UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

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

For the transition period from                      to                     .

TEPPCO Partners, L.P.

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

Title of each class		Name of each exchange on which registered
Limited Partner Units representing Limited		New York Stock Exchange
Partner Interests

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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. (Check one):

      Large accelerated filer þ               Accelerated filer o                         Non-accelerated filer o                         Smaller reporting company o

                                        (Do not check if a smaller reporting company)

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

At June 30, 2007, the aggregate market value of the registrant’s Limited Partner Units held by non-affiliates was $3.2 billion, which was computed using the average of the high and low sales prices of the Limited Partner Units on June 30, 2007.

Limited Partner Units outstanding as of February 1, 2008: 94,766,431.

Documents Incorporated by Reference: None.

 

 

TEPPCO PARTNERS, L.P.
TABLE OF CONTENTS

		Significant Relationships Referenced in this Annual Report			1
		Cautionary Note Regarding Forward-Looking Statements			2
PART I
ITEMS 1		Business and Properties			2
AND 2.
ITEM 1A.		Risk Factors			30
ITEM 1B.		Unresolved Staff Comments			47
ITEM 3.		Legal Proceedings			47
ITEM 4.		Submission of Matters to a Vote of Security Holders			49
PART II
ITEM 5.		Market for Registrant’s Units and Related Unitholder Matters and Issuer Purchases of Equity Securities			50
ITEM 6.		Selected Financial Data			51
ITEM 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			52
ITEM 7A.		Quantitative and Qualitative Disclosures About Market Risk			85
ITEM 8.		Financial Statements and Supplementary Data			87
ITEM 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			87
ITEM 9A.		Controls and Procedures			88
ITEM 9B.		Other Information			90
PART III
ITEM 10.		Directors, Executive Officers and Corporate Governance			90
ITEM 11.		Executive Compensation			95
ITEM 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			108
ITEM 13.		Certain Relationships and Related Transactions, and Director Independence			110
ITEM 14.		Principal Accounting Fees and Services			117
PART IV
ITEM 15.		Exhibits, Financial Statement Schedules			119
Statement of Computation of Ratio of Earnings to Fixed Charges
Subsidiaries
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP
Consent of KPMG LLP
Powers of Attorney
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350

 i

SIGNIFICANT RELATIONSHIPS REFERENCED IN THIS ANNUAL 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” and “TEPPCO Midstream” mean TE Products Pipeline Company, LLC, TCTM, L.P., and TEPPCO Midstream Companies, LLC, our subsidiaries. Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Companies.”

     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 “TEPPCO GP” mean TEPPCO GP, Inc., our subsidiary, which is the general partner or manager of the Operating Companies.

     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.

     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.

     References to “Enterprise Products GP” mean Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners.

     References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.

     References to “DFI” mean Duncan Family Interests, Inc. and “DFIGP” mean DFI GP Holdings L.P. DFI and DFIGP are private company affiliates of EPCO. Enterprise GP Holdings acquired its ownership interests in us and our General Partner from DFI and DFIGP.

     References to “Dan Duncan LLC” mean Dan Duncan LLC, a privately held company that owns EPE Holdings. Dan L. Duncan owns and controls Dan Duncan LLC.

     References to “Duncan Energy Partners” mean Duncan Energy Partners L.P. and its consolidated subsidiaries, a publicly traded Delaware limited partnership and a consolidated subsidiary of Enterprise Products Partners.

     We, Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings, Duncan Energy Partners, DFI, DFIGP and our General Partner are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO and the controlling member of Dan Duncan LLC.

     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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     The matters discussed in this Annual Report on Form 10-K (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 transportation 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.

     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.

PART I

Items 1 and 2. Business and Properties

General

     We are a publicly traded Delaware limited partnership formed in March 1990 and our limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. We are one of the largest common carrier pipelines of refined products and liquefied petroleum gases (“LPGs”) in the United States. In addition, we own and operate petrochemical and natural gas liquids (“NGLs”) pipelines; we are engaged in crude

oil transportation, storage, gathering and marketing; we own and operate natural gas gathering systems; and we own interests in Seaway Crude Pipeline Company (“Seaway”), Centennial Pipeline LLC (“Centennial”) and Jonah Gas Gathering Company (“Jonah”) and an undivided ownership interest in the Basin Pipeline (“Basin”). Through December 31, 2007, we operated and reported in three business segments:

	•		transportation, marketing and storage of refined products, LPGs and petrochemicals (“Downstream Segment”);
	•		gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals (“Upstream Segment”); and
	•		gathering of natural gas, fractionation of NGLs and transportation of NGLs (“Midstream Segment”).

     Our reportable segments offer different products and services and are managed separately because each requires different business strategies. We operate through TE Products, TCTM and TEPPCO Midstream. Texas Eastern Products Pipeline Company, LLC, 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 and 99.999% membership interests in each of TE Products and TEPPCO Midstream. 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. Our interstate transportation operations, including rates charged to customers, are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). In this Report, we refer to refined products, LPGs, petrochemicals, crude oil, lubrication oils and specialty chemicals, NGLs and natural gas, collectively as “petroleum products” or “products.”

     Dan L. 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 and its affiliates, including Duncan Energy Partners. On May 7, 2007, all of the membership interests in our General Partner, together with 4,400,000 of our Units, were sold by DFI and DFIGP to Enterprise GP Holdings, a publicly traded partnership also controlled indirectly by EPCO. Since that sale, 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, DFI, DFIGP and other entities controlled by Mr. Duncan own 16,691,550, or 17.6%, of our Units.

     We do not directly employ any officers or other persons responsible for managing our operations. Under an amended and restated administrative services agreement (“ASA”), EPCO performs all 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.

     At December 31, 2007, 2006 and 2005, we had outstanding 89,911,532, 89,804,829 and 69,963,554 Units, respectively.

Business Strategy

     Our business strategy is to grow TEPPCO’s sustainable cash flow and to increase cash distributions to our unitholders. The key elements of our strategy are to:

	•		Focus on internal growth prospects in order to increase pipeline system and terminal throughput, expand and upgrade existing assets and services and construct new pipelines, terminals and facilities;
	•		Target accretive and complementary acquisitions and expansion opportunities that provide attractive, long-term, balanced growth in each business segment;
	•		Continue to invest in fee based, demand driven, long-lived growth opportunities that complement our businesses, including blending and logistical opportunities using ethanol;
	•		Fund our growth with the financial discipline necessary to maintain our investment grade credit ratings; and
	•		Operate in a safe, efficient, compliant and environmentally responsible manner.

     We continue to build a base for long-term growth by pursuing our strategy. Further, we believe the following trends and factors will drive our growth opportunities in 2008 and beyond:

	•		We expect that refined products imports to the U.S. will increase;
	•		We expect to see turnover in commercial terminal ownership and operations;
	•		We expect that Canadian crude oil imports to the U.S. will increase;
	•		We expect that crude oil imports to the U.S. Gulf Coast will increase;
	•		We expect the demand for marine transportation services in our market areas to remain strong;
	•		We expect to see continued expansion opportunities for natural gas gathering and related services in the Jonah, Pinedale and San Juan Basin areas; and
	•		Standards for use of ethanol and other renewable fuels are currently mandated to increase to 15 billion gallons by 2015 and will ultimately reach 36 billion gallons per year under newly passed energy legislation.

For a detailed discussion of these key trends or factors, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Overview of Business.”

Acquisition of Marine Transportation Business

     On February 1, 2008, we entered the marine transportation business for refined products, crude oil and lubrication products through the purchase of assets from Cenac Towing Co., Inc., Cenac Offshore, L.L.C. (collectively, “Cenac”) and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, the “Cenac Sellers”), for approximately $443.8 million, consisting of approximately $256.6 million in cash and approximately 4.85 million newly issued Units. Additionally, we assumed $63.2 million of Cenac’s long-term debt. We acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements. This business, which we sometimes refer to in this Report as our “marine transportation 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. We financed the cash portion of the acquisition consideration with borrowings under our short-term credit agreement (discussed below). We entered into a transitional operating agreement with the Cenac Sellers under which the purchased assets will continue to be operated by them for up to two years. For additional information, please see “– Marine Transportation Services Segment – Barge Transportation of Petroleum Products.”

Chaparral Open Season

     In February 2008, our subsidiary, Chaparral Pipeline Company, LLC, (“Chaparral”) announced the start of a binding “open season” process to seek shipper support for a proposed expansion of its 845-mile NGL pipeline originating in the Permian Basin of West Texas and eastern New Mexico. The open season is being held to obtain commitments from shippers for a 15-year term at a transportation rate that is sufficient to justify the capital expenditures necessary to expand the Chaparral pipeline capacity. The Chaparral pipeline delivers NGLs to the NGL fractionation complex in Mont Belvieu, Texas. The expansion project is designed to increase annual average system capacity by approximately 15,000 barrels per day or 20,000 barrels per day, depending on shipper response to the open season. The expansion would involve upgrading certain pipe sections, and may include installing additional pumping capability at existing pump stations. If there is sufficient shipper commitment, the additional capacity could be available as soon as early 2009. The open season began February 11, 2008 and continues until March 27, 2008. By April 30, 2008, Chaparral expects to notify shippers who have submitted an executed transportation services agreement whether or not the expansion project will proceed. By signing the transportation services agreement, the shipper will also agree to support Chaparral in any regulatory filings associated with the implementation of the concomitant services.

2007 Developments

Acquisitions

     On July 31, 2007, we purchased an active 170,000 barrel LPG storage cavern and associated assets from Duke Energy Ohio, Inc. and Ohio River Valley Propane, LLC for approximately $6.1 million. For additional information, please see “– Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals.”

     On September 27, 2007, we purchased approximately 44 miles of pipeline in South Texas and related equipment from Shell Pipeline Company LP for approximately $6.8 million. For additional information, please see “– Upstream Segment – Gathering, Transportation, Marketing and Storage of Crude Oil.”

Dispositions

     On January 23, 2007, we sold a 10-mile, 18-inch diameter 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.

     On March 1, 2007, TE Products sold its 49.5% ownership interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”), its 50% ownership interest in Mont Belvieu Venture, LLC (the general partner of MB Storage) and other related assets to Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) for a total of approximately $155.8 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 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 (see Midstream Segment below) and other organic growth projects. We recognized gains of approximately $59.6 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, 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 services. Payments for these services will be made according to the terms specified in the transition services agreement.

Organic Growth Projects

     During 2007, our organic growth projects included the following:

	•		Construction of a 32-mile, 8-inch diameter pipeline, connecting Valero Energy Corp.’s Texas City refinery to its Houston refinery to deliver feedstock from Texas City to Houston under a 15-year capacity lease.
	•		Expansion of our LPG pipeline from Greensburg, Pennsylvania, to Philadelphia, Pennsylvania, which increased capacity of the pipeline by approximately 35% in order to participate in market growth.
	•		Completion of an extension of the refined products pipeline system in Memphis, Tennessee to provide for the delivery of jet fuel to the Memphis airport.
	•		Commencement of construction on a new refined product terminal located in Boligee, Alabama along the Tennessee-Tombigbee waterway. The 500,000 barrel storage terminal is expected to

			have capabilities of receiving U.S. Gulf Coast refined products and distributing them via barge or truck and is expected to be completed in the second quarter of 2008.
	•		Commencement of construction of the multi-year Motiva project (see “– Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals” below).
	•		Construction of a mainline connection to both our 20-inch and 16-inch diameter pipelines allowing gasoline and distillate deliveries to a new grass roots terminal serving northeast Arkansas, supported by a 10-year transportation agreement.
	•		Construction and installation of 50,000 barrel ethanol tank, ethanol truck unloading and gasoline truck rack blending facilities to comply with Missouri’s ethanol gasoline mandate. This project is backed by the mandated use of ethanol in historical truck rack demand, charges for leasing space in the new storage tank and additional ethanol handling fees.
	•		Installation of a new natural gasoline tank with vapor recovery and associated facilities to enable year-round natural gasoline deliveries via new connections to ExxonMobil’s refinery and chemical plants.
	•		Construction of three new crude oil storage tanks at our Cushing, Oklahoma facility, representing a 900,000 barrel, or nearly 50%, increase in our storage capacity at that facility. The expansion, which is supported by long-term lease agreements, brings our total storage capacity at the Cushing facility to 2.8 million barrels.
	•		Completion of a pipeline connection in our West Texas system to supply crude oil to a New Mexico refinery. This connection is supported by a long-term supply agreement.

Jonah Phase V Expansion

     During August 2007, with the completion of the first portion of Jonah’s Phase V expansion in which the system gathering capacity was increased to approximately 2.0 Bcf per day, we and Enterprise Products Partners began sharing 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 December 31, 2007, our ownership interest in Jonah was approximately 80.64%, and Enterprise Products Partners’ ownership interest in Jonah was approximately 19.36%. Our ownership interest in Jonah is currently anticipated to remain at 80.64%. The second and final portion of the expansion is expected to be completed during April 2008. For additional information, please see “– Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs.”

Debt Financings and Retirements

     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”). We used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under our revolving credit facility and for general partnership purposes. 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). TE Products, TEPPCO Midstream, TCTM, and Val Verde Gas Gathering Company, L.P. (“Val Verde”) (collectively, the “Subsidiary Guarantors”) have jointly and severally guaranteed, on a junior subordinated basis, payment of the principal of, premium, if any, and interest on the Junior Subordinated Notes. For further information, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Financial Condition and Liquidity – Credit Facilities.”

     In October 2007, we repurchased $35.0 million principal amount of the 7.51% TE Products Senior Notes for $36.1 million and accrued interest, and on January 28, 2008, we 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. 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 a 364-day term credit agreement discussed below. For further information, please see Note 12 in the Notes to Consolidated Financial Statements.

     On December 18, 2007, we amended our revolving credit facility, extending the maturity date from December 13, 2011 to December 12, 2012, and allowing us to make unlimited requests for one-year extensions of

the maturity date. The amendment also contains an accordion feature whereby the total amount of bank commitments may be increased, with lender approval and the satisfaction of certain other conditions, from $700.0 million to $1.0 billion. For further information, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Financial Condition and Liquidity – Credit Facilities.”

     On December 21, 2007, we entered into a $1.0 billion unsecured, 364-day term credit agreement to fund the retirement of TE Products’ Senior Notes, our marine transportation acquisition and for other general partnership purposes. Loans under the agreement mature on December 19, 2008. For further information, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Financial Condition and Liquidity – Credit Facilities.”

Registration Statements

     In April 2007, we filed a registration statement with the SEC authorizing the issuance of up to 5,000,000 Units in connection with the EPCO, Inc. 2006 TPP Long-Term Incentive Plan (see Note 4 in the Notes to Consolidated Financial Statements), which provides for awards of our Units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us. In June 2007, we filed a registration statement with the SEC authorizing the issuance of up to 1,000,000 Units in connection with the EPCO, Inc. TPP Employee Unit Purchase Plan (see Note 13 in the Notes to Consolidated Financial Statements).

     In September 2007, we filed a registration statement with the SEC authorizing the issuance of up to 10,000,000 Units in connection with our distribution reinvestment plan (“DRIP”). The DRIP provides owners of our Units a voluntary means by which they can increase the number of Units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional Units. Units purchased through the DRIP may be acquired at a discount ranging from 0% to 5% (currently set at 5%), which will be set from time to time by us. As of December 31, 2007, 39,796 Units have been issued in connection with the DRIP.

Business Segments

     Through December 31, 2007, we operated and reported in three business segments: Downstream Segment, Upstream Segment and Midstream Segment. The following is a discussion of the business and properties of these three historical operating segments. See Note 14 in the Notes to the Consolidated Financial Statements for financial information by segment.

     Our marine transportation acquisition resulted in the creation of a new business segment, our Marine Transportation Segment. Accordingly, effective February 1, 2008, we operate and report in four business segments. A discussion of the business and properties of our Marine Transportation Segment follows the discussion of the Midstream Segment below.

Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals

     We conduct business in our Downstream Segment through the following:

	•		TE Products, our principal operating company for the Downstream Segment;
	•		TEPPCO Terminals Company, L.P. (“TEPPCO Terminals”), which owns a refined products terminal and two-bay truck loading rack both connected to the mainline system;
	•		TEPPCO Terminaling and Marketing Company, LLC, (“TTMC”) which provides refined products terminaling and marketing services and owns a refined products terminal in Aberdeen, Mississippi;
	•		a subsidiary which owns the northern portion of the Dean Pipeline (“Dean North”); and
	•		our 50% equity investment in Centennial.

Properties and Operations

     Our Downstream Segment owns, operates or has investments in properties located in 15 states. The operations of the Downstream Segment consist of interstate transportation, storage and terminaling of refined products and LPGs; intrastate transportation of petrochemicals; distribution and marketing operations, including terminaling services and other ancillary services. Other activities are related to the intrastate transportation of petrochemicals under a throughput and deficiency contract.

     TE Products is one of the largest pipeline common carriers of refined products and LPGs in the United States. The Downstream Segment, primarily through TE Products, owns and operates an approximately 4,700-mile pipeline system (together with the receiving, storage and terminaling facilities mentioned below, the “Products Pipeline System”) extending from southeast Texas through the central and midwestern United States to the northeastern United States.

     As an interstate common carrier, we offer interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined products and LPGs who requests these services, provided that the conditions and specifications contained in the applicable tariff are satisfied. In addition to services for transportation of products, we also provide storage and other related services at key points along our Products Pipeline System. Substantially all of the refined products and LPGs transported and stored in our Products Pipeline System are owned by our customers. The products are received from refineries, connecting pipelines and bulk and marine terminals located principally on the southern end of the pipeline system. The U.S. Gulf Coast region is a significant supply source for our facilities and is a major hub for petroleum refining. The products are stored and scheduled into the pipeline in accordance with customer nominations and shipped to delivery terminals for ultimate delivery to the final distributor (including gas stations and retail propane distribution centers) or to other pipelines. Based on industry publications and data provided to us by customers, we believe refining capacity and product flow in the U.S. Gulf Coast region will continue to increase in the near term, which we expect will result in increased demand for transportation, storage and distribution facilities in that region. Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of refined products and LPGs.

     The Products Pipeline System includes 35 storage facilities with an aggregate storage capacity of 21 million barrels of refined products and 6 million barrels of LPGs, including leased storage capacity. The Products Pipeline System makes deliveries to customers at 63 locations including 20 truck racks, rail car facilities and marine facilities that we own. Deliveries to other pipelines occur at various facilities owned by TE Products or by third parties.

     TE Products owns one active marine receiving terminal at Providence, Rhode Island. This facility includes a 400,000-barrel refrigerated storage tank along with ship unloading and truck loading facilities. We operate the terminal and provide propane loading services to a customer. Our ability in the Downstream Segment to serve propane markets in the Northeast is enhanced by this terminal, which is not physically connected to the Products Pipeline System.

     Our Downstream Segment also includes the marketing of refined products through TTMC, which acquired a terminal in November 2006. The facility, located along the Tennessee-Tombigbee Waterway system in Aberdeen, Mississippi, has storage capacity of 130,000 barrels for gasoline and diesel, which are supplied by barge for delivery to local markets, including Tupelo and Columbus, Mississippi. We are constructing a new 500,000-barrel terminal in Boligee, Alabama, at a cost of approximately $24.0 million, on an 80-acre site which we are leasing from the Greene County Industrial Development Board under a 60-year agreement. The Boligee terminal site is located approximately two miles from Colonial Pipeline. The new terminal is expected to begin service during the second quarter of 2008.

     Our Downstream Segment also includes the operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene (“RGP”) from Mont Belvieu, Texas, to Point Comfort, Texas.

     The following table lists the material properties and investments of and ownership percentages in our Downstream Segment assets as of December 31, 2007:

		Our
		Ownership
Refined products and LPGs pipelines and terminals			100	%
Mont Belvieu, Texas, to Port Arthur, Texas, petrochemical pipelines			100	%
Northern portion of Dean Pipeline			100	%
Centennial (1)			50	%

     Refined products and LPGs deliveries in MMBbls for the years ended December 31, 2007, 2006 and 2005, were as follows:

		For Year Ended December 31,
		2007				2006				2005
Refined Products Deliveries: (1)
Gasoline			96.3				94.9				92.4
Jet Fuels			25.7				25.5				25.4
Distillates (2)			53.0				44.9				42.9
Subtotal			175.0				165.3				160.7
LPGs Deliveries:
Propane (3)			31.8				36.5				35.6
Butanes (includes isobutane)			10.1				8.5				9.4
Subtotal			41.9				45.0				45.0
Petrochemical Deliveries (4)			43.9				32.5				37.4
Total Product Deliveries			260.8				242.8				243.1
Centennial Product Deliveries			55.6				44.8				50.6

  Refined Products, LPGs and Petrochemical Pipeline Systems

     The Products Pipeline System is comprised of a 20-inch diameter line extending in a generally northeasterly direction from Baytown, Texas (located approximately 30 miles east of Houston), to a point in southwest Ohio near Lebanon, Ohio and our Todhunter facility near Middleton, Ohio. The Products Pipeline System continues eastward from our Todhunter facility to Greensburg, Pennsylvania, at which point it branches into two segments, one ending in Selkirk, New York (near Albany), and the other ending at Marcus Hook, Pennsylvania (near Philadelphia). The Products Pipeline System east of our Todhunter facility and ending in Selkirk is an 8-inch diameter line, and the line starting at Greensburg and ending at Marcus Hook varies in diameter from 6 inches to 8 inches. A second line, which also originates at Baytown, is 16 inches in diameter until it reaches Beaumont, Texas, at which point it reduces to a 14-inch diameter line. This second line extends along the same path as the 20-inch diameter line to the Products Pipeline System’s terminal in El Dorado, Arkansas, before continuing as a 16-inch diameter line to Seymour, Indiana.

     The Products Pipeline System also includes a 14-inch diameter line from Seymour to Chicago, Illinois, and a 10-inch diameter line running from Lebanon to Lima, Ohio. This 10-inch diameter pipeline connects to the

Buckeye Pipe Line Company system that serves, among others, markets in Michigan and eastern Ohio. The Products Pipeline System also has a 6-inch diameter pipeline connection to the Greater Cincinnati/Northern Kentucky International Airport.

     In addition, the Products Pipeline System contains numerous lines, ranging in size from 6 inches to 20 inches in diameter, associated with the gathering and distribution system, extending from Baytown to Beaumont; Texas City to Baytown; Pasadena, Texas, to Baytown; Mont Belvieu to Beaumont; and an 8-inch diameter pipeline connection to the George Bush Intercontinental Airport terminal in Houston.

     The Products Pipeline System also has various diameter lines that extend laterally from El Dorado to Helena, Arkansas, from Shreveport, Louisiana, to El Dorado and from McRae, Arkansas, to Memphis, Tennessee. The line from El Dorado to Helena has a 10-inch diameter. The line from Shreveport to El Dorado varies in diameter from 8 inches to 10 inches. The line from McRae to Memphis has a 12-inch diameter.

     TE Products also owns three parallel 12-inch diameter common carrier petrochemical pipelines between Mont Belvieu and Port Arthur. Each of these pipelines is approximately 70 miles in length. The pipelines transport ethylene, propylene, natural gasoline and naphtha. We entered into a 20-year agreement in 2002 with a major petrochemical producer for guaranteed throughput commitments on these three pipelines.

     Our Downstream Segment also includes the operations of the northern portion of the Dean Pipeline, which consists of 138 miles of pipeline transporting RGP from Mont Belvieu to Point Comfort.

     On July 31, 2007, we purchased an active 170,000 barrel LPG storage cavern, the associated piping and related equipment and a one bay truck rack from Duke Energy Ohio, Inc. and Ohio River Valley Propane, LLC for approximately $6.1 million. These assets are located adjacent to our Todhunter facility near Middleton, Ohio and are connected to our existing LPG pipeline.

     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 December 31, 2007, we have spent approximately $47.0 million on this construction project. By providing access to several major outbound refined product pipeline systems, shippers should have enhanced flexibility and new transportation options. 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.

  Centennial Pipeline Equity Investment

     TE Products owns a 50% ownership interest in Centennial and Marathon Petroleum Company LLC (“Marathon”) owns the remaining 50% interest. Centennial, which commenced operations in April 2002, owns an interstate refined products pipeline extending from the upper Texas Gulf Coast to central Illinois. Centennial constructed a 74-mile, 24-inch diameter pipeline connecting TE Products’ facility in Beaumont, Texas, with an existing 720-mile, 26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois. The Centennial pipeline intersects TE Products’ existing mainline pipeline near Creal Springs, Illinois, where Centennial

constructed a two million barrel refined products storage terminal. Marathon operates the mainline Centennial pipeline, and TE Products operates the Beaumont origination point and the Creal Springs terminal.

     Through December 31, 2007, including the amount paid for the acquisition of an additional ownership interest in February 2003, TE Products has invested $118.4 million in Centennial. TE Products has not received any distributions from Centennial since its formation.

Seasonality

     The mix of products delivered by our Downstream Segment varies seasonally. We generally realize higher revenues in the Downstream Segment during the first and fourth quarters of each year since LPG 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 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. Weather and economic conditions in the geographic areas served by our Products Pipeline System also affect the demand for, and the mix of, the products delivered.

Major Business Sector Markets and Related Factors

     Our Products Pipeline System transports refined products from the upper Texas Gulf Coast, eastern Texas and southern Arkansas to the Central and Midwest regions of the United States with deliveries in Texas, Louisiana, Arkansas, Missouri, Illinois, Kentucky, Indiana and Ohio. At these points, refined products are delivered to terminals owned by TE Products, connecting pipelines and customer-owned terminals.

     Our Products Pipeline System transports LPGs from the upper Texas Gulf Coast to the Central, Midwest and Northeast regions of the United States and is the only pipeline that transports LPGs from the upper Texas Gulf Coast to the Northeast. The Products Pipeline System east of our Todhunter facility near Middleton, Ohio, is devoted solely to the transportation of LPGs. Our Products Pipeline System also transports normal butane and isobutane in the Midwest and Northeast for use in the production of motor gasoline.

     TTMC conducts distribution and marketing operations whereby we provide terminaling services for our throughput and exchange partners at our Aberdeen terminal. We also purchase refined products from our throughput partners and we in turn establish a margin by selling refined products for physical delivery through spot sales at the Aberdeen truck rack to third-party wholesalers and retailers of refined products. These purchases and sales are generally contracted to occur on the same day.

     For further discussion of refined products and LPGs sensitivity to market conditions and other factors that may affect our Downstream Segment, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Overview of Business.”

Our major operations in the Downstream Segment consist of the transportation, storage and terminaling of refined products and LPGs along our system. Product deliveries, in MMBbls on a regional basis, for the years ended December 31, 2007, 2006 and 2005, were as follows:

		For Year Ended December 31,
		2007				2006				2005
Refined Products Deliveries:
Central (1)			84.3				74.6				73.3
Midwest (2)			66.6				66.6				60.1
Ohio and Kentucky			24.1				24.1				27.3
Subtotal			175.0				165.3				160.7
LPGs Deliveries:
Central, Midwest and Kentucky (1)(2)			22.1				28.5				26.3
Ohio and Northeast (3)			19.8				16.5				18.7
Subtotal			41.9				45.0				45.0
Petrochemical Deliveries (4)			43.9				32.5				37.4
Total Product Deliveries			260.8				242.8				243.1
Centennial Product Deliveries (5)			55.6				44.8				50.6

Customers

     Our customers for the transportation of refined products include major integrated oil companies, independent oil companies, the airline industry and wholesalers. End markets for these deliveries are primarily retail service stations, truck stops, railroads, agricultural enterprises, refineries and military and commercial jet fuel users. Propane customers include wholesalers and retailers who, in turn, sell to commercial, industrial, agricultural and residential heating customers, utilities who use propane as a back-up fuel source and petrochemical companies who use propane as a process feedstock. Refineries constitute our major customers for butane and isobutane, which are used as a blend stock for gasolines and as a feed stock for alkylation units, respectively. Our customers for the transportation of petrochemical feedstocks (natural gasoline and naphtha) and semi-finished chemical products (RGP, polymer grade propylene and ethylene) are primarily major chemical companies that consume these components in the production of plastics and a wide array of other commercial products. TTMC’s customers include major integrated oil companies and wholesale marketers. Our Downstream Segment depends in large part on the level of demand for refined products and LPGs in the geographic locations that we serve and the ability and willingness of customers having access to the pipeline system to supply this demand.

     At December 31, 2007, 2006 and 2005, our Downstream Segment had approximately 130, 125 and 155 customers, respectively. During the years ended December 31, 2007, 2006 and 2005, total revenues attributable to the top 10 customers (and percentage of total segment revenues) were $155.5 million (43%), $143.5 million (47%) and $151.6 million (53%), respectively. During the years ended December 31, 2007 and 2006, no single customer accounted for more than 10% of total Downstream Segment revenues. During the year ended December 31, 2005, Marathon accounted for approximately 14% of total Downstream Segment revenues. During each of the three years ended December 31, 2007, 2006 and 2005, no single customer of the Downstream Segment accounted for 10% or more of TEPPCO’s total consolidated revenues.

Competition

     The Downstream Segment faces competition from numerous sources. Because pipelines are generally the lowest cost method for intermediate and long-haul overland movement of refined products and LPGs, the Products

Pipeline System’s most significant competitors (other than indigenous production in its markets) are pipelines in the areas where the Products Pipeline System delivers products. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. We believe our Downstream Segment is competitive with other pipelines serving the same markets; however, comparison of different pipelines is difficult due to varying product mix and operations.

     Trucks, barges and railroads competitively deliver products in some of the areas served by the Products Pipeline System and TTMC. Trucking costs, however, render that mode of transportation less competitive for longer hauls or larger volumes. Pipeline systems inherently compete with barge transportation, especially at those locations that are in close proximity to major waterways. We face competition from rail and pipeline movements of LPGs from Canada and waterborne imports into terminals located along the upper East Coast. TTMC’s competition in the area is from refineries that require significant truck transportation to deliver their product in the area TTMC serves. TTMC is able to receive product by barge, which gives it a competitive advantage with respect to other terminaling and marketing businesses in the general area, which generally do not receive product by barge. Further, we view the acquisition of our marine transportation business as a complementary extension of the logistics services that we provide to our existing TTMC customers.

Upstream Segment – Gathering, Transportation, Marketing and Storage of Crude Oil

     We conduct business in our Upstream Segment through the following:

	•		TCTM, our holding company for the Upstream Segment;
	•		TEPPCO Crude Pipeline, LLC (“TCPL”), TEPPCO Crude Oil, LLC (“TCO”) and Lubrication Services, LLC (“LSI”), wholly owned subsidiaries of TCTM; and
	•		our 50% equity investment in Seaway.

Properties and Operations

     Our Upstream Segment gathers, transports, markets and stores crude oil, and distributes lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Our Upstream Segment uses its asset base to aggregate crude oil and provide transportation and related services to its customers. Our Upstream Segment purchases crude oil from various producers and operators at the wellhead and makes bulk purchases of crude oil on pipelines, terminal facilities and trading locations. The crude oil is purchased under contracts, the majority of which range in term from a thirty-day evergreen to one year. The crude oil is then sold to refiners and other customers. The Upstream Segment transports crude oil through proprietary gathering systems, common carrier pipelines, equity owned pipelines, trucking operations and third party pipelines. The Upstream Segment also exchanges various grades of crude oil and exchanges crude oil at different geographic locations, as appropriate, in order to maximize margins or meet contract delivery requirements. Certain of our crude oil pipeline assets are interstate common carriers, and as such we file tariffs with the FERC. Movement of product on these lines is available to any shipper who requests these services, provided that the conditions and specifications contained in the applicable tariff are satisfied.

     The areas served by our gathering and transportation operations are geographically diverse, and the forces that affect the supply of the products gathered and transported vary by region. Crude oil prices and production levels affect the supply of these products. The demand for gathering and transportation is affected by the demand for crude oil by refineries, refinery supply companies and similar customers in the regions served by this business, as well as by production levels in the regions served.

     TCO, a significant shipper on TCPL, purchases crude oil and establishes a margin by selling crude oil for physical delivery to third party users. These purchases and sales are generally contracted to occur in the same calendar month. We seek to maintain a balanced marketing position to minimize our exposure to price fluctuations occurring after the initial purchase. However, commodity price risks cannot be completely eliminated.

     Crude oil deliveries on our 100% owned pipeline systems, Basin and Seaway and deliveries of lubrication oils and specialty chemicals for the years ended December 31, 2007, 2006 and 2005, were as follows (in millions):

		For Year Ended December 31,
		2007				2006				2005
Barrels Delivered:
Crude oil transportation			96.5				91.5				94.7
Crude oil marketing			232.0				222.1				203.3
Crude oil terminaling			135.0				126.0				110.3
Lubricants and chemicals (total gallons)			15.3				14.4				14.8
Seaway Barrels Delivered:
Long-haul			49.4				88.4				99.7
Short-haul			229.5				223.4				213.9

  Properties

     The following table describes the major crude oil pipelines and pipeline systems and the ownership percentages in our Upstream Segment as of December 31, 2007:

Crude Oil		Our
Pipeline		Ownership				Operator		Description (1)
Red River System			100	%		TCPL		1,690 miles of small diameter pipeline; 1,491,000 barrels of storage – North Texas to South Oklahoma
South Texas System			100	%		TCPL		1,150 miles of small diameter pipeline; 1,106,000 barrels of storage – South Central Texas to Houston, Texas area
West Texas System			100	%		TCPL		360 miles of small diameter pipeline; 415,000 barrels of storage – connecting West Texas and Southeast New Mexico to TCPL’s Midland, Texas terminal
Other crude oil assets			100	%		TCPL		265 miles of small diameter pipeline; 295,000 barrels of storage – primarily in Texas and Oklahoma
Cushing Terminal			100	%		TCPL		17 tanks with 2,668,000 barrels of storage in Cushing, Oklahoma
Midland Station			100	%		TCPL		12 tanks with 980,000 barrels of storage in Midland, Texas
Seaway (2)		50% general partnership interest				TCPL		500-mile, 30-inch diameter pipeline – Texas Gulf Coast to Cushing, Oklahoma – 2,600,000 barrels of breakout tankage; 30-mile Texas City system – 1,800,000 barrels of storage tankage and 2,436,000 barrels of breakout tankage (3)
Basin		13% joint ownership				Plains All American Pipeline, L.P.		416-mile pipeline, 20 to 24 inches in diameter – Permian Basin (New Mexico and Texas) to Cushing, Oklahoma

     Most of the Red River System crude oil is delivered via third party pipelines to Cushing, Oklahoma or to two local refineries. The crude oil on the South Texas System is delivered to Houston area refineries and to Cushing. The West Texas System connects gathering systems to TCPL’s Midland, Texas, terminal.

     On September 27, 2007, we purchased approximately 44 miles of idle pipeline in South Texas and related equipment from Shell Pipeline Company LP for approximately $6.8 million.

     During the third quarter of 2007, three new crude oil storage tanks were placed into service at our Cushing, Oklahoma facility, representing a 900,000 barrel, or nearly 50%, increase in our storage capacity at that facility. The expansion, which is supported by long-term dedicated lease agreements, brings total capacity at the Cushing facility to 2.8 million barrels. In the third quarter of 2007, we completed a pipeline connection in our West Texas system to supply crude oil to a New Mexico refinery. This connection is supported by a long-term supply agreement.

  Seaway Crude Pipeline Equity Investment

     Seaway is a partnership between TEPPCO Seaway, L.P. (“TEPPCO Seaway”), a subsidiary of TCTM, and subsidiaries of ConocoPhillips. We operate and commercially manage the Seaway assets. Three large diameter lines carry imported crude oil from the Freeport, Texas, marine terminal on the U.S. Gulf Coast to the adjacent Jones Creek Tank Farm, which has six tanks capable of holding approximately 2.6 million barrels of crude oil. The 30-inch diameter, 500-mile pipeline transports crude oil from Freeport to Cushing, a central crude distribution point for the central United States and a delivery point for the New York Mercantile Exchange (“NYMEX”). Additionally, we completed a project in our South Texas system that allows Seaway to receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing.

     The Seaway crude oil marine terminal facility at Texas City, Texas, supplies refineries in the Houston area. Two pipelines connect the Texas City marine terminal to storage facilities in Texas City and Galena Park, Texas, where there are nine tanks with total capacity of approximately 4.2 million barrels. Seaway is able to provide marine terminaling and crude oil storage services for all Houston area refineries.

     The Seaway partnership agreement provides for varying participation ratios throughout the life of Seaway. From June 2002 through December 31, 2005, we received 60% of revenue and expense of Seaway. The sharing ratio changed from 60% to 40% on May 12, 2006, and as such, our share of revenue and expense of Seaway was 47% for 2006. Thereafter, we will receive 40% of revenue and expense (and distributions) of Seaway. During the years ended December 31, 2007, 2006 and 2005, we received distributions from Seaway of $12.4 million, $20.5 million and $24.7 million, respectively.

  Line Transfers, Pumpovers and Other

     Our Upstream Segment provides trade documentation services to its customers, primarily at Cushing and Midland. TCPL documents the transfer of crude oil in its terminal facilities between contracting buyers and sellers. This line transfer documentation service is related to the trading activity by TCPL’s customers of NYMEX crude oil contracts and other physical trading activity. This service provides a record of receipts, deliveries and transactions to each customer, including confirmation of trade matches, inventory management and scheduled movements.

     The line transfer services also attract physical barrels to TCPL’s facilities for final delivery to the ultimate owner. A pumpover occurs when the last title transfer is executed and the physical barrels are delivered out of TCPL’s custody. TCPL owns and operates storage facilities primarily in Midland and Cushing with a storage capacity of approximately 3.6 million barrels to facilitate the pumpover business.

     LSI distributes lubrication oils and specialty chemicals to natural gas pipelines, gas processors and industrial and commercial accounts. LSI’s distribution networks are located in Colorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas and Louisiana.

Customers

     Our customers for the sale, transportation and storage of crude oil include major integrated oil companies, independent refiners and marketers. LSI distributes lubrication oils and specialty chemicals to natural gas pipelines, gas processors and industrial and commercial accounts, with networks located in Colorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas and Louisiana.

     Gross sales revenue of the Upstream Segment attributable to the top 10 customers (and percentage of total segment gross sales revenue) was $8.1 billion (84%), $7.4 billion (75%) and $5.9 billion (73%) for the years ended December 31, 2007, 2006 and 2005, respectively. For the year ended December 31, 2007, Valero Energy Corp. (“Valero”), BP Oil Supply Company and Shell Trading Company accounted for 17%, 15% and 12%, respectively, of the Upstream Segment gross sales revenue. For the year ended December 31, 2006, Valero and BP Oil Supply Company accounted for 15% and 12%, respectively, of the Upstream Segment gross sales revenue. For the year ended December 31, 2005, Valero accounted for 15% of the Upstream Segment gross sales revenue.

     For the year ended December 31, 2007, Valero, BP Oil Supply Company and Shell Trading Company accounted for 16%, 14%, and 12%, respectively, of TEPPCO’s total consolidated revenues. For the year ended December 31, 2006, Valero and BP Oil Supply Company accounted for 14% and 11%, respectively, of TEPPCO’s total consolidated revenues. For the year ended December 31, 2005, Valero accounted for 14% of TEPPCO’s total consolidated revenues.

Competition

     The Upstream Segment faces competition from numerous sources. The most significant competitors in pipeline operations in our Upstream Segment are primarily common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where our pipeline systems receive and deliver crude oil. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service, knowledge of products and markets, and proximity to refineries and connecting pipelines. The crude oil gathering and marketing business can be characterized by thin margins and intense competition for supplies of crude oil at the wellhead.

Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs

     We conduct business in our Midstream Segment through the following:

	•		TEPPCO Midstream, our holding company for the Midstream Segment;
	•		our 80.64% equity investment in Jonah Gas Gathering Company, which gathers natural gas;
	•		Val Verde Gas Gathering Company, L.P., which gathers and treats natural gas for carbon dioxide removal;
	•		Chaparral Pipeline Company, LLC and Quanah Pipeline Company, LLC (collectively referred to as “Chaparral” or “Chaparral NGL system”), Panola Pipeline Company, LLC (“Panola Pipeline”), Dean Pipeline Company, LLC (“Dean Pipeline”) and Wilcox Pipeline Company, LLC (“Wilcox Pipeline”), which transport NGLs; and
	•		TEPPCO Colorado, LLC (“TEPPCO Colorado”), which fractionates NGLs.

Properties and Operations

     Our Midstream Segment gathers natural gas, transports NGLs and fractionates NGLs. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances and the purchase and sale of natural gas by Jonah to facilitate system operations and to provide a service to some of the producers on the system.

     Volume information for the years ended December 31, 2007, 2006 and 2005, is presented below:

		For Year Ended December 31,
		2007				2006				2005
Gathering – Natural Gas – Jonah (Bcf) (1)			587.4				473.9				415.2
Gathering – Natural Gas – Val Verde (Bcf)			175.7				181.9				180.7
Transportation – NGLs (MMBbls)			77.0				69.7				61.1
Fractionation – NGLs (MMBbls)			4.2				4.4				4.4

  Jonah Gas Gathering Joint Venture

     We entered the natural gas gathering business in late 2001 with our acquisition of the Jonah system in the Green River Basin in southwestern Wyoming. The majority of the growth in the Midstream Segment is due to our expansions of the Jonah system. Since the acquisition of Jonah in 2001, we have expanded the system in four phases, increasing system capacity from approximately 450 MMcf/d to approximately 1.5 Bcf per day, adding 130 miles of pipeline and 36,700 horsepower of compression at an aggregate cost of approximately $242.7 million. We are currently in the fifth phase of expanding the Jonah system.

     On August 1, 2006, Enterprise Products Partners, through its affiliate, Enterprise Gas Processing, LLC, became our joint venture partner by acquiring an interest in Jonah, the partnership through which we have owned our interest in the Jonah system. Previously, when Jonah was wholly-owned by us, operating results for Jonah were included in the consolidated Midstream Segment operating results. Effective with the formation of the joint venture on August 1, 2006, Jonah was deconsolidated, and we began using the equity method of accounting to account for our investment in Jonah.

     Enterprise Products Partners serves as operator of Jonah. The Jonah 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. The formation of the joint venture was reviewed and recommended for approval by the Audit, Conflicts and Governance Committee of the Board of Directors of our General Partner (“ACG Committee”).

     In February 2006, Enterprise Products Partners assumed the management of the Jonah Phase V expansion project and funded the initial costs of the expansion. Beginning with the August 1, 2006 formation of the Jonah joint venture, we reimbursed Enterprise Products Partners for 50% of the expansion costs it had previously advanced, and we and Enterprise Products Partners began sharing the costs of the expansion equally.

     In connection with the joint venture arrangement, we and Enterprise Products Partners are continuing the Phase V expansion, which is expected to increase the system capacity of the Jonah system 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 first portion of the expansion, which included a pipeline loop of 75 miles of 36-inch diameter pipe and 12 miles of 24-inch diameter pipe that was completed in December 2006, increased the system gathering capacity to approximately 2.0 Bcf per day and was completed in July 2007. The second and final portion of the expansion, expected to be completed during April 2008, will add approximately 102,000 horsepower of compression and is expected to increase the system gathering capacity to approximately 2.35 Bcf per day. The total anticipated cost of the Phase V expansion is expected to be approximately $505.0 million.

     From August 1, 2006 through July 2007, we and Enterprise Products Partners equally shared the costs of the Phase V expansion, and beginning in December 2006 with the completion of a portion of the expansion (discussed above), Enterprise Products Partners began sharing in the incremental cash flow and distributions 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 December 31, 2007, our ownership interest in Jonah was approximately 80.64%, and Enterprise Products Partners’ ownership interest in Jonah was approximately 19.36%. To the extent the Phase V expansion costs exceed an agreed upon base cost estimate of $415.2 million, we and Enterprise Products Partners will each pay our respective ownership share (approximately 80% and 20%, respectively). Our ownership interest in Jonah is currently anticipated to remain at 80.64%. During the year ended December 31, 2006, Jonah declared a distribution to us of $41.6 million, of which $30.0 million was paid in cash and the remainder was reflected as a receivable from Jonah. During the year ended December 31, 2007, we received distributions from Jonah of $100.0 million, which included $11.6 million of distributions declared in 2006 and paid during the first quarter of 2007.

     Jonah Gas Gathering System Business. The Jonah system serves the Jonah and Pinedale fields in Wyoming, which, according to the Energy Information Administration’s 2006 estimates, were among the top ten natural gas producing fields in the United States. The system delivers natural gas to pipelines and gas processing facilities owned by others. From the processing facilities, the natural gas is delivered into several interstate pipeline systems located in the region for transportation to end-use markets throughout the Midwest, the West Coast and the Rocky Mountain regions. Interstate pipelines in the region include Kern River, Northwest, Colorado Interstate Gas and Questar. Upon the expected completion of the Phase V expansion in April 2008, the Jonah system will consist of approximately 643 miles of pipelines ranging in size from three inches to 36 inches in diameter, five compressor stations with an aggregate of approximately 261,500 horsepower and related metering facilities. Gas gathered on the Jonah system is collected from approximately 1,476 producing wells in southwestern Wyoming’s Green River Basin.

     In addition to gathering natural gas, Jonah also purchases gas at the wellhead and sells gas and condensate. The Jonah system sells condensate liquid from the natural gas stream to TCO. The sales price is contractually based on a crude oil index price less a differential. In May 2006, we began to purchase gas at the wellhead on Jonah and re-sell the aggregated quantities at key Jonah delivery points in order to facilitate Jonah’s operations. The purchases and sales generally occur within the same month to minimize price risk.

     Jonah has fee based gathering agreements with fees that increase as field pressures decrease. Approximately 18 producers are connected to the system, of which seven have life-of-lease contracts that represented approximately 96% of the volumes of the system in 2007. Under these agreements, Jonah gathers and compresses the natural gas supplied to its gathering system and then redelivers the natural gas to gas processing facilities and interstate pipelines located in the region for a fixed fee. Jonah does not generally take title to the natural gas gathered with the exception of inventory imbalances and the purchase and sale of natural gas to facilitate system operations and to provide a service to some of the producers on the system. Other than the effects of normal operating pressure fluctuations, we can neither influence nor control the operation, development or production levels of the gas fields served by the Jonah system, which may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations.

  Val Verde Gas Gathering System

     The Val Verde system, which we have owned since 2002 and operated since mid-2005, consists of approximately 400 miles of pipeline ranging in size from four inches to 36 inches in diameter, 14 compressor stations operating over 75,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide. The gathering system is capable of gathering approximately one billion cubic feet of gas per day, and the current treating capacity of the Val Verde plant is approximately 550 million cubic feet of gas per day. Treating capacity is affected by the content of carbon dioxide in the gas stream and is more indicative of actual system capacity than the overall gathering capacity of the system. The Val Verde system delivers gas to two interstate pipeline systems serving the western United States, as well as local New Mexico markets.

     The Val Verde system gathers coal bed methane (“CBM”), convention natural gas and commingled natural gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system gathers natural gas from more than 500 separate wells throughout northern New Mexico and southern Colorado. Gathering and treating services are provided pursuant to long-term fixed-fee contracts with approximately 40 natural gas producers in the San Juan Basin. These contracts are generally long-term commitments, with evergreen clauses, the

majority of which escalate annually. Under these contracts, Val Verde gathers the natural gas supplied to its gathering systems, removes carbon dioxide to meet pipeline specifications and redelivers the natural gas for a fixed fee. Val Verde does not take title to the natural gas. CBM volumes gathered on the Val Verde system have begun to decline, primarily due to the natural decline of CBM production and the maturity of the field. Other than the effects of normal operating pressure fluctuations, we can neither influence nor control the operation, development or production levels of the gas fields served by the Val Verde system, which may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations.

     In December 2004, we completed a 16-mile project to connect Val Verde with a third party gathering system originating in Colorado and entered into a seven year agreement to transport and treat natural gas through this connection. Val Verde transported an average of 138 MMcf/d from this interconnection in 2007.

  NGL Transportation and Fractionation

     The NGL pipelines of the Midstream Segment are located along the Texas Gulf Coast, in East Texas and from southeastern New Mexico and West Texas to Mont Belvieu. They are all wholly owned and operated by our subsidiaries. Information about these NGL pipelines as of December 31, 2007, is set forth in the following table:

		Physical
		Capacity
NGL Pipeline		(barrels/day)				Description
Chaparral (1) (2)			135,000			845 miles of pipeline – West Texas and New Mexico to Mont Belvieu, Texas
Quanah (1)			30,000			180 miles of pipeline – Sutton County, Texas to the Chaparral Pipeline near Midland, Texas
Panola (3)			70,000			189 miles of pipeline – Carthage, Texas to Mont Belvieu, Texas
San Jacinto (3)			12,000			34 miles of pipeline – Carthage, Texas to Longview, Texas
The southern portion of the Dean Pipeline (4)			8,500			155 miles of pipeline – South Texas to Point Comfort, Texas

     TEPPCO Colorado has two NGL fractionation facilities which separate NGLs into individual components. TEPPCO Colorado is currently supported by a fractionation agreement with DCP Midstream Partners, L.P. (formerly Duke Energy Field Services, LLC) (“DCP”) through 2018, under which TEPPCO Colorado receives a variable fee, primarily a front-loaded fee determined by cumulative volumes fractionated during the contract year and delivered to DCP. Under an operation and maintenance agreement, DCP also operates and maintains the fractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado pays DCP a set volumetric rate for all fractionated volumes delivered to DCP.

Seasonality

     At Jonah, new well connections are subject to seasonal constraints as a result of winter range restrictions in the Pinedale field. Producers in the Pinedale field are prohibited from drilling activities typically during November through April due to wildlife restrictions, and we are accordingly limited in our ability to connect new wells to the system during that time.

Customers

     The Midstream Segment’s customers for natural gas gathering include major integrated oil and gas companies and large to medium-sized independent producers. Natural gas from Jonah and Val Verde is delivered into major interstate gas pipelines for delivery primarily to markets in the western and mid-continent areas of the United States. The Midstream Segment’s customers for transporting NGLs include affiliates of EPCO and other major integrated oil and gas companies.

     At December 31, 2007, the Midstream Segment had approximately 52 customers. Revenue attributable to the top 10 customers (and percentage of total segment revenues) was $105.8 million (87%) for the year ended December 31, 2007, of which ConocoPhillips (and its subsidiary, Burlington Resources Inc.), DCP and its affiliates, and Enterprise Products Partners and its affiliates accounted for approximately 22%, 20% and 11%, respectively. At December 31, 2006, the Midstream Segment had approximately 65 customers. Revenue attributable to the top 10 customers (and percentage of total segment revenues) was $163.4 million (79%) for the year ended December 31, 2006, of which EnCana Corporation, ConocoPhillips (and its subsidiary, Burlington Resources Inc.), DCP and its affiliates and BP Energy accounted for approximately 15%, 14%, 12% and 12%, respectively. At December 31, 2005, the Midstream Segment had approximately 70 customers. Revenue attributable to the top 10 customers (and percentage of total segment revenues) was $194.7 million (87%) for the year ended December 31, 2005, of which EnCana Corporation, DCP and its affiliates and ConocoPhillips (and its subsidiary, Burlington Resources Inc.) accounted for approximately 20%, 19% and 15%, respectively. During each of the three years ended December 31, 2007, 2006 and 2005, no single customer of the Midstream Segment accounted for 10% or more of TEPPCO’s total consolidated revenues.

Competition

     Competition in the natural gas gathering operations of our Midstream Segment is based largely on reputation, efficiency, system reliability, system capacity and price arrangements. Key competitors in the gathering and treating segment include independent gas gatherers as well as other major integrated energy companies. Alternate gathering facilities may be available to producers served by our Midstream Segment, and those producers could also elect to construct proprietary gas gathering systems. Success in the gas gathering and treating business segment is based primarily on a thorough understanding of the needs of the producers served, a strong commitment to providing responsive, high-quality customer service, as well as proximity to new drilling and development.

     The Midstream Segment’s NGL pipeline operations face competition from other competing pipelines. The most significant competition for the NGL pipeline operations of our Midstream Segment comes from pipelines owned and operated by major oil and gas companies and other large independent pipeline companies with facilities that are in or near our operational areas. The ability to compete in the NGL pipeline area is based primarily on competitive fees, the quality of customer service and knowledge of products and markets.

Marine Transportation Segment – Barge Transportation of Petroleum Products

     We conduct business in our Marine Transportation Segment through TEPPCO Marine Services, LLC (“TEPPCO Marine”), which transports refined products, crude oil, condensate and NGLs via tugboats, push boats and barges primarily on the United States inland waterway system and between domestic ports along the Gulf of Mexico Intracoastal Waterway and performs well-testing service activities and crude oil gathering for offshore production facilities and pipelines. We entered the marine transportation business on February 1, 2008 when we acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements from the Cenac Sellers for approximately $443.8 million, consisting of approximately $256.6 million in cash and approximately 4.85 million newly issued Units. Additionally, we assumed $63.2 million of Cenac’s long-term debt.

Concurrent with the acquisition, we entered into a transitional operating agreement providing for the sellers’ operation of the acquired business for a period of up to two years from the date of acquisition.

Properties and Operations

     The United States inland waterway system is a vast and extensively utilized transportation system, consisting of a network of interconnected rivers and canals that serve as water highways upon which vast quantities of products are transported annually. The inland waterway system includes approximately 12,000 miles of waterways that are generally considered navigable.

     The marine transportation industry uses push boats and tugboats as power sources and barges for freight capacity. The combination of the power source and barge freight capacity is called a tow. Our inland tows generally consist of one push boat and from one to four barges, depending upon the horsepower of the push boat, the trading territory, waterway conditions, customer requirements and prudent operations. Our offshore tows generally consist of one tugboat and one ocean-certified tank barge.

     The following is a summary description of the marine vessels we use in our marine transportation business:

				Capacity (bbl)/
Class of Equipment		Number in Class		Horsepower (hp)
Inland:
Barges		16		< 25,000 bbl
Barges		65		> 25,000 bbl
Push boats		18		< 2,000 hp
Push boats		17		> 2,000 hp
Offshore:
Barges		8		> 20,000 bbl
Tug boats		4		< 2,000 hp
Tug boats		3		> 2,000 hp

     The commercial and other agreements constituting part of the marine transportation business require consents of third parties to assign the agreements to TEPPCO Marine, which TEPPCO Marine and Cenac began seeking promptly after the closing of the acquisition. Under the purchase agreement, TEPPCO Marine is entitled to Cenac’s economic benefit of these unassigned agreements, and Cenac continues to be obligated to use reasonable efforts to obtain those consents.

     Most of our marine transportation revenue is expected to be derived from term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from designated origins to designated destinations at set day rates. Most of the term contracts we are acquiring from Cenac have one-year terms with the remainder having terms of up to two years. All of the existing contracts have renewal options, which are exercisable subject to agreement on rates applicable to the option terms. We do not assume ownership of the products we transport in this segment. As is typical for inland liquid affreightment contracts, the term contracts we are acquiring establish firm 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 and equipment retrofits required by emerging government regulation. The costs of fuel and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts.

     Our marine transportation business is subject to regulation by the U.S. Department of Transportation, Department of Homeland Security, Commerce Department and the U.S. Coast Guard (“USCG”) and federal and state laws. Substantially all of our inland barges are inspected by the USCG and carry certificates of inspection. Our inland and offshore towing vessels are not currently subject to USCG inspection requirements; however, regulations are currently proposed that would subject inland and offshore towing vessels to USCG inspection requirements. Most of our offshore towing vessels and barges are built in compliance with American Bureau of Shipping (“ABS”) Load Line standards and are inspected periodically by ABS to maintain this standard. The crews employed by Cenac aboard vessels, including captains, pilots, engineers, tankermen, deckhands and ordinary

seamen, are all licensed by the USCG with the exception of engineers and deckhands on inland vessels. We or Cenac, as operator, are required by various governmental agencies to obtain licenses, certificates and permits for our vessels depending upon such factors as the cargo transported, the waters in which the vessels operate and other factors.

     Cenac belongs to the American Waterways Operators (“AWO”) Responsible Carrier Program (“RCP”). The program provides a framework of safety standards and best practices designed to continuously enhance member companies’ safety and efficiency in the operation of inland marine vessels. The program complements and builds upon existing government regulations, requiring company safety and training standards that in many instances exceed those required by federal law or regulation. Many of Cenac’s contracts contain provisions regarding AWO membership and RCP compliance. The Responsible Carriers Program has been recognized by many groups, including the USCG and shipper organizations. Cenac is periodically audited by an AWO-certified auditor to verify compliance.

     We are a named insured with respect to our marine transportation assets on the policies of Cenac for an interim period, and are obligated under the transitional operating agreement to replace this coverage with a comparable program by June 30, 2008. Limited hull coverage is provided by the existing Cenac insurance policies.

Vessel Management, Crewing and Employees

     In connection with our entry in the marine transportation business, we entered into a transitional operating agreement with Cenac for a period of up two years from the date of acquisition under which the sellers will operate our Marine Transportation Segment with their marine and shore-based support employees. Cenac maintains an experienced work force of marine and shore-based personnel. As of February 15, 2008, approximately 355 of Cenac’s employees provided services to TEPPCO Marine under the transitional operating agreement. Cenac’s tow and barge captains are non-union management supervisors. Its marine employees are paid on a daily basis, and the majority work 14 days on and 7 days off. Cenac’s shore-based personnel are generally salaried and most are located at its headquarters in Houma, Louisiana. We reimburse Cenac for the salaries and other benefits of the employees providing services to us under the transitional operating agreement.

     Cenac’s shore staff provides support for all aspects of our fleet and business operations, including sales and scheduling, crewing and human resources functions, engineering, compliance and technical management, financial and insurance services, and information technology. A staff of dispatchers and schedulers maintain a 24-hour duty rotation to monitor communications and to coordinate fleet operations with our customers and terminals. Communication with our vessels is accomplished by various methods, including wireless data links, cellular telephone, VHF and radio and satellite telephone.

     Under the transitional operating agreement, Cenac is responsible for maintaining our vessels in seaworthy and good working condition and operating our vessels in accordance with applicable laws and prudent industry practices. Cenac’s trained crews regularly inspect each vessel, both at sea and in port, and perform all routine preventive maintenance. Shore-based staff conduct quarterly inspections regarding overall condition, maintenance, safety and crew welfare, and selected vessels are inspected annually by third party consultants.

Seasonality

     We expect that overall increased demand for refined products such as motor fuels during the spring and summer driving seasons will result in increased demand for our marine transportation services during those seasons.

Customers

     Our largest marine transportation customers include major and independent oil companies, crude oil producers, traders and refiners. We provide towing services primarily for major oil companies in the refining industry in the states along the Gulf coast.

Competition

     We expect that our marine transportation business will compete with inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. While competition within the marine transportation business is based largely on price, we believe that the decline in the past two decades in the number of inland barges operating in the inland U.S. waterways, consolidation in the marine transportation industry and barriers to entry in the industry, such as cost and ability to obtain licensed and qualified personnel, have resulted in a favorable pricing environment for our marine transportation business. We also believe that our ability to offer alternative means of transportation, for example, via our Products Pipeline System, will position us well to compete against pipelines and marine transportation companies that service the areas in which our marine transportation business operates. We believe we can offer a competitive advantage over rail tank cars and tractor-trailer tank trucks because, by volume, marine transportation is a substantially more efficient, and generally less expensive, mode of transporting petroleum products and by-products. For example, one of our typical two inland barge unit tows carry a volume of product equal to approximately 69 rail cars or 278 tanker trucks.

Title to Properties

     We believe we have satisfactory title to all of our assets. The properties are subject to liabilities in certain cases, such as contractual interests associated with acquisition of the properties, liens for taxes not yet due, easements, restrictions and other minor encumbrances. We believe none of these liabilities materially affect the value of our properties or our interest in the properties or will materially interfere with their use in the operation of our business.

Capital Expenditures

     Capital expenditures, excluding acquisitions and contributions to joint ventures, totaled $228.2 million for the year ended December 31, 2007. Revenue generating projects include those projects which expand service into new markets or expand capacity into current markets. Capital expenditures to sustain existing operations include projects required by regulatory agencies or required life-cycle replacements. System upgrade projects improve operational efficiencies or reduce cost. We capitalize interest costs incurred during the period that construction is in progress. The following table identifies capital expenditures by segment for the year ended December 31, 2007 (in millions):

						Sustaining
		Revenue				Existing				System				Capitalized
		Generating				Operations				Upgrades				Interest				Total
Downstream Segment		$	125.9			$	27.5			$	6.8			$	5.2			$	165.4
Midstream Segment			2.3				4.5				0.6				—				7.4
Upstream Segment			32.9				19.1				0.7				1.7				54.4
Other			—				1.0				—				—				1.0
Total		$	161.1			$	52.1			$	8.1			$	6.9			$	228.2

     Revenue generating capital spending by the Downstream Segment totaled $125.9 million and was used primarily for the construction of a new refined products storage facility to support the expansion of Motiva’s refinery in Port Arthur, Texas, construction of a new terminal in Boligee, Alabama, the continued integration of assets from an acquisition in 2005 and expansion of delivery capability into Memphis, Tennessee. Revenue generating capital spending by the Midstream Segment totaled $2.3 million and was used primarily to increase capacity of the Panola Pipeline. Revenue generating capital spending by the Upstream Segment totaled $32.9 million and was used primarily for the expansion of our facilities and pipeline connections in West Texas and Cushing, Oklahoma. In order to sustain existing operations, we spent $27.5 million for various Downstream Segment pipeline projects, $4.5 million for the Midstream Segment and $19.1 million for Upstream Segment facilities. An additional $8.1 million was spent on system upgrade projects among all of our business segments.

     We estimate that capital expenditures, excluding acquisitions and joint venture contributions, for 2008 will be approximately $403.0 million (including $13.0 million of capitalized interest). We expect to spend

approximately $321.0 million for revenue generating projects, which includes $153.0 million for our expected spending on the Motiva project. We expect to spend approximately $57.0 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 $124.0 million (including $3.0 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.

Regulation

FERC

     Certain of our crude oil, petroleum products and natural gas liquids pipeline systems (“liquids pipelines”) are interstate common carrier pipelines subject to rate regulation by the FERC, under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (“Energy Policy Act”). The ICA prescribes that interstate tariffs must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations require that interstate oil pipeline transportation rates be filed with the FERC and posted publicly.

     The ICA permits interested persons to challenge proposed new or changed rates and authorizes the FERC to investigate such rates and to suspend their effectiveness for a period of up to seven months. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it may require the carrier to refund the revenues in excess of the prior tariff during the term of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of its complaint.

     On October 24, 1992, Congress passed the Energy Policy Act. The Energy Policy Act deemed just and reasonable under the ICA (i.e., “grandfathered”) liquids pipeline rates that were in effect for the twelve months preceding enactment and that had not been subject to complaint, protest or investigation. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party must show that it was previously contractually barred from challenging the rates, or that the economic circumstances of the liquids pipeline that were a basis for the rate or the nature of the service underlying the rate had substantially changed or that the rate is unduly discriminatory or preferential. Some but not all of our interstate liquids pipeline rates are considered grandfathered under the Energy Policy Act. There is currently pending before the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) a challenge to the FERC’s standards for assessing when such a substantial change has occurred. We cannot at this time predict what effect, if any, the decision in that case will have on the ability of parties to challenge grandfathered rates.

     Certain other rates for our interstate liquids pipeline services are charged pursuant to a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the change from year to year in the Producer Price Index for finished goods (“PPI”). A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s costs. Effective March 21, 2006, FERC issued its final order concluding its second five-year review of the oil pipeline pricing index. FERC concluded that for the five-year period commencing July 1, 2006, liquids pipelines charging indexed rates may adjust their indexed ceilings annually by the PPI plus 1.3 percent (“PPI Index”). At the end of that five year period, in July 2011, the FERC will once again review the PPI Index to determine whether it continues to measure adequately the cost changes in the oil pipeline industry.

     As an alternative to using the PPI Index, interstate liquids pipelines may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements with all of the pipeline’s shippers that the rate is acceptable. TE Products has been granted permission by the FERC to utilize Market-Based Rates for all of its refined products movements other than the Little Rock, Arkansas, Arcadia and Shreveport-Arcadia, Louisiana destination markets, which are currently subject to the PPI Index. As with all rates for service on an oil pipeline subject to FERC regulation under the ICA, TE Products must file its market-based rates with FERC and charge those rates on a non-discriminatory basis, such that the same Market-Based Rate shall be charged to similarly situated shippers. With respect to LPG movements, TE Products uses the PPI Index. All interstate transportation movements of crude oil by TCPL are subject to the PPI Index as are the NGL interstate transportation movements on the Chaparral NGL system.

     Because of the complexity of ratemaking, the lawfulness of any rate is never assured. The FERC uses prescribed rate methodologies for approving regulated tariff rates for transporting crude oil and refined products. 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 rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow. Challenges to our tariff rates could be filed with the FERC. We believe the transportation rates currently charged by our interstate common carrier pipelines are in accordance with the ICA. However, we cannot predict the rates we will be allowed to charge in the future for transportation services by our interstate liquids pipelines.

     In that regard, one element of the FERC’s cost-of-service methodology as it affects partnerships such as us remains under review. In a case involving Lakehead Pipe Line Company, L.P., a partnership that operates a crude oil pipeline, the FERC concluded in its Opinion No. 397 that Lakehead was entitled to include in calculating its rates an income tax allowance only with respect to the portion of its earnings that are attributable to its partners that are not individuals, rationalizing that income attributable to individuals would be subject to only one level of taxation. The parties subsequently settled the case, so there was no judicial review of the FERC’s decision. The FERC subsequently applied this approach in proceedings involving SFPP, L.P., which is a subsidiary of a publicly traded limited partnership engaged in the transportation of petroleum products. In the first SFPP proceeding, Opinion No. 435, the FERC (among other things) affirmed Opinion No. 397’s determination that there should not be an income tax allowance built into a petroleum pipeline’s rates for income attributable to non-corporate partners.

     Following several FERC orders on rehearing, the matter was appealed to the D.C. Circuit. The court found the Lakehead policy to lack a reasonable basis and vacated the portion of the FERC’s rulings that permitted SFPP an income tax allowance in accordance with that policy. The court remanded the issue to the FERC for further consideration, and the FERC thereafter initiated a broader inquiry into the implications of the court’s decision on other FERC-regulated companies. That was followed by the issuance of the FERC’s “Policy Statement on Income Tax Allowances” (“Policy Statement”) on May 4, 2005, which addressed the circumstances in which a partnership or other pass-through entity would be permitted to include a tax allowance in its cost of service. On December 16, 2005, the FERC issued its “Order on Initial Decision and on Certain Remanded Cost Issues” in various dockets involving SFPP (the “SFPP Order”). Among other things, the SFPP Order applied the Policy Statement to the specific facts of the SFPP case, suggesting how the FERC will treat other Master Limited Partnership (“MLP”) petroleum pipelines. The SFPP Order confirmed that an MLP is entitled to a tax allowance with respect to partnership income for which there is an “actual or potential income tax liability” and determined that a unitholder that is required to file a Form 1040 or Form 1120 tax return that includes partnership income or loss is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. The FERC also established certain other presumptions, including that corporate unitholders are presumed to be taxed at the maximum corporate tax rate of 35% while individual unitholders (and certain other types of unitholders taxed like individuals) are presumed to be taxed at a 28% tax rate.

     Both the SFPP Order and the Policy Statement were appealed to the D.C. Circuit, in a case that was argued before the court on December 12, 2006. The matter is currently awaiting a decision.

     The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that affect the rates we charge and terms and conditions of that service. Although state regulation typically is less onerous than FERC regulation, proposed and existing rates subject to state regulation and the provision of non-discriminatory service are subject to challenge by complaint.

     The Val Verde and Jonah natural gas gathering systems are exempt from FERC regulation under the Natural Gas Act of 1938 since they are intrastate gas gathering systems rather than interstate transmission pipelines. However, FERC regulation still significantly affects the Midstream Segment, directly or indirectly, by its influences on the parties that produce the natural gas gathered on the Val Verde and Jonah systems as well as the parties that transport that natural gas. In addition, in recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue the pro-competition policies as it considers pipeline rate case proposals, revisions to rules and policies that affect shipper rights of access to interstate natural gas transportation capacity or proposals by natural gas pipelines to allow natural gas pipelines to charge negotiated rates without rate ceiling limits, such policy changes could have an adverse effect on the gathering rates the Midstream Segment is able to charge in the future.

Environmental and Safety 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, 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.

     The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in material compliance with all these environmental and safety 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.

Water

     The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (“CWA”), and comparable state laws impose strict controls against the discharge of oil and its derivatives into navigable waters. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in navigable waters or into groundwater. Spill prevention control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting navigable waters. The Environmental Protection Agency (“EPA”) has adopted regulations that require us to have permits in order to discharge certain storm water run-off. Storm water discharge permits may also be required by certain states in which we operate. These permits may require us to monitor and sample the storm water run-off. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. We believe that our costs of compliance with these CWA requirements will not have a material adverse effect on our operations.

     The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution — prevention, containment and cleanup, and liability. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety (“OPS”) or the EPA, as appropriate. Numerous states have enacted laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resource damages. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.

     Contamination resulting from spills or releases of petroleum products is an inherent risk within the petroleum pipeline industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operations, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, but such costs are site specific, and we cannot be assured that the effect will not be material in the aggregate.

Air Emissions

     Our operations are subject to the Federal Clean Air Act (the “Clean Air Act”) and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.

     Our permits and related compliance under the Clean Air Act, as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas, may require our operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some of our facilities are included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the Clean Air Act. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than any other similarly situated company.

     The U.S. Congress is actively considering legislation to reduce emissions of “greenhouse gases,” including carbon dioxide and methane. In addition, at least 14 states have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation addressing emissions of greenhouse gases. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our operations or financial condition.

Risk Management Plans

     We are subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain locations. This regulation is intended to work with the Occupational Safety and Health Act (“OSHA”) Process Safety Management regulation (see “Safety Matters” below) to minimize the offsite consequences of catastrophic releases. The regulation required us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program. We are operating in compliance with our risk management program.

Solid Waste

     We generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. We also utilize waste minimization and recycling processes to reduce the volumes of our waste. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the wastes meet certain treatment standards or the land-disposal method meets certain waste containment criteria.

Environmental Remediation

     The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a facility. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, our pipeline systems generate wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by us requires clean up in the future, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.

     At December 31, 2007, we have an accrued liability of $4.0 million related to sites requiring environmental remediation activities. A discussion of legal proceedings that relate to environmental remediation is included elsewhere in this Report under the caption Item 3. Legal Proceedings.

Maritime Law

     The operation of tow boats, barges and marine equipment create maritime obligations involving property, personnel and cargo under the General Maritime Law. These obligations can create risks which are varied and include, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities. Routine towage operations can also create risk of personal injury under the Jones Act and General Maritime Law, cargo claims involving the quality of a product and delivery, terminal claims, contractual claims and regulatory issues.

Jones Act

     The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. As a result of the marine transportation business acquisition on February 1, 2008, we now engage in maritime transportation between locations in the United States, and as such, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiary that engages in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flag vessels be manned by United States citizens. Foreign-flag seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flag vessel operations compared to foreign-flag vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flag vessel owners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flag operators than for owners of vessels registered under foreign flags of convenience. Following Hurricane Katrina, and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United States government. The last suspension

ended on October 24, 2005. Future suspensions of the Jones Act or other similar actions could adversely affect our cash flow and ability to make distributions to our unitholders. The Jones Act also provides a remedy in damages for crew members injured in the course and scope of their employment. In certain circumstances, a Jones Act seaman can have dual employers under the borrowed servant doctrine.

Merchant Marine Act of 1936

     The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the president of the United States of a national emergency or a threat to the national security, the United States secretary of transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (including us, provided that we are considered a United States citizen for this purpose). If one of our towboats or barges were purchased or requisitioned by the United States government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our towboats is requisitioned or purchased and its associated barge or barges are left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barges. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our towboats or barges.

DOT Pipeline Compliance Matters

     We are subject to regulation by the United States Department of Transportation (“DOT”) under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. The HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the Secretary of Transportation. We believe that we are in material compliance with these HLPSA regulations.

     We are subject to the DOT regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks. We believe that we are in material compliance with these DOT regulations.

     We are also subject to the DOT Integrity Management regulations, which specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCA”). HCA are defined as populated areas, unusually sensitive environmental areas and commercially navigable waterways. The regulation requires the development and implementation of an Integrity Management Program (“IMP”) that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. The regulation also requires periodic review of HCA pipeline segments to ensure adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised by the assessment and analysis. In compliance with these DOT regulations, we identified our HCA pipeline segments and have developed an IMP. We believe that the established IMP meets the requirements of these DOT regulations.

Safety Matters

     We are also subject to the requirements of the federal OSHA and comparable state statutes. We believe we are in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.

     The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request. We are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the

consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves certain flammable liquid or gas. We believe we are in material compliance with the OSHA regulations.

Employees

     We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the ASA or by other service providers. For additional information regarding the ASA, please see “Relationship with EPCO” under Item 13 of this Annual Report. As of December 31, 2007, there were approximately 2,300 EPCO personnel that spend all or a portion of their time engaged in our business. Approximately 1,000 of these individuals devote all of their time performing management and operating duties for us. We reimburse EPCO for 100% of the costs it incurs to employee these individuals. The remaining approximate 1,300 personnel are part of EPCO’s shared service organization and spend all or a portion of their time engaged in our business. The cost for their services is reimbursed to EPCO under the ASA and is generally based on the percentage of time such employees perform services on our behalf during the year. For additional information regarding our relationship with EPCO, please read Item 13 of this Report.

Available Information

     As a large accelerated filer, we electronically file certain documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. From time to time, we may also file registration statements and related documents in connection with equity or debt offerings. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports and other information regarding issuers that file electronically with the SEC, including us.

     We provide electronic access to our periodic and current reports on our Internet website (http://www.teppco.com). These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC. You may also contact our Investor Relations Department at (800) 659-0059 for paper copies of these reports free of charge.

Item 1A. Risk Factors

     There are many factors that may affect us and our joint ventures. Security holders and potential investors in our securities should carefully consider the risk factors set forth below, as well as the discussion of other factors that could affect us or our joint ventures included elsewhere in this Report, including under the captions “Cautionary Note Regarding Forward-Looking Statements,” “Items 1 and 2. Business and Properties,” “Item 3. Legal Proceedings,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.” If one or more of these risks were to materialize, our business, financial position or results of operations could be materially and adversely affected. We are identifying 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.

Risks Relating to Our Business

Potential future acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

     As part of our business strategy, we continually evaluate and acquire assets and businesses and undertake expansions that we believe complement our existing assets and businesses. Acquisitions and expansions may

require substantial capital or the incurrence of substantial indebtedness. Consummation of future acquisitions and expansions may significantly change our capitalization and results of operations. Our growth may be limited if acquisitions or expansions are not made on economically favorable terms.

     Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets, personnel and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we may have no recourse or limited recourse under applicable indemnification provisions.

Our marine transportation acquisition may not achieve anticipated results.

     We do not have a depth of experience in the marine transportation business and will initially depend on Cenac and its personnel to continue to operate the marine vessels we acquired for up to two years under a transitional operating agreement entered into in connection with the acquisition. The success of this business is largely dependent on maintaining adequate, licensed crew for our towboats. If the services of Cenac key personnel become limited or unavailable, or if Cenac fails to operate the vessels at the levels we expect, we may lose customers, experience delays or problems with maintaining the vessels or their cargo or other resultant material adverse effects on our business, financial condition and results of operations. Further, we may not be able to locate or engage qualified replacement personnel on acceptable terms and can give no assurance that we will be able to adequately staff our vessels upon expiration or termination of the transitional operating agreement. Recently, high United States employment, coupled with Hurricanes Katrina and Rita that displaced labor and created reconstruction job opportunities in the oil service and construction industries along the Gulf Coast, made for a tight Gulf Coast labor market, resulting in personnel shortages in the marine transportation industry.

     Integrating the operations of our marine transportation acquisition with our other operations will present challenges to our management, including:

	•		managing relationships with customers in a new line of business;
	•		potential loss of key employees, customers or suppliers;
	•		assessing the internal controls and procedures for the acquired operations that we are required to maintain under the Sarbanes-Oxley Act of 2002; and
	•		consolidating other partnership and administrative functions.

Failure to timely and successfully integrate our marine transportation business may have a material adverse effect on our business, financial condition and results of operations.

     While we do not control Cenac, we will have liability to third parties for its actions in operating our vessels, including negligence, during the period in which the transitional operating agreement is in effect. We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, the anticipated benefits of the acquisition may not be realized.

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

     As of February 1, 2008, after giving effect to borrowings under the term credit agreement to retire or redeem the TE Products Senior Notes and to fund a portion of our marine transportation business acquisition, we had approximately $2.2 billion of consolidated debt outstanding, consisting of $520.0 million of borrowings under our revolving credit facility, $715.0 million of borrowings under our term credit agreement, $700.0 million principal amount of Senior Notes and $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 and term credit agreement contain 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 (see Note 13 in the Notes to Consolidated Financial Statements for a discussion of Available Cash), incur certain liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets. These credit agreements also prevent 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 and term credit agreement, to terminate all commitments to extend further credit. Although our revolving credit facility and term credit agreement restrict 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 us being required to post financial collateral under our guaranty of indebtedness of Centennial and/or some of the contracts that we use in connection with our commodity and interest rate hedging transactions.

Our cash distributions may vary based on our operating performance and level of cash reserves.

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

	•		the volume of products that we handle and the prices we receive for our services;
	•		the level of our operating costs;
	•		the level of competition in our business segments;
	•		prevailing economic conditions;
	•		the level of capital expenditures we make;
	•		the restrictions contained in our debt agreements and debt service requirements;
	•		fluctuations in our working capital needs;
	•		the cost of acquisitions, if any; and
	•		the amount, if any, of cash reserves established by our General Partner in its discretion.

     In addition, our ability to pay the minimum quarterly distribution each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make distributions during periods when we record net income.

The interruption of distributions to us from our subsidiaries and joint ventures may affect our ability to satisfy our obligations and to make distributions to our partners.

     We are a holding company with no material operations. Our only significant assets are the equity interests we own in our subsidiaries and joint ventures. As a result, we depend upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of their cash to us in order to meet our financial obligations and to allow us to make distributions to our partners. In addition, charter documents and other agreements governing our joint ventures may restrict or limit the occurrence and amount of distributions to us under certain circumstances, including by giving authority to establish available cash for distribution to management committees or other governing bodies that we do not control.

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

     We engage in several construction and expansion projects involving existing and new facilities that require significant capital expenditures, which may exceed our estimates. We intend to continue to expand the capacity of our existing natural gas gathering systems through the construction of additional facilities. Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities or enter into arrangements such as the Jonah joint venture for the expansion of facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize for a variety of reasons, including because the related reserves are materially lower than we anticipate. As a result, there is the risk that new or expanded facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our financial position or results of operations. Additionally, operating cash flow from a particular project may not be realized until a period of time after its completion or at expected levels. Construction and expansion projects may occur over an extended period of time. If we experience unanticipated or extended delays in generating operating cash flow from these projects, we may be required to reduce or reprioritize our capital budget, sell non-core assets, access the capital markets or decrease or limit distributions to unitholders in order to meet our capital requirements.

Our tariff rates are subject to review and possible adjustment by federal and state regulators, which could have a material adverse effect on our financial condition and results of operations.

     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 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 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 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.

Our partnership status may be a disadvantage to us in calculating our cost of service for rate-making purposes.

     In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. In August 2005, FERC dismissed requests for rehearing of its new policy statement. On December 16, 2005, FERC issued its first significant case-specific review of the income tax allowance issue in another pipeline partnership’s rate case. FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16, 2005 order were appealed to the United States Court of Appeals for the District of Columbia Circuit. The D.C. Circuit issued an order on May 29, 2007 in which it denied these appeals and fully upheld FERC’s new tax allowance policy and the application of that policy in the December 16 order.

     On December 8, 2006, FERC issued a new order addressing rates on another pipeline. In the new order, FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline asked FERC to reconsider this ruling, and the matter remains pending.

     On December 26, 2007, FERC issued another order refining its income tax policy for pipeline partnerships. The order generally reaffirmed that the pipeline partnership at issue is entitled to an income tax allowance. Without referencing the December 8, 2006 order, FERC rejected any proposed adjustments to the allowance or to the equity rate of return to account for any timing differences between when an income tax allowance is recovered in rates and when partners are liable for income tax payments. Shippers have asked FERC to reconsider this ruling, and the matter remains pending.

     The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service.  Currently, none of our tariffs are calculated using cost of service rate methodologies. If, however, in the future our tariffs are calculated using a cost of service rate methodology and the policy statement on income tax allowances is modified on judicial review, our revenues might be adversely affected.

Competition could adversely affect our operating results.

     Our refined products and LPG transportation business and our marine transportation business compete with other pipelines and barge businesses in the areas where we deliver products. We also compete with trucks and railroads in some of the areas we serve. Competitive pressures may adversely affect our tariff rates or volumes shipped or transported. The crude oil gathering and marketing business can be characterized by thin margins and intense competition for supplies of crude oil at the wellhead. A decline in domestic crude oil production has intensified competition among gatherers and marketers. Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where our pipeline systems deliver crude oil and NGLs.

     In our natural gas gathering business, new supplies of natural gas are necessary to offset natural declines in production from wells connected to our gathering systems and to increase throughput volume, and we encounter competition in obtaining contracts to gather natural gas supplies. Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and price arrangements. Our key competitors in the gas gathering segment include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems. If the production delivered to our gathering system declines, our revenues from such operations will decline.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

     Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to fully eliminate customer credit risk. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees. However, these procedures and policies do not fully eliminate customer credit risk.

     Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. For the years ended December 31, 2007, 2006 and 2005, Valero accounted for 16%, 14% and 14%, respectively, of our total consolidated revenues, and for the years ended December 31, 2007 and 2006, BP Oil Supply Company accounted for 14% and 11%, respectively, of our total consolidated revenues. Additionally, for the year ended December 31, 2007, Shell Trading Company accounted for 12% of our total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2007, 2006 and 2005.

Our risk management policies cannot eliminate all commodity price risks. In addition, any non-compliance with our risk management policies could result in significant financial losses.

     To enhance utilization of certain assets and our operating income, we purchase petroleum products. Generally, it is our policy to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to establish a margin for the commodity purchased by selling the same commodity for physical delivery to third party users, such as producers, wholesalers, independent refiners, marketing companies or major oil companies. These policies and practices cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including price risks on product inventory, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity on our pipelines. In addition, our marketing operations involve the risk of non-compliance with our risk management policies. We cannot assure you that our processes and procedures will detect

and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved.

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

     Decreased throughput on interconnected pipelines due to testing, line repair and reduced pressures could result in reduced throughput on our pipeline systems. Such reduced throughput may adversely impact our profitability.

Reduced demand could affect our pipeline shipments and marine transportation business.

     Our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, technological advances in fuel economy and energy-generation devices, exploration and production activities, and actions by foreign nations, any of which could reduce the demand for the petroleum products in the areas we serve. For example:

	•		Demand for gasoline, which has in recent years accounted for approximately 55% of our refined products transportation revenues and which we expect will account for a significant portion of transportation revenues in our marine transportation business, depends upon price, prevailing economic conditions and demographic changes in the markets we serve.
	•		Weather conditions, government policy and crop prices affect the demand for refined products used in agricultural operations.
	•		Demand for jet fuel, which has in recent years accounted for approximately 15% of our refined products revenues, depends on prevailing economic conditions and military usage.
	•		Propane deliveries are generally sensitive to the weather and meaningful year-to-year variances have occurred and will likely continue to occur.

The success of our Jonah gas gathering operations is substantially dependent upon Enterprise Products Partners.

     We own our interest in the Jonah system, which represents a significant component of our Midstream Segment and its potential for future growth, through a joint venture with Enterprise Products Partners, which is under the common control of Enterprise GP Holdings with us and which is a significant customer of our Midstream Segment (see “– Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs”). The joint venture is governed by a management committee comprised of two representatives approved by an Enterprise Products Partners’ affiliate and two representatives approved by subsidiaries of ours, all four of which are EPCO employees. We own an approximate 80.64% interest in the joint venture, with Enterprise Products Partners’ affiliate owning the remaining approximate 19.36%. Each representative on the management committee is entitled to one vote, and the joint venture agreement generally requires the affirmative vote of a majority of the members of the management committee to approve an action. Moreover, Enterprise Products Partners is responsible for managing construction of the Phase V expansion of the system. To the extent the costs exceed an agreed upon base cost estimate of $415.2 million, we and Enterprise Products Partners will each pay our respective ownership share (approximately 80.64% and 19.36%, respectively) of such costs. We and Enterprise Products Partners may not always agree on the best course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in our best interests. Further, Enterprise Products Partners may experience unanticipated delays or costs in construction or operation of the project, which could require additional capital contributions by us and Enterprise Products Partners or diminish expected benefits from the project. Any of these factors could materially and adversely affect our results of operations, financial condition and prospects.

Profits and cash flow from Jonah and Val Verde depend on the volumes of natural gas produced from the fields served by the systems and are subject to factors beyond our control.

     Regional production levels drive the volume of natural gas gathered on Jonah and Val Verde. We cannot influence or control the operation or development of the gas fields we serve. For example, production levels may be affected by:

	•		the absolute price of, volatility in the price of, and market demand for natural gas;
	•		changes in laws and regulations, particularly with regard to taxes, denial of reduced well density spacing, safety and protection of the environment;
	•		the depletion rates of existing wells;
	•		adverse weather and other natural phenomena;
	•		the availability of drilling and service rigs;
	•		the availability of labor and skilled personnel; and
	•		industry changes, including the effect of consolidations or divestitures.

     Our gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. The amount of natural gas reserves underlying these wells may also be less than we anticipate, and the rate at which production from these reserves declines may be greater than we anticipate. Accordingly, to maintain or increase throughput levels on our gathering systems, we must continually compete for and obtain new natural gas supplies.

     Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems, which depends on a number of factors, including energy prices and other economic and business factors over which we have no control. The primary factors that impact drilling decisions are the prices of oil and natural gas, which reached record levels during 2007. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering systems, which would lead to reduced throughput levels on these systems. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits, the availability and cost of drilling rigs and other drilling equipment, and regulatory changes. Because of these factors, even if new natural gas reserves were discovered in areas served by our systems, producers may choose not to develop those reserves or may connect them to different systems.

In accordance with midstream industry practice, we do not obtain third party evaluations of natural gas reserves dedicated to our gathering systems, including Jonah. Accordingly, volumes of natural gas gathering on our pipeline systems in the future could be less than we anticipate, which could adversely affect our cash flow and our ability to make cash distributions to unitholders.

     In accordance with midstream industry practice, we do not obtain third party evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to those systems or the anticipated lives of such reserves. If the total reserves or estimated lives of the reserves connected to our gathering systems, Jonah and Val Verde, are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our systems in the future could be less than we expect. A decline in the volumes of natural gas gathered on our pipeline systems could have an adverse effect on our business, results of operations and financial condition.

The use of derivative financial instruments could result in material financial losses by us.

     We historically have sought to limit a portion of the adverse effects resulting from changes in commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms from time to time. To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though monitored by management, hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge

is imperfect, or hedging policies and procedures are not followed. See Note 6 in the Notes to Consolidated Financial Statements for a discussion of our treasury lock agreements.

Our pipeline integrity program may impose significant costs and liabilities on us.

     The DOT issued final rules (effective March 2001 with respect to hazardous liquid pipelines and February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The ultimate costs of compliance with this rule are difficult to predict. The majority of the costs to comply with the integrity management rule are associated with pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in “high consequence areas” can have a significant impact on the costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines as required by the DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Our operations are subject to governmental laws and regulations relating to the protection of the environment and safety which may expose us to significant costs and liabilities. Additionally, as a result of our marine transportation acquisition, we are subject to additional laws and regulations, including environmental regulations, that may adversely affect the cost, manner or feasibility of doing business in that segment.

     Our facilities are subject to multiple environmental, health and safety obligations and potential liabilities under a variety of federal, 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, 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 currently own or lease, and have owned or leased, many properties that have been used for many years to terminal or store crude oil, petroleum products or other chemicals. Owners, tenants or users of these properties may have disposed of or released hydrocarbons or solid wastes on or under them. Additionally, some sites we operate are located near current or former refining and terminaling operations. There is a risk that contamination has migrated from those sites to ours.

     Further, we cannot ensure 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.

     Various state and federal governmental authorities, including the EPA, the Bureau of Land Management, the DOT and OSHA, have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault under CERCLA, RCRA, and analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipeline systems pass, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

     Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect our products and activities, including storage, transportation and construction and maintenance activities, as well as waste management and air emissions. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability.

     Contamination resulting from spills or releases of petroleum products is an inherent risk within the petroleum pipeline industry. While the costs of remediating groundwater contamination are generally site-specific, such costs can vary substantially and may be material.

     Increasingly stringent federal, state and local laws and regulations governing worker health and safety and the manning, construction and operation of marine vessels may significantly affect our marine transportation operations. Many aspects of the marine industry are subject to extensive governmental regulation by the U.S. Coast Guard, the Department of Transportation, the Department of Homeland Security, the National Transportation Safety Board and the U.S. Customs and Border Protection (“CBP”), and to regulation by private industry organizations such as the American Bureau of Shipping. The U.S. Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards. The U.S. Coast Guard is authorized to inspect vessels at will.

     Our marine transportation operations are also subject to state and local laws and regulations that control the discharge of pollutants into the environment or otherwise relate to environmental protection. Compliance with such laws, regulations and standards may require installation of costly equipment or operational changes. Failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our marine operations. Some environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under the OPA, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil within the internal and territorial waters of, and the 200-mile exclusive economic zone around, the United States. Additionally, an oil spill from one of our vessels could result in significant liability, including fines, penalties, criminal liability and costs for natural resource damages. The potential for these releases could increase if we increase our fleet capacity. In addition, most states bordering on a navigable waterway have enacted legislation providing for potentially unlimited liability for the discharge of pollutants within their waters.

Our marine transportation business would be adversely affected if we failed to comply with the Jones Act provisions on coastwise trade, or if those provisions were modified, repealed or waived.

     As a result of our marine transportation acquisition, we will be subject to the Jones Act and other federal laws that restrict maritime transportation between points in the United States to vessels built and registered in the United States and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of our common units and other partnership interests. If we do not comply with these restrictions, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels.

     In the past, interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoes currently reserved for U.S.-flag vessels under the Jones Act and cargo preference laws. We believe that interest groups may continue efforts to modify or repeal the Jones Act and cargo preference laws currently benefiting U.S.-flag vessels. If these efforts are successful, it could result in increased competition, which could reduce our revenues and cash available for distribution.

     The Secretary of the Department of Homeland Security is vested with the authority and discretion to waive the coastwise laws to such extent and upon such terms as he may prescribe whenever he deems that such action is necessary in the interest of national defense. In response to the effects of Hurricanes Katrina and Rita, the Secretary

of the Department of Homeland Security waived the coastwise laws generally for the transportation of petroleum products from September 1 to September 19, 2005 and from September 26, 2005 to October 24, 2005. In the past, the Secretary of the Department of Homeland Security has waived the coastwise laws generally for the transportation of petroleum released from the Strategic Petroleum Reserve undertaken in response to circumstances arising from major natural disasters. Any waiver of the coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign marine vessel operators, which could reduce our revenues and cash available for distribution.

Maritime claimants could arrest the vessels carrying our cargoes.

     Crew members, suppliers of goods and services to a vessel, other shippers of cargo and other parties may be entitled to a maritime lien against that vessel for unsatisfied debts, claims or damages. In many jurisdictions, a maritime lienholder may enforce its lien by arresting a vessel through foreclosure proceedings. The arrest or attachment of one of our vessels could substantially delay our shipment. In addition, in some jurisdictions, under the “sister ship” theory of liability, a claimant may arrest both the vessel that is subject to the claimant’s maritime lien and any “associated” vessel, which is any vessel owned or controlled by the same owner. Claimants could try to assert “sister ship” liability against one of our vessels for claims relating to a vessel with which we have no relation.

Terrorist attacks aimed at our facilities could adversely affect our business.

     On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11th attacks, the United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

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

     Our operations are subject to the many hazards inherent in the transportation and terminaling of refined products, LPGs, NGLs, petrochemicals, and crude oil and in the gathering, compressing, and treating of natural gas, including ruptures, leaks, fires, spills, severe weather and other disasters. These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. EPCO maintains insurance coverage on land-based operations on our behalf, although insurance will not cover many types of hazards that might occur, including certain environmental accidents, and will not cover amounts up to applicable deductibles. With respect to our marine operations, until June 30, 2008 or such earlier time as we obtain replacement coverage, we are a named insured on the policies of Cenac which provide for limited hull coverage on our vessels. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. For example, changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes of 2005 have made it more difficult for us to obtain certain types of coverage. As a result, EPCO may not be able to renew existing insurance policies on our behalf or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

We depend on the leadership and involvement of our key personnel for the success of our business.

     We depend on the leadership and involvement of our key personnel to identify and develop business opportunities and make strategic decisions. Our president and chief executive officer has over 35 years of relevant experience and our chief financial officer and general counsel each have approximately 20 years of relevant experience. Other senior operational executives who run our business segments have many years of relevant business experience in the areas in which we operate. Any future unplanned departures could have a material

adverse effect on our business, financial condition and results of operations. Certain legacy senior executives have compensation agreements in place but officers appointed since our General Partners was acquired by an EPCO affiliate in 2005, including our chief executive officer, are not party to any compensation agreements.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

     We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for specified periods of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, or increased costs to renew such rights, could have a material adverse effect on our business, financial position, results of operations or cash flows.

Mergers among our customers or competitors could result in lower volumes being shipped by us, thereby reducing the amount of cash we generate.

     Mergers among our existing customers or competitors could provide strong economic incentives for the combined entities to utilize systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to unitholders.

Risks Relating to Our Units as a Result of Our Partnership Structure

We may issue additional limited partnership interests, diluting existing interests of unitholders and benefiting our General Partner.

     Our Partnership Agreement allows us to issue additional Units and other equity securities without unitholder approval. These additional securities may be issued to raise cash or acquire additional assets or businesses or for other partnership purposes. Our Partnership Agreement does not limit the number of Units and other equity securities we may issue. If we issue additional Units or other equity securities, the proportionate partnership interest and voting power of our existing unitholders will decrease and the ratio of taxable income to distributions may increase. Such issuances could negatively affect the amount of cash distributed to unitholders and the market price of our Units.

Cost reimbursements and fees due EPCO and its affiliates may be substantial and will reduce our cash available for distribution to holders of our Units.

     Prior to making any distribution on our Units, we will reimburse EPCO and its affiliates, including our General Partner, for expenses they incur on our behalf for operations and management functions. The payment of these amounts and allocated overhead to EPCO and its affiliates could adversely affect our ability to pay cash distributions to holders of our Units. These amounts include all costs in managing and operating our business, including compensation of executives for time allocated to us, director compensation, costs for rendering administrative staff and support services and overhead allocated to us by EPCO. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence” in this Report. In addition, our General Partner and its affiliates may provide other services to us for which we will be charged fees as determined by our General Partner.

Our General Partner and its affiliates may have conflicts with our partnership.

     The directors and officers of our General Partner and its affiliates (including Enterprise GP Holdings, EPCO and other affiliates of EPCO) have duties to manage the General Partner in a manner that is beneficial to its owner, Enterprise GP Holdings, which is controlled by Dan L. Duncan. At the same time, the General Partner has duties to manage us in a manner that is beneficial to us. Enterprise GP Holdings also controls other publicly traded partnerships, Enterprise Products Partners and Duncan Energy Partners, that engage in similar lines of business. We have significant business relationships with Enterprise Products Partners, EPCO and other entities controlled by

Dan L. Duncan. Mr. Duncan’s economic interests in Enterprise Products Partners and these other related entities are more substantial than his economic interest in us. Therefore, our General Partner’s duties to us may conflict with the duties of its officers and directors to its owner. As a result of these conflicts of interest, our General Partner may favor its own interest or those of Enterprise GP Holdings or its owners over the interest of our unitholders. Possible conflicts may include, among others, the following:

	•		Enterprise GP Holdings, Enterprise Products Partners, EPCO and their affiliates may engage in substantial competition with us on the terms set forth in the ASA.
	•		Neither our Partnership Agreement nor any other agreement requires entities that control our General Partner or other entities controlled by Mr. Duncan (other than our General Partner) to pursue a business strategy that favors us. Directors and officers of EPCO, the general partner of Enterprise GP Holdings and the general partner of Enterprise Products Partners and their affiliates have a fiduciary duty to make decisions in the best interest of their members, shareholders or unitholders, as the case may be, which may be contrary to our interests.
	•		Our General Partner is allowed to take into account the interests of parties other than us, such as Enterprise GP Holdings, Enterprise Products Partners and their affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
	•		Some of the officers of EPCO who provide services to us also may devote significant time to the business of Enterprise Products Partners or its other affiliates and will be compensated by EPCO for such services.
	•		Our Partnership Agreement limits the liability and reduces the fiduciary duties of our General Partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing Units, unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.
	•		Our General Partner determines the amount and timing of asset purchases and sales, operating expenditures, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.
	•		Our General Partner determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us.
	•		Our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
	•		Our General Partner generally seeks to limit its liability regarding our contractual obligations.
	•		Our General Partner may exercise its rights to call and purchase all of our Units if at any time it and its affiliates own 85% or more of the outstanding Units.
	•		Our General Partner controls the enforcement of obligations owed to us by it and its affiliates, including the ASA.
	•		Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence” in this Report.

Unitholders have limited voting rights and control of management.

     Our General Partner manages and controls our activities. Unitholders have no right to elect the General Partner or the directors of the General Partner on an annual or other ongoing basis. However, if the General Partner resigns or is removed, its successor may be elected by holders of a majority of the Units. Unitholders may remove the General Partner only by a vote of the holders of at least 66 ²/3% of the Units. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations. As a result, unitholders will have limited influence on matters affecting our operations, and third parties may find it difficult to gain control of us or influence our actions.

EPCO’s employees may be subjected to conflicts in managing our business and the allocation of time and compensation costs between our business and the business of EPCO and its other affiliates.

     We have no officers or employees and rely on officers of our General Partner and employees of EPCO and its affiliates to conduct our business. These relationships may create conflicts of interest regarding corporate opportunities and other matters, and the resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping employees allocate their time among us, EPCO and other affiliates of EPCO and may face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

     The ASA governs business opportunities among entities controlled by our General Partner, including us (“TEPPCO Companies”), entities controlled by the general partners of Enterprise GP Holdings and Enterprise Products Partners, including Enterprise GP Holdings and Enterprise Products Partners (“Enterprise Companies”), Duncan Energy Partners and its general partner and EPCO and its other affiliates. Under the ASA, we have no obligation to present any business opportunity offered to or discovered by us to the Enterprise Companies, and they are not obligated to present business opportunities that are offered to or discovered by them to us. However, the agreement requires that business opportunities offered to or discovered by EPCO, which is affiliated with both the TEPPCO Companies and the Enterprise Companies, be offered first to certain Enterprise Companies before they may be pursued by EPCO and its other affiliates or offered to us.

     We do not have an independent compensation committee, and substantial components of the compensation of our executive officers and other key employees, including base salary, are not reviewed or approved by our independent directors. The determination of executive officer and key employee compensation could involve conflicts of interest resulting in economically unfavorable arrangements for us.

Our Partnership Agreement limits our General Partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

     Our Partnership Agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:

	•		permits our General Partner to make a number of decisions on its behalf, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right with respect to Units, its registration rights and the determination of whether to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement;
	•		provides that, in the absence of bad faith by the ACG Committee of the board of directors of our General Partner or our General Partner, the resolution, action or terms made, taken or provided by the ACG Committee or our General Partner in connection with a potential conflict of interest transaction will be conclusive and binding on all persons (including all partners) and will not constitute a breach of the Partnership Agreement or any standard of care or duty imposed by law;
	•		provides that any conflict of interest and any resolution of such conflict of interest will be conclusively deemed fair and reasonable to us if approved by the ACG Committee or is on terms objectively demonstrable to be no less favorable to us than those generally being provided to or available from unrelated third party;
	•		provides that the General Partner shall not be liable to the Partnership or any partner for its good faith reliance on the provisions of the Partnership Agreement to the extent it has duties, including fiduciary duties, and liabilities at law or in equity;
	•		provides that it shall be presumed that the resolution of any conflicts of interest by our General Partner or the audit and conflicts committee of the board of directors of our General Partner was not made in bad faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

•

provides that our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

Our General Partner has a limited call right that may require unitholders to sell their Units at an undesirable time or price.

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

Our unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

     Under Delaware law, our General Partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our General Partner. Further, unitholders could be held liable for our obligations to the same extent as a General Partner if a court determined that:

	•		we were conducting business in a state, but had not complied with that particular state’s partnership statute; or
	•		the right of limited partners to remove our General Partner or to take other action under our Partnership Agreement constituted participation in the “control” of our business.

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

The credit and risk profile of our General Partner and its owners could adversely affect our credit ratings and profile, which could increase our borrowing costs or hinder our ability to raise capital.

     The credit and business risk profiles of the general partner or owners of the general partner may be factors in credit evaluations of a master limited partnership. This is because the general partner can exercise significant influence over the business activities of the partnership, including its cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of the general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.

     Entities controlling the owner of our General Partner have significant indebtedness outstanding and are dependent principally on the cash distributions from the general partner and limited partner equity interests in us, Enterprise GP Holdings, Enterprise Products Partners and Energy Transfer Equity, L.P. to service such indebtedness. Any distributions by us to such entities will be made only after satisfying our then current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect our separateness from our General Partner and the entities that control our General Partner, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of Dan L. Duncan or the entities that control our General Partner were viewed as substantially lower or more risky than ours. In addition, the 100% membership interest in our General Partner and the 4,400,000 of our Units that are owned by Enterprise GP Holdings are pledged under Enterprise GP Holdings’ credit facility. Upon an event of default under that credit facility, the lenders could foreclose on Enterprise GP Holdings’ assets, which could ultimately result in a change in control of our General Partner and a change in the ownership of our Units held by Enterprise GP Holdings.

Control of our General Partner may be transferred to a third party without unitholder consent.

     Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of Enterprise GP Holdings from transferring all or a portion of its ownership interest in our General Partner to a third party. Such a third party would then be in a position to replace the board of directors and officers of our General Partner with its own choices and thereby influence the decisions taken by the board of directors and officers.

Tax Risks to Unitholders

We have adopted certain methodologies that may result in a shift of income, gain, loss and deduction between the General Partner and our unitholders. The Internal Revenue Service (“IRS”) may challenge this treatment, which could adversely affect the value of our Units.

     When we issue additional Units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the General Partner, which may be unfavorable to such unitholders. Moreover, under this methodology, subsequent purchasers of Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the General Partner and certain of our unitholders.

     A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of Units and could have a negative impact on the value of the Units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. The amount of cash available for distribution to you would be substantially reduced if the IRS treats us as a corporation or we become subject to a material amount of entity-level taxation for state or foreign tax purposes.

     The anticipated after-tax economic benefit of an investment in the Units depends largely on our being treated as a partnership for federal income tax purposes. Because we are a publicly traded partnership, this requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code (the “Qualifying Income Requirement”). We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

     If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our Units.

     Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level federal income taxation. Our Partnership Agreement currently provides that if a law is enacted that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution level will be adjusted to reflect the impact of that law on us, including any related imposition of state and local income taxes.

     In addition, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are subject to a new entity-level tax on the portion of our income generated in Texas. Specifically, the revised Texas franchise tax is imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such tax on us by Texas, or any other state, will reduce the cash available for distribution to you.

Our tax treatment as a partnership for federal income tax purposes is subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

     Our treatment as a partnership for federal income tax purposes may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the Qualifying Income Requirement, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our Units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code Section 7704(d) and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Units.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our Units, and the cost of an IRS contest will reduce our cash available for distribution to our unitholders.

     We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

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

Tax gain or loss on the disposition of Units could be more or less than expected.

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

Tax-exempt entities and foreign persons face unique tax issues from owning Units that may result in adverse tax consequences to them.

     Investment in Units by tax-exempt entities, such as individual retirement accounts (“IRAs”), other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income

allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person you should consult your tax advisor before investing in our Units.

We treat each purchaser of our Units as having the same tax benefits without regard to the actual Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Units.

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

Unitholders may be subject to foreign, state and local taxes and return filing requirements in states and jurisdictions where they do not live as a result of investing in our Units.

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

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

     We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. If this occurs, you will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to you with respect to that period.

Item 1B. Unresolved Staff Comments

     None.

Item 3. Legal Proceedings

     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 26^th 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 recently 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.

     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, 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 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 December 31, 2007, 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.

     On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel

from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the EPA, was seeking a civil penalty against us for alleged violations of the CWA arising out of this release, as well as three smaller spills at other locations in 2004 and 2005. We agreed with the DOJ on a penalty of approximately $2.9 million, along with our commitment to implement additional spill prevention measures. In August 2007, we deposited $2.9 million into a restricted cash account per the terms of the settlement, and in October 2007, we paid the $2.9 million plus interest earned on the amount to the DOJ. This settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

     One of the spills encompassed in our current settlement discussion with the DOJ involved a 37,450-gallon release from Seaway on May 13, 2005 at Colbert, Oklahoma. This release was remediated under the supervision of the Oklahoma Corporation Commission, but resulted in claims by neighboring landowners that have been settled for approximately $1.0 million. In addition, the release resulted in a Corrective Action Order by the DOT. Among other requirements of this Order, we were required to reduce the operating pressure of Seaway by 20% until completion of required corrective actions. The corrective actions were completed and on June 1, 2006, we increased the operating pressure of Seaway back to 100%. We have a 50% ownership interest in Seaway, and our share of the settlement was covered by our insurance. The settlement of the Colbert release did not have a material adverse effect on our financial position, results of operations or cash flows.

     We are also in negotiations with the DOT 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.

     On February 24, 2005, the General Partner was acquired from DCP by DFIGP. The General Partner owns a 2% general partner interest in us and is our general partner. On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to DFIGP’s legal advisor that it was conducting a non-public investigation to determine whether DFIGP’s acquisition of our General Partner may substantially lessen competition or violate other provisions of federal antitrust laws. We and our General Partner cooperated fully with this investigation.

     On October 31, 2006, an FTC order and consent agreement ending its investigation became final. The order required the divestiture of our equity interest in MB Storage, its general partner and certain related assets to one or more FTC-approved buyers in a manner approved by the FTC and subject to its final approval. The order contained no minimum price for the divestiture and required that we provide the acquirer or acquirers the opportunity to hire employees who spend more than 10% of their time working on the divested assets. The order also imposed specified operational, reporting and consent requirements on us including, among other things, in the event that we acquire interests in or operate salt dome storage facilities for NGLs in specified areas. The FTC approved a buyer and sale terms for our equity interests and certain related assets, and we closed on such sale on March 1, 2007.

     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 lawsuits and 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.

Item 4. Submission of Matters to a Vote of Security Holders

     None.

PART II

Item 5. Market for Registrant’s Units and Related Unitholder Matters and Issuer Purchases of Equity Securities

     Our Units are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “TPP”. The high and low trading prices of our Units in 2007 and 2006, respectively, as reported on the NYSE, were as follows:

		2007								2006
Quarter		High				Low				High				Low
First		$	44.53			$	39.88			$	39.00			$	35.29
Second			46.20				42.15				38.49				35.20
Third			46.01				37.04				37.65				34.44
Fourth			40.81				37.17				41.86				36.90

     Based on the information received from our transfer agent, as of February 1, 2008, there were approximately 1,272 unitholders of record of our Units.

     The quarterly cash distributions on our Units for the years ended December 31, 2007 and 2006, were as follows:

				Amount
Record Date		Payment Date		Per Unit
April 28, 2006		May 5, 2006		$	0.675
July 31, 2006		August 7, 2006			0.675
October 31, 2006		November 7, 2006			0.675
January 31, 2007		February 7, 2007			0.675
April 28, 2007		May 7, 2007			0.685
July 31, 2007		August 7, 2007			0.685
October 31, 2007		November 7, 2007			0.695
January 31, 2008		February 7, 2008			0.695

     We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds (see Note 13 in the Notes to Consolidated Financial Statements).

     We are a publicly traded master limited partnership and are not subject to federal income tax. Instead, unitholders are required to report their allocated share of our income, gain, loss, deduction and credit, regardless of whether we make distributions. We have made quarterly distribution payments since May 1990.

     Distributions of cash paid by us to a unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the Units owned by the unitholder.

Recent Sales of Unregistered Securities

     On February 1, 2008, we issued 4,434,005 Units to Cenac Towing Co., Inc. and 420,894 Units to Mr. Arlen B. Cenac, Jr. in conjunction with the acquisition of our marine transportation business. The Units were issued in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended, afforded by Section 4(2) in reliance upon certain investment representations and warranties in the marine transportation business purchase agreement relating to the knowledge and experience in financial and business matters of the Seller Parties.

Units Authorized for Issuance Under Equity Compensation Plan

     Please read the information included under Item 12 of this Report, which is incorporated by reference into this Item 5.

Issuer Purchases of Equity Securities

     We did not repurchase any of our Units during 2007.

Item 6. Selected Financial Data

     The following tables set forth, for the periods and at the dates indicated, our selected consolidated financial data, which is derived from our audited consolidated financial statements, and our selected operating data. The selected financial data as of and for the years ended December 31, 2006, 2005 and 2004 reflect Jonah’s Pioneer plant, which was sold on March 31, 2006, as discontinued operations. The financial data should be read in conjunction with our audited consolidated financial statements included in the Index to Consolidated Financial Statements on page F-1 of this Report. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

		For Year Ended December 31,
		2007				2006				2005				2004				2003
						(in thousands, except per Unit amounts)
Income Statement Data:
Operating revenues:
Sales of petroleum products		$	9,147,104			$	9,080,516			$	8,061,808			$	5,426,832			$	3,766,651
Transportation – Refined products			170,231				152,552				144,552				148,166				138,926
Transportation – LPGs			101,076				89,315				96,297				87,050				91,787
Transportation – Crude oil			45,952				38,822				37,614				37,177				29,057
Transportation – NGLs			46,542				43,838				43,915				41,204				39,837
Gathering – Natural gas			61,634				123,933				152,797				140,122				135,144
Other revenues			85,521				78,509				68,051				67,539				54,430
Total operating revenues			9,658,060				9,607,485				8,605,034				5,948,090				4,255,832
Purchases of petroleum products			9,017,109				8,967,062				7,986,438				5,367,027				3,711,207
Operating expenses (1)			271,167				278,448				255,359				257,372				235,028
General and administrative expenses			33,657				31,348				33,143				28,016				20,409
Depreciation and amortization			105,225				108,252				110,729				112,284				100,728
Gains on sales of assets			(18,653	)			(7,404	)			(668	)			(1,053	)			(3,948	)
Operating income			249,555				229,779				220,033				184,444				192,408
Interest expense – net			(101,223	)			(86,171	)			(81,861	)			(72,053	)			(84,250	)
Gain on sale of ownership interest in MB Storage			59,628				—				—				—				—
Equity earnings			68,755				36,761				20,094				22,148				12,874
Other income – net (including interest income)			3,022				2,965				1,135				1,320				748
Income before provision for income taxes			279,737				183,334				159,401				135,859				121,780
Provision for income taxes			557				652				—				—				—
Income from continuing operations			279,180				182,682				159,401				135,859				121,780
Discontinued operations (2)			—				19,369				3,150				2,689				—
Net income		$	279,180			$	202,051			$	162,551			$	138,548			$	121,780
Basic and diluted income per Unit: (3)
Continuing operations		$	2.60			$	1.77			$	1.67			$	1.53			$	1.47
Discontinued operations (2)			—				0.19				0.04				0.03				—
Net income per Unit		$	2.60			$	1.96			$	1.71			$	1.56			$	1.47

		December 31,
		2007				2006				2005				2004				2003
										(in thousands)
Balance Sheet Data:
Property, plant and equipment – net		$	1,793,634			$	1,642,095			$	1,960,068			$	1,703,702			$	1,619,163
Total assets			4,750,057				3,922,092				3,680,538				3,186,284				2,934,480
Total short-term debt			353,976				—				—				—				—
Total long-term debt			1,511,083				1,603,287				1,525,021				1,480,226				1,339,650
Partners’ capital			1,264,627				1,320,330				1,201,370				1,011,103				1,102,809

		For Year Ended December 31,
		2007				2006				2005				2004				2003
						(in thousands, except per Unit amounts)
Cash Flow Data:
Net cash provided by continuing operating activities (2)		$	350,572			$	271,552			$	250,723			$	263,896							$	242,424
Net cash provided by operating activities			350,572				273,073				254,505				267,167								242,424
Capital expenditures to sustain existing operations (4)			(52,149	)			(39,966	)			(40,783	)			(41,733	)							(32,864	)
Capital expenditures			(228,272	)			(170,046	)			(220,553	)			(156,749	)							(126,707	)
Distributions paid			(294,450	)			(278,566	)			(251,101	)			(233,057	)							(202,498	)
Distributions paid per Unit (3)		$	2.74			$	2.70			$	2.68			$	2.64							$	2.50

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following information should be read in conjunction with our consolidated financial statements and our accompanying notes listed in the Index to Consolidated Financial Statements on page F-1 of this Report. Our discussion and analysis includes the following:

	•		Overview of Business.
	•		Critical Accounting Policies and Estimates – Presents accounting policies that are among the most critical to the portrayal of our financial condition and results of operations.
	•		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.

     This discussion contains forward-looking statements based on current expectations that are subject to risks and uncertainties, such as statements of our plans, objectives, expectations and intentions. Our actual results and the timing of events could differ materially from those anticipated or implied by the forward-looking statements

discussed here as a result of various factors, including, among others, those set forth under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” herein.

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

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. Through December 31, 2007, we operated and reported in three business segments:

	•		Our Downstream Segment, which is engaged in the transportation, marketing and storage of refined products, LPGs and petrochemicals;
	•		Our Upstream Segment, which is engaged in the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals; and
	•		Our Midstream Segment, which is engaged in the gathering of natural gas, transportation of NGLs and fractionation of NGLs.

     On February 1, 2008, with the acquisition of the marine transportation business, we began operating and reporting in a fourth business segment, Marine Transportation Segment. See “Items 1 and 2. Business and Properties, Marine Transportation Segment – Barge Transportation of Petroleum Products” for further information.

     Consistent with our business strategy, we are also focused on 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.

Downstream Segment

     Our Downstream Segment revenues are earned from transportation, marketing and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Our Downstream Segment transportation activities generate revenue primarily through tariffs filed with the FERC applicable to shippers of refined products and LPGs on our pipelines. 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 third-party wholesalers and retailers of refined products. These purchases and sales are generally contracted to occur on the same day. Storage revenue is generated from fees based on storage volumes contracted for by customers.

     Our Downstream Segment is dependent in large part on the demand for refined products and LPGs in the markets served by its pipelines and the availability of alternative supplies to serve those markets. As such, quantities and mix of products transported may vary. Market demand for refined products shipped in the Downstream Segment varies based upon the different end uses of the products, while transportation tariffs vary among specific product types. Demand for gasoline, which in recent years has accounted for approximately 55% of the Downstream Segment’s refined products transportation revenues, depends upon market price, prevailing economic conditions, demographic changes in the markets served in the Downstream Segment and availability of gasoline produced in refineries located in those markets. Generally, higher market prices of gasoline has little impact on deliveries in the short-term, but may have a more significant impact on us in the long-term due to long lead times associated with expansion of refinery production capacities and conversion of the auto fleets to more fuel efficient models. Demand for distillates, which in recent years has accounted for approximately 30% of the Downstream Segment’s refined products transportation revenues, is affected by truck and railroad freight, the price of natural gas used by utilities, which use distillates as a substitute for natural gas when the price of natural gas is high, and usage for agricultural operations, which is affected by weather conditions, government policy and crop prices. Demand for jet fuel, which in recent years has accounted for approximately 15% of the Downstream Segment’s refined products revenues, depends on prevailing economic conditions and military usage. Increases in

the market price of jet fuel and the impact on airlines has resulted in the use of more efficient airplanes and reductions in total capacity and the number of scheduled flights. High market price of propane could result in the use of alternative fuel sources and tend to reduce the summer and early fall fill of consumer storage of propane. As a result, market price volatility may affect transportation volumes and revenues from period to period.

     The mix of products delivered by our Downstream Segment varies seasonally. 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 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. The two 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 RGP from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investment in Centennial (see Note 9 in the Notes to Consolidated Financial Statements).

Upstream Segment

     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. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or 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 pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas.

     The areas served by our gathering and transportation operations are geographically diverse, and the forces that affect the supply of the products gathered and transported vary by region. Crude oil prices and production levels affect the supply of these products. The demand for gathering and transportation is affected by the demand for crude oil by refineries, refinery supply companies and similar customers in the regions served by this business, as well as by production levels in the regions served.

     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 Upstream Segment also includes our equity investment in Seaway (see Note 9 in the Notes to Consolidated Financial Statements). 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. Additionally, we completed a project in our South Texas system that allows Seaway to receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing.

Midstream Segment

     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 fractionation of NGLs in Colorado. Under its gathering agreements, Val Verde gathers the natural gas supplied to its gathering systems and redelivers the natural gas for a fixed fee. CBM volumes gathered on the Val Verde system have begun to decline, primarily due to the natural decline of CBM production by the producers in the field. Transportation revenues are recognized as NGLs are delivered for customers. 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 have not been materially affected by changes in the prices of natural gas or NGLs.

     Our Midstream Segment also includes our equity investment in Jonah (see Note 9 in the Notes to Consolidated Financial Statements). 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. Under its gathering agreements, Jonah gathers and compresses the natural gas supplied to its gathering system and redelivers the natural gas to gas processing facilities and interstate pipelines located in the region for a fixed fee. Prior to August 1, 2006, when Jonah was wholly-owned by us, operating results for Jonah were included in the consolidated Midstream Segment operating results. Effective August 1, 2006, we entered into the joint venture with Enterprise Product Partners’ affiliate, upon which Jonah was deconsolidated, and its operating results since August 1, 2006, have been accounted for under the equity method of accounting. Operating results of the Pioneer plant, which was part of our Midstream Segment and which we sold to an Enterprise Products Partners’ affiliate in March 2006, are shown as discontinued operations for the years ended December 31, 2006 and 2005.

     Other than the effects of normal operating pressure fluctuations, we can neither influence nor control the operation, development or production levels of the gas fields served by the Jonah and Val Verde systems, which may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations.

Marine Transportation Segment

     Most of our marine transportation revenue is expected to be derived from term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from designated origins to designated destinations at set day rates. Most of the term contracts we are acquiring from Cenac have one-year terms with the remainder having terms of up to two years. All of the existing contracts have renewal options, which are exercisable subject to agreement on rates applicable to the option terms. We do not assume ownership of the products we transport in this segment. As is typical for inland liquid affreightment contracts, the term contracts we are acquiring establish firm 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 and equipment retrofits required by emerging government regulation. The costs of fuel and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts. We use a voyage accounting method of revenue recognition for our marine transportation revenues which allocates voyage revenue and expenses based on the percent of the voyage completed during the period. A decline in demand for, and level of consumption of, refined products could cause demand for tank vessel capacity and charter rates to decline, which would decrease our revenues and profitability.

Business Trends

     We believe the trends or factors identified below will drive our growth opportunities in 2008 and beyond and have identified below, with each trend or factor, the related strategies or opportunities we believe these factors present.

•

We expect that refined products imports to the U.S. will increase.

	o		Acquire or develop facilities to take advantage of the increased volumes.
	o		Enhance refined products storage business.

•

We expect to see turnover in commercial terminal ownership and operations.

o

Acquire refined products terminals and distribution assets to provide logistical service offerings to companies seeking to outsource or partner.

•

We expect that Canadian crude oil imports to the U.S. will increase.

o

Develop competitive options to move Canadian crude oil to U.S. refining customers with third parties through an optimum combination of new pipeline construction and existing pipeline assets.

•

We expect that crude oil imports to the U.S. Gulf Coast will increase.

o

Build onshore or offshore crude oil discharge, handling and transportation facilities to optimize the U.S. Gulf Coast marine delivery options for imported crude oil.

	o		Strengthen market position around our existing market base by focusing on activities in West Texas, South Texas and Red River areas, align Seaway Crude Pipeline Company with key refiners and suppliers and increase margins by expanding services and managing costs.
	o		Focus on new refinery supply markets with existing assets and expand our asset base in the upper Texas Gulf Coast as well as utilize the existing Cushing, Oklahoma, storage for mid-continent refineries and other customers.

•

We expect the demand for marine transportation services in our market areas to remain strong.

	o		Expand our current barge capacity through new construction or acquisition.
	o		Utilize our newly acquired marine transportation business, which complements our existing strategy of developing a network of terminals along the nation’s inland and coastal waterways, to extend the logistical services to our existing and new customers.

•

We expect to see continued expansion opportunities for natural gas gathering and related services in the Jonah, Pinedale and San Juan Basin areas.

	o		Continue development and expansion of the Jonah system which serves the Jonah and Pinedale fields in our Midstream Segment.
	o		Add new volumes and improve the operating efficiency of the Val Verde system in our Midstream Segment in New Mexico’s San Juan Basin, through new connections of conventional and Colorado coal seam gas.
	o		Capitalize on our assets that are positioned in active producing areas important to future domestic gas supply.

•

Standards for use of ethanol and other renewable fuels are currently mandated to increase to 15 billion gallons by 2015 and will ultimately reach 36 billion gallons per year under newly passed energy legislation.

o

Capitalize on blending and logistical business opportunities at our existing terminal locations and participate in the overall supply and distribution of ethanol.

     We also believe other growth opportunities are available to us, including: expanding our West Texas crude oil system and storage capacity at Cushing in our Upstream Segment; increasing throughput on our Midstream Segment NGL systems; expanding our Downstream Segment system delivery capability of refined products to our Midwest markets experiencing a supply shortfall; utilizing available capacity of Centennial to further support increased refined products movements to Midwest market areas, and also support increased movements of long-haul propane volumes; expanding our Downstream Segment gathering capacity of refined products along the upper Texas Gulf Coast; and pursuing acquisitions or organic growth projects that would complement our current operations. We cannot assure that management will achieve all or any of these objectives or those described above.

     Recently, crude oil is trading near $100 per barrel. At these price levels, the cost of motor gasoline to consumers is expected to increase. Also, certain business sectors of the U.S economy, including housing and autos have experienced relatively weak economic conditions. Should motor gasoline prices remain elevated for an extended period and/or should weak economic conditions in the U.S become more widespread for a prolonged period of time, consumers could exercise conservation measures to reduce their demand for motor gasoline. Should this happen, volumes of motor gasoline handled by our pipeline and terminal facilities may decrease.

     Consistent with our business strategy, 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.

Critical Accounting Policies and Estimates

     The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Although we believe that these estimates are reasonable, actual results could differ from these estimates. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements (see Note 2 in the Notes to Consolidated Financial Statements).

     Critical accounting policies are those that are most important to the portrayal of our financial position and results of operations. These policies require management’s most difficult, subjective or complex judgments, often employing the use of estimates and assumptions about the effect of matters that are inherently uncertain. Our critical accounting policies pertain to revenue and expense accruals, environmental costs, property, plant and equipment and goodwill and intangible assets.

Revenue and Expense Accruals

     We routinely make accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling our records with those of third parties. The delayed information from third parties includes, among other things, actual volumes of crude oil purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. We make accruals to reflect estimates for these items based on our internal records and information from third parties. Most of the estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.

     The most difficult accruals to estimate are power costs, property taxes and crude oil margins. Power cost accruals generally involve a two to three month estimate, and the amount varies primarily for actual power usage. Power costs are dependent upon the actual volumes transported through our pipeline systems and the various power rates charged by numerous power companies along the pipeline system. Peak demand rates, which are difficult to predict, drive the variability of the power costs. For the year ended December 31, 2007, approximately 9% of our power costs were recorded using estimates. A variance of 10% in our aggregate estimate for power costs would have an approximate $0.5 million impact on annual earnings. Property tax accruals involve significant tax rate estimates in numerous jurisdictions. Actual property taxes are often not known until the tax bill is settled in subsequent periods, and the tax amount can vary for tax rate changes and changes in tax methods or elections. A variance of 10% in our aggregate estimate for property taxes could have up to an approximate $1.1 million impact on annual earnings. Crude oil margin estimates are based upon historical crude oil marketing volumes, factoring in current market events and prices of crude oil. We use an average of prices that were in effect during the applicable month to determine the expected revenue amount, and we determine the margin by evaluating the actual margins of the prior twelve months. As of December 31, 2007, approximately 2% of our annual crude oil margin is recorded using estimates. A variance from this estimate of 10% would impact the net of revenues and purchases by approximately $0.4 million on an annual basis. Although the resolution of these uncertainties has not historically had a material impact on our reported results of operations or financial condition, because of the high volume, low margin nature of our business, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate.

Reserves for Environmental Matters

     At December 31, 2007, we have accrued a liability of $4.0 million for our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations, including conditions with assets we have acquired. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations. A variance of 10% in our aggregate estimate for environmental costs would have an approximate $0.4 million impact on annual earnings. For information concerning environmental regulation and environmental costs and contingencies, see Items 1 and 2. Business and Properties, “– Environmental and Safety Matters”.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

     In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may

develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Some of these circumstances include changes in laws and regulations relating to restoration and abandonment requirements; changes in expected costs for dismantlement, restoration and abandonment as a result of changes, or expected changes, in labor, materials and other related costs associated with these activities; changes in the useful life of an asset based on the actual known life of similar assets, changes in technology, or other factors; and changes in expected salvage proceeds as a result of a change, or expected change in the salvage market. At December 31, 2007 and 2006, the net book value of our property, plant and equipment was $1,793.6 million and $1,642.1 million, respectively. We recorded $81.1 million, $78.9 million and $80.2 million in depreciation expense during the years ended December 31, 2007, 2006 and 2005, respectively.

     We regularly review long-lived assets for impairment in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Such events or changes include, among other factors: operating losses, unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products in a market area; changes in competition and competitive practices; and changes in governmental regulations or actions. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated future undiscounted net cash flows expected to be generated by the asset. Estimates of future undiscounted net cash flows include anticipated future revenues, expected future operating costs and other estimates. Such estimates of future undiscounted net cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell.

Goodwill and Intangible Assets

     Goodwill and intangible assets represent the excess of consideration paid over the estimated fair value of tangible net assets acquired. Certain assumptions and estimates are employed in determining the estimated fair value of assets acquired including goodwill and other intangible assets as well as determining the allocation of goodwill to the appropriate reporting unit. In addition, we assess the recoverability of these intangibles by determining whether the amortization of these intangibles over their remaining useful lives can be recovered through undiscounted estimated future net cash flows of the acquired operations. The amount of impairment, if any, is measured by the amount by which the carrying amounts exceed the projected discounted estimated future operating cash flows.

     During 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the amortization of goodwill and intangible assets that have indefinite lives and requires an annual test of impairment based on a comparison of the estimated fair value to carrying values. The evaluation of impairment for goodwill and intangible assets with indefinite lives under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections resulting in revisions to our assumptions and, if required, recognizing an impairment loss. Based on our assessment, we do not believe our goodwill is impaired, and we have not recorded a charge from the adoption of SFAS 142 (see Note 11 in the Notes to Consolidated Financial Statements). For each of the years ending December 31, 2007 and 2006, the recorded value of goodwill was $15.5 million.

     At December 31, 2007 and 2006, we had $132.3 million and $153.1 million of intangible assets, net of accumulated amortization, respectively, related to natural gas transportation contracts which were recorded as part of our acquisition of Val Verde on June 30, 2002. The value assigned to the natural gas transportation contracts required management to make estimates regarding the fair value of the assets acquired. In connection with the acquisition of Val Verde, we assumed fixed-term gas transportation contracts with customers in the San Juan Basin in New Mexico and Colorado. We assigned $239.6 million of the purchase price to these fixed-term contracts based upon a fair value appraisal at the time of the acquisition. The value assigned to intangible assets is amortized on a unit-of-production basis, based upon the actual throughput of the system compared to the expected total throughput for the lives of the contracts. From time to time, we update throughput estimates and evaluate the remaining

expected useful life of the contract assets based upon the best available information. A variance of 10% in our aggregate production estimate for the Val Verde systems would have an approximate $2.4 million impact on annual amortization expense. Changes in the estimated remaining production will impact the timing of amortization expense reported for future periods.

     At December 31, 2007, we have $40.2 million of excess investments, net of accumulated amortization, in our equity investments in Centennial, Seaway and Jonah, which are being amortized over periods ranging from 10 to 39 years (see Note 12 in the Notes to Consolidated Financial Statements). The value assigned to our excess investment in Centennial was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. The value assigned to our excess investment in Seaway was created upon acquisition of our 50% ownership interest in 2000. We are amortizing the $26.9 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to the life of the pipeline. The value assigned to our excess investment in Jonah was created as a result of interest capitalized on the construction of Jonah’s expansion. As portions of the expansion are placed into service, we amortize the $7.0 million excess investment in Jonah on a straight-line basis over the life of the assets constructed. A variance of 10% in our amortization expense allocated to equity earnings could have up to an approximate $0.6 million impact on annual earnings.

Results of Operations

     The following table summarizes financial information by business segment for the years ended December 31, 2007, 2006 and 2005 (in thousands):

		For Year Ended December 31,
		2007				2006				2005
Operating revenues:
Downstream Segment		$	362,691			$	304,301			$	287,191
Upstream Segment			9,173,683				9,109,629				8,110,239
Midstream Segment (1)			122,235				201,269				211,171
Intersegment eliminations			(549	)			(7,714	)			(3,567	)
Total operating revenues			9,658,060				9,607,485				8,605,034
Operating income:
Downstream Segment			135,055				91,262				88,143
Upstream Segment			84,222				70,840				33,174
Midstream Segment (1)			25,767				65,499				98,716
Intersegment eliminations			4,511				2,178				—
Total operating income			249,555				229,779				220,033
Equity earnings (losses):
Downstream Segment			(12,396	)			(8,018	)			(2,984	)
Upstream Segment			2,602				11,905				23,078
Midstream Segment (1)			83,060				35,052				—
Intersegment eliminations			(4,511	)			(2,178	)			—
Total equity earnings			68,755				36,761				20,094
Earnings before interest: (2)
Downstream Segment			184,251				84,746				85,914
Upstream Segment			87,246				83,540				56,408
Midstream Segment (1)			109,463				101,219				98,940
Interest expense			(112,253	)			(96,852	)			(88,620	)
Interest capitalized			11,030				10,681				6,759
Income before provision for income taxes			279,737				183,334				159,401
Provision for income taxes			557				652				—
Income from continuing operations			279,180				182,682				159,401
Discontinued operations			—				19,369				3,150
Net income		$	279,180			$	202,051			$	162,551

Downstream Segment

     The following table provides financial information for the Downstream Segment for the years ended December 31, 2007, 2006 and 2005 (in thousands):

		For Year Ended December 31,												Increase (Decrease)
		2007				2006				2005				2007-2006				2006-2005
Operating revenues:
Sales of petroleum products		$	30,326			$	5,800			$	—			$	24,526			$	5,800
Transportation — Refined products			170,231				152,552				144,552				17,679				8,000
Transportation — LPGs			101,076				89,315				96,297				11,761				(6,982	)
Other			61,058				56,634				46,342				4,424				10,292
Total operating revenues			362,691				304,301				287,191				58,390				17,110
Costs and expenses:
Purchases of petroleum products			30,041				5,526				—				24,515				5,526
Operating expense			103,406				106,455				98,534				(3,049	)			7,921
Operating fuel and power			39,906				38,354				32,500				1,552				5,854
General and administrative			16,929				17,085				17,653				(156	)			(568	)
Depreciation and amortization			46,141				41,405				39,403				4,736				2,002
Taxes — other than income taxes			9,866				8,437				11,097				1,429				(2,660	)
Gains on sales of assets			(18,653	)			(4,223	)			(139	)			(14,430	)			(4,084	)
Total costs and expenses			227,636				213,039				199,048				14,597				13,991
Operating income			135,055				91,262				88,143				43,793				3,119
Gain on sale of ownership interest in MB Storage			59,628				—				—				59,628				—
Equity losses			(12,396	)			(8,018	)			(2,984	)			(4,378	)			(5,034	)
Interest income			879				1,008				477				(129	)			531
Other income — net			1,085				494				278				591				216
Earnings before interest		$	184,251			$	84,746			$	85,914			$	99,505			$	(1,168	)

     The following table presents volumes delivered in barrels and average tariff per barrel for the years ended December 31, 2007, 2006 and 2005 (in thousands, except tariff information):

														Percentage
		For Year Ended December 31,												Increase (Decrease)
		2007				2006				2005				2007-2006				2006-2005
Volumes Delivered:
Refined products			174,910				165,269				160,667				6	%			3	%
LPGs			41,950				44,997				45,061				(7	%)			—
Total			216,860				210,266				205,728				3	%			2	%
Average Tariff per Barrel:
Refined products		$	0.97			$	0.92			$	0.90				5	%			2	%
LPGs			2.41				1.98				2.14				22	%			(7	%)
Average system tariff per barrel		$	1.25			$	1.15			$	1.17				9	%			(2	%)

  Year Ended December 31, 2007 Compared with Year Ended December 31, 2006

     Effective November 1, 2006, we purchased a refined products terminal in Aberdeen, Mississippi, from Mississippi Terminal and Marketing Inc. At this 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 third-party wholesalers and retailers of refined products. For the years ended December 31, 2007 and 2006, sales related to petroleum products marketing activities were $30.3 million and $5.8 million, respectively, and purchases of petroleum products were $30.0 million and $5.5 million, respectively.

     Revenues from refined products transportation increased $17.7 million for the year ended December 31, 2007, compared with the year ended December 31, 2006, primarily due to a 6% increase in the refined products volumes delivered and a 5% increase in the average tariff per barrel. Volume increases were primarily due to increases in motor fuel and distillate revenue due to demand in the Midwest markets resulting from refineries undergoing maintenance. The average tariff per barrel for refined products increased primarily due to increases in system tariffs, which went into effect in February and July 2007, as well as the impact of Centennial on the average rates. Movements during the year ended December 31, 2007 on Centennial were a smaller 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 $11.8 million for the year ended December 31, 2007, compared with the year ended December 31, 2006, primarily due to a 22% increase in the LPG average tariff per barrel, partially offset by a 7% decrease in the LPG volumes delivered. The increase in the average rate per barrel is a result of decreased short-haul deliveries and increased long-haul deliveries during the year ended December 31, 2007 compared with the year ended December 31, 2006. The decrease in the short-haul volumes delivered is due to the sale of a pipeline on March 1, 2007 to Louis Dreyfus. LPG transportation volumes in 2006 include approximately 9.8 million barrels of short-haul propane movements through this pipeline as compared to 2.2 million barrels during the period from January 1, 2007 through February 28, 2007. This decrease was partially offset by an increase in long-haul deliveries of propane in the Midwest and Northeast market areas primarily as a result of colder than normal weather that extended from January through April of 2007 and lower deliveries of propane in the 2006 period in the Midwest and Northeast market areas as a result of warmer than normal winter weather, high propane prices and scheduled plant maintenance, known as turnarounds.

     Other operating revenues increased $4.4 million for the year ended December 31, 2007, compared with the year ended December 31, 2006, primarily due to a $2.9 million increase in LPG rental, location exchange and tender deduction revenue, a $2.0 million increase in rental and storage revenue from previous asset acquisitions and $1.5 million in increased volumes of product sales, partially offset by $2.6 million of increased costs in upsystem product exchanges.

     Costs and expenses increased $14.6 million for the year ended December 31, 2007, compared with the year ended December 31, 2006. Purchases of petroleum products, discussed above, increased $24.5 million, compared with the prior year. Operating expenses decreased $3.0 million primarily due to a $4.9 million decrease in pipeline inspection and repair costs associated with our integrity management program; a $3.4 million increase in product measurement gains; a $2.8 million decrease relating to prior year settlement charges for our retirement cash balance plan (see Note 5 in the Notes to Consolidated Financial Statements); a $2.6 million decrease in operating costs related to the migration to a shared services environment with EPCO, including integrating such departments as engineering and information technology; and a $1.5 million prior year lower of cost or market adjustment on inventory. These decreases in operating expenses were partially offset by a $4.0 million increase in transportation expense related to movements on the Centennial pipeline; a $3.6 million decrease in the prior year in accruals for employee vacations due to the migration to a shared services environment with EPCO; a $3.6 million increase in pipeline operating costs as a result of timing of projects in the current year; and a $1.1 million increase in environmental assessment and remediation costs. Operating fuel and power increased $1.6 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 $0.2 million primarily due to $1.9 million of severance expense in the prior year resulting from the migration to a shared services environment with EPCO, partially offset by a $1.0 million increase in office rental expenses and a $0.6 million increase in labor and benefits expense. Depreciation expense increased $4.7 million primarily due to assets placed into service, asset retirements in 2006 and 2007 and an acceleration of depreciation expense related to the decommissioning of a pipeline segment in 2007. Taxes — other than income taxes increased $1.4 million primarily due to a higher property asset base in the 2007 period and true-ups of property tax accruals. During the year ended December 31, 2007, we recognized net gains of $18.7 million from the sales of various assets in the Downstream Segment to Enterprise Products Partners and Louis Dreyfus, compared with $4.2 million of net gains in 2006 (see Note 10 in the Notes to Consolidated Financial Statements).

     Net losses from equity investments increased for the year ended December 31, 2007, compared with the year ended December 31, 2006, as shown below (in thousands):

		For Year Ended
		December 31,								Increase
		2007				2006				(Decrease)
Centennial		$	(13,528	)		$	(17,094	)		$	3,566
MB Storage			1,089				9,082				(7,993	)
Other			43				(6	)			49
Total equity losses		$	(12,396	)		$	(8,018	)		$	(4,378	)