.125% Senior Notes, our 5.90% Senior Notes, our 6.65% Senior Notes, our 7.55% Senior Notes and our 7.00% junior subordinated notes include an aggregate of $5.6 million of unamortized debt discounts. The deferred gain and the unamortized debt discounts are excluded from this table.

(2)

Includes interest payments due on our senior notes and junior subordinated notes and interest payments and commitment fees due on our Revolving Credit Facility. The interest amounts calculated on the Revolving Credit Facility and the junior subordinated notes are based on the assumption that the amounts outstanding and the interest rates charged both remain at their current levels.

Credit Ratings

Our debt securities are rated BBB- by S&P, Baa3 by Moody’s and BBB- by Fitch Ratings, all with stable outlooks. Based upon the characteristics of the fixed/floating unsecured junior subordinated notes that we issued in May 2007, Moody’s and S&P each assigned 50% equity treatment to these notes. Fitch Ratings assigned 75% equity treatment to these notes.

Recent Accounting Pronouncements

See discussion of new accounting pronouncements in Note 2 in the Notes to Unaudited Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

We are exposed to financial market risks, including changes in commodity prices and interest rates. We do not have foreign exchange risks. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices. 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 our General Partner. For additional discussion of our exposure to market risks, please refer to “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.

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We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates, resulting in the realization of income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.

Commodity Risk Hedging Program

We seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. We take the normal purchase and normal sale exclusion in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133, where permitted.

As part of our crude oil marketing business, we enter into derivative contracts such as swaps and other business hedging devices. Generally, we elect hedge accounting where permitted under SFAS 133. The terms of these contracts are typically one year or less. The purpose is to balance our position or lock in a margin and, as such, the derivative contracts do not expose us to additional significant market risk. For derivatives where hedge accounting is elected, the effective portion of changes in fair value are recorded in other comprehensive income and reclassified into earnings as such transactions affect earnings. For derivatives where hedge accounting is not elected, we mark these transactions to market and the changes in the fair value are recognized in current earnings. This results in some financial statement variability during quarterly periods.

At March 31, 2008, we had a limited number of commodity derivatives that were accounted for as cash flow hedges. These contracts will expire during 2008, and any amounts remaining in accumulated other comprehensive income will be recorded in net income. Gains and losses on these derivatives are offset against corresponding gains or losses of the hedged item and are deferred through other comprehensive income, thus minimizing exposure to cash flow risk. No ineffectiveness was recognized as of March 31, 2008. In addition, we had some commodity derivatives that did not qualify for hedge accounting. These financial instruments had a minimal impact on our earnings. The fair value of the open positions at March 31, 2008 was a liability of $15.4 million.

The following table shows the effect of hypothetical price movements on the estimated fair value (“FV”) of this portfolio at the dates indicated (in thousands):

Scenario	Resulting Classification	December 31, 2007			March 31, 2008			April 22, 2008

FV assuming no change in underlying commodity prices	Liability	$	(18,897	)	$	(15,391	)	$	(24,391	)
FV assuming 10% increase in underlying commodity prices	Liability		(33,606	)		(24,574	)		(32,895	)
FV assuming 10% decrease in underlying commodity prices	Liability		(4,188	)		(6,208	)		(15,887	)

The fair value of the open positions was based upon both quoted market prices obtained from NYMEX and from other sources such as reporting services, industry publications, brokers and marketers. The fair values were determined based upon the differences by month between the fixed contract price and the relevant forward price curve, the volumes for the applicable month and applicable discount rate.

Interest Rate Risk Hedging Program

We 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. Interest rate swaps that manage our cash flow risk reduce our exposure to increases in the benchmark interest rates underlying variable rate debt. Interest rate swaps that manage our fair value risks are intended to reduce our exposure to changes in the fair value of the fixed rate debt. Interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional value upon which the payments

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are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest.

Interest Rate Swap Expirations and Terminations. In January 2006, we entered into interest rate swap agreements with a total notional value of $200.0 million to hedge our exposure to increases in the benchmark interest rate underlying our variable rate Revolving Credit Facility. Under the swap agreements, we paid a fixed rate of interest ranging from 4.67% to 4.695% and received a floating rate based on the three-month U.S. Dollar LIBOR rate. At December 31, 2007, the fair value of these interest rate swaps was an asset of $0.3 million. These interest rate swaps expired in January 2008.

Treasury Locks. We utilize treasury locks to hedge the underlying U.S. treasury rate related to our anticipated debt incurrence. In 2007, we entered into treasury locks, accounted for as cash flow hedges, that extended through January 31, 2008 for a notional value totaling $600.0 million. At December 31, 2007, the fair value of the treasury locks was a liability of $25.3 million. In January 2008, these treasury locks were extended through April 30, 2008. In March 2008, these treasury locks were settled concurrently with the issuance of senior notes (see Note 11 in the Notes to Unaudited Condensed Consolidated Financial Statements). The settlement of the treasury locks resulted in losses of $52.1 million, and these losses were recorded in accumulated other comprehensive income. We recognized approximately $3.6 million of this loss in interest expense as a result of interest payments hedged under the treasury locks not occurring as forecasted. The remaining losses are being amortized using the effective interest method as increases to future interest expense over the terms of the forecasted interest payments, which range from five to ten years. Over the next twelve months, we expect to reclassify $2.8 million of accumulated other comprehensive loss that was generated by these treasury locks as an increase to interest expense. In the event of early extinguishment of these senior notes, any remaining unamortized losses would be recognized in the statement of consolidated income at the time of extinguishment.

Fair Values of Debt

The following table summarizes the estimated fair values of the senior notes and junior subordinated notes at March 31, 2008 and December 31, 2007:

			Fair Value
			March 31,		December 31,
	Face Value		2008		2007

6.45% TE Products Senior Notes, due January 2008 (1)	$	180,000	$	--	$	179,982
7.625% Senior Notes, due February 2012		500,000		533,188		536,765
6.125% Senior Notes, due February 2013		200,000		202,368		202,027
5.90% Senior Notes, due April 2013		250,000		251,960		--
6.65% Senior Notes, due April 2018		350,000		353,531		--
7.51% TE Products Senior Notes, due January 2028 (1)		175,000		--		181,571
7.55% Senior Notes, due April 2038		400,000		404,031		--
7.000% Junior Subordinated Notes, due June 2067		300,000		253,724		270,485

_________________

(1)

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Item 4. Controls and Procedures.

As of the end of the period covered by this Report, our management carried out an evaluation, with the participation of our principal executive officer (the “CEO”) and our principal financial officer (the “CFO”), of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based on those evaluations, as of the end of the period covered by this Report, the CEO and CFO concluded:

(i)

that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and

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

Changes in Internal Control over Financial Reporting

Other than the events discussed under “TEPPCO Marine Services Transactions” below, there has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the first quarter of 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

TEPPCO Marine Services Transactions

On February 1, 2008, we acquired transportation assets and certain intangible assets that comprised the marine transportation business of Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. On February 29, 2008, we purchased marine assets from Horizon Maritime, L.L.C., a privately-held Houston-based company and an affiliate of Mr. Cenac. These purchases were recorded using purchase accounting. In recording the TEPPCO Marine Services purchase transactions, we followed our normal accounting procedures and internal controls. We are continuing to integrate these operations into our internal controls, and we expect that this effort will continue during the remainder of 2008.

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

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. See discussion of legal proceedings in Note 16 in the Notes to Unaudited Condensed Consolidated Financial Statements under the headings "- Litigation" and "- Regulatory Matters", which is incorporated into this item by reference.

Item 1A. Risk Factors.

Security holders and potential investors in our securities should carefully consider the risk factor set forth below and the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2007, in

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addition to other information in such Report and this Report. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Our future debt level or downgrades of our debt ratings by credit agencies may limit our future financial and operating flexibility.

At March 31, 2008, we had outstanding approximately (i) $2.1 billion of consolidated senior debt, consisting of $429.2 million of borrowings under our Revolving Credit Facility and $1.7 billion principal amount of senior notes, and (ii) $300.0 million principal amount of junior subordinated notes.

The amount of our future debt could have significant effects on our operations, because, among other reasons:

a significant portion of our cash flow could be dedicated to the payment of principal and interest on our future debt and may not be available for other purposes, including the payment of distributions on our Units and capital expenditures;
credit rating agencies may view our debt level negatively;
covenants contained in our existing debt arrangements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
our ability to obtain additional financing for working capital, capital expenditures, acquisitions, and general partnership purposes may be limited;
we may be at a competitive disadvantage relative to similar companies that have less debt; and
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

Our Revolving Credit Facility contains restrictive financial and other covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur certain additional indebtedness, make distributions in excess of available cash (generally defined in our partnership agreement as consolidated cash receipts less consolidated cash disbursements and cash reserves established by our General Partner), incur certain liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets. This facility also prevents us from making a distribution if an event of default has occurred or would occur as a result of the distribution. Our breach of these restrictions or restrictions in the provisions of our other indebtedness could permit the holders of the indebtedness to declare all amounts outstanding thereunder to be immediately due and payable and, in the case of our Revolving Credit Facility, to terminate all commitments to extend further credit. Although our Revolving Credit Facility restricts our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial.

Our ability to access capital markets to raise capital on favorable terms will be affected by our debt level, the amount of our debt maturing in the next several years and current maturities, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade our credit ratings, we could experience an increase in our borrowing costs, difficulty accessing capital markets, or a reduction in the market price of our Units. Such a development could adversely affect our ability to obtain financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness. If we are unable to access the capital markets on favorable terms at the time a debt obligation becomes due in the future, we might be forced to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected rates. In addition, a downgrade of our credit ratings could result in our being required to post financial collateral under our guaranty of indebtedness of our Centennial joint venture or some of the contracts that we use in connection with our commodity and interest rate hedging transactions.

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Item 5. Other Information.

The last paragraph under Note 19 in the Notes to Unaudited Condensed Consolidated Financial Information and the first paragraph under Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments are incorporated by reference into this Item 5.

Item 6. Exhibits.

Exhibit

Number Description

3.1	Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).

3.2

Fourth Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated December 8, 2006 (Filed as Exhibit 3 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on December 13, 2006).

3.3

Amended and Restated Limited Liability Company Agreement of Texas Eastern Products Pipeline Company, LLC (Filed as Exhibit 3 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 10, 2007 and incorporated herein by reference).

3.4

First Amendment to Fourth Amended and Restated Partnership Agreement of TEPPCO Partners, L.P. dated as of December 27, 2007 (Filed as Exhibit 3.1 to Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed December 28, 2007 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

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).

4.3

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).

4.4

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).

4.5

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

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January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

4.6

Full Release of Guarantee dated as of July 31, 2006 by Wachovia Bank, National Association, as trustee, in favor of Jonah Gas Gathering Company (Filed as Exhibit 4.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2006 and incorporated herein by reference).

4.7

Indenture, dated as of May 14, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and The Bank of New York Trust Company, N.A., as trustee (Filed as Exhibit 99.1 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 15, 2007 and incorporated herein by reference).

4.8

First Supplemental Indenture, dated as of May 18, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and The Bank of New York Trust Company, N.A., as trustee (Filed as Exhibit 4.2 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 18, 2007 and incorporated herein by reference).

4.9

Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. , Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as subsidiary guarantors, and The Bank of New York Trust Company, N.A., as trustee (Filed as Exhibit 4.2 to the Current Report on Form 8-K of TE Products Pipeline Company, LLC (Commission File No. 1-13603) filed on July 6, 2007 and incorporated herein by reference).

4.10

Fourth Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as subsidiary guarantors, and U.S. Bank National Association, as trustee (Filed as Exhibit 4.3 to the Current Report on Form 8-K of TE Products Pipeline Company, LLC (Commission File No. 1-13603) filed on July 6, 2007 and incorporated herein by reference).

4.11*

Fifth Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC, and Val Verde Gathering Company, L.P., as subsidiary guarantors, and U.S. Bank National Association, as trustee.

4.12*

Sixth Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and U.S. Bank National Association, as trustee.

4.13*

Seventh Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as subsidiary guarantors, and U.S. Bank National Association, as trustee.

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10.1

Amended and Restated Guaranty Agreement, dated as of January 17, 2008, by and among The Prudential Insurance Company of America, TCTM, L.P., TEPPCO Midstream Companies, LLC, TEPPCO Partners, L.P. and TE Products Pipeline Company, LLC (Filed as Exhibit 10.1 to Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed January 24, 2008 and incorporated herein by reference).

10.2

Asset Purchase Agreement, dated February 1, 2008, by and among TEPPCO Marine Services, LLC, TEPPCO Partners, L.P., Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. (Filed as Exhibit 2 to Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed February 7, 2008 and incorporated herein by reference).

10.3

Transitional Operating Agreement, dated February 1, 2008, by and among TEPPCO Marine Services, LLC, Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr. (Filed as Exhibit 10 to Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed February 7, 2008 and incorporated herein by reference).

10.4

Asset Purchase Agreement, dated February 29, 2008, by and among TEPPCO Marine Services, LLC, Horizon Maritime, L.L.C., Mr. Arlen B. Cenac, Jr., Mr. Steven G. Proehl, Mr. John P. Binion, Mr. Richard M. Seale and CHO, LLC (Filed as Exhibit 10 to Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed March 6, 2008 and incorporated herein by reference).

10.5*

Amendment No. 1, dated February 29, 2008, to Asset Purchase Agreement, dated February 1, 2008, by and among TEPPCO Marine Serivces, LLC, TEPPCO Partners, L.P., Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr.

10.6*

Amendment No. 1, dated February 29, 2008, to Transitional Operating Agreement, dated February 1, 2008, by and among Cenac Towing Co., Inc., Cenac Offshore, L.L.C., Mr. Arlen B. Cenac, Jr., and TEPPCO Marine Serivces, LLC.

10.7*

Form of TPP Employee Unit Option Grant under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan.

10.8*

Form of TPP Employee Amendment to Unit Option Grant under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan for options granted between April 2007 and April 2008.

12.1*

Statement of Computation of Ratio of Earnings to Fixed Charges.

31.1*

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

31.2*

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

32.1**

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

32.2**

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

_________________________

* Filed herewith.

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

+ A management contract or compensation plan or arrangement.

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	TEPPCO Partners, L.P.
Date: May 8, 2008	By: /s/ JERRY E. THOMPSON Jerry E. Thompson, President and Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC, General Partner

Date: May 8, 2008	By: /s/ WILLIAM G. MANIAS William G. Manias, Vice President and Chief Financial Officer of Texas Eastern Products Pipeline Company, LLC, General Partner