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, 2006

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. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

     Large accelerated filer þ          Accelerated Filer o          Non-accelerated Filer o

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, 2006, the aggregate market value of the registrant’s Limited Partner Units held by non-affiliates was $2,378,923,338, which was computed using the average of the high and low sales prices of the Limited Partner Units on June 30, 2006.

Limited Partner Units outstanding as of February 27, 2007: 89,804,829.

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			1
PART I
ITEMS 1		Business and Properties			2
AND 2.
ITEM 1A.		Risk Factors			26
ITEM 1B.		Unresolved Staff Comments			40
ITEM 3.		Legal Proceedings			40
ITEM 4.		Submission of Matters to a Vote of Security Holders			43
PART II
ITEM 5.		Market for Registrant’s Units and Related Unitholder Matters and Issuer Purchases of Equity Securities			44
ITEM 6.		Selected Financial Data			46
ITEM 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			47
ITEM 7A.		Quantitative and Qualitative Disclosures About Market Risk			77
ITEM 8.		Financial Statements and Supplementary Data			79
ITEM 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			79
ITEM 9A.		Controls and Procedures			80
ITEM 9B.		Other Information			82
PART III
ITEM 10.		Directors, Executive Officers and Corporate Governance			82
ITEM 11.		Executive Compensation			88
ITEM 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			102
ITEM 13.		Certain Relationships and Related Transactions, and Director Independence			105
ITEM 14.		Principal Accounting Fees and Services			111
PART IV
ITEM 15.		Exhibits, Financial Statement Schedules.			113
Form of Supplemental Agreement
Form of Retention Agreement
Amended Agreement of Limited Partnership
Second Amended Agreement of Limited Partnership
Third Amended Agreement of Limited Partnership
Statement of Computation of Ratio of Earnings to Fixed Charges
Subsidiaries
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 Pursuant to Section 1350
Certification Pursuant to Section 1350

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 “General Partner” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and owned by a private company subsidiary of EPCO, Inc.

     References to “TE Products,” “TCTM” and “TEPPCO Midstream” mean TE Products Pipeline Company, Limited Partnership, TCTM, L.P., and TEPPCO Midstream Companies, L.P., our subsidiaries. Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.”

     References to “TEPPCO GP” mean TEPPCO GP, Inc., our subsidiary, which is the general partner of the Operating Partnerships.

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

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

     References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., which owns Enterprise Products GP.

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

     References to “EPCO” mean EPCO, Inc., a privately-held company that indirectly owns the General Partner.

     References to “DFI” mean DFI GP Holdings L.P., an affiliate of EPCO.

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

     We, Enterprise, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings, DEP and the General Partner are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

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 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. 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. 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 Securities and Exchange Commission (“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.

Items 1 and 2. Business and Properties

General

     We are a Delaware master limited partnership formed in March 1990. 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”), Mont Belvieu Storage Partners, L.P. (“MB Storage”), Jonah Gas Gathering Company (“Jonah”) and an undivided ownership interest in the Basin Pipeline (“Basin”). We operate and report 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 the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. 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 his affiliates, including EPCO, DFI, and Dan Duncan LLC, privately-held companies controlled by him, control us, our General Partner and Enterprise and its affiliates, including Enterprise GP Holdings and DEP. DFI owns all of the membership interests in our General Partner. Accordingly, DFI controls the 2% general partner interest in us and indirectly owns the incentive distribution rights associated with the general partner interest. In addition, DFI owns 2,500,000 of our limited partner units (“Units”), and the partners in DFI (or their parent companies) own 14,191,550 Units, representing a combined 18.6% interest in us.

     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. In February 2005, DFI acquired our General Partner for approximately $1.1 billion from a joint venture between ConocoPhillips and Duke Energy Corporation.

     At December 31, 2006, 2005 and 2004, we had outstanding 89,804,829, 69,963,554 and 62,998,554 Units, respectively.

     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

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 the 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 growth potential;
	•		Maintain a balanced mix of assets; and
	•		Operate in a safe, efficient, compliant and environmentally responsible manner.

     We continue to build a base for long-term growth by pursuing new business opportunities, increasing throughput on our pipeline systems, constructing new pipeline and gathering systems, and expanding and upgrading our existing infrastructure. In 2006, our management performed a detailed analysis of our business environment and identified several key trends or factors that we believe will drive our growth opportunities in 2007 and beyond:

	•		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 that refined products imports to the U.S. will increase.
	•		We expect to see changes in commercial terminal ownership and operations.
	•		Standards for use of ethanol and other renewable fuels are currently mandated to double from 2005 to 2012; under federal legislation, renewable fuels will comprise increasing percentages of U.S. fuel supply, with a fuel standard of 7.5 billion gallons for such fuels set for 2012.
	•		We expect to see continued natural gas gathering and related service opportunities in the Jonah, Pinedale and San Juan Basin areas.

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.”

Financial Information by Business Segment

     See Note 15 in the Notes to the Consolidated Financial Statements for financial information by segment.

2006 Developments

Growth Projects, Acquisitions and Dispositions

     In December 2006, we announced that we had signed an agreement with Motiva Enterprises, LLC (“Motiva”) for us to construct and operate a new refined products storage facility to support the proposed expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms of the agreement, we will construct 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 3.5-mile product pipelines connecting the storage facility to Motiva’s refinery, 15,000 horsepower of pumping capacity and distribution pipeline connections to the Colonial, Explorer and Magtex pipelines. For additional information, please see “– Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals.”

     In November 2006, we purchased a refined products terminal in Aberdeen, Mississippi, for approximately $5.8 million from Mississippi Terminal and Marketing Inc. (“MTMI”). The facility, located along the Tennessee-Tombigbee Waterway system, 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. For additional information, please see “– Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals.”

     In July and December 2006, we purchased two active caverns, one active brine pond, a four bay truck rack, seven above ground storage tanks, and a twelve-spot railcar rack for $10.0 million and one active 170,000 barrel LPG storage cavern, the associated piping and related equipment for $4.8 million, respectively. For additional information, please see “– Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals.”

     On March 11, 2005, the Bureau of Competition of the Federal Trade Commission (“FTC”) delivered written notice to DFI’s legal advisor that it was conducting a non-public investigation to determine whether DFI’s acquisition of our General Partner may substantially lessen competition or violate other provisions of federal antitrust laws. On October 31, 2006, an FTC order and consent agreement ending its investigation became final. The order requires the divestiture of our 50% interest in MB Storage and certain related assets to one or more FTC-approved buyers in a manner approved by the FTC and subject to its final approval. We expect to sell our interest in MB Storage and certain related pipelines during the first quarter of 2007. See Item 3. Legal Proceedings for further information.

Sale of Pioneer Silica Gel Plant

     In March 2006, we sold our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise for $38.0 million in cash. The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes. For additional information, please see “– Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs, Pioneer Plant.”

Jonah Joint Venture

     On August 1, 2006, Enterprise, through its affiliate, Enterprise Gas Processing, LLC, became our joint venture partner by acquiring an interest in Jonah, the general partnership through which we own an interest in the Jonah system.

     We are in the fifth phase of our significant expansion of the Jonah system. In connection with the joint venture arrangement, we and Enterprise plan to continue the Phase V expansion, which is expected to increase the system capacity of the Jonah system from 1.5 Bcf/d to approximately 2.3 Bcf/d 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 is in turn expected to increase the system gathering capacity to approximately 2.0 Bcf/d, is scheduled to be completed in the second quarter of 2007. The second portion of the expansion is expected to be completed by the end of 2007. The anticipated cost of the Phase V expansion is expected to be approximately $444.0 million. We expect to reimburse Enterprise for approximately 50% of these costs. To the extent the costs exceed an agreed upon base cost estimate of $415.2 million, we and Enterprise will each pay our respective ownership share (approximately 80% and 20%, respectively) of such costs. For additional information, please see “– Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs.”

Special Unitholder Meeting

     On December 8, 2006, at a special meeting of our unitholders, the Fourth Amended and Restated Agreement of Limited Partnership (the “New Partnership Agreement”), which amends and restates the Third Amended and Restated Agreement of Limited Partnership in effect prior to the special meeting (the “Previous Partnership Agreement”) was approved and became effective. The New Partnership Agreement contains the following amendments to the Previous Partnership Agreement, among others:

	•		changes to certain provisions that relate to distributions and capital contributions, including the reduction in the General Partner’s incentive distribution rights from 50% to 25% (“IDR Reduction Amendment”), elimination of the General Partner’s requirement to make capital contributions to us to maintain a 2% capital account, and adjustment of our minimum quarterly distribution and target distribution levels for entity-level taxes;
	•		changes to various voting percentage requirements, in most cases from 66 2/3% of outstanding Units to a majority of outstanding Units;
	•		a reduction in the percentage of holders of outstanding Units necessary to constitute a quorum from 66 2/3% to a majority of the outstanding Units;
	•		removal of provisions requiring unitholder approval for specified actions with respect to the Operating Partnerships;
	•		changes to supplement and revise certain provisions that relate to conflicts of interest and fiduciary duties; and
	•		changes to provide for certain registration rights of the General Partner and its affiliates (including with respect to the Units issued in respect of the IDR Reduction Amendment, as described below), for the maintenance of the separateness of us from any other person or entity and other miscellaneous matters.

     References in this Report to our “Partnership Agreement” are to our partnership agreement (including, as applicable, the Previous Partnership Agreement or the New Partnership Agreement), as in effect from time to time. By approval of the various proposals at the special meeting, and upon effectiveness of the New Partnership Agreement, an agreement was effectuated whereby we issued 14,091,275 Units on December 8, 2006 to our General Partner as consideration for the IDR Reduction Amendment. The number of Units issued to our General Partner was based upon a predetermined formula that, based on the distribution rate and the number of Units outstanding at the time of the issuance, resulted in our General Partner’s receiving cash distributions from the newly-issued Units and from its reduced maximum percentage interest in our quarterly distributions approximately equal to the cash distributions our General Partner would have received from its maximum percentage interest in our quarterly distributions without the IDR Reduction Amendment. Effective as of December 8, 2006, the General Partner distributed the newly issued Units to its member, which in turn caused them to be distributed to other affiliates of EPCO.

Public Offering

     In July 2006, we issued and sold in an underwritten public offering 5,750,000 Units at a price to the public of $35.50 per Unit. The net proceeds from the offering, which totaled approximately $196.0 million, were used to

reduce indebtedness under our revolving credit facility. For further information, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Financial Condition and Liquidity.”

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

     We conduct business in our Downstream Segment through the following:

	•		TE Products;
	•		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, and TG Pipeline, L.P. (“TG Pipeline”), which owns a 90-mile pipeline and storage facilities;
	•		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”);
	•		our 50% equity investment in Centennial; and
	•		our 50% equity investment in MB Storage.

Properties and Operations

     Our Downstream Segment owns, operates or has investments in properties located in 14 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. Effective November 1, 2006, we purchased a refined products terminal in Aberdeen, Mississippi, for approximately $5.8 million from MTMI. The facility, located along the Tennessee-Tombigbee waterway system, 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. In connection with this acquisition, which we plan to integrate into our Downstream Segment, we plan to construct a new 500,000-barrel terminal in Boligee, Alabama, at a cost of approximately $20.0 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 fourth quarter of 2007.

     As an interstate common carrier, our Products Pipeline System offers 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 increase over the next five years, 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.

     Excluding the storage facilities of Centennial and MB Storage, 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 storage capacity leased to outside parties. The Products Pipeline System makes deliveries to customers at 62 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 also 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.

     The following table lists the material properties and investments of and ownership percentages in our Downstream Segment assets as of December 31, 2006:

		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	%
MB Storage (2)			50	%

     Refined products and LPGs deliveries in MMBbls for the years ended December 31, 2006, 2005 and 2004, were as follows:

		For Year Ended December 31,
		2006				2005				2004
Refined Products Deliveries: (1)
Gasoline			94.9				92.4				89.3
Jet Fuels			25.5				25.4				25.6
Distillates (2)			44.9				42.9				37.5
Subtotal			165.3				160.7				152.4
LPGs Deliveries:
Propane			36.5				35.6				34.3
Butanes (includes isobutane)			8.5				9.4				9.7
Subtotal			45.0				45.0				44.0
Petrochemical Deliveries (3)			21.6				25.4				25.5
Total Product Deliveries			231.9				231.1				221.9
Centennial Product Deliveries			44.8				50.6				41.2

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 and Baytown to Mont Belvieu and an 8-inch diameter pipeline connection to the George Bush Intercontinental Airport terminal in Houston.

     The Products Pipeline System also has smaller diameter lines that extend laterally from El Dorado to Helena, Arkansas, from Shreveport, Louisiana, to El Dorado and from McRae, Arkansas, to West Memphis, Arkansas. 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 West 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. During the years ended December 31, 2006, 2005, and 2004, we recognized $12.5 million, $12.1 million and $12.0 million, respectively, of revenue under the throughput and deficiency contract.

     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. In connection with this acquisition, which we plan to integrate into our Downstream Segment, we plan to construct a new 500,000-barrel terminal in Boligee, Alabama, at a cost of approximately $20.0 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 fourth quarter of 2007.

     Our Downstream Segment also includes the operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene (“RGP”) from Mont Belvieu to Point Comfort. The northern portion of the Dean Pipeline consists of 138 miles of pipeline from Mont Belvieu to Point Comfort.

     On July 14, 2006, we purchased assets from New York LP Gas Storage, Inc. for $10.0 million. The assets consist of two active caverns, one active brine pond, a four bay truck rack, seven above ground storage tanks, and a twelve-spot railcar rack located east of our Watkins Glen, New York facility.

     On December 26, 2006, we purchased assets from Vectren Utility Holdings, Inc. for $4.8 million. The assets consist of one active 170,000 barrel LPG storage cavern, the associated piping and related equipment. These assets are located adjacent to our Todhunter facility near Middleton, Ohio and tie into our existing LPG pipeline.

     On December 19, 2006, we announced that we had signed an agreement with Motiva for us to construct and operate a new refined products storage facility to support the proposed expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms of the agreement, we will construct 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 3.5-mile product pipelines connecting the storage facility to Motiva’s refinery, 15,000

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 in mid-2009. As a part of a separate but complementary initiative, we will construct 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. This associated project 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 $240.0 million, including $20.0 million for the 11-mile, 20-inch pipeline. 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. If the cancellation were to occur in 2007, Motiva would also pay costs incurred to date plus a five percent cancellation fee, with the fee increasing to ten percent after 2007.

     On November 1, 2006, we announced plans to construct a new 20-inch diameter lateral pipeline to connect our mainline system to the Enterprise and MB Storage facilities at Mont Belvieu, Texas, at a cost of approximately $8.6 million. The new connection, which provides delivery from Enterprise of propane into our system at full line flow rates, complements our current ability to source product from MB Storage. The new connection also offers the ability to deliver other liquid products such as butanes and natural gasoline from Enterprise’s storage facilities into our system at reduced flow rates until enhancements can be made. The capability to deliver butanes and natural gasoline from MB Storage at full flow rates is not expected to be impacted. Construction of the new connection was completed and placed in service in December 2006. This new pipeline replaces a 10-mile, 18-inch segment of pipeline that we sold to an Enterprise affiliate on January 23, 2007 for approximately $8.0 million. This asset was part of our Downstream Segment and had a net book value of approximately $2.5 million.

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, 2006, including the amount paid for the acquisition of an additional ownership interest in February 2003, TE Products has invested $107.3 million in Centennial. TE Products has not received any distributions from Centennial since its formation.

Mont Belvieu Storage Equity Investment

     On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed MB Storage, and each own a 50% ownership interest in MB Storage. MB Storage owns storage capacity at the Mont Belvieu fractionation and storage complex and a short haul transportation shuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coast energy marketplace. The Mont Belvieu fractionation and storage complex is the largest complex of its kind in the United States. MB Storage is a service-oriented, fee-based venture serving the fractionation, refining and petrochemical industries with substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. MB Storage receives revenue from the storage, receipt and delivery of product from refineries and fractionators to pipelines, refineries and petrochemical facilities on the upper Texas Gulf Coast. MB Storage has no commodity trading activity. TE Products operates the facilities for MB Storage. We expect to sell our interest in MB Storage and certain related pipelines during the first quarter of 2007 pursuant to an FTC order and consent agreement.

     MB Storage has approximately 36 million barrels of LPGs storage capacity and approximately 7 million barrels of refined products storage capacity, including storage capacity leased to outside parties. MB Storage

includes a short-haul transportation shuttle system, consisting of a complex system of pipelines and interconnects, that ties Mont Belvieu to nearly all of the refinery and petrochemical facilities on the upper Texas Gulf Coast. MB Storage also provides truck and rail car loading capability and includes a 400-acre parcel of property for future expansion. Total shuttle volumes for the three years ended December 31, 2006, 2005 and 2004, were 34.1 million barrels, 37.7 million barrels and 39.3 million barrels, respectively.

     For the years ended December 31, 2006, 2005 and 2004, TE Products’ sharing ratio in the earnings of MB Storage was 59.4%, 64.2% and 69.4%, respectively. During the years ended December 31, 2006, 2005 and 2004, TE Products received distributions of $12.9 million, $12.4 million and $10.3 million, respectively, from MB Storage. During the years ended December 31, 2006, 2005 and 2004, TE Products contributed $4.8 million, $5.6 million and $21.4 million, respectively, to MB Storage. The 2005 contribution includes a combination of non-cash asset transfers of $1.4 million and cash contributions of $4.2 million. The 2004 contribution includes $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures.

Seasonality

     The mix of products delivered by our Downstream Segment varies seasonally. Gasoline demand is generally stronger in the spring and summer months, and LPGs demand is generally stronger in the fall and winter months, including the demand for normal butane which is used for the blending of gasoline. 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. Because propane demand is generally sensitive to weather in the winter months, meaningful year-to-year variations of propane deliveries have occurred most recently in the first and fourth quarters of 2006 and will likely continue to occur.

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 partner and we in turn establish a margin by selling refined products for physical delivery through spot sales at the Aberdeen truck rack to independent wholesalers and retailers of refined products. These purchases and sales are generally contracted to occur on the same day.

     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, 2006, 2005 and 2004, were as follows:

		For Year Ended December 31,
		2006				2005				2004
Refined Products Deliveries:
Central (1)			74.6				73.3				69.0
Midwest (2)			66.6				60.1				53.5
Ohio and Kentucky			24.1				27.3				29.9
Subtotal			165.3				160.7				152.4
LPGs Deliveries:
Central, Midwest and Kentucky (1)(2)			28.5				26.3				27.0
Ohio and Northeast (3)			16.5				18.7				17.0
Subtotal			45.0				45.0				44.0
Petrochemical Deliveries (4)			21.6				25.4				25.5
Total Product Deliveries			231.9				231.1				221.9
Centennial Product Deliveries			44.8				50.6				41.2

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, 2006, our Downstream Segment had approximately 125 customers. During the year ended December 31, 2006, total revenues (and percentage of total revenues) attributable to the top 10 customers were $143.5 million (47%), of which no single customer accounted for more than 10% of total Downstream Segment revenues. At December 31, 2005, our Downstream Segment had approximately 155 customers. During the year ended December 31, 2005, total revenues (and percentage of total revenues) attributable to the top 10 customers were $151.6 million (53%), of which Marathon accounted for approximately 14% of total Downstream Segment revenues. At December 31, 2004, our Downstream Segment had approximately 139 customers. During the year ended December 31, 2004, total revenues (and percentage of total revenues) attributable to the top 10 customers were $151.7 million (54%), of which Marathon accounted for approximately 17% of total Downstream Segment revenues. During each of the three years ended December 31, 2006, 2005 and 2004, no single customer of the Downstream Segment accounted for 10% or more of 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. Barge transportation of refined products is generally more competitive with the Products Pipeline System 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.

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, L.P. (“TCPL”), TEPPCO Crude Oil, L.P. (“TCO”) and Lubrication Services, L.P. (“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 at pipeline and 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, including pipeline sections within our Red River, South Texas and West Texas systems and Basin and Seaway, are in interstate common carrier service, 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.

     TCO 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.

     Product deliveries on TCPL’s 100% owned pipeline systems, Basin and Seaway for the years ended December 31, 2006, 2005 and 2004, were as follows (in millions):

		For Year Ended December 31,
		2006				2005				2004
Barrels Delivered:
Crude oil transportation			91.5				94.7				101.5
Crude oil marketing			222.1				203.3				177.3
Crude oil terminaling			126.0				110.3				113.2
Lubricants and chemicals (total gallons)			14.4				14.8				14.0
Seaway Barrels Delivered:
Long-haul			88.4				99.7				94.3
Short-haul			223.4				213.9				215.8

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, 2006:

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; 275,000 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		15 tanks with 1,875,000 barrels of storage in Cushing, Oklahoma
Midland Station			100	%		TCPL		11 tanks with 980,000 barrels of storage in Midland, Texas
Seaway (2)		50% general partnership interest				TCPL		500-mile, 30-inch diameter pipeline; 6,836,000 barrels of storage – Texas Gulf Coast to Cushing, Oklahoma; 30-mile Texas City system
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 to Cushing, Oklahoma, via third party pipelines, or to two local refineries. The crude oil on the South Texas System is delivered on a tariff basis to Houston area

refineries and to Cushing. The West Texas Trunk System connects gathering systems to TCPL’s Midland, Texas, terminal.

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 the Seaway assets. Three large diameter lines carry 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 storing 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”).

     The Seaway crude oil marine terminal facility at Texas City, Texas, is used to supply 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 a combined capacity of approximately 4.2 million barrels. Seaway has the capability 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 of Seaway. During the years ended December 31, 2006, 2005 and 2004, we received distributions from Seaway of $20.5 million, $24.7 million and $36.9 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 2.9 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 and independent refiners. 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 was $7.4 billion (75%), $5.9 billion (73%) and $3.8 billion (70%) for the years ended December 31, 2006, 2005 and 2004, respectively. For the year ended December 31, 2006, Valero Energy Corp. (“Valero”) and BP Oil Supply Company accounted for 15% and 12%, respectively, of the Upstream gross sales revenue. For the years ended December 31, 2005 and 2004, Valero 15% and 17%, respectively, of the Upstream gross sales revenue. For the year ended December 31, 2006, Valero and BP Oil Supply Company accounted for 14% and 11%, respectively, of our total consolidated revenues. For the years ended December 31, 2005 and 2004, Valero accounted for 14% and 16%, respectively, of our 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:

	•		our equity ownership in Jonah Gas Gathering Company, which gathers, purchases and sells natural gas;
	•		Val Verde Gas Gathering Company, L.P. (“Val Verde”), which gathers and treats natural gas for carbon dioxide removal;
	•		TEPPCO Midstream and its wholly owned subsidiaries, Chaparral Pipeline Company, L.P. and Quanah Pipeline Company, L.P. (collectively referred to as “Chaparral” or “Chaparral NGL system”), Panola Pipeline Company, L.P. (“Panola Pipeline”), Dean Pipeline Company, L.P. (“Dean Pipeline”) and Wilcox Pipeline Company, L.P. (“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 or NGLs, except for the wellhead sale and purchase 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, 2006, 2005 and 2004, is presented below:

		For Year Ended December 31,
		2006				2005				2004
Gathering – Natural Gas – Jonah (Bcf) (1)			472.9				415.2				354.5
Gathering – Natural Gas – Val Verde (Bcf)			181.9				180.7				144.5
Transportation – NGLs (MMBbls)			69.7				61.1				59.5
Fractionation – NGLs (MMBbls)			4.4				4.4				4.1

Jonah Gas Gathering Joint Venture

     We entered the natural gas gathering business in late 2001 when we purchased Jonah from Alberta Energy Company for approximately $360.0 million. DCP Midstream Partners, L.P. (formerly Duke Energy Field Services, LLC (“DEFS”)) managed and operated Jonah on our behalf under a contractual agreement through the second quarter of 2005, when we assumed these operations as a result of the change in ownership of our General Partner. The majority of the recent growth in the Midstream Segment is due to the expansions of Jonah in the Green River Basin in southwestern Wyoming.

     On August 1, 2006, Enterprise, through its affiliate, Enterprise Gas Processing, LLC, became our joint venture partner by acquiring an interest in Jonah Gas Gathering Company, the general partnership through which we

own an 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.

     The Jonah joint venture is governed by a management committee comprised of two representatives approved by Enterprise and two representatives approved by us, each with equal voting power. Enterprise is the operator of Jonah. Based upon a formula in the partnership agreement that takes into account the capital contributions of the parties to fund the Phase V expansion project discussed below, as well as certain capital expenditures made by us not related to the expansion project, we expect that after completion of the expansion and reaching certain milestones, we will own an interest in Jonah of approximately 80%, with Enterprise owning the remaining 20%.

     Under a letter of intent we entered into in February 2006, Enterprise assumed the management of the 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 for 50% of the expansion costs it had previously advanced, and we and Enterprise began sharing the costs of the expansion equally. We expect to reimburse Enterprise for approximately 50% of the Phase V expansion costs. To the extent the costs exceed an agreed upon base cost estimate of $415.2 million, we and Enterprise will each pay our respective ownership share (approximately 80% and 20%, respectively) of such costs.

     In that regard, we have been working with producers to finalize the scope and design of the Phase V expansion to optimally serve the expected production needs in both the Jonah and Pinedale fields. However, the overall high level of activity in the greater Green River Basin area has strained locally available resources, which, coupled with rising steel costs, is likely to cause the final cost of the expansion to exceed the original agreed upon estimate.

     We received all distributions from the joint venture until a specified milestone in the Phase V expansion was achieved in November of 2006, at which point, Enterprise became entitled to receive approximately 50% of the incremental cash flow from certain portions of the expansion project already placed in service. Upon completion of the next specified milestone, Enterprise will begin to share in revenues of the joint venture based upon the total amount of its capital contributions until, as discussed above, final ownership in the joint venture will be approximately 80% us and 20% Enterprise.

     Jonah Gas Gathering System Business. The Jonah system serves the Jonah and Pinedale fields in Wyoming, which, according to the Energy Information Administration’s 2005 estimates, were in 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 to 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. The Jonah system consists of approximately 643 miles of pipelines ranging in size from three inches to 36 inches in diameter, four compressor stations with an aggregate of approximately 92,000 horsepower and related metering facilities. Gas gathered on the Jonah system is collected from approximately 1,130 producing wells in southwestern Wyoming’s Green River Basin.

     In addition to gathering natural gas, Jonah also purchases and sells wellhead gas and condensate. The Jonah system sells condensate liquid from the natural gas stream to TCO based on a contracted price based generally on an index based crude oil price less a differential. In May 2006, we began to aggregate purchases of wellhead gas on Jonah and re-sell the aggregated quantities at key Jonah delivery points in order to facilitate operational needs and throughput on Jonah. The purchases and sales are generally contracted to occur in 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 95% of the volumes of the system in 2006. Under these 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. It does not take title to the natural gas. Other than the effects of normal operating pressure fluctuations, we cannot influence or 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.

     Since the acquisition of Jonah in 2001, we have expanded both the pipeline capacity and processing capacity of the Jonah system as follows:

	•		The Phase I expansion was completed in May 2002, at a cost of approximately $25.0 million and increased system capacity by 62%, from approximately 450 MMcf/d to approximately 730 MMcf/d.
	•		In October 2002, the Phase II expansion project was completed at a cost of approximately $35.3 million, which increased the capacity of the Jonah system from 730 MMcf/d to approximately 880 MMcf/d.
	•		In 2003, the Jonah system was again expanded by the Phase III project to include an 80-mile pipeline loop and 3,700 horsepower of new compression on the system and the building of a new 300 MMcf/d gas processing plant near Opal, Wyoming. Phase III was substantially completed during the fourth quarter of 2003, with system capacity increasing to 1,180 MMcf/d at a cost of approximately $53.4 million.
	•		Additional capacity of 100 MMcf/d was completed during the fourth quarter of 2004, at a cost of approximately $13.0 million.
	•		The Phase IV expansion project was completed in February 2006, at a cost of approximately $116.0 million and increased system capacity to 1.5 Bcf/d with the addition of 33,000 horsepower of compression and approximately 50 miles of pipeline.
	•		Through the joint venture with Enterprise, a Phase V expansion project is expected to increase the system capacity of the Jonah system from 1.5 Bcf/d to approximately 2.3 Bcf/d 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 is expected to increase the system gathering capacity to approximately 2.0 Bcf/d, is scheduled to be completed in the second quarter of 2007. The pipeline looping part of the first portion of the expansion, which included the addition of 75 miles of 36-inch diameter pipe and 12 miles of 24-inch diameter pipe, was completed in December 2006. The second portion of the expansion is expected to be completed by the end of 2007. The anticipated cost of the Phase V expansion is expected to be approximately $444.0 million.

     Pioneer Plant. On March 31, 2006, we sold our ownership interest in the Pioneer silica gel natural gas processing plant, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields located in Opal, Wyoming, to Enterprise for $38.0 million. The sale of the Pioneer plant was initiated because it was not an integral part of our Midstream Segment operations, and natural gas processing is not a core business. The sales proceeds were used to fund organic growth projects, retire debt and for other general partnership purposes.

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 system has a gathering capacity of approximately one billion cubic feet of gas per day. The current treating capacity of the system 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 a more relevant measure than the gathering capacity of the system. The Val Verde system delivers gas to several interstate pipeline systems serving the western United States, as well as local New Mexico markets.

     The Val Verde system gathers coal bed methane (“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system gathers CBM from more than 500 separate wells throughout northern New Mexico and southern Colorado, and provides gathering and treating services pursuant to long-term

fixed-fee contracts with approximately 40 natural gas producers in the San Juan Basin. These contracts are generally twenty years in length, with evergreen clauses, the majority of which escalate annually. Under these contracts, Val Verde gathers the natural gas supplied to its gathering systems and redelivers the natural gas for a fixed fee. Under these arrangements, 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 by the producers in the field. Other than the effects of normal operating pressure fluctuations, we cannot influence or 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 125 MMcf/d from this interconnection in 2006.

NGL Transportation and Fractionation

     The NGL pipelines of the Midstream Segment are located along the Texas Gulf Coast, 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, 2006, is set forth in the following table:

		Physical
		Capacity
NGL Pipeline		(barrels/day)				Description
Chaparral (1)			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 (2)			46,000			189 miles of pipeline – Carthage, Texas to Mont Belvieu, Texas
San Jacinto (2)			12,000			34 miles of pipeline – Carthage, Texas to Longview, Texas
The southern portion of the Dean Pipeline (3)			10,000			155 miles of pipeline – South Texas to Point Comfort, Texas
Wilcox (4)			7,500			103 miles of pipeline – Southeast Texas

     TEPPCO Colorado has two NGL fractionation facilities which separate NGLs into individual components. TEPPCO Colorado is currently supported by a fractionation agreement with DEFS through 2018, under which TEPPCO Colorado receives a variable fee, primarily a front-loaded fee determined by cumulative volumes fractioned during the contract year, for all fractionated volumes delivered to DEFS. Under an operation and maintenance agreement, DEFS also operates and maintains the fractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS.

Seasonality

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

Customers

     The Midstream Segment’s customers for the gathering of natural gas 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 United States. The Midstream Segment’s customers for the transporting of NGLs include affiliates of EPCO and other major integrated oil and gas companies.

     At December 31, 2006, the Midstream Segment had approximately 67 customers. Revenue attributable to the top 10 customers was $158.0 million (77%) for the year ended December 31, 2006, of which EnCana Corporation, DEFS and its affiliates, Burlington Resources Inc. and BP Energy accounted for approximately 15%, 12%, 12% and 12%, respectively, of revenues of the Midstream Segment. At December 31, 2005, the Midstream Segment had approximately 70 customers. Revenue attributable to the top 10 customers was $190.0 million (85%) for the year ended December 31, 2005, of which EnCana Corporation, DEFS and its affiliates and Burlington Resources Inc. accounted for approximately 20%, 19% and 12%, respectively, of revenues of the Midstream Segment. At December 31, 2004, the Midstream Segment had approximately 75 customers. Revenue attributable to the top 10 customers was $172.8 million (83%) for the year ended December 31, 2004, of which EnCana Corporation, DEFS and its affiliates and Burlington Resources Inc. accounted for approximately 21%, 18% and 16%, respectively, of revenues of the Midstream Segment. During each of the three years ended December 31, 2006, 2005 and 2004, no single customer of the Midstream Segment accounted for 10% or more of 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 a few sources. 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 contiguous operations. The ability to compete in the NGL pipeline area is based primarily on the quality of customer service and knowledge of products and markets.

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 $170.0 million for the year ended December 31, 2006. 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, 2006 (in millions):

						Sustaining
		Revenue				Existing				System				Capitalized
		Generating				Operations				Upgrades				Interest				Total
Downstream Segment		$	30.7			$	20.5			$	19.1			$	5.0			$	75.3
Midstream Segment			39.8				0.2				1.0				1.9				42.9
Upstream Segment			25.6				16.3				4.3				2.2				48.4
Other			—				3.0				0.4				—				3.4
Total		$	96.1			$	40.0			$	24.8			$	9.1			$	170.0

     Revenue generating capital spending by the Downstream Segment totaled $30.7 million and was used primarily for the continued integration of assets we acquired from Texas Genco, LLC (“Genco”) in 2005, the expansion of our truck loading terminal in Bossier City, Louisiana, the expansion of our pipeline system extending from Seymour to Indianapolis, Indiana and additional propane capacity in our Northeast market. Revenue generating capital spending by the Midstream Segment totaled $39.8 million and was used primarily for the expansion of the Jonah system prior to the formation of the joint venture, after which Jonah’s capital spending is reflected through capital contributions to equity investments, and additional well connections on both the Jonah and Val Verde systems. Revenue generating capital spending by the Upstream Segment totaled $25.6 million and was used primarily for the expansion of our pipelines and facilities in South Texas, West Texas and Cushing, Oklahoma, including integration of previously acquired assets. In order to sustain existing operations, we spent $20.5 million for various Downstream Segment pipeline projects, $0.2 million for the Midstream Segment and $16.3 million for Upstream Segment facilities. An additional $24.8 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 2007 will be approximately $300.0 million (including $8.0 million of capitalized interest). We expect to spend approximately $251.0 million for revenue generating projects. We expect to spend approximately $38.0 million to sustain existing operations (including $12.0 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 $3.0 million to improve operational efficiencies and reduce costs among all of our business segments. Amounts related to Jonah capital expenditures will be reported as joint venture contributions due to the deconsolidation of Jonah on August 1, 2006.

     During 2007, TE Products may be required to contribute additional cash to Centennial to cover capital expenditures or other operating needs and to MB Storage to cover capital expenditures prior to the sale of the asset. Additionally, we expect to contribute approximately $120.0 million to our Jonah joint venture for the construction of the Phase V expansion during 2007 and approximately $31.0 million for other capital expenditures. 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

     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.

     Congress is currently considering proposed legislation directed at reducing “greenhouse gas emissions”. It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact our business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial position, results of operations and cash flows.

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, 2006, we have an accrued liability of $1.8 million related to sites requiring environmental remediation activities. Discussion of legal proceedings that relate to environmental remediation is included elsewhere in this Report under the caption Item 3. Legal Proceedings.

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.

Antitrust Matters

     The FTC has imposed certain restrictions on us in connection with its 2006 investigation of us related to DFI’s acquisition of our General Partner in 2005. For further discussion, see Item 3. Legal Proceedings.

Employees

     We do not directly employ any officers or other persons responsible for managing our operations. As of December 31, 2006, approximately 1,000 persons spend 100% of their time engaged in the management and operations of our business, and the cost for their services is reimbursed 100% to EPCO under the ASA. An additional approximately 1,100 persons assigned to EPCO’s shared services organizations spend all or a portion of their time engaged in our business. The cost for their services is reimbursed to EPCO under the ASA generally based on the time allocated for services provided to us during the year. In addition, there are approximately 50 contract maintenance and other various personnel who provide services to us. 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 the business and results of operations of us and our joint ventures. Additional discussion regarding factors that may affect the businesses and operating results of us and our joint ventures is 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 actually occur, our business, financial position or results of operations could be materially and adversely affected.

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 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 future debt level may limit our future financial and operating flexibility.

     As of December 31, 2006, we had approximately $1.6 billion of consolidated debt outstanding, consisting of $490.0 million of borrowings under our revolving credit facility and $1.1 billion principal amount of senior notes. The amount of our future debt could have significant effects on our operations, including, among other things:

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

     Our revolving credit facility contains restrictive financial and other covenants that, among other things, limit our ability to incur additional indebtedness, make distributions in excess of Available Cash (see Note 14 in the Notes to the Consolidated Financial Statements for discussion of Available Cash), and complete mergers, acquisitions and sales of assets. The facility also prevents us from making a distribution if an event of default under the facility has occurred or would occur as a result of the distribution. Our breach of these restrictions or restrictions in the provisions of our other indebtedness could permit the holders of the indebtedness to declare all amounts outstanding thereunder to be immediately due and payable and, in the case of our revolving credit facility, to terminate all commitments to extend further credit. Although our revolving credit facility restricts our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial.

     Our ability to access capital markets to raise capital on favorable terms will be affected by our debt level, the amount of our debt maturing in the next several years and current maturities, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade our credit ratings, then 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.

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 sole 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 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 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. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. 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, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline for partnership interests held by partners with an actual or potential income tax liability on public utility income, if the pipeline proves that the owner of the partnership interest has an actual or potential income tax liability. On December 16, 2005, the FERC issued its first significant case-specific oil pipeline review of the income tax allowance issue in another pipeline company’s rate case. The 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 order have been appealed to the United States Court of Appeals for the District of Columbia Circuit. As a result, the ultimate outcome of these proceedings is not certain and could result in changes to the 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, the policy statement on income tax allowances is applied to us differently in the future or is modified on judicial review, our rates may be subject to calculation using cost of service methodologies and this might adversely affect us.

Competition could adversely affect our operating results.

     Our refined products and LPG transportation business competes with other pipelines in the areas where we deliver products. We also compete with trucks, barges and railroads in some of the areas we serve. Competitive pressures may adversely affect our tariff rates or volumes shipped. 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. 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, 2006, 2005 and 2004, Valero Energy Corp. accounted for 14%, 14% and 16%, respectively, of our total consolidated revenues, and for the year ended December 31, 2006, BP Oil Supply Company accounted for 11% 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, 2006, 2005 and 2004.

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 process 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 shipments on our pipelines.

     Our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets served by our pipelines. 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; all 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 45% of our refined products transportation revenues, 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.

     We own our interest in the Jonah gas gathering system, which represents a significant component of our Midstream Segment and its potential for future growth, through a joint venture with Enterprise, which is under common control with us by EPCO and its affiliates. The joint venture is governed by a management committee comprised of two representatives approved by an Enterprise affiliate and two representatives approved by subsidiaries of ours. We expect to ultimately own an approximate 80% interest in the joint venture, with Enterprise’s affiliate owning the remaining approximate 20%. However, 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 is responsible for managing construction of the Phase V expansion of the system. We expect to reimburse Enterprise for approximately 50% of these construction costs. To the extent the costs exceed an agreed upon base cost estimate of $415.2 million, we and Enterprise will each pay our respective ownership share (approximately 80% and 20%, respectively) of such costs. We and Enterprise 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 may experience unanticipated delays or costs in construction or operation of the project, which could require additional capital contributions by us and Enterprise 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, over which we have no control.

     The level of drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is the price of oil and natural gas. These commodity prices reached record levels during 2006, but current prices have declined in recent months. 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 industry practice, we do not obtain independent 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 industry practice, we do not obtain independent 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 connect 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 anticipate. 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.

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. At this time, we cannot predict the ultimate costs of compliance with this rule because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing that is required by the rule. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. 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.

     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 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.

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, 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 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. 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 was appointed in April 2006, our chief financial officer was appointed in January 2006, and our general counsel was appointed in March 2006. 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. 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 new officers may not be 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 a specific period 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 on our pipelines, 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 in not only 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 you.

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. The issuance 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. 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 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 EPCO and other affiliates of EPCO) have duties to manage the General Partner in a manner that is beneficial to its owners, which are controlled by EPCO. At the same time, the General Partner has duties to manage us in a manner that is beneficial to us. EPCO also controls other publicly traded partnerships, Enterprise and DEP, that engage in similar lines of business. We have significant business relationships with Enterprise and EPCO and other entities controlled by Dan L. Duncan. Mr. Duncan’s economic interests in Enterprise 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 owners. As a result of these conflicts of interest, our General Partner may favor its own interest or those of EPCO or its owners over the interest of our unitholders. Possible conflicts may include, among others, the following:

	•		Enterprise, 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 EPCO or its affiliates (other than our General Partner) to pursue a business strategy that favors us. Directors and officers of EPCO and the general partner of Enterprise and their affiliate have a fiduciary duty to make decisions in the best interest of their shareholders or unitholders, 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 EPCO, Enterprise 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 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 will be 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.

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 66²/ 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 solely on officers of our General Partner and employees of EPCO and its affiliates. 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.

     We have entered into the ASA which 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, including Enterprise GP Holdings and Enterprise (“Enterprise Companies”), DEP 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 controls 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 aspects 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, 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 in the absence of bad faith by the audit and conflicts committee of the board of directors of our General Partner or our General Partner, the resolution, action or terms made, taken or provided in connection with a potential conflict of interest transaction will be conclusive and binding on all person (including all partners) and will not constitute a breach of the Partnership Agreement or any standard of care or duty imposed by law;
	•		Provides 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;
	•		Generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the board of directors of our General Partner must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or otherwise be “fair and reasonable” to us;
	•		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 a 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 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 the separateness of us 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 the entities that control our General Partner were viewed as substantially lower or more risky than ours.

     The ownership interests in us that are owned or controlled by EPCO and its affiliates, which include all of the membership interests in our General Partner, are pledged as security under the credit facility of an affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, Enterprise and us. If EPCO were to default under the credit facility, its lender banks could own our General Partner.

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 the owners of our General Partner or DFI from transferring all or a portion of their respective ownership interest in our General Partner or DFI to a third party. The owners of our General Partner or DFI 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

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 Internal Revenue Service (“IRS”) treats us as a corporation or we become subject to a material amount of entity-level taxation for state 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. 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 will be subject to a new entity-level tax on the portion of our income generated in Texas beginning in 2007. Specifically, the Texas margin tax will be 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.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our Units, and the cost of any 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 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 the Unit is sold at a price greater than your tax basis in that Unit, even if the price 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 state and local taxes and return filing requirements.

     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, 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, foreign, state and local 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

     In the fall of 1999, the General Partner and TE Products were named as defendants in a lawsuit in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et al. and Michael and Linda Robson, et al. v. Texas Eastern Corporation, et al. In the lawsuit, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaint, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. On March 18, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs dismissing all of these plaintiffs’ claims on terms that did not have a material adverse effect on our financial position, results of operations or cash flows. Although we did not settle with all plaintiffs and we therefore remain named parties in the Michael and Linda Robson, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed, by Cooperative Defense Agreement, to fund the defense and satisfy all final judgments which might be rendered with the remaining claims

asserted against us. Consequently, we do not believe that the outcome of these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.

     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 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 are pursuing class certification and have claimed personal injuries and property damage arising from alleged contamination of the refinery property in the amount of $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 or its affiliates. The complaint names as defendants the General Partner; the Board of Directors of the General Partner; the parent companies of the General Partner, including EPCO; Enterprise and certain of its affiliates; and Dan L. Duncan. We are named as a nominal defendant.

     The complaint alleges, among other things, that certain of the transactions proposed in the Proxy Statement, including a proposal to reduce the General Partner’s maximum percentage interest in our distributions in exchange for Units (the “Issuance Proposal”), are unfair to our unitholders and constitute 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 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 or its affiliates that are unfair to us or otherwise unfairly favored Enterprise or its affiliates over us. The complaint alleges that such transactions include the Jonah joint venture entered into by us and an Enterprise affiliate in August 2006 (citing the fact that our AC Committee (defined below) did not obtain a fairness opinion from an independent investment banking firm in approving the transaction) and the sale by us to an Enterprise affiliate of the Pioneer plant in March 2006 and the impending divestiture of our interest in MB Storage in connection with an investigation by the FTC. As more fully described in the Proxy Statement, the Audit and Conflicts Committee of the Board of Directors of the General Partner (“AC Committee”) recommended the Issuance Proposal for approval by the Board of Directors of the General Partner. The complaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting the three members of the AC Committee, cannot be considered independent because of their alleged ownership of securities in Enterprise and its affiliates and their relationships with Mr. Duncan.

     The complaint seeks relief (i) rescinding transactions in the complaint that have been consummated or awarding rescissory damages in respect thereof; (ii) awarding damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts.

     On September 22, 2006, the plaintiff in the action filed a motion to expedite the proceedings, requesting the Court to schedule a hearing on plaintiff’s motion for a preliminary injunction to enjoin the defendants from proceeding with the special meeting of unitholders. On September 26, 2006, the defendants advised the Court that we would provide to our unitholders specified supplemental disclosures, which were included in the Form 8-K and supplemental proxy materials we filed with the SEC on October 5, 2006. The special meeting was convened on December 8, 2006, at which our unitholders approved all of the proposals. In light of the foregoing, we believe that the plaintiff’s grounds for seeking relief by requiring us to issue a proxy statement that corrects the alleged misstatements and omissions in the Proxy Statement and enjoining the special meeting are moot. On November 17, 2006, the defendants (other than us, the nominal defendant) moved to dismiss the complaint. 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.

     In 1994, the LDEQ issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this 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, 2006, we have an accrued liability of $0.1 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program 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, is 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 have agreed with the DOJ on a proposed penalty of $2.9 million, along with our commitment to implement additional spill prevention measures, and expect to finalize the settlement in the second quarter of 2007. We do not expect this settlement to 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 $0.7 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 any settlement should be covered by our insurance. We do not expect the completion of our obligations relating to the Colbert release to have a material adverse effect on our financial position, results of operations or cash flows.

     On September 18, 2005, a propane release and fire occurred at our Todhunter facility, near Middletown, Ohio. The incident resulted in the death of one of our employees; there were no other injuries. Repairs to the impacted facilities have been completed. On March 17, 2006, we received a citation from OSHA arising out of this incident, with a penalty of $0.1 million. The settlement of this citation 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 DEFS by DFI. The General Partner owns a 2% general partner interest in us and is the general partner of the Partnership. On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to DFI’s legal advisor that it was conducting a non-public

investigation to determine whether DFI’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 requires the divestiture of our 50% interest in MB Storage and certain related assets to one or more FTC-approved buyers in a manner approved by the FTC and subject to its final approval. Because we did not divest the interest and related assets by December 31, 2006, the order allows the FTC to appoint a divestiture trustee to oversee their sale to one or more approved buyers. The order contains no minimum price for the divestiture and requires 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 imposes 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. We have made application with the FTC to approve a buyer and sale terms for our interest in MB Storage and certain related pipelines, and we expect to close on such sale during the first quarter of 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

     On December 8, 2006, we held a special meeting of our unitholders. At the meeting, our unitholders approved seven proposals provided for in our definitive proxy statement dated September 5, 2006, as supplemented and filed with the SEC. By approving the proposals, the unitholders effected or adopted:

•

Four proposals by which we amended and restated our Partnership Agreement (the “Amendment Proposals”):

	a)		A proposal to revise certain provisions of our Partnership Agreement that relate to distributions and capital contributions, including reduction of our General Partner’s maximum percentage interest in our quarterly distributions from 50% to 25% (the “IDR Reduction Amendment”), elimination of our General Partner’s requirement to make capital contributions to us to maintain a 2% capital account, and adjustment of our minuimum quarterly distribution and target distribution levels for entity-level taxes (51,875,620 “For,” 3,812,756 “Against,” 1,288,075 “Abstain”).
	b)		A proposal to change various voting percentage requirements of our Partnership Agreement, in most cases from 66 2/3% of outstanding Units to a majority of outstanding Units (50,912,506 “For,” 4,702,226 “Against,” 1,361,719 “Abstain”).
	c)		A proposal to supplement and revise certain provisions of our Partnership Agreement that relate to conflicts of interest and fiduciary duties (50,909,929 “For,” 4,155,340 “Against,” 1,911,182 “Abstain”).
	d)		A proposal to make additional amendments to our Partnership Agreement to provide for certain registration rights of our General Partner, for the maintenance of the separateness of our partnership from any other person or entity and other miscellaneous matters (51,735,496 “For,” 3,661,239 “Against,” 1,579,716 “Abstain”).

	•		A proposal to issue Units to our General Partner as consideration for the IDR Reduction Amendment (the “Issuance Proposal”) (50,103,934 “For,” 5,096,150 “Against,” 1,776,366 “Abstain”).
	•		A proposal to approve the terms of the EPCO, Inc. 2006 TPP Long-Term Incentive Plan (49,567,252 “For,” 5,589,417 “Against,” 1,818,781 “Abstain”).
	•		A proposal to approve the terms of the EPCO, Inc. TPP Employee Unit Purchase Plan (50,613,444 “For,” 4,478,510 “Against,” 1,884,497 “Abstain”).

     The Amendment Proposals and the Issuance Proposal were conditioned upon one another, such that all were required to pass in order for any of them to pass.

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 2006 and 2005, respectively, as reported on the NYSE, were as follows:

		2006								2005
Quarter		High				Low				High				Low
First		$	39.00			$	35.29			$	45.45			$	38.53
Second			38.49				35.20				44.72				39.85
Third			37.65				34.44				42.75				39.61
Fourth			41.86				36.90				41.15				33.15

     Based on the information received from our transfer agent, as of February 23, 2007, there were approximately 1,400 unitholders of record of our Units.

     The quarterly cash distributions on our Units for the years ended December 31, 2006 and 2005, were as follows:

				Amount
Record Date		Payment Date		Per Unit
April 29, 2005		May 6, 2005		$	0.6625
July 29, 2005		August 5, 2005			0.675
October 31, 2005		November 7, 2005			0.675
January 31, 2006		February 7, 2006			0.675
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

     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 14 in the Notes to the Consolidated Financial Statements).

     Effective December 8, 2006, upon receiving approval of our unitholders at a special meeting, we amended and restated our Partnership Agreement, among other things, to reduce our General Partner’s maximum percentage interest in our quarterly distributions from 50% to 25% (the “IDR Reduction Amendment”) in exchange for 14,091,275 Units (“Issuance”). Due to the IDR Reduction Amendment and the Issuance, subsequent increases in the level of our quarterly distribution on our Units would result in lower total cash distributions on partnership interests held by our General Partner and its affiliates than under our Previous Partnership Agreement, as the increased distribution to our General Partner and its affiliates due to the distribution rate increase and the Issuance will be more than offset by the lower distributions to it as a result of the IDR Reduction Amendment. Conversely, if we subsequently decrease the level of our quarterly distribution on our Units, total cash distributions on partnership interests held by our General Partner and its affiliates will be higher than under the Previous Partnership Agreement, since the distributions foregone by them as a result of the IDR Reduction Amendment will be more than offset by the lower distributions on our Units, including those Units issued pursuant to the Issuance. For additional information regarding the amendment to our Partnership Agreement, please see Items 1 and 2. Business and

Properties, “– 2006 Developments,” Item 4. Submission of Matters to a Vote of Security Holders and our definitive proxy statement dated September 5, 2006 on file with the SEC. We expect to continue to pay comparable quarterly cash distributions, assuming no adverse change in our financial position, results of operations or cash flows. Although we have never reduced our quarterly distributions, there can be no assurance that we will not do so in the future.

     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

     As described above, on December 8, 2006, we issued 14,091,275 Units to our General Partner as consideration for the IDR Reduction Amendment. The Units were issued to the General Partner in a transaction not involving a public offering and exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended. Effective as of December 8, 2006, the General Partner distributed the newly issued units to its member, which in turn caused them to be distributed to other affiliates of EPCO.

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 2006.

Item 6. Selected Financial Data

     The following tables set forth, for the periods and at the dates indicated, our selected consolidated financial and operating data. The selected financial data as of and for the years ended December 31, 2006, 2005 and 2004, reflect Jonah Gas Gathering Company’s Pioneer plant, which was sold on March 31, 2006, as discontinued operations. The selected financial data as of and for the years ended December 31, 2006, 2005, 2004 and 2003 is derived from our audited consolidated financial statements. The selected financial data for the year ended December 31, 2002, is derived from unaudited consolidated financial statements and, in the opinion of management, has been prepared in accordance with accounting principles generally accepted in the United States of America and reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of results for this period. 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,
		2006				2005				2004				2003				2002 (1)
		(in thousands, except per Unit amounts)
Income Statement Data:
Operating revenues:
Sales of petroleum products		$	9,080,516			$	8,061,808			$	5,426,832			$	3,766,651			$	2,823,800
Transportation – Refined products			152,552				144,552				148,166				138,926				123,476
Transportation – LPGs			89,315				96,297				87,050				91,787				74,577
Transportation – Crude oil			38,822				37,614				37,177				29,057				27,414
Transportation – NGLs			43,838				43,915				41,204				39,837				38,870
Gathering – Natural gas			123,933				152,797				140,122				135,144				90,053
Mont Belvieu operations			—				—				—				—				15,238
Other revenues			78,509				68,051				67,539				54,430				48,735
Total operating revenues			9,607,485				8,605,034				5,948,090				4,255,832				3,242,163
Purchases of petroleum products			8,967,062				7,986,438				5,367,027				3,711,207				2,772,328
Operating expenses (2)			278,448				255,359				257,372				235,028				197,726
General and administrative expenses			31,348				33,143				28,016				20,409				15,830
Depreciation and amortization			108,252				110,729				112,284				100,728				86,032
Gains on sales of assets			(7,404	)			(668	)			(1,053	)			(3,948	)			—
Operating income			229,779				220,033				184,444				192,408				170,247
Interest expense – net			(86,171	)			(81,861	)			(72,053	)			(84,250	)			(66,192	)
Equity earnings			36,761				20,094				22,148				12,874				8,853
Other income – net (including interest income)			2,965				1,135				1,320				748				1,827
Income before deferred income tax expense			183,334				159,401				135,859				121,780				114,735
Deferred income tax expense			652				—				—				—				—
Income from continuing operations			182,682				159,401				135,859				121,780				114,735
Discontinued operations (3)			19,369				3,150				2,689				—				—
Net income		$	202,051			$	162,551			$	138,548			$	121,780			$	114,735

		For Year Ended December 31,
		2006				2005				2004				2003				2002 (1)
		(in thousands, except per Unit amounts)
Basic and diluted income per Unit: (4)
Continuing operations		$	1.77			$	1.67			$	1.53			$	1.47			$	1.74
Discontinued operations (3)			0.19				0.04				0.03				—				—
Net income per Unit		$	1.96			$	1.71			$	1.56			$	1.47			$	1.74

		December 31,
		2006				2005				2004				2003				2002 (1)
		(in thousands)
Balance Sheet Data:
Property, plant and equipment – net		$	1,642,095			$	1,960,068			$	1,703,702			$	1,619,163			$	1,587,824
Total assets			3,922,092				3,680,538				3,186,284				2,934,480				2,765,900
Total debt			1,603,287				1,525,021				1,480,226				1,339,650				1,377,692
Class B Units held by related party			—				—				—				—				103,234
Partners’ capital			1,320,330				1,201,370				1,011,103				1,102,809				889,449

		For Year Ended December 31,
		2006				2005				2004				2003				2002 (1)
		(in thousands, except per Unit amounts)
Cash Flow Data:
Net cash provided by continuing operating activities (3)		$	271,552			$	250,723			$	263,896			$	242,424			$	234,917
Net cash provided by operating activities			273,073				254,505				267,167				242,424				234,917
Capital expenditures to sustain existing operations (5)			(39,966	)			(40,783	)			(41,733	)			(32,864	)			(21,978	)
Capital expenditures			(170,046	)			(220,553	)			(156,749	)			(126,707	)			(133,372	)
Distributions paid			(278,566	)			(251,101	)			(233,057	)			(202,498	)			(151,853	)
Distributions paid per Unit (4)		$	2.70			$	2.68			$	2.64			$	2.50			$	2.35

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.

     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.

     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

Overview of Business

     Certain factors are key to our operations. These include the safe, reliable and efficient operation of the pipelines and facilities that we own or operate while meeting the regulations that govern the operation of our assets and the costs associated with such regulations. We are also focused on our continued growth through expansion of the assets that we own and through the construction and acquisition of assets that complement our current operations. We operate and report 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.

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 partner and establishing a margin by selling refined products for physical delivery through spot sales at the Aberdeen truck rack to independent wholesalers and retailers of refined products. These purchases and sales are generally contracted to occur on the same day. 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 45% 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 21% 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. Distillate is more sensitive to short-term changes in price as customers shift from the use of trucking for freight transportation to railcars. 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.

     We generally realize higher revenues in the Downstream Segment during the first and fourth quarters of each year since these operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating. 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 refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in MB Storage, which we are required to divest (see Note 18 in the Notes to the Consolidated Financial Statements), and in Centennial (see Note 9 in the Notes to the Consolidated Financial Statements).

Upstream Segment

     Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals principally in Oklahoma, Texas, 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.

     Except for crude oil purchased from time to time as inventory, 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 economically hedged.

     Our Upstream Segment also includes our equity investment in Seaway (see Note 9 in the Notes to the 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.

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 or NGLs, except for the wellhead sale and purchase of natural gas by Jonah to facilitate system operations and to provide a service to some of the producers on the system. Therefore, the results of our Midstream Segment are not directly 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 the Consolidated Financial Statements). Jonah, which is a joint venture between us and an affiliate of Enterprise, 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’s 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 affiliate in March 2006, are shown as discontinued operations for the years ended December 31, 2006, 2005 and 2004.

     Other than the effects of normal operating pressure fluctuations, we cannot influence or 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.

Business Trends

     In 2006, our management performed a detailed analysis of the business environment, and identified several key trends or factors that we believe will drive our growth opportunities in 2007 and beyond. With each trend or factor, we identify below the related strategies or opportunities we believe that factor presents.

•

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 Cushing, Oklahoma, acquired storage and newly constructed storage for mid-continent refineries.

•

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

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

•

We expect to see changes 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.

•

Standards for use of ethanol and other renewable fuels are currently mandated to double from 2005 to 2012; under federal legislation, renewable fuels will comprise increasing percentages of U.S. fuel supply, with a fuel standard of 7.5 billion gallons for such fuels set for 2012.

o

Participate in the aggregation, terminaling and transportation associated with the overall supply and distribution of ethanol.

•

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

	o		Continued development and expansion of the Jonah system which serves the Jonah and Pinedale fields in our Midstream Segment. Through additional Jonah expansions, which should be completed in the fourth quarter of 2007, we expect to increase the capacity to 2.3 billion cubic feet per day.
	o		Adding new volumes and improving 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.

We also believe other growth opportunities are available to us, including through: expanding our West Texas 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 gasoline and diesel fuel in the Indianapolis and Chicago market areas; expanding service to the Midwest markets experiencing a supply shortfall; pursuing growth of refined products market share by expanding deliveries to existing markets and by developing new markets; utilizing available Downstream Segment system capacity of Centennial to move refined products to Midwest market areas, which enables us to increase 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 in any of our business segments that would complement our current operations. We cannot assure that management will achieve all or any of these objectives or those described above.

     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 accounting principles generally accepted in the United States 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 the 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, 2006, approximately 10% of our power costs were recorded using estimates. A variance of 10% in our aggregate estimate for power costs would have an approximate $0.6 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 $1.2 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, 2006, approximately 7% 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 $1.1 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, 2006, we have accrued a liability of $1.8 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 $0.2 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, 2006 and 2005, the net book value of our property, plant and equipment was $1,642.1 million and $1,960.1 million, respectively. We recorded $78.9 million, $80.8 million and $80.7 million in depreciation expense during the years ended December 31, 2006, 2005 and 2004, 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 12 in the Notes to the Consolidated Financial Statements). At December 31, 2006 and 2005, the recorded value of goodwill was $15.5 million and $16.9 million, respectively. The decrease in the value of goodwill is due to the deconsolidation of Jonah effective August 1, 2006 as a result of the formation of a joint venture with Enterprise, partially offset by an increase in goodwill related to the acquisition of MTMI in November 2006.

     At December 31, 2006 and 2005, we had $153.1 million of intangible assets, net of accumulated amortization, related to natural gas transportation contracts which were recorded as part of our acquisition of Val Verde on June 30, 2002. At December 31, 2005, we had $344.0 million of intangible assets, net of accumulated amortization, related to natural gas transportation contracts which were recorded as part of our acquisitions of Jonah on September 30, 2001, and Val Verde. The decrease in intangible assets is due to the deconsolidation of Jonah effective August 1, 2006 as a result of the formation of a joint venture with Enterprise. The value assigned to the natural gas ptransportation 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. On a quarterly basis, 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 $2.5 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, 2006, we have $42.2 million of excess investments, net of accumulated amortization, in our equity investments in Centennial and Seaway, which are being amortized over periods ranging from 10 to 39 years and in our investment in Jonah, in which amortization will begin as the assets are placed in service (see Note 12 in Notes to the 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 $27.1 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 upon its formation related to the construction of

the Phase V expansion. Amortization of this excess investment will begin upon the various phases of the Phase V expansion being placed into service. A variance of 10% in our amortization expense allocated to equity earnings could have up to an approximate $0.4 million impact on annual earnings.

Results of Operations

     The following table summarizes financial information by business segment for the years ended December 31, 2006, 2005 and 2004 (in thousands):

		For Year Ended December 31,
		2006				2005				2004
Operating revenues:
Downstream Segment		$	304,301			$	287,191			$	279,400
Upstream Segment			9,109,629				8,110,239				5,475,995
Midstream Segment (1)			201,269				211,171				195,902
Intersegment eliminations			(7,714	)			(3,567	)			(3,207	)
Total operating revenues			9,607,485				8,605,034				5,948,090
Operating income:
Downstream Segment			91,262				88,143				71,263
Upstream Segment			70,840				33,174				32,265
Midstream Segment (1)			65,499				98,716				80,916
Intersegment eliminations			2,178				—				—
Total operating income			229,779				220,033				184,444
Equity earnings (losses):
Downstream Segment			(8,018	)			(2,984	)			(6,544	)
Upstream Segment			11,905				23,078				28,692
Midstream Segment (1)			35,052				—				—
Intersegment eliminations			(2,178	)			—				—
Total equity earnings			36,761				20,094				22,148
Earnings before interest:
Downstream Segment			84,746				85,914				65,506
Upstream Segment			83,540				56,408				61,363
Midstream Segment (1)			101,219				98,940				81,043
Interest expense			(96,852	)			(88,620	)			(76,280	)
Interest capitalized			10,681				6,759				4,227
Income before deferred income tax expense			183,334				159,401				135,859
Deferred income tax expense			652				—				—
Income from continuing operations			182,682				159,401				135,859
Discontinued operations			19,369				3,150				2,689
Net income		$	202,051			$	162,551			$	138,548

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

Downstream Segment

     The following table provides financial information for the Downstream Segment for the years ended December 31, 2006, 2005 and 2004 (in thousands):

		For Year Ended December 31,												Increase (Decrease)
		2006				2005				2004				2006-2005				2005-2004
Operating revenues:
Sales of petroleum products		$	5,800			$	—			$	—			$	5,800			$	—
Transportation — Refined products			152,552				144,552				148,166				8,000				(3,614	)
Transportation — LPGs			89,315				96,297				87,050				(6,982	)			9,247
Other			56,634				46,342				44,184				10,292				2,158
Total operating revenues			304,301				287,191				279,400				17,110				7,791
Costs and expenses:
Purchases of petroleum products			5,526				—				—				5,526				—
Operating expense			106,455				98,534				108,021				7,921				(9,487	)
Operating fuel and power			38,354				32,500				31,706				5,854				794
General and administrative			17,085				17,653				16,884				(568	)			769
Depreciation and amortization			41,405				39,403				43,135				2,002				(3,732	)
Taxes — other than income taxes			8,437				11,097				8,917				(2,660	)			2,180
Gains on sales of assets			(4,223	)			(139	)			(526	)			(4,084	)			387
Total costs and expenses			213,039				199,048				208,137				13,991				(9,089	)
Operating income			91,262				88,143				71,263				3,119				16,880
Equity losses			(8,018	)			(2,984	)			(6,544	)			(5,034	)			3,560
Interest income			1,008				477				309				531				168
Other income — net			494				278				478				216				(200	)
Earnings before interest		$	84,746			$	85,914			$	65,506			$	(1,168	)		$	20,408

     The following table presents volumes delivered in barrels and average tariff per barrel for the years ended December 31, 2006, 2005 and 2004 (in thousands, except tariff information):

														Percentage
		For Year Ended December 31,												Increase (Decrease)
		2006				2005				2004				2006-2005				2005-2004
Volumes Delivered:
Refined products			165,269				160,667				152,437				3	%			5	%
LPGs			44,997				45,061				43,982				—				2	%
Total			210,266				205,728				196,419				2	%			5	%
Average Tariff per Barrel:
Refined products (1)		$	0.92			$	0.90			$	0.97				2	%			(7	%)
LPGs			1.98				2.14				1.98				(7	%)			8	%
Average system tariff per barrel		$	1.15			$	1.17			$	1.20				(2	%)			(3	%)

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

     Effective November 1, 2006, we purchased a refined products terminal in Aberdeen, Mississippi, from MTMI. Through our TTMC subsidiary, we conduct distribution and marketing operations whereby we provide terminaling services for our throughput and exchange partners at this terminal. We also purchase refined products from our throughput partner that we in turn sell through spot sales at the Aberdeen truck rack to independent wholesalers and retailers of refined products. For the period ended December 31, 2006, sales related

to these refined products marketing activities were $5.8 million and purchases of refined products for these activities were $5.5 million.

     Revenues from refined products transportation increased $8.0 million for the year ended December 31, 2006, compared with the year ended December 31, 2005, primarily due to minor increases in refined products volumes transported and the refined products average rate per barrel. Volume increases were primarily due to increased demand for products supplied from the U.S. Gulf Coast into Midwest markets resulting from higher distillate price differentials and a greater demand for gasoline blendstocks, partially offset by unfavorable differentials for motor fuels during the first quarter of 2006. Additionally, refined products revenues increased due to increased terminaling activity at truck racks, including at our Shreveport terminal, which was placed in service in 2005, and higher product storage fees. The average tariff increased primarily due to an increase in gasoline blendstock deliveries, which have a higher tariff, and an increase in system tariffs, which went into effect in April and July 2006. The increase in the refined products average tariff rate was partially offset by the impact of Centennial on the average rates. When a larger proportion of the refined products deliveries are delivered under a Centennial tariff, TEPPCO’s average tariff declines. Conversely, if the proportion of refined products deliveries moving under a Centennial origin decrease, the average TEPPCO tariff increases. Movements of refined products on Centennial therefore result in a decrease in the refined products average rate per barrel; however, utilizing Centennial for refined products movements allows us to transport incremental refined products and increase movements of long-haul propane volumes.

     Revenues from LPGs transportation decreased $7.0 million for the year ended December 31, 2006, compared with the year ended December 31, 2005, due to lower deliveries of propane in the upper Midwest and Northeast market areas as a result of warmer than normal winter weather in the first and fourth quarters of 2006, high propane prices and scheduled plant maintenance, known as a turnaround. Butane deliveries were below prior year levels due to a refinery turnaround during the fourth quarter of 2006. The LPGs average rate per barrel decreased from the prior year period primarily as a result of increased short-haul deliveries during the year ended December 31, 2006, compared with the year ended December 31, 2005.

     Other operating revenues increased $10.3 million for the year ended December 31, 2006, compared with the year ended December 31, 2005, primarily due to a $5.3 million increase from increased storage revenue on assets acquired from Genco in July 2005 and an increase of $1.9 million in other system storage, a $2.1 million increase in refined products tender deduction revenues, additives and custody transfers fees, a $0.7 million increase in refined products loading fees and $0.4 million of higher RGP revenues on the northern portion of our Dean Pipeline.

     Costs and expenses (excluding purchases of petroleum products) increased $8.4 million for the year ended December 31, 2006, compared with the year ended December 31, 2005. Operating expenses increased $7.9 million primarily due to a $5.8 million increase in pipeline operating costs primarily as a result of acquisitions made in 2005; a $3.5 million increase in product measurement losses; $2.8 million in settlement charges related to the termination of our retirement cash balance plan (see Note 5 in the Notes to the Consolidated Financial Statements); $2.1 million of higher insurance premiums; a $1.5 million lower of cost or market adjustment on inventory (see Note 7 in the Notes to the Consolidated Financial Statements); $0.8 million of expenses relating to our special unitholder meeting; a $0.7 million increase in rental expense on a lease with a third-party pipeline and $0.6 million in severance expense as a result of the migration to a shared services environment with EPCO. These increases in costs and expenses were partially offset by a $3.4 million decrease in pipeline inspection and repair costs associated with our integrity management program, a $1.8 million decrease in accruals for employee vacations due to a change in the vacation policy in the current year period as a result of the migration to a shared services environment with EPCO; a $1.6 million decrease in labor and benefits expense primarily associated with incentive compensation plan vestings in the prior year period; a $1.1 million decrease due to regulatory penalties for past incidents; $0.6 million favorable insurance settlement for prior insurance claims; and $0.6 million decrease in accruals related to post employment liabilities associated with DEFS. Operating fuel and power increased $5.9 million primarily due to increased mainline throughput and higher power rates. Depreciation expense increased $2.0 million primarily due to assets placed into service, asset retirements in 2006 and the recording of a conditional asset retirement obligation as discussed below. Taxes – other than income taxes decreased $2.7 million primarily due to a true-up of property tax accruals for prior tax years and higher payroll taxes in the prior year period. General and administrative expenses decreased $0.6 million primarily due to a $1.5 million decrease in labor and benefits expense associated with prior

year vesting provisions in our incentive compensation plans and decrease in accruals for employee vacations and $0.9 million in transition costs in the 2005 period due to the change in ownership of our General Partner, partially offset by a $1.1 million increase relating to the retirement of an executive in February 2006 and $0.7 million in severance expense as a result of the migration to a shared services environment with EPCO and higher executive compensation expense. During the years ended December 31, 2006 and 2005, we recognized net gains of $4.2 million and $0.1 million, respectively, from the sales of various assets in the Downstream Segment.

     During 2006, we recorded $0.3 million of expense, included in depreciation and amortization expense, related to a conditional asset retirement obligation, and we recorded a $0.5 million liability, which represents the fair value of the conditional asset retirement obligation related to structural restoration work to be completed on leased office space that is required upon our anticipated office lease termination (see Note 8 in the Notes to the Consolidated Financial Statements).

     Net losses from equity investments increased for the year ended December 31, 2006, compared with the year ended December 31, 2005, as shown below (in thousands):

		For Year Ended
		December 31,								Increase
		2006				2005				(Decrease)
Centennial		$	(17,094	)		$	(10,727	)		$	(6,367	)
MB Storage			9,082				7,715				1,367
Other			(6	)			28				(34	)
Total equity losses		$	(8,018	)		$	(2,984	)		$	(5,034	)

     Equity losses in Centennial increased $6.4 million for the year ended December 31, 2006, compared with the year ended December 31, 2005, primarily due to lower transportation volumes and increased costs relating to pipeline inspection and repair costs associated with its integrity management program, partially offset by lower amortization expense on the portion of TE Products’ excess investment in Centennial. Equity earnings in MB Storage increased $1.4 million for the year ended December 31, 2006, compared with the year ended December 31, 2005, primarily due to lower product measurement losses on the MB Storage system and higher revenues, partially offset by higher system maintenance expenses and higher operating fuel and power resulting from higher power rates and increased volumes.

     For the years ended December 31, 2006 and 2005, TE Products received the first $1.7 million per quarter (or $6.78 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the Agreement of Limited Partnership of MB Storage. TE Products’ share of MB Storage’s earnings may be adjusted annually by the partners of MB Storage. Any amount of MB Storage’s annual income before depreciation expense in excess of $6.78 million is allocated evenly between TE Products and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the years ended December 31, 2006 and 2005, TE Products’ sharing ratios in the earnings of MB Storage were approximately 59.4% and 64.2%, respectively.

     Interest income increased $0.5 million for the year ended December 31, 2006, compared with the year ended December 31, 2005, due to higher interest income earned on cash investments and other investing activities.

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004

     Revenues from refined products transportation decreased $3.6 million for the year ended December 31, 2005, compared with the year ended December 31, 2004. Revenues from refined products transportation decreased primarily due to the recognition of $4.1 million of deferred revenue in 2004 related to the expiration of two customer transportation agreements. Under some of our transportation agreements with customers, the contracts specify minimum payments for transportation services. If the transportation services paid for are not used, the unused transportation service is recorded as deferred revenue. The contracts generally specify a subsequent period of time in which the customer can transport excess products to recover the amount recorded as deferred revenue.

During the third quarter of 2004, the time limit under two transportation agreements expired without the customers recovering the unused transportation services. As a result, we recognized the deferred revenue as refined products revenue in that period.

     Additionally, refined products revenues decreased due to reduced deliveries of product as a result of Hurricanes Katrina and Rita in August and September 2005, as discussed below. These decreases in revenues from refined products transportation resulting from the hurricanes were partially offset by an overall increase in the refined products volumes delivered primarily due to deliveries of products moved on Centennial. Volume increases were due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets. The refined products average rate per barrel decreased from the prior year period primarily due to the impact of greater growth in the volume of products delivered under a Centennial tariff compared with the growth in deliveries under a TEPPCO tariff, which resulted in an increased proportion of lower tariff barrels transported on our system. In February 2003, we entered into a lease agreement with Centennial that increased our flexibility to deliver refined products to our market areas. Volumes transported on Centennial increased due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets. Centennial has provided our system with additional pipeline capacity for products originating in the U.S. Gulf Coast area. Prior to the construction of Centennial, deliveries on our pipeline system were limited by our pipeline capacity, and transportation services for our customers were allocated in accordance with a proration policy. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs, Illinois.

     Revenues from LPGs transportation increased $9.3 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, due to higher deliveries of propane in the upper Midwest and Northeast market areas due to system expansion projects completed in 2004 and colder winter weather in March and December 2005. Prior year LPG transportation revenues were negatively impacted by a price spike in the Mont Belvieu propane price in late February 2004, which resulted in TEPPCO sourced propane being less competitive than propane from other source points. The LPGs average rate per barrel increased from the prior period primarily as a result of a combination of decreased propane short-haul deliveries and increased long-haul propane deliveries during 2005, and an increase in tariff rates which went into effect in July 2005. These increases were partially offset by reduced propane revenues resulting from decreased propane deliveries due to a propane release and fire at a dehydration unit in September 2005 at our Todhunter storage facility, near Middletown, Ohio. As a result of the propane release and fire, our Todhunter LPG loading facilities were shut down for approximately three weeks.

     Revenues from refined products and LPGs were also impacted by Hurricanes Katrina and Rita, which affected the U.S. Gulf Coast in August and September 2005, respectively. Hurricane Katrina disrupted refineries and other pipeline systems in the central U.S. Gulf Coast, which provided us with additional deliveries at Shreveport and Arcadia, Louisiana, as shippers used alternative sources to supply product to areas where normal distribution patterns were disrupted. Hurricane Katrina also resulted in higher prices of refined products and LPGs, which had a negative impact on the current demand for the products. Hurricane Rita disrupted production at western U.S. Gulf Coast refineries, many of which directly supply us with product. Hurricane Rita also disrupted power to our Beaumont terminal, which resulted in the mainline being shut down for four days and Centennial being shut down for ten days. Our 230,000 barrel per day capacity, 20-inch diameter mainline system, which primarily delivers LPGs and gasoline from the Texas Gulf Coast to the Midwest, was pumping from MB Storage’s facility at approximately 60% of normal operating capacity until mid-October. Our 110,000 barrel per day capacity, 14-inch and 16-inch diameter pipelines, which primarily deliver distillates and gasoline from the Texas Gulf Coast to the Midwest, were pumping at approximately 75% of normal operating capacity from our Baytown, Texas, terminal until mid-October. We installed generators at our Beaumont, Texas, facility, which enabled receipt and delivery of refined products out of tankage at the terminal. Commercial power was restored to the Beaumont terminal and the Newton, Texas, pump station in mid-October and full operations were resumed. Centennial resumed operating at its normal capacity on October 1, 2005.

     Other operating revenues increased $2.2 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to higher refined products tender deduction, additive and loading fees, partially offset by lower propane inventory fees in 2005. Lower volumes of product inventory sales in the 2005 period were partially offset by increased sales margin on the product inventory sales.

     Costs and expenses (excluding purchases of petroleum products) decreased $9.0 million for the year ended December 31, 2005, compared with the year ended December 31, 2004. Operating expenses decreased $9.5 million primarily due to: a $15.1 million decrease in pipeline inspection and repair costs associated with our integrity management program as we neared completion of the first cycle of our integrity management program; a $2.0 million decrease in postretirement benefit accruals related to plan amendments (see Note 5 in the Notes to the Consolidated Financial Statements); a $2.1 million decrease in product measurement losses, and a $2.0 million decrease in legal expenses related to a legal settlement in 2004. These decreases to costs and expenses were partially offset by: a $2.9 million increase in labor and benefits expenses primarily associated with vesting provisions in certain of our compensation plans as a result of the change in ownership of our General Partner, higher labor expenses associated with an increase in the number of employees between years and higher incentive compensation expense as a result of improved operating performance; a $3.4 million increase in pipeline operating and maintenance expense; a $1.8 million increase attributable to regulatory penalties for past incidents; a $1.6 million increase in insurance expense; a $0.6 million increase in rental expense on a lease agreement from the Centennial pipeline capacity lease agreement, and an increase in other miscellaneous operating supplies expenses during the year, including a $0.4 million increase in environmental assessment and remediation expenses, a $0.3 million increase in labor and benefits expense related to retirement plan settlements with DEFS and hurricane related expenses.

     Depreciation expense decreased $3.7 million primarily due to a $4.4 million non-cash impairment charge in the third quarter of 2004, partially offset by a $0.8 million write-off of assets related to the propane release and fire at a storage facility in Ohio (see Note 8 in the Notes to the Consolidated Financial Statements), assets placed into service and assets retired to depreciation expense in the 2005 period. Taxes – other than income taxes increased $2.2 million primarily due to asset acquisitions and a higher tax base in the 2005 period. Operating fuel and power expense increased $0.8 million primarily as a result of increased volumes and higher power rates during the 2005 period. General and administrative expenses increased $0.8 million primarily as a result of a $1.5 million increase related to transition costs due to the change in ownership of our General Partner and a $0.7 million increase in labor and benefits expenses primarily associated with vesting provisions in certain of our compensation plans as a result of the change in ownership of our General Partner, higher labor expenses associated with an increase in the number of employees between years and higher incentive compensation expense as a result of improved operating performance, partially offset by a $1.1 million decrease in consulting services primarily related to acquisition related activities in the 2004 period and a $0.6 million decrease in postretirement benefit accruals related to plan amendments (see Note 5 in the Notes to the Consolidated Financial Statements). During the year ended December 31, 2004, we recognized net gains of $0.5 million from the sales of various assets in the Downstream Segment.

     Net losses from equity investments decreased for the year ended December 31, 2005, compared with the year ended December 31, 2004, as shown below (in thousands):

		For Year Ended
		December 31,								Increase
		2005				2004				(Decrease)
Centennial		$	(10,727	)		$	(14,379	)		$	3,652
MB Storage			7,715				7,874				(159	)
Other			28				(39	)			67
Total equity losses		$	(2,984	)		$	(6,544	)		$	3,560