10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-10403

TEPPCO Partners, L.P.

(Exact name of Registrant as specified in its charter)

Delaware	76-0291058
(State of Incorporation or Organization)	(I.R.S. Employer Identification Number)
2929 Allen Parkway
P.O. Box 2521
Houston, Texas 77252-2521
(Address of principal executive offices, including zip code)
(713) 759-3636
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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 ý 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 ý

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 twelve 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 ý 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 ý     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 ý

At June 30, 2005, the aggregate market value of the registrant’s Limited Partner Units held by non-affiliates was $2,902,119,651, which was computed using the average of the high and low sales prices of the Limited Partner Units on June 30, 2005.

Limited Partner Units outstanding as of February 24, 2006: 69,963,554.

Documents Incorporated by Reference:  None

TABLE OF CONTENTS

	Explanatory Note
	Cautionary Note Regarding Forward-Looking Statements
PART I
ITEMS 1	Business and Properties
AND 2.
ITEM 1A.	Risk Factors
ITEM 1B.	Unresolved Staff Comments
ITEM 3.	Legal Proceedings
ITEM 4.	Submission of Matters to a Vote of Security Holders
PART II
ITEM 5.	Market for Registrant’s Units and Related Unitholder Matters
ITEM 6.	Selected Financial Data
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk
ITEM 8.	Financial Statements and Supplementary Data
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
ITEM 9A.	Controls and Procedures
ITEM 9B.	Other Information
PART III
ITEM 10.	Directors and Executive Officers of the Registrant
ITEM 11.	Executive Compensation
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management
ITEM 13.	Certain Relationships and Related Transactions
ITEM 14.	Principal Accounting Fees and Services
PART IV
ITEM 15.	Exhibits, Financial Statement Schedules.

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EXPLANATORY NOTE

This Form 10-K includes restated financial statements and selected financial information for the fiscal years ended December 31, 2004 and 2003, and restated quarterly financial information for the quarterly periods ended December 31, 2004 and for the first three quarters of 2005.  This filing also includes the initial issuance of our financial statements for the year ended December 31, 2005, which have not previously been issued and are not restated.  The restated financial statements for the fiscal year ended December 31, 2002 are unaudited and, in the opinion of management, have been prepared in accordance with accounting principles generally accepted in the United States of America and reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of results for those periods.

The restated financial statements include the effect of correcting the accounting for our excess investments in Centennial Pipeline LLC and Seaway Crude Pipeline Company from an intangible asset with an indefinite life and equity method goodwill, respectively, to intangible assets with definite lives.  The restatement caused a $3.8 million, or $0.05 per unit, and $4.0 million, or $0.05 per unit, reduction to net income and earnings per unit as previously reported for the fiscal years ended December 31, 2004 and 2003, respectively.  As a result of the accounting correction, net income for the fiscal year ended December 31, 2005, includes a charge of $4.8 million, of which $3.8 million relates to the first nine months of 2005.  Additionally, partners’ capital at December 31, 2002, reflects a $2.5 million reduction representing the cumulative effect of this correction for fiscal years ended December 31, 2000 through 2002.

For further discussion of the effect of the restatement, see Note 20 in the Notes to the Consolidated Financial Statements.

In addition to the restatement reported in this Annual Report on Form 10-K, this restatement will also be reported in our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2006, June 30, 2006, and September 30, 2006.  As we have included restated financial statements and related selected financial information for (i) restated financial information for the quarterly periods ended March 31, 2005 and 2004, June 30, 2005 and 2004, and September 30, 2005 and 2004, (ii) restated financial statements for the fiscal years ended December 31, 2004 and 2003, and (iii) restated selected financial information for the fiscal years ended December 31, 2002 and 2001, we do not plan to file any other amendments to our previously filed Annual Report on Form 10-K or Quarterly Reports on Form 10-Q, except as described above.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The matters discussed in this Annual Report on Form 10-K (this “Report”) include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  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 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

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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 a 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 Form 10-K.

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 TEPPCO Partners, L.P. or any person acting on its behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Annual Report on Form 10-K and in our future periodic reports filed with the Securities and Exchange Commission.  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

TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990.  We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”).  Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.”  Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us.

On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly owned by us.  TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us.  In exchange for this contribution, the Company’s interest as our general partner was increased to 2%.  The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships.  As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest.  This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.

Through February 23, 2005, the General Partner was an indirect wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips.  Duke Energy held an interest of approximately 70% in DEFS, and ConocoPhillips held the remaining interest of approximately 30%.  On February 24, 2005, the General Partner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP Holdings L.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan, for approximately $1.1 billion.  As a result of the transaction, DFI owns and controls the 2% general partner interest in us and has the right to receive the incentive distribution rights associated with the general partner interest.  In conjunction with an amended and restated administrative services agreement, 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.  As a result of the sale of our General Partner, DEFS and Duke Energy continued to provide some administrative services for us for a period of up to one year after the sale, at which time, we assumed these services.  In connection with us assuming

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the operations of certain of the TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005.

At formation in 1990, we completed an initial public offering of 26,500,000 Units representing Limited Partner Interests (“Limited Partner Units”).  In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”).  Effective April 1, 1994, the DPIs were converted to Limited Partner Units (“Units”), but they have not been listed for trading on the New York Stock Exchange.  These Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000.  On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 Units for $104.0 million.  At December 31, 2005, we had outstanding 69,963,554 Units, including 2,500,000 Units held by DFI.

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

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

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

Business Strategy

Our corporate business strategy is to grow sustainable cash flow and 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;

•To target accretive and complementary acquisitions and expansion opportunities that provide attractive growth potential;

•To maintain an appropriate mix of assets; and

•To operate in a safe, efficient and environmentally responsible manner.

The following is a discussion of our business strategy by segment.

Downstream Segment Strategy

Our Downstream Segment is one of our core business segments, having been the primary business of the Partnership since our formation.  Our Downstream Segment is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States.  Over the past few years, we have continued to pursue growth opportunities and acquisitions to expand our market share and deliveries into existing and new markets.  Key elements to our Downstream Segment business strategy include the following:

•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.

•Pursuing growth of LPGs market share through capacity expansions and improved operating performance.

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•Improving and optimizing refined products gathering infrastructure related to our 2005 acquisition of assets from Texas Genco, LLC and integrating the assets from acquisitions into our system.

•Pursuing acquisitions both adjacent to and outside of the Downstream Segment system.

•Enhancing refined products storage business.

Upstream Segment Strategy

A significant portion of the growth in our Upstream Segment has occurred through acquisitions of pipeline transportation and gathering systems and organic growth projects.  Our acquisitions in this segment have provided increased efficiencies for the gathering and transportation of crude oil with our existing pipeline systems as well as expansion into new market areas.  Key elements to our Upstream Segment business strategy include the following:

•Strengthening market position around existing market base by focusing on activities in West Texas, South Texas and Red River areas, aligning Seaway Crude Pipeline Company with key refiners and suppliers and increase margins by expanding services and managing costs.

•Focusing 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 for mid-continent refineries.

•Pursuing strategic acquisitions to complement existing assets.

Midstream Segment Strategy

The majority of the recent growth in the Midstream Segment is due to the acquisition and expansions of Jonah Gas Gathering Company (“Jonah”) in the Green River Basin in southwestern Wyoming and the acquisition of Val Verde Gas Gathering Company, L.P. (“Val Verde”) in the San Juan Basin in New Mexico and Colorado.  Key elements to our Midstream Segment business strategy include the following:

•Increasing throughput on the Jonah system and NGL systems and maintaining or increasing the revenue stream with new volumes and increasing operating efficiency on the Val Verde system.

•Further expansion of the Jonah system to enhance our ability to serve the growing needs of our customers.

•Capitalizing on our assets that are positioned in active producing areas important to future domestic gas supply.

•Pursuing acquisitions providing long-lived, fee-based cash flows.

Financial Information by Business Segment

See Note 17 in the Notes to the Consolidated Financial Statements for financial information by Segment.

Recent Developments since December 31, 2004

On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”).  The assets include approximately 158 miles of pipeline, which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston.  We have integrated these assets into our South Texas pipeline system, included in our Upstream Segment, which will allow us to realize synergies within our existing asset base and will provide future growth opportunities.

On April 1, 2005, we purchased crude oil storage and terminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P. (“Koch”) for $35.4 million.  The assets consist of eight storage tanks with 945,000 barrels of storage capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land.  The storage and terminaling assets complement our existing infrastructure in Cushing and will strengthen our gathering and marketing business in our Upstream Segment.

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In April 2005, we completed construction on a refined products truck loading facility in Bossier City, Louisiana, in our Downstream Segment. The facility includes six storage tanks and an automated two-bay truck loading rack.  The assets have added more than 20,000 barrels per day of refined products delivery capacity to the Northwest Louisiana and East Texas markets.

On July 12, 2005, we purchased a refined products terminal and truck loading rack in North Little Rock, Arkansas, for $6.9 million from ExxonMobil Corporation.  The assets include three storage tanks and a two-bay truck loading rack.  The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.

On July 15, 2005, we acquired from Texas Genco, LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $62.1 million.  The assets of the purchased companies will be integrated into our Downstream Segment origin infrastructure in Texas City and Baytown, Texas.  As a result of this acquisition, we initiated the expansion of refined products origin capabilities in the Houston and Texas City, Texas, areas.  Our existing Texas City origin facility and a 10-inch diameter, 70,000 barrel per day pipeline system from Texas City to Baytown will be replaced by an 18-inch diameter, 180,000 barrel per day pipeline. The 18-inch diameter pipeline will provide additional receipt and delivery capabilities through the system at major exchange terminals in the Houston area. The integration and other system enhancements should be in service by the fourth quarter of 2006, at an estimated cost of $45.0 million.  The strategic location of these assets, with refined products interconnections to major exchange terminals in the Houston area, will provide significant long-term value to our customers and our Texas Gulf Coast refining and logistics system.

In 2005, we began a Phase IV expansion project on the Jonah Gas Gathering System, which is part of our Midstream Segment.  This expansion is expected to increase system capacity to 1.5 billion cubic feet per day with the addition of 33,000 horsepower of compression and approximately 50 miles of pipeline.  The Phase IV expansion was substantially completed in December 2005, with total costs anticipated to be approximately $116.0 million.

On January 26, 2006, we signed a letter of intent to sell our ownership interest in the Pioneer silica gel natural gas processing plant to an affiliate of Enterprise Products Partners L.P. (“Enterprise”), including all of Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields.  The proposed sale of the Pioneer plant is subject to the execution of definitive agreements and to regulatory approvals.  The proposed sale is expected to be completed by the middle of 2006.  The Pioneer plant is not an integral part of our Midstream Segment operations, and natural gas processing is not a core business.  The anticipated sales proceeds would be used to fund organic growth projects, retire debt, or for other general partnership purposes.

On February 13, 2006, we and Enterprise entered into a letter agreement related to an additional expansion (the “Jonah Expansion”) of the Jonah system (the “Letter Agreement”).  The Jonah Expansion will consist of the installation of approximately 90,000 horsepower of gas turbine compression at a new compression station, related new piping and certain related facilities, which is expected to increase capacity of the Jonah system from 1.5 billion cubic feet per day to 2.0 billion cubic feet per day.  We expect to enter into a joint venture (“Joint Venture”) agreement relating to the construction and financing of the Jonah Expansion.  Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million).  Such advance will constitute a subscription for an equity interest in the proposed Joint Venture (the “Subscription”).  We expect the Jonah Expansion to be put into service in late 2006.  We have the option to return to Enterprise up to 100% of the amount of the Subscription.  If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly.  The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.

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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, L.P. (“TEPPCO Terminals”), which owns a refined products terminal and two-bay truck loading rack, and TG Pipeline, L.P. (“TG Pipeline”), which owns a 90-mile pipeline and storage facilities acquired from Genco;

•a subsidiary which owns the northern portion of the Dean Pipeline (“Dean North”);

•our 50% owned equity investment in Centennial Pipeline LLC (“Centennial”); and

•our 50% owned equity investment in Mont Belvieu Storage Partners, L.P. (“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 petroleum products; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex through MB Storage; intrastate transportation of petrochemicals and other ancillary services.  Other activities are related to the intrastate transportation of petrochemicals under a throughput and deficiency contract.

As an interstate common carrier, our TE Products pipeline offers interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined petroleum 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 pipeline systems.  Substantially all of the refined petroleum products and LPGs transported and stored in our pipeline systems 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 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.  The growth in refining capacity and increased product flow attributable to the Gulf Coast region has increased demand for transportation, storage and distribution facilities.  Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of petroleum products and LPGs.

The following table lists the material properties and investments of and ownership percentages in our Downstream Segment assets as of December 31, 2005:

	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 (1)	100	%
Centennial (2)	50	%
MB Storage (3)	50	%

(1)Effective January 1, 2003, the northern portion of the Dean Pipeline was converted to transport refinery grade propylene (“RGP”) from Mont Belvieu, Texas, to Point Comfort, Texas.

(2)Accounted for as an equity investment.  Effective February 10, 2003, TE Products acquired an additional 16.7% interest in Centennial, bringing its ownership percentage to 50%.

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(3)Accounted for as an equity investment.  Effective January 1, 2003, TE Products contributed substantially all of its Mont Belvieu LPG assets to MB Storage, a partnership formed with Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”).

Refined products and LPGs deliveries in MMBbls for the years ended December 31, 2005, 2004 and 2003, were as follows:

	Years Ended December 31,
	2005	2004	2003
Refined Products Mainline Transportation:
Gasoline	92.4	89.3	89.8
Jet Fuels	25.4	25.6	26.4
Distillates (1)	42.9	37.5	37.9
Subtotal	160.7	152.4	154.1
LPGs Mainline Transportation:
Propane	35.6	34.3	34.5
Butanes	9.4	9.7	8.0
Subtotal	45.0	44.0	42.5
Total Mainline Transportation	205.7	196.4	196.6
Petrochemical Transportation	3.6	3.6	3.4
Total Product Deliveries	209.3	200.0	200.0

(1)Primarily diesel fuel, heating oil and other middle distillates.

Refined Products, LPGs and Petrochemical Pipeline Systems

TE Products is one of the largest pipeline common carriers of refined petroleum 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.

Excluding the storage facilities of Centennial and MB Storage, the Products Pipeline System includes 33 storage facilities with an aggregate storage capacity of 21 million barrels of refined petroleum products and 5 million barrels of LPGs, including storage capacity leased to outside parties.  The Products Pipeline System makes deliveries to customers at 62 locations including 19 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.  The Providence terminal is not physically connected to the Products Pipeline System.

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 and Todhunter, Ohio.  The Products Pipeline System continues eastward from Todhunter, Ohio, 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 Todhunter 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

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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.  During the years ended December 31, 2005, 2004, and 2003, we recognized $12.1 million, $12.0 million and $11.9 million, respectively, of revenue under the throughput and deficiency contract.

Our Downstream Segment also includes the operations of the northern portion of the Dean Pipeline.  Beginning in January 2003, the northern portion of the Dean Pipeline was converted to transport 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.

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 petroleum 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 petroleum 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, 2005, including the amount paid for the acquisition of an additional ownership interest in February 2003, TE Products has invested $104.8 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 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.

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

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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, 2005, 2004 and 2003, were 37.7 million barrels, 39.3 million barrels and 33.1 million barrels, respectively.

For the years ended December 31, 2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage was 64.2%, 69.4% and 70.4%, respectively.  During the years ended December 31, 2005, 2004 and 2003, TE Products received distributions of $12.4 million, $10.3 million and $5.3 million, respectively, from MB Storage.  During the years ended December 31, 2005, 2004 and 2003, TE Products contributed $5.6 million, $21.4 million and $2.5 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 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, year-to-year variations of propane deliveries have occurred and will likely continue to occur.

Major Business Sector Markets

Our Products Pipeline System transports refined petroleum 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 petroleum 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 Todhunter, 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.

Market prices for refined petroleum products affect the demand in the markets served by our Downstream Segment.  Therefore, quantities and mix of products transported may vary.  Transportation tariffs of refined petroleum products vary among specific product types.  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 the cyclical nature of the refined products market.  Increases in the market price of jet fuel deliveries 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.  Distillate is more sensitive to short-term changes in price as customers shift from the use of trucking for freight transportation to railcars.  As a result, market price volatility may affect transportation volumes and revenues from period to period.

Our ability in the Downstream Segment to serve propane markets in the Northeast is enhanced by our marine import 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 an affiliate of DEFS.  During the years ended December 31, 2005, 2004 and 2003, revenues of $4.3 million, $4.3 million and $3.2 million, respectively, from an affiliate of DEFS were recognized pursuant to this agreement.

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Our major operations in the Downstream Segment consist of the transportation, storage and terminaling of refined petroleum products and LPGs along our mainline system. Product deliveries, in millions of barrels (MMBbls) on a regional basis, for the years ended December 31, 2005, 2004 and 2003, were as follows:

	Years Ended December 31,
	2005	2004	2003
Refined Products Mainline Transportation:
Central (1)	73.3	69.0	67.0
Midwest (2)	60.1	53.5	57.7
Ohio and Kentucky	27.3	29.9	29.4
Subtotal	160.7	152.4	154.1
LPGs Mainline Transportation:
Central, Midwest and Kentucky (1)(2)	26.3	27.0	23.4
Ohio and Northeast (3)	18.7	17.0	19.1
Subtotal	45.0	44.0	42.5
Total Mainline Transportation	205.7	196.4	196.6
Petrochemical Transportation (4)	3.6	3.6	3.4
Total Product Deliveries	209.3	200.0	200.0

(1)           Arkansas, Louisiana, Missouri and Texas.

(2)           Illinois and Indiana.

(3)           New York and Pennsylvania.

(4)Includes Dean North RGP volumes.  Petrochemical transportation between Mont Belvieu and Port Arthur, Texas, has not been included as those volumes are with one customer.

Customers

Our customers for the transportation of refined petroleum 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 Downstream Segment depends in large part on the level of demand for refined petroleum 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, 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 the year ended December 31, 2003, total revenues (and percentage of total revenues) attributable to the top 10 customers were $149.5 million (56%), of which Marathon accounted for approximately 18% of total Downstream Segment revenues.  During each of the three years ended December 31, 2005, 2004 and 2003, no single customer of the Downstream Segment accounted for 10% or more of total consolidated revenues.

Competition

The Products Pipeline System conducts operations without the benefit of exclusive franchises from government entities.  Interstate common carrier transportation services are provided through the system pursuant to tariffs filed with the FERC.

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The Products Pipeline System faces competition from numerous sources.  Because pipelines are generally the lowest cost method for intermediate and long-haul overland movement of refined petroleum 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.  Trucking costs, however, render that mode of transportation less competitive for longer hauls or larger volumes.  Barge fees for the transportation of refined products are generally lower than TE Products’ tariffs.  We face competition from rail and pipeline movements of LPGs from Sarnia, Ontario, Canada, and waterborne imports into terminals located along the upper East Coast.

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

We conduct business in our Upstream Segment through the following:

•TCTM;

•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% owned equity investment in Seaway Crude Pipeline Company (“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.  We commenced our Upstream Segment business in connection with the acquisition of assets from an affiliate of DEFS in November 1998.  Our Upstream Segment uses its asset base to aggregate crude oil and provide transportation and specialized services to its regional 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 from independent producers 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 crude oil for another grade of crude oil or at a different geographic location, as appropriate, in order to maximize margins or meet contract delivery requirements.

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 large industrial, refineries, 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, basis risks cannot be completely eliminated.

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Product deliveries on TCPL’s 100% owned pipeline systems, undivided joint interest pipelines and Seaway for the years ended December 31, 2005, 2004 and 2003, were as follows (in millions):

	Years Ended December 31,
	2005	2004	2003
Barrels Delivered:
Crude oil transportation	94.7	101.5	95.5
Crude oil marketing	203.3	177.3	159.7
Crude oil terminaling	110.3	113.2	115.1
Lubricants and chemicals (total gallons)	14.8	14.0	10.4
Seaway Barrels Delivered:
Long-haul	99.7	94.3	71.0
Short-haul	213.9	215.8	179.8

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, 2005:

Crude Oil Pipeline	Our Ownership	Operator	Description
Red River System	100%	TCPL	1,690 miles of pipeline; 1,491,000 barrels of storage – North Texas to South Oklahoma
South Texas System	100%	TCPL	1,000 miles of pipeline; 1,161,000 barrels of storage – South Central Texas to Houston, Texas area
West Texas Trunk System	100%	TCPL	275 miles of smaller diameter pipeline – connecting West Texas and Southeast New Mexico to TCPL’s Midland, Texas terminal
Cushing Terminal	100%	TCPL	15 tanks with 1,870,000 barrels of storage in Cushing, Oklahoma
Midland Station	100%	TCPL	10 tanks with 900,000 barrels of storage in Midland, Texas
Seaway (1)	50% general partnership interest	TCPL	500-mile, 30-inch diameter pipeline; 5,636,000 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 – Permian Basin (New Mexico and Texas) to Cushing, Oklahoma

(1)TCPL’s participation in revenues and expenses of Seaway vary as described below in “Seaway Crude Pipeline Equity Investment.”

The majority of the Red River System crude oil is delivered to Cushing, Oklahoma, via third party pipelines, or to two local refineries.  The majority of the crude oil on the South Texas System is delivered on a tariff basis to Houston area refineries.  The West Texas Trunk System is a fee based system which connects gathering systems to TCPL’s Midland, Texas, terminal.  Other crude oil assets, located primarily in Texas and Oklahoma, consist of 265 miles of pipeline and 295,000 barrels of storage capacity.

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Seaway Crude Pipeline Equity Investment

Seaway is a partnership between TEPPCO Seaway, L.P. (“TEPPCO Seaway”), a subsidiary of TCTM, and ConocoPhillips.  We operate the Seaway assets.  The 30-inch diameter, 500-mile pipeline transports crude oil from Freeport, Texas, on the U.S. Gulf Coast to Cushing, a central crude distribution point for the central United States and a delivery point for the New York Mercantile Exchange (“NYMEX”).  Three large diameter lines carry crude oil from the Freeport marine terminal to the adjacent Jones Creek Tank Farm, which has six tanks capable of handling approximately 2.6 million barrels of crude oil.  A 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 seven tanks with a combined capacity of approximately 3.3 million barrels.  Seaway is currently constructing two additional tanks at Texas City with a combined capacity of 1.2 million barrels, which are expected to be completed in April 2006.  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 July 20, 2000, through May 2002, we received 80% of revenue and expense of Seaway.  From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway.  Thereafter, we will receive 40% of revenue and expense of Seaway.  During the years ended December 31, 2005, 2004 and 2003, we received distributions from Seaway of $24.7 million, $36.9 million and $22.7 million, respectively.

Line Transfers, Pumpovers and Other

Our Upstream Segment provides trade documentation services to its customers, primarily at Cushing and Midland.  TCPL documents the transfer of crude oil in its terminal facilities between contracting buyers and sellers.  This line transfer documentation service is related to the trading activity by TCPL’s customers of NYMEX open-interest 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 an operational capacity of approximately 3.1 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

TCO purchases crude oil primarily from major integrated oil companies and independent oil producers.  Crude oil sales are primarily to major integrated oil companies and independent refiners.  Gross sales revenue of the Upstream Segment attributable to the top 10 customers was $5.9 billion (73%), $3.8 billion (70%) and $2.6 billion (67%) for the years ended December 31, 2005, 2004 and 2003, respectively.  For the years ended December 31, 2005, 2004 and 2003, Valero Energy Corp. (“Valero”) accounted for 15%, 17% and 18%, respectively, of the Upstream gross sales revenue.  For the years ended December 31, 2005, 2004 and 2003, Valero accounted for 14%, 16% 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 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

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pipelines.  The crude oil gathering and marketing business is 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:

•Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P., which gather and process natural gas;

•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 to customers in Colorado.  Our Midstream Segment also sells condensate liquid extracted from the natural gas stream to TCO.  We generally do not purchase or sell the natural gas gathered, NGLs transported or NGLs fractionated, except for the NGLs produced at one gas processing plant.  Our Midstream Segment has multiple long-term contracts with producers connected to the Jonah and Val Verde systems.  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.

Volume information for the years ended December 31, 2005, 2004 and 2003, is presented below:

	Years Ended December 31,
	2005	2004	2003
Gathering – Natural Gas – Jonah (billion cubic feet (“Bcf”))	415.2	354.5	303.0
Gathering – Natural Gas – Val Verde (Bcf)	180.7	144.5	158.3
Transportation – NGLs (million barrels)	61.1	59.5	57.9
Fractionation – NGLs (million barrels)	4.4	4.1	4.1

The majority of the recent growth in the Midstream Segment is due to the acquisition and expansions of Jonah in the Green River Basin in southwestern Wyoming and the acquisition of Val Verde in the San Juan Basin in New Mexico and Colorado.  Typically, new supplies of natural gas are necessary to offset the natural declines in production from wells connected to any gathering system.  The Jonah and Pinedale fields that are the focus of the Jonah system in Wyoming are both relatively young producing areas, characterized by long-lived production profiles with many years of significant growth potential ahead.

Jonah Gas Gathering System

We entered the natural gas gathering industry in late 2001 when we purchased Jonah from Alberta Energy Company.  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 Jonah system consists of approximately 580 miles of pipelines ranging in size from three inches to 24 inches in diameter, four compressor stations with an aggregate of approximately 125,000 horsepower and related metering facilities.  Gas gathered on the Jonah system is collected from approximately 930 producing wells in southwestern Wyoming’s Green River Basin, which is one of the most prolific natural gas basins in the United States.  Gas is also delivered to gas processing facilities owned by others.  From these processing facilities, the

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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.

Since the acquisition of Jonah for approximately $360.0 million, 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 million cubic feet per day (“MMcf/day”) to approximately 730 MMcf/day.

•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/day to approximately 880 MMcf/day.

•In 2003, the Jonah system was again expanded by a 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 250 MMcf/day gas processing plant near Opal, Wyoming.  Phase III was substantially completed during the fourth quarter of 2003, and the system was operational, with system capacity increasing to 1,180 MMcf/day at a cost of approximately $53.4 million.

•Additional capacity of 100 MMcf/day was completed during the fourth quarter of 2004, at a cost of approximately $13.0 million.

•A Phase IV expansion project, which is expected to increase system capacity to 1.5 billion cubic feet per day with the addition of 33,000 horsepower of compression and approximately 50 miles of pipeline, was substantially completed in December 2005, with total costs anticipated to be approximately $116.0 million.

We expect to complete the sale of our ownership interest in the Pioneer silica gel natural gas processing plant located in Opal, Wyoming, to Enterprise by the middle of 2006.  The proposed sale of the Pioneer plant was initiated because it is not an integral part of our Midstream Segment operations, and natural gas processing is not a core business.  The anticipated sales proceeds would be used to fund organic growth projects, retire debt, or for other general partnership purposes.

We expect to expand the Jonah system with a service date for such expansion being late 2006.  The Jonah Expansion will consist of the installation of approximately 90,000 horsepower of gas turbine compression at a new compression station, related new piping and certain related facilities, which is expected to increase capacity of the Jonah system from 1.5 billion cubic feet per day to 2.0 billion cubic feet per day.  We expect to enter into a joint venture agreement with Enterprise relating to the construction and financing of the expansion.  Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million).  Such advance will constitute a Subscription for an equity interest in the proposed Joint Venture.  We have the option to return to Enterprise up to 100% of the amount of the Subscription.  If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly.  The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.

Val Verde Gas Gathering System

On June 30, 2002, we purchased Val Verde for approximately $444.0 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc.  The acquisition increased our presence in the natural gas gathering industry.  DEFS managed and operated Val Verde 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.

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The Val Verde system consists of approximately 400 miles of pipeline ranging in size from four inches to 36 inches in diameter, 14 compressor stations operating over 93,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide.  The system has a gathering capacity of approximately one billion cubic feet of gas per day.  The Val Verde system gathers coal bed methane (“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, a long-term source of natural gas supply in North America.  The basin is one of the most prolific sources of CBM and also contains significant conventional gas reserves.  The system is one of the largest CBM gathering and treating facilities in the United States, gathering CBM from more than 500 separate wells throughout northern New Mexico and southern Colorado, and provides gathering and treating services pursuant to long-term contracts with approximately 40 natural gas producers in the San Juan Basin.  The Val Verde system delivers gas to several interstate pipeline systems serving the western United States, as well as local New Mexico markets.

In July 2003, the New Mexico Oil Conservation Division approved an application for infill drilling to allow two wells per standard 320-acre gas spacing unit in the Fruitland Coal Formation of the San Juan Basin.  Wells have been drilled on approximately half of the available locations on acreage dedicated to the Val Verde system.

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 104 MMcf/day from this interconnection in 2005.

In 2005, the Colorado Oil and Gas Conservation Commission approved two applications to double well density in the Fruitland Coal to one well per 80 acres.  One other operator in Colorado has submitted a similar application.  These downspacings could result in increased volumes to Val Verde from Colorado.

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, 2005, is set forth in the following table:

NGL Pipeline	Capacity (barrels/day)	Description
Chaparral	135,000	845 miles of pipeline – West Texas and New Mexico to Mont Belvieu, Texas
Quanah	22,000	180 miles of pipeline – Sutton County, Texas to the Chaparral Pipeline near Midland, Texas
Panola	46,000	189 miles of pipeline – Carthage, Texas to Mont Belvieu, Texas
San Jacinto	12,000	34 miles of pipeline – Carthage, Texas to Longview, Texas
The southern portion of the Dean Pipeline	10,000	155 miles of pipeline – South Texas to Point Comfort, Texas
Wilcox	7,500	103 miles of pipeline – Southeast Texas

On March 1, 2002, we purchased the Chaparral NGL system for approximately $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P.  The Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu.  The Panola Pipeline and San Jacinto Pipeline originate at an East Texas Plant Complex in Panola County, Texas, and transport NGLs for major integrated oil and gas companies.  The southern portion of the Dean Pipeline originates in South Texas and transports NGLs for one customer into its pipeline at Point Comfort, Texas.  The Wilcox Pipeline transports NGLs for a customer from its natural gas processing plant and is currently supported by a throughput agreement with that customer through November 2006.

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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 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.

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 DEFS and its affiliates, affiliates of EPCO, and other major integrated oil and gas companies.  Condensate sales from the Jonah system are primarily to TCO.

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 (formerly Alberta Energy Company), 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.  At December 31, 2003, the Midstream Segment had approximately 70 customers.  Revenue attributable to the top 10 customers was $155.9 million (84%) for the year ended December 31, 2003, of which EnCana Corporation, Burlington Resources Inc. and DEFS and its affiliates accounted for approximately 21%, 18% and 14%, respectively, of revenues of the Midstream Segment.  During each of the three years ended December 31, 2005, 2004 and 2003, no single customer of the Midstream Segment accounted for 10% or more of total consolidated revenues.

Competition

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.

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.

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, totaled $220.6 million for the year ended December 31, 2005.  Revenue generating projects include those projects which expand service into new markets or expand capacity into

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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, 2005 (in millions):

	Revenue Generating		Sustaining Existing Operations		System Upgrades		Capitalized Interest		Total
Downstream Segment	$	22.6	$	19.6	$	13.4	$	3.0	$	58.6
Midstream Segment	112.9		1.4		2.6		2.9		119.8
Upstream Segment	18.2		19.6		2.4		0.8		41.0
Other	—		0.2		1.0		—		1.2
Total	$	153.7	$	40.8	$	19.4	$	6.7	$	220.6

Revenue generating capital spending by the Downstream Segment totaled $22.6 million and was used primarily for construction of a new truck loading terminal in Bossier City, Louisiana, the expansion of our pipeline system extending from Seymour to Indianapolis, Indiana, additional propane capacity in our Northeast market and the initial phase of integration of assets we acquired from Genco.  Revenue generating capital spending by the Midstream Segment totaled $112.9 million and was used primarily for the expansion of the Jonah system and additional well connections on both the Jonah and Val Verde systems.  Revenue generating capital spending by the Upstream Segment totaled $18.2 million and was used primarily for the expansion of our pipelines and facilities in West Texas and Oklahoma, including integration of assets we acquired from BP and Koch.  In order to sustain existing operations, we spent $19.6 million for various Downstream Segment pipeline projects, $1.4 million for the Midstream Segment and $19.6 million for Upstream Segment facilities.  An additional $19.4 million was spent on system upgrade projects among all of our business segments.

We estimate that capital expenditures, excluding acquisitions, for 2006 will be approximately $209.7 million (including $6.0 million of capitalized interest).  We expect to spend approximately $147.4 million for revenue generating projects.  Capital spending on revenue generating projects and facility improvements will include approximately $70.9 million for the expansion of our Downstream Segment facilities.  We expect to spend $16.3 million to expand our Upstream Segment pipelines and facilities in West Texas and Oklahoma and approximately $60.2 million to expand our Midstream Segment assets, with further expansions on our Jonah system.  We expect to spend approximately $37.8 million to sustain existing operations, 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 $18.5 million to improve operational efficiencies and reduce costs among all of our business segments.  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

Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the provisions of the Interstate Commerce Act, the Energy Policy Act of 1992 and rules and orders promulgated thereunder.  FERC regulation requires that interstate petroleum products and crude oil pipeline rates be posted publicly and that these rates be “just and reasonable” and nondiscriminatory.

Rates of interstate petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI”).  Effective as of February 24, 2003, the FERC modified the index from PPI minus 1% to PPI without any negative adjustment.  That decision was upheld by the United States Court of Appeals for the District of Columbia Circuit on April 9, 2004.   The FERC’s next 5-year review of the index is currently underway.  The Commission has proposed to continue use of the unadjusted PPI; in response, the Association of Oil Pipe Lines (“AOPL”) submitted comments supporting an index based on the PPI plus at least 1.3 percent.  Various parties have filed comments in support of both the FERC’s and AOPL’s proposals.  A final decision by FERC, which will be effective as of July 1, 2006, is pending.

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As an alternative to using the PPI Index, interstate petroleum products and crude oil pipeline companies 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.  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.

On March 26, 2004, a decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”).  The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged.  In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates.  The elements identified in the decision are volume changes, allowed total return and total cost-of-service (including major cost elements such as rate base, tax rates and tax allowances, among others).  The FERC did reject, however, the use of changes in tax rates and income tax allowances as stand-alone factors.  Judicial review of that decision, which has been sought by a number of parties to the case, is currently pending before the U.S. Court of Appeals for the District of Columbia Circuit.  We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.

On July 20, 2004, the District of Columbia Circuit issued an opinion in BP West Coast Products LLC v. FERC.  In reviewing a series of orders involving SFPP, L.P., the court held among other things that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its income attributable to partnership interests owned by corporate partners.  Under the FERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-service filing for the percentage of its net operating (pre-tax) income attributable to partnership units held by corporations, and was denied an income tax allowance equal to the percentage attributable to partnership units held by non-corporate partners.  The court remanded the case back to the FERC for further review.  As a result of the court’s remand, on May 4, 2005, the FERC issued its Policy Statement on Income Tax Allowances, which permits regulated partnerships, limited liability companies and other pass-through entities an income tax allowance on their income attributable to any owner that has an actual or potential income tax liability on that income, regardless whether the owner is an individual or corporation.  If there is more than one level of pass-through entities, the regulated company income must be traced to where the ultimate tax liability lies.  The Policy Statement is to be applied in individual cases, and the regulated entity bears the burden of proof to establish the tax status of its owners.  On December 16, 2005, the FERC issued the first of those decisions, in an order involving SFPP (the “SFPP Order”).  The SFPP Order confirmed that a master limited partnership 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.  The SFPP Order remains subject to further administrative proceedings (including compliance filings by SFPP and possible rehearing requests), as well as potential judicial review.  The ultimate outcome of the FERC’s inquiry on income tax allowance should not affect our current rates and rate structure because our rates are not based on cost-of-service methodology.  However, the outcome of the income tax allowance would become relevant to us should we (i) elect in the future to use cost-of-service to support our rates, or (ii) be required to use such methodology to defend our indexed rates.

The natural gas gathering operations of the Jonah and Val Verde 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, the 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 Jonah and Val Verde systems.  In addition,

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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 operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment and various safety matters. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities.  We believe our operations have been and are in material compliance with applicable environmental and safety laws and regulations, and that compliance with existing environmental laws and regulations are not expected to have a material adverse effect on our competitive position, financial positions, results of operations or cash flows.  However, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.  At December 31, 2005, we have an accrued liability of $2.4 million related to sites requiring environmental remediation activities.

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.

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.

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.

Air Emissions

Our operations are subject to the Federal Clean Air Act (the “Clean Air Act”) and comparable state laws.  Amendments to 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,

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which are subject to increasing regulation under the Clean Air Act.  The Clean Air Act requires federal operating permits for major sources of air emissions.  Under this program, a federal operating permit (a “Title V” permit) may be issued.  The permit acts as an umbrella that includes other federal, state and local preconstruction and/or operating permit provisions, emission standards, grandfathered rates and record keeping, reporting and monitoring requirements in a single document. The federal operating permit is the tool that the public and regulatory agencies use to review and enforce a site’s compliance with all aspects of clean air regulation at the federal, state and local level. We have completed applications for the facilities for which these regulations apply.

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. 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.

Superfund

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.

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

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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 we have substantially complied with our IMP and all assessment requirements imposed by the DOT regulations.

Safety Matters

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

The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations.  Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request.  We are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.  These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves certain flammable liquid or gas.  We believe we are in material compliance with the OSHA regulations.

Employees

The Partnership does not have any employees.  However, for organizational purposes, TEPPCO GP, TEPPCO NGL Pipelines, LLC and TEPPCO Crude GP, LLC have officers and directors, who are employees of EPCO.  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 and our subsidiaries.  As of December 31, 2005, EPCO had 1,270 employees dedicated to managing and operating us and our subsidiaries.  None of these employees are represented by labor unions, and our relations with these employees are good.

Available Information

We file annual, quarterly and other reports and other information with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”).  You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549.  You may obtain additional information about 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, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

We also make available free of charge on or through our Internet website (http://www.teppco.com) or through our Investor Relations Department (1-800-659-0059) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other information statements and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

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Item 1A.   Risk Factors

Unitholders and potential investors in our Units should carefully consider the following risk factors, in addition to other information in this Report.  We are identifying these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by or on behalf of us.  We are relying upon the safe-harbor for forward-looking statements and any such statements made by or on behalf of us are qualified by reference to the following cautionary statements, as well as to those set forth elsewhere in this Report.

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.

We are negotiating terms of a Joint Venture agreement with Enterprise relating to the construction and financing of the Jonah Expansion.  If we fail to timely consummate a Joint Venture agreement before the completion of the Jonah Expansion, then the terms of the Joint Venture will be determined by non-appealable, binding arbitration.  We cannot assure you that any such terms determined by arbitration will be economically favorable to us.

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 have no recourse under applicable indemnification provisions.

Our debt instruments may limit our ability to borrow additional funds and increase the costs of borrowing.

We are subject to restrictions that may limit our ability to structure or refinance existing or future debt and may prevent us from entering into transactions.  These restrictions include the maintenance of financial ratios, as well as limits on our ability to incur additional indebtedness.  These financial restrictions could result in higher costs of borrowing.  Additionally, rising short-term interest rates may also increase our financing costs.

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

Distributions are dependent on the amount of cash we generate and may fluctuate based on our performance.  The cash that is distributed will vary based on many factors, some of which are outside of our control.  Cash distributions are based on cash flow measures, and are not determined by our level of profitability.

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.

We expect to expand the capacity of our existing natural gas gathering systems through the construction of additional facilities. The construction of gathering facilities requires the expenditure of significant amounts of capital, which may exceed our estimates.  Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction.  Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize.  As a result, there is the risk that new 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.

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

The FERC, pursuant to the Interstate Commerce Act, regulates the tariff rates for our interstate common carrier pipeline operations. To be lawful under that Act, interstate tariff rates must be just and reasonable and not unduly discriminatory.  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 under rates ultimately found unlawful.  The FERC 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.

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.  Additional challenges to our tariff rates could be filed with the FERC.

Although our intrastate 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 as it considers proposals by natural gas pipelines to allow negotiated gathering rates that are not limited by rate ceilings, pipeline rate case proposals and revisions to rules and policies that may affect our shippers’ rights of access to interstate natural gas transportation capacity, it could have an adverse effect on the rates we are able to charge in the future.

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

In a 1995 decision involving an unrelated oil pipeline limited partnership, the FERC partially disallowed the inclusion of income taxes in that partnership’s cost of service.  In another FERC proceeding involving a different oil pipeline limited partnership, the FERC held that the oil pipeline limited partnership may not claim an income tax allowance for income attributable to non-corporate limited partners, both individuals and other entities.  Because corporations are taxpaying entities, income taxes are generally allowed to be included as a corporate cost-of-service. While we currently do not use the cost-of-service methodology to support our rates, these decisions might adversely affect us should we elect in the future to use the cost-of-service methodology or should we be required to use that methodology to defend our rates if challenged by our customers.  This could put us at a competitive disadvantage.

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 is 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 natural gas liquids.

New supplies of natural gas are necessary to offset natural declines in production from wells connected to our gathering system 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.

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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.  We utilize letters of credit and guarantees for certain of our receivables.  However, these procedures and policies do not fully eliminate customer credit risk.  During each of the years ended December 31, 2005, 2004 and 2003, we expensed less than $1.0 million of uncollectible receivables.

Our crude oil marketing business involves risks relating to product prices.

Our crude oil operations subject us to pricing risks as we buy and sell crude oil for delivery on our crude oil pipelines.  These are the risks that price relationships between delivery points, classes of products or delivery periods will change after our initial purchases and before physical delivery of the crude oil.

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 own pipeline systems.  Such reduced throughput may adversely impact our profitability.

Reduced demand could affect shipments on the pipelines.

Our products pipeline business depends in large part on the demand for refined products and LPGs in the markets served by our pipelines.  Reductions in that demand adversely affect our pipeline business.   Market demand varies based upon the different end uses of the products we ship.  We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation or technological advances in fuel economy and energy-generation devices, all of which could reduce the demand for refined petroleum products and LPGs in the areas we serve.  Demand for gasoline, which has in recent years accounted for approximately forty percent 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 twenty percent 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.

Our gathering system profits and cash flow depend on the volumes of natural gas produced from the fields served by our gathering systems and are subject to factors beyond our control.

Regional production levels drive the volume of natural gas gathered on our system.  We cannot influence or control the operation or development of the gas fields we serve.  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; and

•industry changes, including the effect of consolidations or divestitures.

Any declines in the volumes of natural gas delivered for gathering on our system will adversely affect our revenues and could, if sustained or pronounced, materially adversely affect our financial position or results of operations.

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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 current operations as well as the construction of new facilities are subject to federal, state and local laws and regulations relating to protection of the environment and occupational health and safety.  There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to permit requirements, our handling of the products we gather or transport, air emissions related to our operations, historical industry operations, waste disposal practices and the construction of new facilities in environmentally protected areas, some of which may be material.  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.  In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material.

Various state and federal governmental authorities including the U.S. Environmental Protection Agency, the Bureau of Land Management, the Department of Transportation and the Occupational Safety and Health Administration 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 processing, 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.  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.

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, specifically 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 covered by insurance.

Our operations are subject to the many hazards inherent in the transportation of refined petroleum products, LPGs and petrochemicals, the transportation of crude oil and the gathering, compressing, treating and processing of natural gas and NGLs and in the storage of residue gas, including ruptures, leaks and fires.  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.  We are not fully insured against all risks incident to our business.  If a significant accident or event occurs that is not fully insured, it could adversely affect our financial position or results of operations.

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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.  We are currently searching for a permanent chief executive officer.  Our chief financial officer was appointed in January 2006, and our general counsel will be appointed effective March 1, 2006, each having approximately twenty or more years of relevant experience.  However, while retention plans are in place for certain senior executives, any future unplanned departures could have a material adverse effect on our business, financial conditions and results of operations.  Legacy senior executives have compensation agreements in place; however, new leadership appointments are not party to any compensation agreements.

Risks Relating to Our Partnership Structure

We are a holding company and depend entirely on our operating subsidiaries’ distributions to service our debt obligations.

We are a holding company with no material operations.  If we cannot receive cash distributions from our operating subsidiaries, we will not be able to meet our debt service obligations.  Our operating subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions, which could further limit each operating subsidiary’s ability to make distributions to us.

The debt securities issued by us and the guarantees issued by our subsidiary guarantors will be structurally subordinated to the claims of the creditors of our operating subsidiaries who are not guarantors of the debt securities.   Our non-guarantor operating subsidiaries currently have no indebtedness for borrowed money.  Holders of the debt securities will not be creditors of our operating partnerships that have not guaranteed the debt securities.  The claims to the assets of non-guarantor operating subsidiaries derive from our own partnership interests in those operating subsidiaries.  Claims of our non-guarantor operating subsidiaries’ creditors will generally have priority as to the assets of those operating subsidiaries over our own partnership interest claims and will therefore have priority over the holders of our debt, including the debt securities.  Our non-guarantor operating subsidiaries’ creditors may include:

•general creditors,

•trade creditors,

•secured creditors,

•taxing authorities, and

•creditors holding guarantees.

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.  The issuance could negatively affect the amount of cash distributed to unitholders and the market price of our Units.  At our current level of cash distributions, our General Partner receives as incentive distributions approximately 50% of any incremental increase in our distributions.  As a result, acquisitions funded through the issuance of additional Units may benefit our General Partner more than our unitholders.

Our tax treatment depends on our status as a partnership for federal income tax purposes and our exemption from state-level taxation by states.

If we were treated as a corporation, cash distributions would be reduced substantially.  One of the primary benefits of investing in our Units is dependent on the treatment of our entity as a partnership for federal income tax purposes.   Currently, to maintain our partnership status under the “Qualifying Income Exception”, we must derive 90% of annual gross income from certain activities.   We may not be able to meet this requirement despite our best

27

efforts.  Additionally, the legal requirements for partnership status may change and we may not be able to meet the new standard.

Several states are considering subjecting partnerships to tax at the entity level.  If a state imposed tax on us at the entity level, the cash available for distributions would be reduced.

Some of our executive officers and directors face potential conflicts of interest in managing our business.

Certain of our executive officers and directors are also officers and/or directors of EPCO and other affiliates of EPCO.  These relationships may create conflicts of interest regarding corporate opportunities and other matters.  The resolution of any such conflicts may not always be in our or our unitholders’ best interests.  In addition, these overlapping executive officers and directors allocate their time among us, EPCO and other affiliates of EPCO.  These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.  See Item 10 of this Report for more detailed information.

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 member.  At the same time, the General Partner has duties to manage us in a manner that is beneficial to us.  Therefore, the General Partner’s duties to us may conflict with the duties of its officers and directors to its member.  Provisions of our partnership agreement, the partnership agreements for each of our operating partnerships and/or the administrative services agreement provide for a standard of care that may allow our General Partner to approve actions in the context of possible conflicts, which under state law a corporation would be required to analyze with greater scrutiny.  Possible conflicts may include, among others, the following:

•decisions of our General Partner regarding the amount and timing of cash expenditures, borrowings and issuances of additional Units or other equity securities can affect the amount of incentive compensation payments we make to our General Partner;

•decisions of our General Partner regarding our acquisitions, expansions or business strategy, which may provide benefits to the General Partner and its affiliates;

•under our partnership agreement we reimburse the General Partner for the costs of managing and operating us;

•under our partnership agreement, it is not a breach of our General Partner’s fiduciary duties for affiliates of our General Partner to engage in activities that compete with us;

•the directors and officers of our General Partner are allowed to resolve conflicts of interest involving us and EPCO and its affiliates;

•the directors and officers of our General Partner are allowed to take into account the interests of parties other than us, such as EPCO and its affiliates, in resolving conflicts of interest;

•any resolution of a conflict of interest by the directors and officers of our General Partner not made in bad faith and that is fair and reasonable to us shall be binding on the partners and shall not be a breach of our partnership agreement;

•we do not have any employees and we rely solely on employees of EPCO;

•our partnership agreement does not restrict the General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; and

•the directors and officers of our General Partner and EPCO control the enforcement of obligations owed to us by our general partner,  EPCO and its affiliates.

In addition, the partnership agreements grant broad rights of indemnification to the General Partner and its directors, officers, employees and affiliates for acts taken in good faith in a manner believed to be in or not opposed to our best interests.  We have significant business relationships with entities controlled by Dan L. Duncan, including EPCO and its affiliates.  For detailed information on these relationships and related transactions with these entities, see Item 13 included within this Report.

Unitholders have limited voting rights and control of management.

Our General Partner manages and controls our activities and the activities of our operating partnerships.  Unitholders have no right to elect the General Partner or the directors of the General Partner on an annual or other ongoing basis.  However, if the General Partner resigns or is removed, its successor may be elected by holders of a majority of the Units.  Unitholders may remove the General Partner only by a vote of the holders of at least 66 2/3% of the Units and only after receiving state regulatory approvals required for the transfer of control of a public utility.  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.

If EPCO or other entities that own or control our General Partner are presented with certain business opportunities, Enterprise will have the first right to pursue such opportunities.

Our previous relationship with DEFS and Duke Energy from time to time resulted in business opportunities for us.  We do not know whether similar opportunities will be available from EPCO or its affiliates.  EPCO, Enterprise, DFI and certain affiliated entities (collectively, the “Group”), our General Partner and us, are parties to an administrative services agreement that provides, among other things, that neither the Group, on one hand, nor our General Partner, on the other hand, have any obligation to present business opportunities to the other.

To the extent that our General Partner shares executive offices or other personnel with EPCO and its affiliates, there may be conflicts in the allocation of their time and compensation costs between our business and the business of EPCO and its other affiliates.

Our General Partner manages our operations and activities.  We have entered into an administrative services agreement with EPCO and its affiliates to provide all administrative, operational and other services, including employee support, for us and our General Partner.  Some of the EPCO employees providing these services

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to us may also have duties and responsibilities related to EPCO and its affiliates, including Enterprise.  The services performed by these shared personnel will generally be limited to non-commercial functions, including but not limited to human resources, information technology, financial and accounting services and legal services.  EPCO may encounter conflicts of interest in allocating the available time and employee costs of shared personnel between us and other EPCO affiliates.

We do not have an independent compensation committee and our independent directors do not deliberate, decide or approve recommendations related to the compensation of our executive officers or other key employees.  The determination of executive officer and key employee compensation could involve conflicts of interest resulting in economically unfavorable arrangements for us.

Item 1B.   Unresolved Staff Comments

None.

Item 3.      Legal Proceedings

In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the General Partner and Partnership).In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water.  They further contend that the release caused damages to the plaintiffs.  In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages.  On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards 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 Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all 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 have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance.  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 May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana.  There are numerous plaintiffs identified in the action that are alleged to have suffered damages as a result of alleged exposure to asbestos-containing products and materials.  According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor.  This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual.  The individual’s claims involve numerous employers and alleged job

29

sites.  The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit.  The plaintiffs have not stipulated the amount of damages that they are seeking in this suit.  We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit.  We cannot estimate the loss, if any, associated with this pending lawsuit.  We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

On August 5, 2005, we were named as a third-party defendant in a matter styled ConocoPhillips, et al. v. BP Amoco Seaway Products Pipeline Company as filed in the 55^th Judicial District of Harris County, Texas.  ConocoPhillips alleges a right to indemnity from BP Amoco Seaway Products Pipeline Company (“BP Amoco”) for tax liability incurred by ConocoPhillips as a result of the reverse merger of Seaway Pipeline Company (the “Original Seaway Partnership”).  The reverse merger of the Original Seaway Partnership was undertaken in preparation for our purchase of ARCO Pipe Line Company pursuant to the Amended and Restated Purchase Agreement (the “Purchase Agreement”) dated May 10, 2000, between us and Atlantic Richfield Company. BP Amoco has claimed a right to indemnity from us under the Purchase Agreement should BP Amoco have any indemnity liability to ConocoPhillips.  ConocoPhillips alleged the income tax liability to be approximately $4.0 million.  On January 20, 2006, we entered into a settlement agreement with BP Amoco dismissing and resolving all of BP Amoco’s claims. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26^th Judicial District Court of Bossier Parish, Louisiana.  The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants.  The former refinery is located near our Bossier City facility.  Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property.  The plaintiffs have recently pursued certification as a class and have significantly increased their demand to approximately $175.0 million.  This revised demand includes amounts for environmental restoration not previously claimed by the plaintiffs.  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.

In 1994, the Louisiana Department of Environmental Quality (“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 in 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, 2005, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility.  We do not expect that the completion of the remediation program 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.  We are in discussions with the DOJ regarding this matter and have responded to its request for additional information.  The maximum statutory penalty proposed by the DOJ for this alleged violation of the CWA is $2.1 million.  We do not expect a civil 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 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 the General Partner may substantially lessen competition.  The General Partner is cooperating fully with this investigation.

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. On or about February 22, 2006, we received verbal notification from a representative of the Occupational Safety and Health Administration that they intend to serve us with a citation arising out of this incident.  At this time, we have not received any citation, and we cannot predict with certainty the amount of any fine or penalty associated with any such citation; however, we do not expect any fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.

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

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

None.

PART II

Item 5.      Market for Registrant’s Units and Related Unitholder Matters

Our Units are listed and traded on the New York Stock Exchange under the symbol “TPP”.  The high and low trading prices of our Units in 2005 and 2004, respectively, as reported in The New York Times, were as follows:

	2005				2004
Quarter	High		Low		High		Low
First	$	45.45	$	38.53	$	41.99	$	34.50
Second	44.72		39.85		42.05		32.75
Third	42.75		39.61		41.75		37.96
Fourth	41.15		33.15		42.36		37.44

Based on the information received from our transfer agent and from brokers and nominees, we estimate the number of beneficial holders of our Units as of February 24, 2006, to be approximately 89,000.

The quarterly cash distributions for the years ended December 31, 2005 and 2004, were as follows:

Record Date	Payment Date	Amount Per Unit
April 30, 2004	May 7, 2004	$	0.6625
July 30, 2004	August 6, 2004	0.6625
October 29, 2004	November 5, 2004	0.6625
January 31, 2005	February 7, 2005	0.6625
April 29, 2005	May 6, 2005	$	0.6625
July 29, 2005	August 5, 2005	0.675
October 31, 2004	November 7, 2005	0.675
January 31, 2006	February 7, 2006	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 11 in the Notes to the Consolidated Financial Statements).  We expect to continue to pay comparable quarterly cash distributions, assuming no adverse change in our financial position, results of operations or cash flows.

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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.

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 December 31, 2005, 2004 and 2003 and for the years ended December 31, 2005, 2004 and 2003, is derived from audited consolidated financial statements, which is included elsewhere in this Report.  The selected financial data for the years ended December 31, 2002 and 2001, 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 these periods.  With the exception of December 31, 2005, the financial information shown below has been restated to reflect a restatement adjustment for an accounting correction (see also “Explanatory Note” in this Form 10-K and Note 20 in the Notes to the Consolidated Financial Statements).  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.

	Years Ended December 31,
	2005			2004			2003			2002 (1)			2001 (2)
				(as restated)			(as restated)			(as restated)			(as restated)
										(unaudited)			(unaudited)
	(in thousands, except per Unit amounts)
Income Statement Data:
Operating revenues:
Sales of petroleum products	$	8,072,287		$	5,434,127		$	3,766,651		$	2,823,800		$	3,219,816
Transportation – Refined products	144,552			148,166			138,926			123,476			139,315
Transportation – LPGs	96,297			87,050			91,787			74,577			77,823
Transportation – Crude oil	37,614			37,177			29,057			27,414			24,223
Transportation – NGLs	43,915			41,204			39,837			38,870			20,702
Gathering – Natural gas	152,797			140,122			135,144			90,053			8,824
Mont Belvieu operations	—			—			—			15,238			14,116
Other revenues	71,026			70,346			54,430			48,735			51,594
Total operating revenues	8,618,488			5,958,192			4,255,832			3,242,163			3,556,413
Purchases of petroleum products	7,995,433			5,372,971			3,711,207			2,772,328			3,172,805
Operating expenses	289,199			286,247			255,437			213,556			185,918
Depreciation and amortization	111,341			112,894			100,728			86,032			45,899
Gains on sales of assets	(668		)	(1,053		)	(3,948		)	—			—
Operating income	223,183			187,133			192,408			170,247			151,791
Interest expense – net	(81,861		)	(72,053		)	(84,250		)	(66,192		)	(62,057		)
Equity earnings	20,094			22,148			12,874			8,853			17,611
Other income – net	1,135			1,320			748			1,827			1,999
Net income (as restated) (3)	162,551			138,548			121,780			114,735			109,344
Amortization of goodwill	—			—			—			—			1,013
Adjusted net income	$	162,551		$	138,548		$	121,780		$	114,735		$	110,357
Basic and diluted income per Unit: (4)
As reported	$	1.71		$	1.56		$	1.47		$	1.74		$	2.19
Amortization of goodwill	—			—			—			—			0.02
Adjusted net income per Unit	$	1.71		$	1.56		$	1.47		$	1.74		$	2.21

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	December 31,
	2005		2004		2003		2002 (1)		2001 (2)
			(as restated)		(as restated)		(as restated)		(as restated)
							(unaudited)		(unaudited)
	(in thousands)
Balance Sheet Data:
Property, plant and equipment – net	$	1,960,068	$	1,703,702	$	1,619,163	$	1,587,824	$	1,180,461
Total assets	3,680,538		3,186,284		2,934,480		2,765,900		2,065,952
Long-term debt (net of current maturities)	1,525,021		1,480,226		1,339,650		1,377,692		715,842
Total debt	1,525,021		1,480,226		1,339,650		1,377,692		1,075,842
Class B Units held by related party	—		—		—		103,234		105,678
Partners’ capital	1,201,370		1,011,103		1,102,809		889,449		543,737

	Years Ended December 31,
	2005			2004			2003			2002 (1)			2001 (2)
				(as restated)			(as restated)			(as restated)			(as restated)
										(unaudited)			(unaudited)
	(in thousands, except per Unit amounts)
Cash Flow Data:
Net cash provided by operating activities	$	254,505		$	267,167		$	242,424		$	234,917		$	169,148
Capital expenditures to sustain existing operations	(40,783		)	(41,733		)	(32,864		)	(21,978		)	(18,578		)
Distributions paid	(251,101		)	(233,057		)	(202,498		)	(151,853		)	(104,412		)
Distributions paid per Unit (4)	$	2.68		$	2.64		$	2.50		$	2.35		$	2.15

(1)Data reflects the operations of the Chaparral and Val Verde assets acquired on March 1, 2002 and June 30, 2002, respectively.

(2)Data reflects the operations of the Jonah assets acquired on September 30, 2001.

(3)See Note 20 of the Notes to Consolidated Financial Statements for the effect of the restatement adjustment on net income for the years ended December 31, 2004 and 2003.  The restatement adjustment decreased net income for the year ended December 31, 2002, by $3.1 million, or $0.05 per Unit, and increased net income for the year ended December 31, 2001, by $0.2 million, or $0.01 per Unit, respectively.

(4)Per Unit calculation includes 7,750,000 Units issued in 2001, 13,359,597 Units issued in 2002 and 9,188,957 Units issued in 2003, net of retirement of Class B Units of 3,916,547.  No Units were issued in 2004.  In 2005, 6,965,000 Units were issued.

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.

•Restatement of Consolidated Financial Statements – Discusses the restatement adjustment.

•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 consolidated statements of income.

•Financial Condition and Liquidity – Analyzes cash flows and financial position.

•Other Considerations – Addresses available source of liquidity, trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.

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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.  When used in this discussion, 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.  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.  You should not place undue reliance on these forward-looking statements, which speak only as of the date of this Report.  Except as required by law, we undertake no obligation to publicly update or revise any of the forward-looking statements in this discussion after the date of this Report.

Overview of Business

Our corporate business strategy is to grow sustainable cash flow and 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, to target accretive and complementary acquisitions and expansion opportunities that provide attractive growth potential; to maintain an appropriate mix of assets; and to operate in a safe, efficient and environmentally responsible manner.

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 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 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.

Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services.  The two largest operating expense items of the Downstream Segment are labor and electric power.  We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons.  LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating.  Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports RGP from Mont Belvieu to Point Comfort, Texas.  Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6 in the Notes to the Consolidated Financial Statements).

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 of the crude oil to local refineries, marketers or other end users.  Our Upstream Segment also includes our equity investment in Seaway (see Note 6 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.

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Our Midstream Segment revenues are earned from the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde; transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; and the fractionation of NGLs in Colorado.

We continued building a base for long-term growth by enhancing existing systems and pursuing new business opportunities.  We increased throughput on our pipeline systems, constructed new pipeline and gathering systems, and expanded and upgraded our existing infrastructure.  In 2005, our major accomplishments included:

•Substantially completing the Phase IV expansion on the Jonah system, increasing capacity to approximately 1.5 billion cubic feet per day.

•Benefiting from a full year of revenues and volumes from the connection to a gathering system in Colorado on Val Verde.

•Opening a refined products truck loading terminal in Bossier City, Louisiana, to provide the Northwest Louisiana and East Texas markets with access to 20,000 additional barrels per day of delivery capacity of Gulf Coast sourced gasoline and diesel fuel.

•Expanding our Gulf Coast refined products infrastructure, which included the acquisition of a 90-mile pipeline and 5.5 million barrels of storage in the Houston, Texas, area.

•Continuing the expansion of our Northeast LPGs pipeline system.

•Acquiring a refined products terminal and truck rack in North Little Rock, Arkansas, to complement our existing infrastructure.

•Acquiring 945,000 barrels of crude oil storage in Cushing, Oklahoma, which provides additional terminaling and storage opportunities for Mid-Continent refiners, and enables us to strengthen our gathering and marketing business.

•Integrating a 158-mile crude oil pipeline in Southeast Texas into our South Texas system, which will provide increased market flexibility for our customers and future growth opportunities.

In 2006, we remain confident that our business strategy will provide continued growth in earnings and cash distributions.  This growth potential is based on:

•Continued development of the Jonah system which serves the Jonah and Pinedale fields in our Midstream Segment, as we increase throughput on the Jonah system with the completion of our Phase IV expansion in February 2006.  Through the Jonah Expansion, we expect to increase the capacity to 2 billion cubic feet per day, which should be completed in the fourth quarter of 2006.

•Growth in our Downstream Segment, resulting from both our expanding gathering system capacity and the continued capacity of Centennial, additional acquisitions and the growing demand for Gulf Coast sourced product.  Centennial continues to provide us with additional system capacity to move additional refined products to the Chicago, Illinois, market areas.

•Substantially completing an expansion project to increase delivery capacity of gasoline and diesel fuel to the Indianapolis, Indiana, and Chicago market areas.

•Strengthening our existing market base in our Upstream Segment, as we integrate our 2005 acquisitions into our existing asset base and concentrate on future acquisitions to expand our core operating areas.

•Continued growth in our Upstream Segment, resulting from expansions of our West Texas systems and storage capacity at Cushing.

•Adding new volumes and improving the operating efficiency of the Val Verde system in New Mexico’s San Juan Basin, through new connections of conventional and Colorado coal seam gas.

•Increasing the throughput on our NGL systems.

Our Upstream Segment’s performance will be impacted by a decrease in our participation ratio in the revenue and expense of Seaway, in accordance with the partnership agreement.  From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway.  Thereafter, we will receive 40% of revenue and expense of Seaway.  On a pro-rated basis, our share of revenue and expense of Seaway will decrease to approximately 47% for 2006.

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We expect to complete the sale of our ownership interest in the Pioneer silica gel natural gas processing plant located in Opal, Wyoming, to Enterprise by the middle of 2006.  The proposed sale of the Pioneer plant was initiated because it is not an integral part of our Midstream Segment operations, and natural gas processing is not a core business.  The anticipated sales proceeds would be used to fund organic growth projects, retire debt, or for other general partnership purposes.  The margin of the Midstream Segment, calculated as revenues generated from the processing arrangements at the Jonah Pioneer plant, less purchase of gas, will be reduced in 2006 as a result of the anticipated sale of the Pioneer plant.  We do not expect that the sale of the Pioneer plant will have a material adverse effect on our financial condition, results of operations or cash flows.

We expect to expand the Jonah system with a service date for such expansion being late 2006.  We expect to enter into a joint venture agreement with Enterprise relating to the construction and financing of the expansion.  Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million).  Such advance will constitute a Subscription for an equity interest in the proposed Joint Venture.  We have the option to return to Enterprise up to 100% of the amount of the Subscription.  If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly.  The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.

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.

Restatement of Consolidated Financial Statements

We are restating our previously reported consolidated financial statements for the fiscal years ended December 31, 2003 and 2004.  For the impact of the restated consolidated financial results for the quarterly periods during the years ended December 31, 2005 and 2004, see Note 20 in the Notes to the Consolidated Financial Statements.  We have determined that our method of accounting for the $33.4 million excess investment in Centennial, previously described as an intangible asset with an indefinite life, and the $27.1 million excess investment in Seaway, previously described as equity method goodwill, was incorrect.  Through our accounting for these excess investments in Centennial and Seaway as intangible assets with indefinite lives and equity method goodwill, respectively, we have been testing the amounts for impairment on an annual basis as opposed to amortizing them over a determinable life.  We determined that it would be more appropriate to account for these excess investments as intangible assets with determinable lives.  As a result, we made non-cash adjustments that reduced the net value of the excess investments in Centennial and Seaway, and increased amortization expense allocated to our equity earnings.  The effect of this restatement caused a $3.8 million and $4.0 million reduction to net income as previously reported for the fiscal years ended December 31, 2004 and 2003, respectively.  As a result of the accounting correction, net income for the fiscal year ended December 31, 2005, includes a charge of $4.8 million, of which $3.8 million relates to the first nine months.  Additionally, partners’ capital at December 31, 2002, reflects a $2.5 million reduction representing the cumulative effect of this correction for fiscal years ended December 31, 2000 through 2002.

While we believe the impacts of these non-cash adjustments are not material to any previously issued financial statements, we determined that the cumulative adjustment for these non-cash items was too material to record in the fourth quarter of 2005, and therefore it was most appropriate to restate prior periods’ results.  These non-cash adjustments had no effect on our operating income, compensation expense, debt balances or ability to meet all requirements related to our debt facilities.  The restatement had no impact on total cash flows from operating activities, investing activities or financing activities.  All amounts in the accompanying consolidated financial statements have been adjusted for this restatement.

We will continue to amortize the $30.0 million excess investment in Centennial related to a contract using units-of-production methodology over a 10-year life.  The remaining $3.4 million related to a pipeline will continue to be amortized on a straight-line basis over 35 years.  We will continue to

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amortize the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to a pipeline.

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, 2005, approximately 12% 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 $1.4 million impact on annual earnings.  Crude oil margin estimates are based upon an average of the past twelve months of 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, 2005, approximately 11% of our annual crude oil margin is recorded using estimates.  A variance from this estimate of 10% would impact the respective line items by approximately $1.2 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.

Environmental Costs

At December 31, 2005, we have accrued a liability of $2.4 million for our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations.  Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs

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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 $0.3 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.

Property, Plant and Equipment

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 3 in the Notes to the Consolidated Financial Statements).  At December 31, 2005, the recorded value of goodwill was $16.9 million.

At December 31, 2005, we have $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 on June 30, 2002.  The value assigned to the natural gas transportation contracts required management to make estimates regarding the fair value of the assets acquired.  In connection with the acquisition of Jonah, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in

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Wyoming.  We assigned $222.8 million of the purchase price to these production contracts based upon a fair value appraisal at the time of the acquisition.  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 Jonah and Val Verde systems would have an approximate $7.5 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, 2005, we have $43.8 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 (see Note 3 in Notes to Consolidated Financial Statements). The value assigned to our excess investment in Centennial was created upon its formation.  Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life.  The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years.  The value assigned to our excess investment in Seaway was created upon acquisition of our 50% ownership interest in 2000.  We are amortizing the $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.  A variance of 10% in our amortization expense allocated to equity earnings could have up to an approximate $0.5 million impact on annual earnings.

Results of Operations

The following table summarizes financial information by business segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Operating revenues:
Downstream Segment	$	287,191		$	279,400		$	266,427
Upstream Segment	8,110,239			5,475,995			3,806,215
Midstream Segment	224,625			206,004			185,105
Intercompany eliminations	(3,567		)	(3,207		)	(1,915		)
Total operating revenues	8,618,488			5,958,192			4,255,832
Operating income:
Downstream Segment	88,143			71,263			83,704
Upstream Segment	33,174			32,265			28,416
Midstream Segment	101,866			83,605			80,288
Total operating income	223,183			187,133			192,408
Earnings before interest:
Downstream Segment	85,914			65,506			76,546
Upstream Segment	56,408			61,363			48,980
Midstream Segment	102,090			83,732			80,577
Intercompany eliminations	—			—			(73		)
Total earnings before interest	244,412			210,601			206,030
Interest expense	(88,620		)	(76,280		)	(89,540		)
Interest capitalized	6,759			4,227			5,290
Net income	$	162,551		$	138,548		$	121,780

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

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Downstream Segment

The following table provides financial information for the Downstream Segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Years Ended December 31,									Increase (Decrease)
	2005			2004			2003			2005-2004			2004-2003
				(as restated)			(as restated)
Transportation – Refined products	$	144,552		$	148,166		$	138,926		$	(3,614	)	$	9,240
Transportation – LPGs	96,297			87,050			91,787			9,247			(4,737		)
Other	46,342			44,184			35,714			2,158			8,470
Total operating revenues	287,191			279,400			266,427			7,791			12,973
Operating, general and administrative	116,187			124,905			113,389			(8,718		)	11,516
Operating fuel and power	32,500			31,706			28,806			794			2,900
Depreciation and amortization	39,403			43,135			31,620			(3,732		)	11,515
Taxes – other than income taxes	11,097			8,917			8,908			2,180			9
Gains on sales of assets	(139		)	(526		)	—			387			(526		)
Total costs and expenses	199,048			208,137			182,723			(9,089		)	25,414
Operating income	88,143			71,263			83,704			16,880			(12,441		)
Equity losses	(2,984		)	(6,544		)	(7,384		)	3,560			840
Other income – net	755			787			226			(32		)	561
Earnings before interest	$	85,914		$	65,506		$	76,546		$	20,408		$	(11,040	)

The following table presents volumes delivered in barrels and average tariff per barrel for the years ended December 31, 2005, 2004 and 2003 (in thousands, except tariff information):

	Years Ended December 31,						Percentage Increase (Decrease)
	2005		2004		2003		2005-2004		2004-2003
Volumes Delivered:
Refined products	160,667		152,437		154,061		5	%	(1	)%
LPGs	45,061		43,982		42,543		3	%	3	%
Total	205,728		196,419		196,604		5	%	—
Average Tariff per Barrel:
Refined products (1)	$	0.90	$	0.97	$	0.90	(7	)%	8	%
LPGs	2.14		1.98		2.16		8	%	(8	)%
Average system tariff per barrel	$	1.17	$	1.20	$	1.17	(3	)%	3	%

(1)The 2004 period includes $4.1 million of deferred revenue related to the expiration of two customer transportation agreements, which increased the refined products average tariff for the year ended December 31, 2004, by $0.02 per barrel, or 2%.

Our Downstream Segment’s results are dependent in large part on the demand for refined products and LPGs in the markets served by its pipelines.  Reductions in that demand adversely affect the pipeline business of the Downstream Segment.  Market demand varies based upon the different end uses of the products shipped in the Downstream Segment.  Demand for gasoline, which in recent years has accounted for approximately forty percent of the Downstream Segment’s refined products transportation revenues, depends upon price, prevailing economic conditions and demographic changes in the markets served in the Downstream Segment.  Demand for distillates is affected by truck and railroad freight, the price of natural gas used by utilities, which use distillates as a substitute for natural gas when the price of natural gas is high, and usage for agricultural operations, which is affected by weather conditions, government policy and crop prices.  Demand for jet fuel, which in recent years has accounted for approximately twenty percent of the Downstream Segment’s 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 in the past and will likely continue to occur in the future.

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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 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 LPG loading facilities at Todhunter 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

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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 decreased $9.0 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, due to decreased operating, general and administrative expenses and decreased depreciation and amortization expense, partially offset by increased taxes – other than income taxes, increased operating fuel and power and lower gains on the sales of assets in the 2005 period.  Operating, general and administrative expenses decreased $8.7 million primarily due to the following:

•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 $2.6 million decrease in postretirement benefit accruals related to plan amendments (see Note 15 in the Notes to the Consolidated Financial Statements),

•a $2.1 million decrease in products losses,

•a $2.0 million decrease in legal expenses related to a legal settlement in 2004 (see Note 16 in the Notes to the Consolidated Financial Statements) and

•a $1.1 million decrease in consulting services primarily related to acquisition related activities in the 2004 period.

These decreases to costs and expenses were partially offset by the following:

•a $3.4 million increase in labor and benefits expenses primarily associated with vesting provisions in certain of our compensation plans as a result of changes 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 $1.5 million increase related to transition costs due to the changes in ownership of our General Partner,

•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 general and administrative supplies expenses during the year, including a $0.4 million increase in environmental assessment and remediation expenses, a $0.4 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 9 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.  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.

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Net losses from equity investments decreased $3.6 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, as shown below (in thousands):

	Years Ended December 31,						Increase
	2005			2004			(Decrease)
	(as restated)
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

Equity losses in Centennial decreased $3.7 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to higher transportation revenues and volumes.

Equity earnings in MB Storage decreased $0.2 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to increased depreciation and amortization expense and higher general and administrative expenses, partially offset by higher rental and storage revenues and volumes.  MB Storage was impacted by Hurricane Rita, which reduced revenues and increased operating expenses.  Additionally, in April 2004, MB Storage acquired storage and pipeline assets and contracts for approximately $35.0 million, of which TE Products contributed $16.5 million.  Increases in storage revenue, shuttle revenue, rental revenue and depreciation and amortization expense for year ended December 31, 2005, compared with the year ended December 31, 2004, are primarily related to the acquired storage assets and contracts.

For the year ended December 31, 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 operating agreement.  For the year ended December 31, 2004, TE Products received the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense.  TE Products’ share of MB Storage’s earnings is 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 for 2005 and $7.15 million for 2004 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, 2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage was approximately 64.2%, 69.4% and 70.4%, respectively.

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Revenues from refined products transportation increased $9.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003.  Refined products transportation revenues increased primarily due to higher market-based tariff rates which went into effect in July 2003 and May 2004 and a shift in the distribution of product moved by us to favor longer haul, higher tariff movements.  These changes resulted in a 5% increase in the refined products average rate per barrel from the prior year and offset the effect of a 1% decrease in refined products delivery volumes.  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.  Refined products transportation revenues also increased due to the recognition of $4.1 million of deferred revenue in the 2004 period related to the expiration of two customer transportation agreements.

Revenues from LPGs transportation decreased $4.7 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to lower deliveries of propane in the upper Midwest and Northeast market areas attributable to warmer weather during the first and fourth quarters of 2004.  Additionally, in late February 2004, the Mont Belvieu propane price spiked, which resulted in TEPPCO sourced propane being less competitive than propane from other source points.  Also contributing to the decrease were less favorable price differentials between Mont Belvieu and other supply centers during the second and third quarters of 2004.   High

43

propane prices in 2004 also reduced the summer and early fall fill of consumer storage of propane during 2004.  These decreases were partially offset by increased deliveries of isobutane to Chicago area refineries and increased short-haul propane deliveries to U.S. Gulf Coast petrochemical customers.  The LPGs average rate per barrel decreased 8% from the prior year period primarily as a result of increased short-haul deliveries during 2004.

Other operating revenues increased $8.5 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to higher propane inventory fees, higher margins on product inventory sales, higher revenue from our Providence, Rhode Island import facility and higher refined products tender deduction, loading and custody transfer revenues.

Costs and expenses increased $25.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to increased operating, general and administrative expenses, increased depreciation and amortization expense and increased operating fuel and power, partially offset by net gains on the sales of assets.  Operating, general and administrative expenses increased primarily due to a $6.2 million increase in pipeline inspection and repair costs associated with our integrity management program, a $2.0 million increase in legal accruals related to the settlement of a lawsuit (see Note 16 in the Notes to the Consolidated Financial Statements), a $1.5 million increase in rental expense from the Centennial pipeline capacity lease agreement that we entered into in February 2003, a $1.3 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002 and a $1.1 million increase in costs related to unsuccessful acquisition evaluations.  These increases were partially offset by $0.8 million of lower expenses in the 2004 period associated with the write-off of receivables related to customer bankruptcies and non-payments in 2003.  Depreciation expense increased from the prior year period because of a $4.4 million charge resulting from the impairment of marine assets in the Beaumont area (see Note 9 in the Notes to the Consolidated Financial Statements).  In addition, we wrote off approximately $2.1 million in assets taken out of service during the period to depreciation expense.  Depreciation expense also increased approximately $5.0 million as a result of assets placed in service during 2003 and 2004, partially offset by an increase in the estimated remaining life of a section of our pipeline system in the Northeast, resulting from pipeline capital improvements made as part of our integrity management program.  Operating fuel and power expense increased primarily as a result of higher power rates during the 2004 period.  In addition, we recognized net gains of $0.5 million during 2004 from the sales of various assets in the Downstream Segment.

Net losses from equity investments decreased $0.8 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, as shown below (in thousands):

	Years Ended December 31,
	2004			2003			Increase
	(as restated)			(as restated)
Centennial	$	(14,379	)	$	(14,671	)	$	292
MB Storage	7,874			7,354			520
Other	(39		)	(67		)	28
Total equity losses	$	(6,544	)	$	(7,384	)	$	840

Equity losses in Centennial decreased $0.3 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to increased transportation revenues and volumes and lower operating expenses.  During 2003, we acquired an additional 16.7% interest in Centennial on February 10, 2003, bringing TE Products’ ownership interest to 50%.  Included in the equity loss for the year ended December 31, 2004, is $1.2 million of equity income relating to the settlement of certain transmix matters recognized in previous periods.

Equity earnings in MB Storage increased $0.5 million for the year ended December 31, 2004, compared with the year ended December 31, 2003.  In April 2004, MB Storage acquired storage and pipeline assets and contracts for approximately $35.0 million, of which TE Products contributed $16.5 million.  The increase in equity earnings is due to increased storage revenue, shuttle revenue and rental revenue primarily from the acquired contracts and lower pipeline rehabilitation expenses on the MB Storage system, partially offset by increased amortization and depreciation expense on storage assets and contracts acquired.

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Other income – net increased $0.6 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to higher interest income earned on cash investments and higher interest income earned on a capital lease.

Upstream Segment

The following table provides financial information for the Upstream Segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Years Ended December 31,									Increase (Decrease)
	2005			2004			2003			2005-2004			2004-2003
				(as restated)			(as restated)
Sales of petroleum products	$	8,062,131		$	5,426,832		$	3,766,651		$	2,635,299		$	1,660,181
Transportation – Crude oil	37,614			37,177			29,057			437			8,120
Other	10,494			11,986			10,507			(1,492		)	1,479
Total operating revenues	8,110,239			5,475,995			3,806,215			2,634,244			1,669,780
Purchases of petroleum products	7,989,682			5,370,234			3,713,122			2,619,448			1,657,112
Operating, general and administrative	59,885			51,424			50,471			8,461			953
Operating fuel and power	5,122			5,490			3,672			(368		)	1,818
Depreciation and amortization	17,161			13,130			11,311			4,031			1,819
Taxes – other than income taxes	5,333			3,979			3,171			1,354			808
Gains on sales of assets	(118		)	(527		)	(3,948		)	409			3,421
Total costs and expenses	8,077,065			5,443,730			3,777,799			2,633,335			1,665,931
Operating income	33,174			32,265			28,416			909			3,849
Equity earnings	23,078			28,692			20,258			(5,614		)	8,434
Other income – net	156			406			306			(250		)	100
Earnings before interest	$	56,408		$	61,363		$	48,980		$	(4,955	)	$	12,383

Information presented in the following table includes the margin of the Upstream Segment, which may be viewed as a non-GAAP (Generally Accepted Accounting Principles) financial measure under the rules of the SEC.  We calculate the margin of the Upstream Segment as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil, less the costs of purchases of crude oil and lubrication oil.  We believe that margin is a more meaningful measure of financial performance than sales and purchases of crude oil and lubrication oil due to the significant fluctuations in sales and purchases caused by variations in the level of volumes marketed and prices for products marketed.  Additionally, we use margin internally to evaluate the financial performance of the Upstream Segment as we believe margin is a better indicator of performance than operating income as operating, general and administrative expenses, operating fuel and power and depreciation expense are not directly related to the margin activities.  Margin and volume information for the years ended December 31, 2005, 2004 and 2003 is presented below (in thousands, except per barrel and per gallon amounts):

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	Years EndedDecember31,						Percentage Increase (Decrease)
	2005		2004		2003		2005-2004		2004-2003
Margins: (1)
Crude oil transportation	$	61,611	$	55,425	$	45,794	11	%	21	%
Crude oil marketing	30,597		22,468		22,017		36	%	2	%
Crude oil terminaling	10,400		9,388		9,403		11	%	—
Lubrication oil sales	7,455		6,494		5,372		15	%	21	%
Total margin	$	110,063	$	93,775	$	82,586	17	%	14	%
Total barrels:
Crude oil transportation	94,743		101,462		95,541		(7	)%	6	%
Crude oil marketing	203,325		177,273		159,710		15	%	11	%
Crude oil terminaling	110,254		113,197		115,076		(3	)%	(2	)%
Lubrication oil volume (total gallons)	14,844		13,964		10,449		6	%	34	%
Margin per barrel:
Crude oil transportation	$	0.650	$	0.546	$	0.479	19	%	14	%
Crude oil marketing	0.150		0.127		0.138		19	%	(8	)%
Crude oil terminaling	0.094		0.083		0.082		14	%	1	%
Lubrication oil margin (per gallon):	$	0.502	$	0.465	$	0.514	8	%	(10	)%

(1)Margins in this table are presented prior to the elimination of intercompany sales, revenues and purchases between TCO and TCPL.

The following table reconciles the Upstream Segment margin to operating income in the consolidated statements of income using the information presented in the tables above, in the consolidated statements of income and in the statements of income in Note 17 in the Notes to the Consolidated Financial Statements (in thousands):

	Years EndedDecember31,
	2005			2004			2003
				(as restated)			(as restated)
Sales of petroleum products	$	8,062,131		$	5,426,832		$	3,766,651
Transportation – Crude oil	37,614			37,177			29,057
Less: Purchases of petroleum products	(7,989,682		)	(5,370,234		)	(3,713,122		)
Total margin	110,063			93,775			82,586
Other operating revenues	10,494			11,986			10,507
Total operating revenues	120,557			105,761			93,093
Operating, general and administrative	59,885			51,424			50,471
Operating fuel and power	5,122			5,490			3,672
Depreciation and amortization	17,161			13,130			11,311
Taxes – other than income taxes	5,333			3,979			3,171
Gains on sales of assets	(118		)	(527		)	(3,948		)
Operating income	$	33,174		$	32,265		$	28,416

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

Our margin increased $16.3 million for the year ended December 31, 2005, compared with the year ended December 31, 2004.  Crude oil marketing margin increased $8.1 million primarily due to increased volumes marketed primarily due to asset acquisitions, partially offset by increased transportation costs. Crude oil transportation margin increased $6.2 million primarily due to increased transportation volumes and revenues on our South Texas system due to the acquisition of crude oil pipeline assets in April 2005 and higher revenues on our West Texas systems resulting from organic growth projects on the systems and benefits realized from assets acquired at Cushing.  The average margin per barrel increased 22% primarily due to movements of volumes on

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higher tariff segments, including higher tariffs on the assets acquired from BP in April 2005.  Lubrication oil sales margin increased $1.0 million due to increased sales of lubrication oils and chemicals and the acquisitions of lubrication oil distributors in Casper, Wyoming, in August 2004, and in Dumas, Texas, in August 2005.  Crude oil terminaling margin increased $1.0 million as a result of increased pumpover volumes at Cushing, Oklahoma, partially offset by decreased pumpover volumes at Midland, Texas.

Other operating revenues decreased $1.5 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to a $1.4 million favorable settlement of inventory imbalances in the first quarter of 2004 and lower revenues from documentation and other services to support customers’ trading activity at Midland and Cushing in 2005.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $13.9 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, due to increased operating, general and administrative expenses, increased depreciation and amortization expense, increased taxes – other than income taxes and lower gains on sales of assets in the 2005 period, partially offset by decreased operating fuel and power.  Operating, general and administrative expenses increased $8.5 million from the prior year period as a result of the following:

•a $4.8 million increase in pipeline operating and maintenance expense primarily due to acquisitions and the continued integration of the Genesis assets into our system,

•a $2.7 million increase in labor and benefits expense related to vesting provisions in certain of our compensation plans as a result of changes in ownership of our General Partner, an increase in the number of employees between periods, and higher incentive compensation expense as a result of improved operating performance,

•a $1.0 million settlement of an indemnity related to a past acquisition,

•a $0.7 million increase in transition charges as a result of changes in ownership of our General Partner,

•a $0.7 million increase in bad debt expense primarily related to a customer nonpayment,

•a $0.4 million increase in operating costs for our undivided ownership interest in Basin Pipeline,

•a $0.3 million increase related to a legal settlement and

•increases in miscellaneous administrative supplies and expenses.

These increases were partially offset by a $2.3 million decrease in product measurement losses, a $1.9 million decrease in pipeline inspection and repair costs associated with our integrity management program and a $1.2 million decrease in environmental assessment and remediation costs.  Depreciation and amortization expense increased $4.0 million primarily as a result of a $2.6 million non-cash impairment charge in the third quarter of 2005, resulting from the impairment of two crude oil systems (see Note 9 in the Notes to the Consolidated Financial Statements).  Depreciation expense also increased as a result of assets placed in service and assets retired to depreciation expense during the period.  Taxes – other than income taxes increased $1.4 million due to asset acquisitions and a higher asset base in the 2005 period.  During the year ended December 31, 2004, we recognized a gain of $0.4 million from the sale of our remaining interest in the original Rancho Pipeline system (see Note 5 in the Notes to the Consolidated Financial Statements).  Operating fuel and power decreased $0.4 million primarily as a result of lower transportation volumes in 2005.

Equity earnings from our investment in Seaway decreased $5.6 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to higher operating, general and administrative expenses related to a pipeline release in May 2005 discussed below, higher power costs, decreased gains on inventory sales, higher depreciation expense and a favorable settlement in the first quarter of 2004 with a former owner of Seaway’s crude oil assets regarding inventory imbalances that were not acquired by us, partially offset by higher long-haul transportation volumes.

After Seaway’s pipeline release in May 2005, the maximum operating pressure on the pipeline system was reduced by 20% until the cause of the failure is determined and any required corrective measures are implemented.  A study of the failed pipe was performed by independent, metallurgical experts who determined that the pipe failed due to damage that occurred during rail shipment associated with its installation thirty years ago.  The corrective actions include running a very sophisticated, high definition inspection tool through the pipe to determine if there

47

are any other sections of pipe that have similar damage.  This approach is consistent with directives from the United States Department of Transportation’s Office of Pipeline Safety in past failures of this type.  The inspection tool has been run and the resulting data is currently being analyzed.  We expect Seaway to be operating at reduced maximum pressures through the second quarter of 2006.  As a result of operating at reduced maximum pressures, during the third quarter of 2005, we began using a drag reducing agent to increase the flow of product through the pipeline system.  The drag reducing agent allowed us to maintain the higher volumes transported, but also increased our operating costs.  At this time, we do not believe the reduced pressures will have a material adverse effect on our financial position, results of operations or cash flows.

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Our margin increased $11.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003.  Crude oil transportation margin increased $9.6 million primarily due to an increase in transportation volumes and revenues on our South Texas and Red River systems.  Our Basin system also had increased transportation volumes and revenues primarily due to the expansion of the system between Midland, Texas, and Wichita Falls, Texas, resulting in an additional capacity of ten thousand barrels per day on the system, and movements of barrels on higher tariff segments.  During the fourth quarter of 2003, we completed the purchase of crude supply and transportation assets (Genesis), which have been integrated into our South Texas system (see Note 5 in the Notes to the Consolidated Financial Statements).  Lubrication oil sales margin increased $1.1 million due to increased sales of chemical volumes and increased volumes related to the acquisitions of lubrication oil distributors in Abilene, Texas, in December 2003 and in Casper, Wyoming, in August 2004.  Crude oil marketing margin increased $0.5 million as a result of increased volumes marketed, partially offset by an unfavorable invoicing settlement on a marketing contract in the first quarter of 2003, which reduced the marketing margin in 2003, and increased transportation costs.  Crude oil terminaling margin remained unchanged as a result of higher pumpover volumes at Cushing, Oklahoma, offset by lower pumpover volumes at Midland, Texas.

Other operating revenues of the Upstream Segment increased $1.5 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to a $1.4 million favorable settlement of inventory imbalances, and higher revenues from documentation and other services to support customers’ trading activity at Midland and Cushing.

Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $5.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to increased operating fuel and power, increased depreciation and amortization expense, increased operating, general and administrative expenses and increased taxes – other than income taxes.  Operating fuel and power increased $1.8 million primarily as a result of the acquisition of the Genesis assets and higher volumes in 2004.  Depreciation and amortization expense increased $1.8 million primarily due to the assets acquired from Genesis.  Operating, general and administrative expenses increased $1.0 million from the prior year primarily due to a $3.9 million increase in pipeline inspection and repair costs associated with our integrity management program, a $2.0 million increase in expenses related to the Genesis acquisition, a $1.4 million increase in labor and benefits expense related to incentive compensation plans and an increase in the number of employees between periods, a $0.7 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002 and a $0.6 million increase in rental expense due to our pipeline lease at Freeport, Texas, with Seaway.  These increases were partially offset by $3.8 million of higher environmental assessment and remediation costs in 2003, $1.7 million of expense in 2003 from the net settlement of crude oil imbalances with customers, $1.5 million of higher legal costs in 2003 related to the litigation and settlement with D.R.D. Environmental Services, Inc. and $0.5 million of lower expenses in 2004 from the sale of the Rancho assets in 2003.  Taxes – other than income taxes increased $0.8 million due to increases in property tax accruals.

In June 2003, we recorded a net gain of $3.9 million, included in the gain on sale of assets in our consolidated statements of income, on the sale of certain of the assets of the Rancho Pipeline.  During the year ended December 31, 2004, we recorded net gains of $0.5 million, included in the gains on sales of assets in our consolidated statements of income, primarily related to the sale of our remaining interest in the original Rancho Pipeline system (see Note 5 in the Notes to the Consolidated Financial Statements).

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Equity earnings from our investment in Seaway increased $8.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to higher transportation volumes, gains on crude oil inventory sales, a settlement with a former owner of Seaway’s crude oil assets regarding inventory imbalances that were not acquired by us and lower operating, general and administrative expenses.

Midstream Segment

The following table provides financial information for the Midstream Segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Years EndedDecember31,							Increase (Decrease)
	2005			2004		2003		2005-2004			2004-2003
Sales of petroleum products	$	10,479		$	7,295	$	—	$	3,184		$	7,295
Gathering – Natural gas	152,797			140,122		135,144		12,675			4,978
Transportation – NGLs	43,915			41,204		39,837		2,711			1,367
Other	17,434			17,383		10,124		51			7,259
Total operating revenues	224,625			206,004		185,105		18,621			20,899
Purchases of petroleum products	8,995			5,944		—		3,051			5,944
Operating, general and administrative	43,738			44,318		34,618		(580		)	9,700
Operating fuel and power	11,350			10,943		8,884		407			2,059
Depreciation and amortization	54,777			56,629		57,797		(1,852		)	(1,168		)
Taxes – other than income taxes	4,310			4,565		3,518		(255		)	1,047
Gains on sales of assets	(411		)	—		—		(411		)	—
Total costs and expenses	122,759			122,399		104,817		360			17,582
Operating income	101,866			83,605		80,288		18,261			3,317
Other income – net	224			127		289		97			(162		)
Earnings before interest	$	102,090		$	83,732	$	80,577	$	18,358		$	3,155

The following table presents volume and average rate information for the years ended December 31, 2005, 2004 and 2003 (in thousands, except average fee and average rate amounts):

	Years Ended December 31,						Percentage Increase (Decrease)
	2005		2004		2003		2005-2004		2004-2003
Gathering – Natural Gas – Jonah:
Million cubic feet (“MMcf”)	415,181		354,546		302,951		17	%	17	%
Billion British thermal units (“MMmbtu”)	458,159		392,154		336,032		17	%	17	%
Average fee per Million British thermal unit (“MMBtu”)	$	0.188	$	0.194	$	0.193	(3	)%	1	%
Gathering – Natural Gas – Val Verde:
MMcf	180,699		144,539		158,286		25	%	(9	)%
MMmbtu	159,398		122,706		133,094		30	%	(8	)%
Average fee per MMBtu	$	0.418	$	0.523	$	0.529	(20	)%	(1	)%
Transportation – NGLs:
Thousand barrels	61,051		59,549		57,902		3	%	3	%
Average rate per barrel	$	0.719	$	0.692	$	0.688	4	%	1	%
Fractionation – NGLs:
Thousand barrels	4,431		4,149		4,131		7	%	—
Average rate per barrel	$	1.747	$	1.797	$	1.804	(3	)%	—
Sales – Condensate:
Thousand barrels	62.1		84.4		63.3		(26	)%	33	%
Average rate per barrel	$	52.21	$	37.99	$	30.25	37	%	26	%

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Information presented in the following discussion includes the margin of the Midstream Segment, which may be viewed as a non-GAAP financial measure under the rules of the SEC.  We calculate the margin of the Midstream Segment as revenues generated from the processing arrangements at the Jonah Pioneer plant, less purchases of gas.   Pioneer’s processing agreements allow Jonah to retain and sell the NGLs extracted during the process and deliver to producers the residue gas equivalent in energy to the natural gas received from the producers.  Jonah sells the NGLs it retains and purchases gas to replace the equivalent energy removed in the liquids.  We believe that margin is a more meaningful measure of financial performance than sales and purchases of petroleum products due to the significant fluctuations in sales and purchases caused by variations in the level of volumes marketed and prices for products marketed.  Additionally, we use margin internally to evaluate the financial performance of the Midstream Segment’s processing activities as we believe margin is a better indicator of performance than operating income as operating, general and administrative expenses, operating fuel and power and depreciation expense are not directly related to the margin activities.  The following table reconciles the Midstream Segment margin to operating income in the consolidated statements of income using the information presented in the tables above, in the consolidated statements of income and in the statements of income in Note 17 in the Notes to the Consolidated Financial Statements (in thousands):

	Years EndedDecember31,
	2005			2004			2003
Sales of petroleum products	$	10,479		$	7,295		$	—
Less: Purchases of petroleum products	(8,995		)	(5,944		)	—
Total margin	1,484			1,351			—
Gathering – Natural Gas	152,797			140,122			135,144
Transportation – NGLs	43,915			41,204			39,837
Other operating revenues	17,434			17,383			10,124
Total operating revenues	215,630			200,060			185,105
Operating, general and administrative	43,738			44,318			34,618
Operating fuel and power	11,350			10,943			8,884
Depreciation and amortization	54,777			56,629			57,797
Taxes – other than income taxes	4,310			4,565			3,518
Gains on sales of assets	(411		)	—			—
Operating income	$	101,866		$	83,605		$	80,288

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

Revenues from the gathering of natural gas increased $12.7 million for the year ended December 31, 2005, compared with the year ended December 31, 2004.  Natural gas gathering revenues from the Jonah system increased $10.2 million and volumes gathered increased 60.6 Bcf for the year ended December 31, 2005, primarily due to the expansion of the Jonah system in 2004.  Installation of additional capacity of 100 million cubic feet per day was completed during the fourth quarter of 2004.  Jonah’s average natural gas gathering rate per MMcf decreased due to higher system wellhead pressures.  Natural gas gathering revenues from the Val Verde system increased $2.5 million and volumes gathered increased 36.7 Bcf for the year ended December 31, 2005, primarily due to increased volumes from two new connections made to the Val Verde system in May and December 2004, partially offset by the natural decline of CBM production.  Val Verde’s average natural gas gathering rate per MMcf decreased due to contracts entered into relating to the new connections, which have lower rates than the existing Val Verde system’s average rates.

Margin (sales of petroleum products less purchases of petroleum products) resulting from the processing arrangements at the Jonah Pioneer plant increased $0.1 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to increased volumes and higher NGL prices.  Jonah’s Pioneer gas processing plant was completed during the first quarter of 2004, as a part of the Phase III expansion to increase the processing capacity in southwestern Wyoming.  Pioneer’s processing agreements allow the producers to elect annually whether to be charged under a fee-based arrangement or a fee plus keep-whole arrangement.  Under the fee-based election, Jonah receives a fee for its processing services.  Under the fee plus keep-whole election, Jonah receives a lower fee for its processing services, retains and sells the NGLs extracted during the process and delivers to producers the residue gas equivalent in energy to the natural gas received from the producers.  Jonah sells

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the NGLs it retains and purchases gas to replace the equivalent energy removed in the liquids.  For the 2004 and 2005 periods, the producers elected the fee plus keep-whole arrangement.

Revenues from the transportation of NGLs increased $2.7 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to increased volumes transported on the Chaparral, Panola and Dean Pipelines, partially offset by decreased volumes transported on the Wilcox Pipeline.  The increase in the NGL transportation average rate per barrel resulted from a higher average rate per barrel on volumes transported on the Panola Pipeline offset by a lower average rate per barrel on the Chaparral Pipeline.

Other operating revenues remained unchanged for the year ended December 31, 2005, compared with the year ended December 31, 2004.  Val Verde’s other operating revenues increased $0.8 million due to revenues generated as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage during 2005.  Val Verde retains a portion of its producers’ gas to compensate for fuel used in operations.  The actual usage of gas can differ from the amount contractually retained from producers.  Value retained from producers or sales generated as a result of efficient fuel usage are recognized as other operating revenues.  Jonah’s processing fee revenue and other operating revenues increased $0.5 million as a result of the expansion of the Jonah system and higher volumes.  NGL fractionation revenues increased $0.3 million as a result of higher volumes.  Other operating revenues on Chaparral decreased $1.6 million primarily due to the recognition of deferred revenue related to an inventory settlement in the prior year period.

Costs and expenses (excluding purchases of petroleum products) decreased $2.8 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, due to decreased depreciation and amortization expense, decreased operating, general and administrative expenses, decreased taxes – other than income taxes and a net gain recorded on the sale of an asset, partially offset by increased operating fuel and power.  Amortization expense on the Jonah system decreased $2.6 million primarily due to a $3.9 million decrease related to revisions to the estimated life of intangible assets under the units-of-production method, partially offset by a $1.3 million increase as a result of higher volumes in 2005.  Amortization expense on the Val Verde system increased $1.4 million primarily due to a $2.4 million increase related to revisions to the estimated life of intangible assets under the units-of-production method, partially offset by a $1.0 million decrease as a result of lower volumes in 2005 on contracts included in the intangible assets, resulting from the natural decline in CBM production.  Depreciation expense decreased $0.7 million primarily due to a $3.1 million decrease on Jonah as a result of increases to the estimated lives of Jonah’s assets, partially offset by a $1.4 million increase on Val Verde as a result of assets placed into service in 2004 and a $1.0 million increase on the NGL pipelines as a result of assets placed into service and adjustments to asset lives.

Operating, general and administrative expenses decreased $0.6 million from the prior year period as a result a $6.0 million decrease in gas settlement expenses, a $1.2 million decrease in a operating expenses primarily related to Val Verde and a $0.5 million decrease in inspection and repair costs associated with our integrity management program.  These decreases were partially offset by a $2.1 million increase in labor and benefits expense primarily associated with vesting provisions in certain of our compensation plans and with certain DEFS employees becoming employees of EPCO, a $1.9 million increase in transition expenses as a result of changes in ownership of our General Partner, a $1.5 million increase in insurance expense and increases in various general and administrative supplies and expenses.  Taxes – other than income taxes decreased $0.3 million as a result of adjustments to property tax accruals.  Operating fuel and power increased $0.4 million compared to the prior year due to adjustments to the fuel and power accrual in the prior year period, partially offset by increased expenses in 2005 related to higher transportation volumes.  A net gain of $0.4 million was recognized on the sale of equipment in the current period.

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Revenues from the gathering of natural gas increased $5.0 million for the year ended December 31, 2004, compared with the year ended December 31, 2003.  Natural gas gathering revenues from the Jonah system increased $11.3 million and volumes gathered increased 51.6 Bcf for the year ended December 31, 2004, due to the expansion of the Jonah system during 2003.  The Phase III expansion was substantially completed during the fourth quarter of 2003 and increased system capacity from 880 MMcf/day to 1,180 MMcf/day.  The increase in Jonah’s revenues was also partially due to higher gathering rates realized due to lower system pressures resulting from the increased

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capacity provided by the Phase III expansion.  Natural gas gathering revenues from the Val Verde system decreased $6.3 million and volumes gathered decreased 13.7 Bcf for the year ended December 31, 2004, primarily due to the natural decline of CBM production and slower than anticipated completion and connection of infill wells, partially offset by increased volumes from two new connections made to the Val Verde system in May and December 2004.  Val Verde’s average natural gas gathering rate per MMcf decreased due to contracts entered into relating to the new connections, which have lower rates than the existing Val Verde system’s average rates.

For the year ended December 31, 2004, the sales and purchases under the fee arrangements at the Pioneer plant resulted in a margin (sales of petroleum products less purchases of petroleum products) of $1.4 million.

Revenues from the transportation of NGLs increased $1.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to increased volumes transported on the Chaparral and Panola Pipelines, partially offset by decreased volumes on the Dean and Wilcox Pipelines.  Higher average rates per barrel on volumes transported on the Panola and Wilcox Pipelines were offset by lower average rates per barrel on volumes transported on the Chaparral and Dean Pipelines.

Other operating revenues increased $7.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003.  Processing fee revenues increased $2.8 million as a result of Jonah’s Pioneer processing plant, which was constructed as part of the Phase III expansion and placed in service in January 2004.  Jonah’s other operating revenues also increased $0.9 million primarily due to higher condensate sales.  Other operating revenues on Chaparral increased $1.9 million due to the recognition of deferred revenue related to an inventory settlement.  Val Verde’s operating revenues increased $1.6 million due to revenues generated as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage during the year ended December 31, 2004.

Costs and expenses (excluding purchases of petroleum products) increased $11.7 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to increases in operating, general and administrative expense, operating fuel and power and taxes – other than income taxes, partially offset by a decrease in depreciation and amortization expense.  Operating, general and administrative expense increased due to a $3.8 million increase in gas settlement expenses, a $3.0 million increase in general and administrative labor expense, a $1.3 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002, a $0.9 million increase related to our integrity management program and a $0.9 million increase related to Jonah’s processing plant which began operations in 2004.  These increases were partially offset by a $0.6 million decrease in expense related to the sale of our Enron Corp. receivable, which had been fully reserved in 2001, and a $0.4 million decrease in maintenance expenditures at Val Verde.  Operating fuel and power increased $2.1 million, primarily due to higher variable power rates and increased NGL volumes transported during times of peak variable power rates.  Depreciation expense increased $3.5 million, primarily as a result of assets placed in service in 2003 related to the expansion of the Jonah system and additional well connections on the Val Verde system in 2004.  Taxes – other than income taxes increased $1.0 million as a result of higher property balances.  Amortization expense decreased $4.7 million primarily due to revisions to the estimated life of Jonah’s intangible assets under the units-of-production method, partially offset by a $1.7 million increase as a result of higher volumes in the 2004 period.  In second quarter 2003, Jonah’s estimated total throughput of the system was adjusted, which resulted in an extension of the expected amortization period from 16 years to 25 years.  During the fourth quarter of 2004, additional limited production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we again increased our best estimate of future throughput on the Jonah system.  This increase in the estimate of future throughput extended the amortization period of Jonah’s natural gas gathering contracts (see Note 3 in the Notes to the Consolidated Financial Statements).  Amortization expense on the Val Verde system decreased $2.1 million primarily due to lower volumes in the 2004 period, resulting from the natural decline in CBM production.

Other income – net decreased $0.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to lower interest income earned on cash investments.

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Interest Expense and Capitalized Interest

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

Interest expense increased $12.3 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to higher outstanding borrowings and higher short term floating interest rates on our revolving credit facility and $2.0 million of expense related to the termination of a treasury lock (see Note 4 in the Notes to the Consolidated Financial Statements).  These increases were partially offset by a higher percentage of fixed interest rate debt during the year ended December 31, 2004, that carried a higher rate of interest as compared with floating interest rate debt.  The higher percentage of fixed interest rate debt resulted from an interest rate swap that expired in April 2004 (see Note 4 in the Notes to the Consolidated Financial Statements).

Capitalized interest increased $2.5 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, due to interest capitalized on higher construction work-in-progress balances in 2005.

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Interest expense decreased $13.3 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to a higher percentage of variable interest rate debt during the year ended December 31, 2004, that carried a lower rate of interest as compared to fixed interest rate debt.  The higher percentage of variable interest rate debt resulted from the expiration of an interest rate swap in April 2004 (see Note 4 in the Notes to the Consolidated Financial Statements).  The decrease was partially offset by higher balances outstanding on our revolving credit facility in 2004.

Capitalized interest decreased $1.1 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to interest capitalized on higher construction work-in-progress balances in 2003.

Financial Condition and Liquidity

Cash generated from operations, credit facilities and debt and equity offerings are our primary sources of liquidity.  At December 31, 2005, and 2004, we had working capital deficits of $38.1 million and $37.8 million, respectively.  At December 31, 2005, we had approximately $274.6 million in available borrowing capacity (applying the most restrictive financial covenants) under our revolving credit facility to cover any working capital needs.  Cash flows for the years ended December 31, 2005, 2004 and 2003 were as follows (in millions):

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Cash provided by (used in):
Operating activities	$	254.5		$	267.2		$	242.4
Investing activities	(350.9		)	(190.2		)	(188.3		)
Financing activities	80.1			(90.1		)	(55.6		)

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Operating Activities

Net cash from operating activities for the years ended December 31, 2005, 2004 and 2003, was comprised of the following (in millions):

	Years Ended December 31,
	2005				2004			2003
					(as restated)			(as restated)
Net income	$		162.5		$	138.5		$	121.8
Depreciation and amortization	111.4				112.9			100.7
Earnings in equity investments	(20.1			)	(22.1		)	(12.9		)
Distributions from equity investments	37.1				47.2			28.0
Gains on sales of assets	(0.7			)	(1.1		)	(3.9		)
Non-cash portion of interest expense	1.6				(0.4		)	4.8
Cash provided by (used in) working capital and other	(37.3			)	(7.8		)	3.9
Net cash from operating activities	$	254.5			$	267.2		$	242.4

For a discussion of changes in earnings before interest, depreciation and amortization, equity earnings, gain on sales of assets by segment and consolidated interest expense – net, see “Results of Operations.”  Cash distributions from equity investments decreased $10.1 million primarily due to Seaway funding its construction of additional storage tanks from its operating cash flows.  Cash used for working capital purposes increased $29.5 million for the year ended December 31, 2005, primarily due to the timing of cash disbursements and cash receipts for crude oil inventory.  Cash distributions from our equity investments increased $19.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to an improved operating performance in Seaway and MB Storage during the year ended December 31, 2004.  Cash used for working capital purposes and other operating activities increased $11.7 million for the year ended December 31, 2004, primarily due to the timing of cash disbursements and cash receipts for working capital components.

Net cash from operating activities for the years ended December 31, 2005, 2004 and 2003, included interest payments, net of amounts capitalized, of $82.3 million, $77.5 million and $79.9 million, respectively.  Excluding the effects of hedging activities and interest capitalized during the year ended December 31, 2006, we expect interest payments on our fixed rate Senior Notes to be approximately $78.0 million.  We expect to pay our interest payments with cash flows from operating activities.

Investing Activities

 Cash flows used in investing activities totaled $350.9 million for the year ended December 31, 2005, and were comprised of $220.6 million of capital expenditures, $69.0 million for the acquisition of Downstream Segment assets, $43.2 million for the acquisition of Upstream Segment assets, $14.4 million of cash paid for linefill on assets owned and $4.2 million of cash contributions for TE Products’ ownership interest in MB Storage for capital expenditures, partially offset by $0.5 million in net cash proceeds from an asset sale in our Midstream Segment. Cash flows used in investing activities totaled $190.2 million for the year ended December 31, 2004, and were comprised of $164.1 million of capital expenditures, $1.5 million of cash contributions for TE Products’ ownership interest in Centennial to cover operating needs and capital expenditures, $21.4 million of cash contributions for TE Products’ ownership interest in MB Storage of which $16.5 million was used to acquire storage assets, $3.4 million for the acquisition of assets during the year ended December 31, 2004 and $1.0 million of cash paid for linefill on assets owned, partially offset by $1.2 million in net cash proceeds from the sales of various assets in our Upstream and Downstream Segments.  Cash flows used in investing activities totaled $188.3 million for the year ended December 31, 2003, and were comprised of $140.5 million of capital expenditures, $22.0 million for the acquisition of assets, $20.0 million for TE Products’ acquisition of an additional 16.7% interest in Centennial, $4.0 million of cash contributions for TE Products’ ownership interest in Centennial to cover operating needs and capital expenditures, $2.5 million of cash contributions for TE Products’ ownership interest in MB Storage for capital expenditures and $3.1 million of cash paid for linefill on assets owned.  These uses of cash were partially offset by $3.0 million in net cash proceeds from the Rancho Pipeline transactions and $0.8 million received on matured cash investments.

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Financing Activities

Cash flows provided by financing activities totaled $80.1 million for the year ended December 31, 2005, and were comprised of $278.8 million of net proceeds received from the issuance of 7.0 million Units in May and June 2005 and $52.9 million in borrowings, net of repayments, on our revolving credit facility, partially offset by $251.1 million of distributions paid to unitholders and $0.5 million of debt issuance costs related to an amendment of our revolving credit facility.  Cash flows used in financing activities totaled $90.1 million for the year ended December 31, 2004, and were comprised of $233.1 million of distributions paid to unitholders, partially offset by $143.0 million in borrowings, net of repayments, from our revolving credit facility.  Cash flows used in financing activities totaled $55.6 million for the year ended December 31, 2003, and were comprised of $382.0 million in proceeds from revolving credit facilities; $198.6 million from the issuance in January 2003 of our 6.125% Senior Notes due 2013, partially offset by debt issuance costs of $3.4 million; and $287.5 million from the issuance of 9.2 million Units in April and August 2003.  These sources of cash for the year ended December 31, 2003, were partially offset by $604.0 million of repayments on our revolving credit facilities, $113.8 million to repurchase and retire all of the 3.9 million outstanding Class B Units, and $202.5 million of distributions paid to unitholders.

We paid cash distributions to our limited partners and general partner, including general partner incentive distributions, of $251.1 million ($2.675 per Unit), $233.1 million ($2.6375 per Unit), and $202.5 million ($2.50 per Unit) during each of the years ended December 31, 2005, 2004 and 2003, respectively.  Additionally, on January 13, 2006, we declared a cash distribution of $0.675 per Unit for the quarter ended December 31, 2005.  The distribution of $66.9 million was paid on February 7, 2006, to unitholders of record on January 31, 2006 (see Note 11 in the Notes to the Consolidated Financial Statements).

On May 5, 2005, we sold in an underwritten public offering 6.1 million Units at $41.75 per Unit.  The proceeds from the offering, net of underwriting discount, totaled approximately $244.5 million.  On June 8, 2005, 865,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on May 5, 2005.  Proceeds from the over-allotment sale, net of underwriting discount, totaled $34.7 million.  The proceeds were used to reduce indebtedness under our revolving credit facility, to fund revenue generating and system upgrade capital expenditures and for general partnership purposes.

Other Considerations

Universal Shelf

We have filed with the SEC a universal shelf registration statement that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $2.0 billion of equity securities, debt securities or a combination thereof.  In the May 2005 equity offering, we issued $279.2 million of equity securities.  At December 31, 2005, we had $1.7 billion available under this shelf registration, subject to customary marketing terms and conditions.

Credit Facilities

We have in place an unsecured revolving credit facility for up to $700.0 million (“Revolving Credit Facility”), which may be increased up to a maximum of $850.0 million upon our request, subject to lender approval and the satisfaction of certain other conditions.  The Revolving Credit Facility expires on December 13, 2010.  Interest is payable at an applicable margin above either the lender’s base rate or LIBOR.  At December 31, 2005, $405.9 million was outstanding under the facility, and we had $274.6 million of availability under the most restrictive financial covenant.  Restrictive covenants in the credit agreement limit our ability to, among other things, incur additional indebtedness, make distributions in excess of Available Cash (see Note 11 in the Notes to the Consolidated Financial Statements), and complete mergers, acquisitions and sales of assets.  In addition, the credit agreement requires us to maintain certain financial ratios, which we were in compliance with at December 31, 2005.

Future Capital Needs and Commitments

We estimate that capital expenditures, excluding acquisitions, for 2006 will be approximately $209.7 million (including $6.0 million of capitalized interest).  We expect to spend approximately $147.4 million for revenue generating projects.  Capital spending on revenue generating projects and facility improvements will include approximately $70.9 million for the expansion of our Downstream Segment facilities.  We expect to spend

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$16.3 million to expand our Upstream Segment pipelines and facilities in West Texas and Oklahoma and approximately $60.2 million to expand our Midstream Segment assets, with further expansions on our Jonah system.  We expect to spend approximately $37.8 million to sustain existing operations, 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 $18.5 million to improve operational efficiencies and reduce costs among all of our business segments.  During 2006, TE Products may be required to contribute cash to Centennial to cover capital expenditures, acquisitions or other operating needs and to MB Storage to cover significant capital expenditures or additional acquisitions.  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.

The construction of the Jonah Expansion is expected to be completed through a proposed Joint Venture between us and Enterprise, relating to the construction and financing of the Jonah Expansion.  Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million).  Such advance will constitute a Subscription for an equity interest in the proposed Joint Venture.  We expect the Jonah Expansion to be put into service in late 2006.  We have the option to return to Enterprise up to 100% of the amount of the Subscription.  If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly.  The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.

Liquidity Outlook

We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities.  Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and to complete the Jonah Expansion, revenue generating expenditures, interest payments on our Senior Notes and Revolving Credit Facility, distributions to our General Partner and unitholders and acquisitions of new assets or businesses.  Our cash requirements for 2006 are expected to be funded through operating cash flows and our arrangement with Enterprise under the pending Joint Venture agreement related to the Jonah Expansion.   Long-term cash requirements for expansion projects, acquisitions and debt repayments are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities, joint ventures and possibly the issuance of additional equity and debt securities.  Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

Off-Balance Sheet Arrangements

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

Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2005, $150.0 million was outstanding under those credit facilities.  TE Products and Marathon have each guaranteed one-half of the repayment of Centennial’s outstanding debt balance (plus interest) under a long-term credit agreement, which expires in 2024, and a short-term credit agreement, which expires in 2007.  The guarantees arose in order for Centennial to obtain adequate financing, and the proceeds of the credit agreements were used to fund construction and conversion costs of its pipeline system.  Prior to the expiration of the long-term credit agreement, TE Products could be relinquished from responsibility under the guarantee should Centennial meet certain financial tests.  If Centennial defaults on its outstanding balance, the estimated maximum potential amount of future payments for TE Products and Marathon is $75.0 million each at December 31, 2005.

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TE Products, Marathon and Centennial have entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event.  There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each.  As a result of the catastrophic event guarantee, TE Products has recorded a $4.6 million obligation, which represents the present value of the estimated amount that we would have to pay under the guarantee.  If a catastrophic event were to occur and we were required to contribute cash to Centennial, contributions exceeding our deductible might be covered by our insurance.

One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various equipment.  We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements.  Generally, events of default would trigger our performance under the guarantee.  The maximum potential amount of future payments under the guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments.  We carry insurance coverage that may offset any payments required under the guarantees.

Contractual Obligations

The following table summarizes our debt repayment obligations and material contractual commitments as of December 31, 2005 (in millions): 

	Amount of Commitment Expiration Per Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
Revolving Credit Facility	$	405.9	$	—	$	—	$	405.9	$	—
6.45% Senior Notes due 2008 (1) (2)	180.0		—		180.0		—		—
7.625% Senior Notes due 2012 (2)	500.0		—		—		—		500.0
6.125% Senior Notes due 2013 (2)	200.0		—		—		—		200.0
7.51% Senior Notes due 2028 (1) (2)	210.0		—		—		—		210.0
Interest payments (3)	823.1		97.8		189.9		171.6		363.8
Debt and interest subtotal	2,319.0		97.8		369.9		577.5		1,273.8
Operating leases (4)	83.7		19.5		28.3		14.3		21.6
Capital expenditure obligations (5)	24.5		24.5		—		—		—
Other liabilities and deferred credits (6)	3.7		—		3.2		0.3		0.2
Total	$	2,430.9	$	141.8	$	401.4	$	592.1	$	1,295.6

(1)Obligations of TE Products.

(2)Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028.  At December 31, 2005, the 7.51% Senior Notes include an adjustment to decrease the fair value of the debt by $0.9 million related to this interest rate swap agreement.  We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012.  At December 31, 2005, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $32.4 million.  At December 31, 2005, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $2.4 million of unamortized debt discounts.  The fair value adjustments, the deferred gain adjustment and the unamortized debt discounts are excluded from this table.

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

(4)Includes a pipeline capacity lease with Centennial.  In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement.  For the year ended December 31, 2005, TE Products exceeded the minimum throughput requirements on the lease agreement.

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(5)Includes accruals for costs incurred but not yet paid relating to capital projects.

(6)Excludes approximately $8.6 million of long-term deferred revenue payments, which are being transferred to income over the term of the respective revenue contracts and $4.6 million related to our estimated amount of obligation under a catastrophic event guarantee for Centennial.  The amount of commitment by year is our best estimate of projected payments of these long-term liabilities.

At December 31, 2005, we had an $11.5 million standby letter of credit in connection with crude oil purchases in the fourth quarter of 2005.  This amount will be paid during the first quarter of 2006.

We expect to repay the long-term, senior unsecured obligations and bank debt through the issuance of additional long-term senior unsecured debt at the time the 2008, 2012, 2013 and 2028 debt matures, issuance of additional equity, with proceeds from dispositions of assets, cash flow from operations or any combination of the above items.

In addition to the items in the table above, we have entered into various operational commitments and agreements related to pipeline operations and to the marketing, transportation, terminaling and storage of crude oil.  The majority of contractual commitments we make for the purchase of crude oil range in term from a thirty-day evergreen to one year.  A substantial portion of the contracts for the purchase of crude oil that extend beyond thirty days include cancellation provisions that allow us to cancel the contract with thirty days written notice.  During the year ended December 31, 2005, crude oil purchases averaged approximately $665.8 million per month.

Our senior unsecured debt is rated BBB- by Standard and Poors (“S&P”) and Baa3 by Moody’s Investors Service (“Moody’s”).  S&P assigned this rating on June 14, 2005, following its review of the ownership structure, corporate governance issues, and proposed funding after the acquisition of the General Partner by DFI.  Both ratings are with a stable outlook.  A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness.  Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it determines that the circumstances warrant such a change.  The senior unsecured debt of our subsidiary, TE Products, is also rated BBB- by S&P and Baa3 by Moody’s.  Both ratings are with a stable outlook.

Recent Accounting Pronouncements

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

Item 7A.   Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk

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

We seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations.  On the majority of our crude oil derivative contracts, we take the normal purchase and normal sale exclusion in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133.

On a small portion of our crude oil marketing business, we enter into derivative contracts such as swaps and other business hedging devices for which we cannot take the normal purchase and normal sale exclusion.  Generally, hedge accounting is elected.  The terms of these contracts are typically one year or less.  The purpose is to balance our position or lock in a margin and, as such, the derivative contracts do not expose us to additional

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significant market risk.  For derivatives where hedge accounting is elected, the effective portion of changes in fair value are recorded in other comprehensive income and reclassified into earnings as such transactions are settled.  For derivatives where hedge accounting is not elected, we mark these transactions to market and the changes in the fair value are recognized in current earnings.  This results in some financial statement variability during quarterly periods; however, any unrealized gains and losses reflected in the financial statements related to marking these transactions to market are offset by realized gains and losses in different quarterly periods when the transactions are settled.

At December 31, 2005, we had a limited number of commodity derivatives that were accounted for as cash flow hedges.  Gains and losses on these derivatives are offset against corresponding gains or losses of the hedged item and are deferred through other comprehensive income, thus minimizing exposure to cash flow risk.  The fair value of the open positions at December 31, 2005 was $0.1 million.  Assuming a hypothetical across-the-board 10% price decrease in the forward curve, the change in fair value of the hedging instrument would have been $0.7 million.  At December 31, 2004, we had a limited number of commodity derivatives where the transactions were marked to market because hedge accounting was not elected.  The fair value of the open positions at December 31, 2004 was $0.3 million.  The fair value of the open positions was based upon both quoted market prices obtained from NYMEX and were estimated based on quoted prices from various sources such as independent reporting services, industry publications, brokers and marketers.  The fair values were determined based upon the differences by month between the fixed contract price and the relevant forward price curve, the volumes for the applicable month and a discount rate of 6%.

Interest Rate Risk

At December 31, 2005, we had $405.9 million outstanding under our variable interest rate revolving credit facility.  The interest rate is based, at our option, on either the lender’s base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semiannually.  Utilizing the balances of our variable interest rate debt outstanding at December 31, 2005, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense would be $4.1 million.

The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2005 and 2004 (in millions):

			Fair Value
	Face		December 31,
	Value		2005		2004
6.45% TE Products Senior Notes, due January 2008	$	180.0	$	183.7	$	187.1
7.625% Senior Notes, due February 2012	500.0		552.0		569.6
6.125% Senior Notes, due February 2013	200.0		205.6		210.2
7.51% TE Products Senior Notes, due January 2028	210.0		224.1		225.6

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

In July 2000, we entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility.  This interest rate swap matured in April 2004.  We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge.  The swap agreement was based on a notional amount of $250.0 million.  Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate.  Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings.  During the years ended December 31, 2004 and 2003, we

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recognized an increase in interest expense of $2.9 million and $14.4 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge.  The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes.  Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%.  During the years ended December 31, 2005, 2004 and 2003, we recognized reductions in interest expense of $5.6 million, $9.6 million and $10.0 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.  During the years ended December 31, 2005, 2004 and 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized.  The fair value of this interest rate swap was a loss of approximately $0.9 million at December 31, 2005, and a gain of approximately $3.4 million at December 31, 2004. Utilizing the balance of the 7.51% TE Products Senior Notes outstanding at December 31, 2005 and including the effects of hedging activities, assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $2.1 million.

During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012.  The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes.  Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%.  These swap agreements were later terminated in 2002 resulting in gains of $44.9 million.  The gains realized from the swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes.  At December 31, 2005, the unamortized balance of the deferred gains was $32.4 million.  In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

During May 2005, we executed a treasury rate lock agreement with a notional amount of $200.0 million to hedge our exposure to increases in the treasury rate that was to be used to establish the fixed interest rate for a debt offering that was proposed to occur in the second quarter of 2005.  During June 2005, the proposed debt offering was cancelled, and the treasury lock was terminated with a realized loss of $2.0 million.  The realized loss was recorded as a component of interest expense in the consolidated statements of income.

In January 2006, we entered into interest rate swaps with a total notional amount of $200.0 million, whereby we will receive a floating rate of interest and will pay a fixed rate of interest for a two-year term.  These interest rate swaps were executed to decrease the exposure to potential increases in floating interest rates.  Using the balances of outstanding debt at December 31, 2005, these interest rate swaps decrease the level of floating interest rate debt from 41% to 29% of total outstanding debt.

Item 8.       Financial Statements and Supplementary Data

Our consolidated financial statements, together with the independent registered public accounting firm’s report of KPMG LLP, begin on page F-1 of this Report.

Item 9.       Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

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Item 9A.   Controls and Procedures

As of the end of the period covered by this report, our management carried out an evaluation, with the participation of our acting principal executive officer (the “CEO”) and our principal financial officer (the “CFO”), of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934.  Based on those evaluations, as of December 31, 2005, the acting CEO and CFO concluded:

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

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

Management’s Annual Report on Internal Control over Financial Reporting

The management of Texas Eastern Products Pipeline Company, LLC, (the “General Partner”), the General Partner of TEPPCO Partners, L.P. (the “Partnership”), is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  The Partnership’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  The Partnership’s internal control over financial reporting includes those policies and procedures that:

(i)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Partnership;

(ii)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and

(iii)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2005.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

Based on the assessment and those criteria, management believes that the Partnership maintained effective internal control over financial reporting as of December 31, 2005.

The Partnership’s registered public accounting firm has issued an attestation report on management’s assessment of the Partnership’s internal control over financial reporting.  That report appears below.

/s/ LEE W. MARSHALL, SR.

Lee W. Marshall, Sr.

Acting Chief Executive Officer and Chairman of the Board

Texas Eastern Products Pipeline Company, LLC, General Partner

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/s/ WILLIAM G. MANIAS

William G. Manias

Vice President and Chief Financial Officer

Texas Eastern Products Pipeline Company, LLC, General Partner

Report of Independent Registered Public Accounting Firm

To the Partners of

TEPPCO Partners, L.P.:

We have audited management’s assessment, included in the accompanying report titled Management’s Annual Report on Internal Control over Financial Reporting included in Item 9A, that TEPPCO Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissions (COSO).  TEPPCO Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of TEPPCO Partners, L.P.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that TEPPCO Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Also, in our opinion, TEPPCO Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2005 and 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash

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flows for each of the years in the three-year period ended December 31, 2005, and our report dated February 28, 2006, expressed an unqualified opinion on those consolidated financial statements. Our report contains a separate paragraph that states that as discussed in Note 20 to the consolidated financial statements, TEPPCO Partners, L.P. has restated its consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, partners’ capital and comprehensive income and cash flows for the years ended December 31, 2004 and 2003.

	KPMG LLP
Houston, Texas
February 28, 2006

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information

None.

PART III

Item 10.  Directors and Executive Officers of the Registrant

Partnership Management

We do not directly have directors or officers, as is commonly the case with publicly traded partnerships. Our operations and activities are managed by the General Partner, which employs our management and operational personnel.  The officers and directors of the General Partner are responsible for managing us.  All directors of the General Partner were elected annually by DEFS through February 24, 2005.  From February 24, 2005, all directors of the General Partner are elected annually by EPCO.  All officers serve at the discretion of the directors.  None of the officers of the General Partner, with the exception of William Ordemann, serve as officers or employees of EPCO or any other parent-affiliated company.  Mr. Ordemann serves as Senior Vice President of Enterprise Products GP, LLC (“Enterprise Products GP”), the general partner of Enterprise and as Senior Vice President of the Company.

Because we are a limited partnership, we meet the definition of a “controlled company” under the listing standards of the New York Stock Exchange.  Accordingly, we and our General Partner are not required to have a majority of independent directors or a nominating or compensation committee of the General Partner’s board of directors (the “Board”).

Effective March 22, 2005, Jim W. Mogg, Mark A. Borer, Michael J. Bradley, Milton Carroll, Derrill Cody, John P. DesBarres, William H. Easter III and Paul F. Ferguson, Jr., each of whom had been elected to the Board by DEFS, resigned.  These changes followed the acquisition of the Company by an affiliate of EPCO from DEFS.  The newly elected directors were Ralph S. Cunningham, Lee W. Marshall, Sr., Murray H. Hutchison and Michael B. Bracy.  Dr. Cunningham served as Chairman of the Board until his resignation effective November 23, 2005.  Barry R. Pearl continued to serve as chief executive officer, president and a director until his retirement effective December 31, 2005.  Mr. Marshall was named Chairman upon Dr. Cunningham’s resignation and acting chief executive officer upon Mr. Pearl’s resignation.  Effective January 6, 2006, Richard S. Snell was named a director of the Company.  Effective February 14, 2006, Richard H. Bachmann, Michael A. Creel and W. Randall Fowler were elected as directors of the Company.

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Committees of the Board of Directors

Audit and Conflicts Committee

Our General Partner has an audit and conflicts committee (the “Audit and Conflicts Committee”) comprised of three board members who were determined by the Board to be “independent” as that term is defined in Rule 10A-3 of the Exchange Act and as that term is used in applicable listing standards of the New York Stock Exchange.  Accordingly, our Board has determined that no Audit and Conflicts Committee member has a material relationship with the Company.  The members of the Audit and Conflicts Committee are Michael B. Bracy (Chairman), Murray H. Hutchison and Richard S. Snell.  Lee W. Marshall, Sr. had been a member of the Audit and Conflicts Committee from March 22, 2005 until December 31, 2005, when he became acting chief executive officer of the Company.  The current members of the Audit and Conflicts Committee are non-employee directors of the General Partner and are not officers, directors or otherwise affiliated with EPCO or its subsidiaries, with the exception of Mr. Snell, who was also a member of the board of directors of Enterprise Products GP, the general partner of Enterprise, until February 14, 2006.  The Board determined that Mr. Snell’s directorship with Enterprise Products GP was not a material relationship because Mr. Snell has no relationship with us, the General Partner, Enterprise Products GP or any of their respective affiliates, other than serving as a director as described above.  Furthermore Mr. Snell has received no compensation or fees (directly or indirectly) from any of these entities or their affiliates, other than ordinary-course compensation for serving as a board or committee member of the General Partner and Enterprise Products GP.  No member of the Audit and Conflicts Committee of our General Partner serves on the audit committees of more than three public companies.  Our Board has also determined that Mr. Bracy qualifies as an audit committee financial expert as defined in Item 401(h) of Regulation S-K promulgated by the SEC.

The Audit and Conflicts Committee provides independent oversight with respect to our internal controls, disclosure controls, accounting policies, financial reporting, the integrity of the financial statements, internal audit function, the independent auditors and compliance with legal and regulatory requirements.  The Audit and Conflicts Committee also reviews the scope and quality, including the independence and objectivity of the independent and internal auditors.  The Audit and Conflicts Committee has sole authority as to the retention, evaluation, compensation and oversight of the work of the independent auditors.  The independent auditors report directly to the Audit and Conflicts Committee.  The Audit and Conflicts Committee also has sole authority to approve all audit and non-audit services provided by the independent auditors and shall ensure that the independent auditors are not engaged to perform specific non-audit services prohibited by law or regulation.

Our Audit and Conflicts Committee has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters.  Persons wishing to communicate with our Audit and Conflicts Committee may do so by calling 1-877-888-0002.

Code of Ethics, Corporate Governance Guidelines and Charter of the Audit and Conflicts Committee

We have adopted a Code of Ethics applicable to all employees, including the principal executive officer, principal financial officer and directors of the General Partner.  A copy of the Code of Ethics is available on our website at www.teppco.com under Corporate Governance.  We intend to post on our website any amendments to, or waivers from, our Code of Ethics applicable to our senior officers.

Our Corporate Governance Guidelines address director qualification standards; director responsibilities; director access to management, and as necessary and appropriate, independent advisors; director compensation; director orientation and continuing education; management succession and annual performance evaluation of the Board.  The Charter of our Audit Committee and our Corporate Governance Guidelines are currently available on our website at www.teppco.com under Corporate Governance.  Additionally, the Code of Ethics, our Corporate Governance Guidelines and the Charter of the Audit and Conflicts Committee are available in print to any person who requests the information.  Persons wishing to obtain this printed material should submit a request in care of Secretary, TEPPCO Partners, L.P., 2929 Allen Parkway, P.O. Box 2521, Houston, Texas 77252-2521.

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NYSE Corporate Governance Listing Standards

Annual CEO Certification

On October 3, 2005, our chief executive officer certified to the New York Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, that as of October 3, 2005, he was not aware of any violation by us of the New York Stock Exchange’s Corporate Governance listing standards.

Executive Sessions of Non-Management Directors

For the period from January 1, 2005 through March 22, 2005, Mark A. Borer, Michael J. Bradley, Milton Carroll, Derrill Cody, John P. DesBarres, William H. Easter III, Paul F. Ferguson, Jr. and Jim W. Mogg, were non-management directors of our General Partner.  They met at regularly scheduled executive sessions without management.  Mr. Mogg served as the presiding director at those executive sessions.  For the period from January 1, 2005 through March 22, 2005, Milton Carroll, John P. DesBarres and Paul F. Ferguson, Jr., were independent directors of our General Partner.  They met once during this period in executive session without management and the other directors.

For the period from March 22, 2005 through December 31, 2005, Michael B. Bracy, Murray H. Hutchison and Lee W. Marshall, Sr., were independent directors of our General Partner, except that effective December 31, 2005, Lee W. Marshall, Sr. was appointed acting chief executive officer and was no longer determined to be independent.  They met at regularly scheduled executive sessions without management.  On January 6, 2006, Richard S. Snell was elected a director of the General Partner and became an independent director.  The chair of the Audit and Conflicts Committee, Michael B. Bracy, is the chair of the independent directors.  Persons wishing to communicate with the Company’s independent directors may do so by calling 1-877-888-0002.

Directors and Executive Officers

The following table sets forth certain information with respect to the directors and executive officers of the General Partner as of February 28, 2006. 

Name	Age	Position with Our General Partner
Lee W. Marshall, Sr.	73	Chairman of the Board and Acting Chief Executive Officer
Michael B. Bracy	64	Director, Member of Audit and Conflicts Committee*
Murray H. Hutchison	67	Director, Member of the Audit and Conflicts Committee
Richard S. Snell	63	Director, Member of the Audit and Conflicts Committee
Michael A. Creel	52	Director
Richard H. Bachmann	53	Director
W. Randall Fowler	49	Director
J. Michael Cockrell+	59	Senior Vice President of Commercial Upstream
Leonard W. Mallett+	49	Senior Vice President of Operations
James C. Ruth+	58	Senior Vice President, General Counsel and Secretary
William Ordemann	46	Senior Vice President
William G. Manias	44	Vice President and Chief Financial Officer
Barbara A. Carroll+	51	Vice President of Environmental, Health and Safety
John N. Goodpasture+	57	Vice President of Corporate Development
Stephen W. Russell+	54	Vice President of Support Services
C. Bruce Shaffer+	47	Vice President of Human Resources and Ethics and Compliance Officer
Stephen O. McNair	43	Vice President of Natural Gas Services
Samuel N. Brown	49	Vice President of Commercial Downstream
Patricia A. Totten	55	Vice President, General Counsel and Secretary**

* Chairman of committee

+ See Executive Employment Contracts and Termination of Employment Arrangements

** Effective March 1, 2006.

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Lee W. Marshall, Sr. was elected Acting Chief Executive Officer effective December 31, 2005 upon the retirement of Barry R. Pearl, and Chairman of the Board in November 2005, upon the resignation of Dr. Ralph S. Cunningham.  He served as a member of the Audit and Conflicts Committee from March 2005 to December 2005.  Prior to being elected to the Board in March 2005 upon the change in ownership of the General Partner, Mr. Marshall served as a director of Enterprise Products GP, the general partner of Enterprise from 1998 until his resignation on March 22, 2005.  Mr. Marshall has been the managing partner and principal owner of Bison Resources, LLC, a privately held oil and gas production company, since 1993.  Previously, he held senior management positions with Union Pacific Resources as senior vice president, refining, manufacturing and marketing; with Wolverine Exploration Company as executive vice president and chief financial officer; and with Tenneco Oil Company as senior vice president, marketing.

Michael B. Bracy was elected a director of the General Partner in March 2005, upon the change in ownership of the General Partner.  He also serves as Chairman of the Audit and Conflicts Committee.  Prior to being elected to the Board in March 2005, Mr. Bracy served as a director of the general partner of GulfTerra Energy Partners, L.P. (“GulfTerra”) from October 1998 until September 30, 2004, when it merged with Enterprise.  He was also an audit committee financial expert as determined under the SEC rules while serving on the board of GulfTerra’s general partner.  Mr. Bracy also serves as an audit committee financial expert on the Board of the General Partner.  From 1993 to 1997, Mr. Bracy served as director, executive vice president and chief financial officer of NorAm Energy Corp.  For nine years prior, he served in various executive capacities with NorAm Energy Corp.  Mr. Bracy is a member of the board of directors of Itron, Inc.

Murray H. Hutchison was elected a director of the General Partner in March 2005, upon the change in ownership of the General Partner.  He also serves as a member of the Audit and Conflicts Committee.  Mr. Hutchison is a private investor managing his own portfolio.  He also consults with corporate managements on strategic issues.  Mr. Hutchison retired in 1997 as chairman and chief executive officer of the IT Group (International Technology Corporation) after serving in that position for over 27 years.  Mr. Hutchison serves as chairman of the board of Huntington Hotel Corporation and as a director on the boards of Cadiz Inc., Jack in the Box Inc., The Olson Company and Cardium Therapeutics, Inc.  He is a member of the board of management of the San Diego Foundation and the Rancho Santa Fe Foundation.

Richard S. Snell was elected a director of the General Partner in January 2006.  He also serves as a member of the Audit and Conflicts Committee.  Mr. Snell was an attorney with the Snell & Smith, P.C. law firm in Houston, Texas, from the founding of the firm in 1993 until May 2000.  Since May 2000, he has been a partner with the firm of Thompson & Knight LLP in Houston, Texas, and is a certified public accountant.  Mr. Snell served as a director of Enterprise Products GP from June 2000 until his resignation in February 2006.

Michael A. Creel was elected a director of the General Partner in February 2006.  Mr. Creel is currently executive vice president of Enterprise Products GP and EPCO, having been elected in January 2001, after serving as a senior vice president of Enterprise Products GP and EPCO from November 1999 to January 2001.  Mr. Creel, a certified public accountant, served as chief financial officer of EPCO from June 2000 through April 2005 and was named chief operating officer of EPCO in April 2005.  In June 2000, Mr. Creel was also named chief financial officer of Enterprise Products GP.  Mr. Creel has served as a director of Enterprise Products OLPGP, Inc. (a wholly subsidiary of Enterprise) since December 2003, and has served as president, chief executive officer and a director of EPE Holdings, LLC since August 2005.  Mr. Creel was elected a director of Edge Petroleum Corporation (a publicly traded oil and natural gas exploration and production company) in October 2005 and a director of Enterprise Products GP in February 2006.

Richard H. Bachmann was elected a director of the General Partner in February 2006.  Mr. Bachmann is currently executive vice president, chief legal officer and secretary of Enterprise Products GP and EPCO, having been elected in January 1999.  Mr. Bachmann previously served as a director of Enterprise Products GP from June 2000 to January 2004.  Mr. Bachmann has served as a director of Enterprise Products OLPGP, Inc. since December 2003, and has served as executive vice president, chief legal officer and secretary of EPE Holdings, LLC since August 2005.  Mr. Bachmann was elected a director of EPCO in January 1999 and EPE Holdings, LLC and Enterprise Products GP in February 2006.  Mr. Bachmann was a partner in the law firms of Snell & Smith, P.C. from 1993 to 1998 and Butler & Binion from 1988 to 1993.

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W. Randall Fowler was elected a director of the General Partner in February 2006.  Mr. Fowler is currently senior vice president and treasurer of Enterprise Products GP, having been elected in February 2005, and is chief financial officer of EPCO, having been elected in April 2005.  Mr. Fowler, a certified public accountant (inactive), joined Enterprise Products Partners L.P. as director of investor relations in January 1999 and served as treasurer and a vice president of Enterprise Products GP and EPCO from August 2000 to February 2005.  Mr. Fowler has served as senior vice president and chief financial officer of EPE Holdings, LLC since August 2005.  Mr. Fowler was elected a director of EPE Holdings, LLC and Enterprise Products GP in February 2006.

J. Michael Cockrell is Senior Vice President, Commercial Upstream of the General Partner, having been elected in February 2003.  Mr. Cockrell was previously Vice President, Commercial Upstream from September 2000 until February 2003.  He was elected Vice President of the General Partner in January 1999 and also serves as President of TEPPCO Crude GP, LLC.  He joined PanEnergy in 1987 and served in a variety of positions in supply and development, including president of DETTCO.

Leonard W. Mallett is Senior Vice President, Operations of the General Partner, having been elected in February 2005.  He was previously Vice President, Operations from September 2000 until February 2005.  Mr. Mallett was previously Region Manager of the Southwest Region of the Company from 1994 until 1999 and Director of Engineering, from 1992 until 1994.  Mr. Mallett joined the Company in 1979 as an engineer.

James C. Ruth was Senior Vice President, General Counsel and Secretary of the General Partner, having been elected in February 2001. Mr. Ruth was previously Vice President and General Counsel and Secretary from 1998 until February 2001, and Vice President, General Counsel from 1991 until 1998.  Mr. Ruth joined the Company in 1970.  Effective February 28, 2006, Mr. Ruth retired from the Company.

William Ordemann is Senior Vice President, responsible for the commercial development of the Jonah system, of the General Partner, having been elected in July 2005.  Mr. Ordemann has served as senior vice president of Enterprise Products GP, the general partner of Enterprise, since September 2001.  He was previously vice president of Enterprise Products GP from October 1999 to September 2001.  Prior to joining Enterprise Products GP, Mr. Ordemann served as vice president of Tejas Natural Gas Liquids, LLC from February 1998 to September 1999, and vice president of Shell Midstream Enterprises, LLC from January 1997 to February 1998.

William G. Manias is Chief Financial Officer of the Company, having been elected effective January 13, 2006.  Mr. Manias was vice president of corporate development of Enterprise Products GP from October 2004 until January 2006.  He served as vice president and chief financial officer of Gulfterra Energy Partners, L.P. from February 2004 until October 2004.  Mr. Manias was previously vice president of business development and strategic planning at El Paso Energy Partners, L.P. from October 2001 to February 2004.  Prior to his joining El Paso Energy Partners, L.P. in October 2001, Mr. Manias served as vice president of investment banking for J.P. Morgan Securities Inc. (formerly Chase Securities Inc.) from January 1996 to August 2001.  Mr. Manias serves as principal financial and accounting officer of the Company.

Barbara A. Carroll is Vice President, Environmental, Health and Safety, having been elected in February 2002.  Ms. Carroll joined ExxonMobil in 1990 and served in a variety of management positions, including procurement services manager, materials and service manager and Baytown area public affairs manager until she joined the Company in February 2002.  Prior to ExxonMobil, Ms. Carroll was general manager, corporate environmental protection and compliance with Panhandle Eastern Corporation.

John N. Goodpasture is Vice President, Corporate Development of the General Partner, having joined the Company in November 2001.  Mr. Goodpasture was previously vice president of business development for Enron Transportation Services from June 1999 until he joined the Company. Prior to his employment at Enron Transportation Services, Mr. Goodpasture spent 19 years in various executive positions at Seagull Energy Corporation (now Devon Energy Corporation), a large independent oil and gas company.  At Seagull Energy, Mr. Goodpasture had most recently served for over ten years as senior vice president, pipelines and marketing.

Stephen W. Russell is Vice President, Support Services of the General Partner, having been elected in September 2000.  Mr. Russell was previously Region Manager of the Southwest Region from July 1999 until

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September 2000, and Technical Operations Superintendent of the Southwest Region from 1994 until 1999.  Mr. Russell joined the Company in 1988 as Project Manager in Engineering.

C. Bruce Shaffer is Vice President, Human Resources and Ethics and Compliance Officer of the General Partner, having been elected in February 2005.  Mr. Shaffer joined the Company in August 2004 supporting Human Resources.  He was previously vice president of human resources services for Duke Energy Gas Transmission and Duke Energy Americas from January 2004 until July 2004 and vice president of human resources for Duke Energy North America from June 2003 until July 2004.  Mr. Shaffer joined Duke Energy in January 2000 as managing director of human resources for Duke Energy North America and Duke Energy International.

Stephen O. McNair is Vice President, Natural Gas Services of the General Partner, having been elected in July 2005.  Mr. McNair joined our General Partner in June 2005.  He was previously Rockies Region vice president for DEFS.  He joined DEFS as general manager of operations, West Permian Region in 2000.  Prior to his employment with DEFS, Mr. McNair held various engineering, commercial and operations management positions with Conoco Inc. and GPM Gas Corporation.

Samuel N. Brown is Vice President, Commercial Downstream of the General Partner, having been elected in June 2005.  He was previously Vice President, Pipeline Marketing and Business Development in our Upstream Segment from September 2000 to June 2005.  Mr. Brown joined the Company in 1998 as Vice President of Pipeline Marketing and Business Development.  Prior to joining the Company in 1998, he was vice president of commercial operations at DETTCO from 1996 until 1998.

Patricia A. Totten has been elected Vice President, General Counsel and Secretary of the General Partner, effective March 1, 2006.  She was previously associate general counsel and deputy general counsel for Enterprise Products GP from December 2002 to January 2006.  Prior to joining Enterprise Products GP in August 2002, Ms. Totten served as general counsel of Solid Systems Inc. from March 2001 to August 2002, and as assistant general counsel and vice president of marketing for a small wireless company from 1995 to December 2000 that was merged into Verizon Wireless in 2000.

In addition to our Executive Officers, Mark G. Stockard serves as Treasurer since May 2002.  Mr. Stockard was Assistant Treasurer of the General Partner from July 2001 until May 2002.  He was previously Controller from October 1996 until May 2002.  Mr. Stockard joined the Company in October 1990.  Tracy E. Ohmart serves as Controller since May 2002.  Mr. Ohmart served as acting Chief Financial Officer of the General Partner from July 2005 until January 2006.  Mr. Ohmart joined the General Partner in January 2001 and held various positions with the Company until he became Assistant Controller in May 2001.  Prior to his employment with the General Partner, Mr. Ohmart spent 12 years in various positions at ARCO Pipe Line Company, most recently serving as supervisor of general accounting and policy.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of such equity securities.  Based on information furnished to the Company and written representation that no other reports were required, to the Company’s knowledge, all applicable Section 16(a) filing requirements were complied with during the year ended December 31, 2005, except for a report covering a transaction that was filed late by Mr. McNair and four reports covering four transactions totaling $640 that were filed late by Mr. Mallett.

Item 11.  Executive Compensation

Summary Compensation Table

The officers of the General Partner manage and operate our business.  We do not directly employ any of the persons responsible for managing or operating our operations, but instead reimburse the General Partner for the services of these persons (see Note 7 in the Notes to the Consolidated Financial Statements).  The following table

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reflects information regarding compensation paid or accrued by the General Partner for the years ended December 31, 2005, 2004 and 2003, with respect to each person who served as Chief Executive Officer during 2005, the four other most highly compensated executive officers serving at December 31, 2005, and one former executive officer for whom disclosure would have been required but for the fact that he was not serving at December 31, 2005 (collectively, the “Named Executive Officers”).

SUMMARY COMPENSATION TABLE

				Other	Long Term
	Annual Compensation			Annual	Compensation	All Other
Name and			Bonus	Compensation	Payouts	Compensation
Principal Position	Year	Salary ($)	($) (1)	($) (2)	($)(3)	($) (4)
Lee W. Marshall, Sr. (5)	2005	—	—	—	—	66,669
Chairman and Acting Chief Executive Officer
Barry R. Pearl (6)	2005	329,409	256,939	31,202	1,255,057	1,624,199
President and Chief	2004	291,738	157,242	59,431	291,910	31,321
Executive Officer	2003	283,500	196,465	52,000	—	27,608
J. Michael Cockrell	2005	232,973	139,565	8,407	190,746	44,278
Senior Vice President,	2004	209,654	91,451	12,021	—	32,714
Commercial Upstream	2003	202,846	114,364	7,250	108,225	69,078
James C. Ruth (7)	2005	228,768	133,829	9,799	304,250	42,543
Senior Vice President and	2004	208,308	88,218	14,906	183,106	34,069
General Counsel	2003	195,654	108,333	20,250	456,084	864,675
Charles H. Leonard (8)	2005	124,570	—	6,559	403,082	1,035,348
Senior Vice President and	2004	202,654	86,391	14,906	183,106	325,281
Chief Financial Officer	2003	195,654	108,800	20,250	271,523	22,007
Thomas R. Harper (9)	2005	218,077	129,170	8,535	245,201	32,536
Senior Vice President,	2004	197,115	84,365	12,322	139,300	29,646
Commercial Downstream	2003	181,154	102,135	15,500	493,052	25,334
John N. Goodpasture	2005	212,409	125,215	9,330	301,773	2,410
Vice President,	2004	195,846	81,296	14,707	3,445	19,775
Corporate Development	2003	189,846	104,263	13,250	—	18,996

(1)Amounts represent bonuses accrued during the year under the Management Incentive Compensation Plan (“MICP”). Payments under the MICP are made in the subsequent year.  Annual compensation does not include awards under long-term incentive plans, which are described in the 2000 LTIP awards table under “Compensation Pursuant to General Partner Plans”.

(2)Amounts represent quarterly distribution equivalents under the terms of the Company’s 2000 Long Term Incentive Plan (“2000 LTIP”).

(3)Amounts represent payouts under the 2000 LTIP.

(4)Includes (i) Company matching contributions under funded, qualified, defined contribution retirement plans; (ii) Company matching contribution credits under unfunded, non qualified plans; (iii) the imputed value of premiums paid by the Company for Named Executive Officers’ life insurance; (iv) credits earned to Performance Unit accounts; and (v) payments received under the Duke Energy Retirement Cash Balance Plan.  Includes severance payments, including unused vacation days and COBRA insurance premiums, for Mr. Pearl and Mr. Leonard.

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(5)Mr. Marshall became Acting Chief Executive Officer effective December 31, 2005.  Mr. Marshall is not being compensated for his position as Acting Chief Executive Officer.  Amount included in All Other Compensation is compensation for his service as a director and as Chairman.

(6)Mr. Pearl was President and Chief Executive Officer of the Company in 2005 until his retirement effective December 31, 2005.

(7)Mr. Ruth retired effective February 28, 2006.

(8)Mr. Leonard retired effective July 8, 2005.

(9)Mr. Harper retired effective February 3, 2006.

Executive Employment Contracts and Termination of Employment Arrangements

On February 12, 2001, Barry R. Pearl and the Company entered into an employment agreement, as amended on February 23, 2005 and June 1, 2005, (collectively, the “Pearl Employment Agreement”).  The Pearl Employment Agreement could be terminated by the Company for cause, upon Mr. Pearl’s death or disability, or by the Company or Mr. Pearl upon written notice.  Mr. Pearl participated in other Company sponsored benefit plans on the same basis as other senior executives.  In the event Mr. Pearl was terminated due to death or disability or for cause, Mr. Pearl was entitled only to base salary earned through the date of termination.  In the event of termination for any other reason, Mr. Pearl was entitled to base salary earned through the date of termination plus a lump sum severance payment equal to two times his annual base salary and two times the current target bonus approved under the MICP by the Board. In the event Mr. Pearl was involuntarily terminated within twelve months following a change in control, he was entitled to a lump sum severance payment equal to three times his annual base salary plus three times his current target bonus.  If Mr. Pearl was involuntarily terminated after twelve months following a change in control, he was entitled to a lump sum severance payment equal to two times his base annual salary plus two times his current target bonus.

In connection with Mr. Pearl’s retirement, the Pearl Employment Agreement was terminated effective December 31, 2005, and he and the Company entered into an Agreement and Release, dated December 30, 2005.  The Agreement and Release provides for Mr. Pearl to be paid, in lump sum, three times his base salary plus three times his target bonus.  The Company will also pay COBRA insurance premiums for up to 36 months on behalf of Mr. Pearl and will make payments and provide benefits in accordance with the Company’s various plans and programs, including incentive, retirement and benefit plans.  The amount of Mr. Pearl’s lump sum payment was $1.9 million.

The Company has entered into employment agreements with each of its Named Executive Officers, except for Mr. Marshall.  The agreements may be terminated for death, disability or by the Company with or without cause, or for any reason by the Company or the Named Executive Officer.  In the event the executive’s employment is terminated upon death or disability or by the Company for cause, the executive is entitled only to base salary earned through the date of termination.  In the event of termination by the Company for any other reason, the executive is entitled to base salary earned through the date of termination plus a lump sum severance payment equal to two times such executive’s base annual salary and two times the current target bonus approved under the MICP by the Chief Executive Officer.  In the event the executive is involuntarily terminated within twelve months following a change in control, the executive is entitled to a lump sum severance payment equal to three times his base annual salary plus three times his current target bonus.  In the event that the executive is involuntarily terminated after twelve months following a change in control or is involuntarily terminated following a change in control, such executive will be entitled to a lump sum severance payment equal to two times his base annual salary plus two times his current target bonus. Mr. Harper’s agreement terminated upon his retirement effective February 3, 2006.

On December 22, 1998, Charles H. Leonard, Senior Vice President and Chief Financial Officer, and the Company entered into an employment agreement, as amended on February 23, 2005, (collectively, the “Leonard Employment Agreement”).  In connection with Mr. Leonard’s retirement, the Leonard Employment Agreement was terminated effective July 8, 2005, and he and the Company entered into an Agreement and Release, dated July 11, 2005.  The Agreement and Release provides for Mr. Leonard to be paid, in lump sum, three times his base salary

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plus three times his target bonus.  The Company will also pay COBRA insurance premiums for up to 36 months on behalf of Mr. Leonard and will make payments and provide benefits in accordance with the Company’s various plans and programs, including incentive, retirement and benefit plans.  The amount of Mr. Leonard’s lump sum payment was $1.1 million.

On December 22, 1998, James C. Ruth, Senior Vice President, General Counsel and Secretary, and the Company entered into an employment agreement, as amended on February 23, 2005, (collectively, the “Ruth Employment Agreement”).  In connection with Mr. Ruth’s retirement, the Ruth Employment Agreement was terminated effective February 28, 2006, and he and the Company entered into an Agreement and Release, dated January 25, 2006.  The Agreement and Release provides for Mr. Ruth to be paid, in lump sum, three times his base salary plus three times his target bonus.  The Company will also pay COBRA insurance premiums for up to 36 months on behalf of Mr. Ruth and will make payments and provide benefits in accordance with the Company’s various plans and programs, including incentive, retirement and benefit plans.  The amount of Mr. Ruth’s lump sum payment is expected to total $1.2 million.

Compensation Committee Interlocks and Insider Participation

From January 1, 2005 through March 22, 2005, Jim W. Mogg, a director of the General Partner and group vice president and chief development officer of Duke Energy, was Chairman of the Compensation Committee of the General Partner and participated in deliberations concerning the General Partner’s executive officer compensation.  The other four members of the Compensation Committee of the General Partner at that time, Milton Carroll, Derrill Cody, John P. DesBarres and Paul F. Ferguson, Jr., were non-employee directors of the General Partner and were not officers or directors of DEFS or its parent companies, ConocoPhillips or Duke Energy.

Effective March 22, 2005, the Company no longer has a Compensation Committee.  The directors of the General Partner do not participate in deliberations concerning the General Partner’s executive officer compensation.  From March 22, 2005, through December 31, 2005, Barry R. Pearl determined the amount of cash compensation paid to the executive officers of the General Partner, other than himself.  For the period from March 22, 2005, to November 23, 2005, Dr. Ralph S. Cunningham, as Chairman of the Board of the General Partner, determined the amount of cash compensation paid to Mr. Pearl.  For the period from November 23, 2005, through December 31, 2005, Lee W. Marshall, Sr., as Chairman of the Board of the General Partner, determined the amount of cash compensation paid to Mr. Pearl.

Compensation Pursuant to General Partner Plans

Management Incentive Compensation Plan. (“MICP”)

For 2005, the General Partner established the MICP, which provides for the payment of additional cash compensation to participants if certain Partnership performance objectives and personal objectives are met each year.  In 2005, all of the Company’s employees were eligible participants in the MICP.  At the beginning of the year, our Chief Executive Officer determines the target award for each of the Named Executive Officers other than himself and approves the target awards for all other participants based on the recommendations of management.  The Chairman of the Board determines the Chief Executive Officer’s target award.  Target awards are determined as a percentage of total annual eligible earnings for the plan year less any incentive compensation payments during the plan year. Such target award determines the additional compensation to be paid if certain of the Partnership’s financial performance objectives and the participant’s personal objectives are met. The amount of the target awards may range from 10% to 60% of a participant’s base salary.  Awards are paid as soon as practicable following approval by the Chief Executive Officer after the close of a year.  The Chief Executive Officer has discretion to approve payment of awards for participants who are no longer employed by the Company (i.e., due to death, disability or retirement) on the date the awards are paid. 

1994 Long Term Incentive Plan

During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”).  The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Units.  These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Unit options awarded.  Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted.  No awards have been made under the 1994 LTIP since 1999, and none are expected to be made in the future.

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There were no Aggregated Option Exercises during the year ended December 31, 2005, under the 1994 LTIP by the Named Executive Officers, and there were no unexercised outstanding Unit options under the 1994 LTIP to the Named Executive Officers as of December 31, 2005.

2000 Long Term Incentive Plan

Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance.  Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period.  Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period.  If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period.

The performance period applicable to awards granted in 2005 is the three-year period that commenced on January 1, 2005, and ends on December 31, 2007.  Each participant’s performance percentage is the result of 100% +/- [(A) minus (C)] divided by [(C) minus (B)] where (A) is the actual Economic Value Added for the performance period, (B) is $73.0 million (which represents the actual Economic Value Added for the three-year period immediately preceding the performance period) and (C) is $97.7 million (which represents the Target Economic Value Added during the three-year performance period).  No amounts will be payable under the awards granted in 2005 for the 2000 LTIP unless Economic Value Added for the three year performance period exceeds $73.0 million.  The performance percentage may not exceed 150%.

Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period.  For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion the CEO of the partnership may exclude gains or losses from extraordinary, unusual or non-recurring items.  For the years ended December 31, 2005, 2004 and 2003, EBITDA means, in addition to the above, earnings before other income — net.  Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil operating oil supply and the gross value of intangibles and equity investments.  Our cost of capital is approved by the CEO at the date of award grant.

In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award.

The following table provides information concerning awards under the 2000 LTIP to each of the Named Executive Officers during 2005.

Name	Number of Phantom Units	Performance Period	Estimated Future Payouts (1)
			Threshold (#) (2)	Target (# (3)	Maximum (# (4)
Mr. Cockrell	2,500	3 years	—	2,500	3,750
Mr. Harper (5)	2,200	3 years	—	2,200	3,300
Mr. Goodpasture	2,200	3 years	—	2,200	3,300

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(1)Phantom units will be settled in cash based upon the then market price of the Units at the end of the performance period as described above.

(2)No amounts will be payable for awards granted in 2005 unless Economic Value Added for the three year performance period exceeds $73.0 million.

(3)In number of phantom units.  Pursuant to Instruction 5 to Regulation S-K, Item 402(e) promulgated by the Securities and Exchange Commission, these amounts assume that the 11% increase in Economic Value Added for 2005 as compared with 2004 is maintained for each of the three years in the performance period.  There can be no assurance that any specific amount of Economic Value Added will be attained for such period.

(4)The maximum potential payout under the 2000 LTIP is 150% of phantom units awarded.

(5)Mr. Harper retired from the Company effective February 3, 2006.  However, he remains an EPCO employee.  As he remains employed by an affiliate of the Partnership, he is entitled to a portion of his awarded units following the 2005-2007 performance period.

Pension Plan

Prior to the transfer of the General Partner interest from Duke Energy to DEFS on April 1, 2000, the Company’s employees participated in the Duke Energy Retirement Cash Balance Plan, which is a noncontributory, trustee-administered pension plan. Effective January 1, 1999, the benefit formula for all eligible employees was a cash balance formula.  Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age, and service.  In addition, the Named Executive Officers participated in the Duke Energy Executive Cash Balance Plan, which is a noncontributory, nonqualified, defined benefit retirement plan.  The Duke Energy Executive Cash Balance Plan was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans.

Benefits under the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan were based on eligible pay, generally consisting of base pay, short term incentive pay and lump-sum merit increases.  The Duke Energy Retirement Cash Balance Plan excludes deferred compensation, other than deferrals pursuant to Sections 401(k) and 125 of the Internal Revenue Code.  All benefits owed to the Named Executive Officers under the Duke Energy Retirement Cash Balance Plan have been paid.  As part of the change in ownership on March 31, 2000, the Company is no longer responsible for the funding of the liabilities associated with the Duke Energy Executive Cash Balance Plan.

Effective April 1, 2000, the Company adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) and the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”). The benefits and provisions of these plans were substantially identical to the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan previously in effect prior to April 1, 2000.

Under the cash balance benefit accrual formula that applies in determining benefits under the TEPPCO RCBP, an eligible employee’s plan account received a pay credit at the end of each month in which the employee remained eligible and received eligible pay for services.  The monthly pay credit was equal to a percentage of the employee’s monthly eligible pay.  The percentage depended on age added to completed years of services at the beginning of the year, as shown below:

	Monthly Pay
	Credit
Age plus Service	Percentage
34 or less	4	%
35 to 49	5	%
50 to 64	6	%
65 or more	7	%

The above monthly pay credit was increased by an additional 4% of any portion of eligible pay above the Social Security taxable wage base ($90,000 for 2005). Employee accounts also received monthly interest credits on

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their balances.  The rate of the interest credit was adjusted quarterly and was derived from the average annual yield on 30-year U.S. Treasury Bonds during the third week of the last month of the previous quarter, subject to a minimum rate of 4% per year and a maximum rate of 9% per year.

On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended.  Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date.  Effective December 31, 2005, all plan benefits accrued were frozen, participants will not receive additional pay credits after that date, and all plan participants will be 100% vested regardless of their years of service.  The TEPPCO RCBP plan was terminated effective December 31, 2005, subject to IRS approval of plan termination, and plan participants will have the option to receive their benefits either through a lump sum payment in 2006 or through an annuity.  For those plan participants who elect to receive an annuity, we will purchase an annuity contract from an insurance company in which the plan participant owns the annuity, absolving us of any future obligation to the participant.  Participants in the TEPPCO SBP received pay credits through November 30, 2005, and received lump sum benefit payments in December 2005.

Assuming that the Named Executive Officers continue in their present positions at their present salaries until retirement at age 65, their estimated annual pensions in a single life annuity form under the applicable pension plan(s) (including the Duke Energy Executive Cash Balance Plan, the TEPPCO RCBP and the TEPPCO SBP) attributable to such salaries would be as follows: Barry R. Pearl, $10,579; J. Michael Cockrell, $12,319; James C. Ruth, $27,314; John N. Goodpasture, $8,275; and Thomas R. Harper, $9,505.  Such estimates were calculated assuming interest credits at a rate of 4.59% per annum and using a future Social Security taxable wage base equal to $94,200.

Compensation of Directors

Effective January 1, 2005, for the period from January 1, 2005 through March 22, 2005, directors of the General Partner who were neither officers nor employees of either the Company or DEFS received a retainer of $35,000 per annum, $1,000 for attendance at each meeting of the Board, $1,000 for attendance at each meeting of a committee of the Board, except for attendance of the Audit Committee, for which the amount was $2,000 for each meeting, and reimbursement of expenses incurred in connection with attendance at a meeting of the Board or a committee of the Board.  Each non-employee director who served as Chairman of a committee of the Board received an additional retainer of $8,000 per annum, except for the Chairman of the Audit Committee, who received an additional retainer of $20,000 per annum.  Effective September 1, 1999, non-employee directors could elect to defer payment of retainer and attendance fees until termination of service on the Board.  Upon termination, the director could elect to receive payment either in a lump sum or in equal installments over five years.  Such deferral could either be 50% or 100% in either a fixed income investment account that is credited with annual interest (currently 7%) or an investment account based upon the market value of our Units.  Effective with the change in ownership of the General Partner on February 24, 2005, deferrals of Board compensation was discontinued.

Effective March 22, 2005, with the changes in the Board, fees for attendance at meetings were discontinued upon the election of the new Board members on March 22, 2005.  Mr. Hutchison and Mr. Snell each receive a retainer of $50,000 per annum as members of the Board.  Mr. Bracy receives a retainer of $60,000 per annum for his service as Chairman of the Audit and Conflicts Committee and as a member of the Board.  During his service as Chairman of the Board, Dr. Cunningham received a retainer of $25,000 per month, which was paid by EPCO.  Mr. Marshall received a retainer of $50,000 per annum as a member of the Board.  Upon his election to Chairman, Mr. Marshall receives a retainer of $25,000 per month for his service as Chairman of the Board.

During 2005, Mr. Pearl was not compensated for his services as a director.  It is not anticipated that any compensation for service as a director will be paid in the future to directors who are either officers or full-time employees of DFI, EPCO, or the General Partner or any of their affiliates.  Mr. Bachmann, Mr. Creel and Mr. Fowler will not be compensated for their services as directors.

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Item 12.  Security Ownership of Certain Beneficial Owners and Management

Equity Compensation Plan Information

At December 31, 2005, we had no Equity Compensation Plans approved or unapproved by security holders as none of our compensation plans require the issuance of securities or options.  During the year ended December 31, 2003, all of the remaining outstanding Unit options under the 1994 LTIP were exercised (see Compensation Pursuant to General Partner Plans).  We have no other compensation plans that would result in the issuance of Units.

Security Ownership of Certain Beneficial Owners

As of February 24, 2006, DFI, through its ownership of the Company and other subsidiaries, owns 2,500,000 Units, representing 3.6% of the 70.0 million Units outstanding.  No other person is known by us to own more than 5% of our outstanding Units.

 Security Ownership of Management

The following table sets forth certain information, as of February 24, 2006, concerning the beneficial ownership of Units by each director and Named Executive Officer of the General Partner and by all directors and officers of the General Partner as a group.  This information is based on data furnished by the persons named.  Based on information furnished to the General Partner by these persons, no director or officer of the General Partner owned beneficially, as of February 24, 2006, more than 1% of the 70.0 million Units outstanding at that date.

Name	Number of Units (1)
Michael B. Bracy	4,000
J. Michael Cockrell	5,000
James C. Ruth	5,000
Richard S. Snell (2)	4,000
All directors and officers (consisting of 17 people, including those named above)	20,052

(1)Unless otherwise indicated, the persons named above have sole voting and investment power over the Units reported. Includes Units that the named person has the right to acquire within 60 days.

(2)These Units are held by an estate for which Mr. Snell is the co-executor. Mr. Snell disclaims beneficial ownership of these Units.

Item 13.  Certain Relationships and Related Transactions

Our Management and Relationships with Duke Energy, DEFS and affiliates and EPCO and affiliates

The Partnership does not have any employees.  We are managed by the Company, which for all periods prior to February 23, 2005, was an indirect wholly owned subsidiary of DEFS.  According to the Partnership Agreement, the Company was entitled to reimbursement of all direct and indirect expenses related to our business activities.  As a result of the change in ownership of the General Partner on February 24, 2005, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to an administrative services agreement.  We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees (see Note 1 in the Notes to the Consolidated Financial Statements).

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The following table summarizes the related party transactions with EPCO and affiliates and DEFS and affiliates for the periods indicated (in millions):

	Years Ended December 31,
	2005		2004		2003
Revenues from EPCO and affiliates (1)
Transportation — NGLs (2)	$	7.4	$	—	$	—
Transportation — LPGs (3)	4.3		—		—
Other operating revenues (4)	0.3		—		—
Costs and Expenses from EPCO and affiliates (1)
Payroll and administrative (5)	68.2		—		—
Purchases of petroleum products (6)	3.4		—		—
Revenues from DEFS and affiliates (7)
Sales of petroleum products (8)	4.3		23.2		15.2
Transportation — NGLs (9)	2.8		16.7		17.2
Gathering — Natural gas — Jonah (10)	0.5		3.3		2.0
Transportation — LPGs (11)	0.7		2.6		2.8
Other operating revenues (12)	2.4		14.0		10.8
Costs and Expenses from DEFS and affiliates (7) (13) (14)
Payroll and administrative (5)	16.2		95.9		88.8
Purchases of petroleum products — TCO (15)	37.7		141.3		110.7
Purchases of petroleum products — Jonah (16)	0.8		5.1		—

(1)	Operating revenues earned and expenses incurred from activities with EPCO and its affiliates are considered related party transactions from February 24, 2005, through December 31, 2005, as a result of the change in ownership of the General Partner (see Note 1 in the Notes to the Consolidated Financial Statements).
(2)	Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines.
(3)	Includes revenues from LPG transportation on the TE Products pipeline.
(4)	Includes other operating revenues on TE Products.
(5)	Substantially all of these costs were related to payroll, payroll related expenses and administrative expenses incurred in managing us and our subsidiaries.
(6)	Includes TCO purchases of condensate and expenses related to LSI’s use of an affiliate of EPCO as a transporter.
(7)	Operating revenues earned and expenses incurred from activities with DEFS and its affiliates are considered related party transactions for all periods through February 23, 2005, as a result of the change in ownership of the General Partner (see Note 1 in the Notes to the Consolidated Financial Statements).
(8)	Includes LSI sales of lubrication oils and specialty chemicals and Jonah NGL sales in connection with Jonah’s Pioneer processing plant operations, which was constructed during the Phase III expansion and began operating in 2004.
(9)	Includes revenues from NGL transportation on the Chaparral, Panola, Dean and Wilcox NGL pipelines.
(10)	Includes gas gathering revenues on the Jonah system.
(11)	Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. We recognized revenue from an affiliate of DEFS pursuant to this agreement.
(12)	Includes fractionation revenues and other revenues. Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Other operating revenues also include other operating revenues on TE Products and processing and other revenues on the Jonah gas gathering system.
(13)	Includes operating costs and expenses related to DEFS managing and operating the Jonah and Val Verde systems and the Chaparral NGL pipeline on our behalf under a contractual agreement established at the time of acquisition of each asset. In connection with the change in ownership of our General Partner, we have assumed these activities.

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(14)	Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into an Operation and Maintenance Agreement, whereby DEFS 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.
(15)	Includes TCO purchases of condensate.
(16)	Includes Jonah purchases of natural gas in connection with Jonah’s Pioneer processing plant operations.

At December 31, 2005, we had a receivable from EPCO and affiliates of $4.3 million related to sales and transportation services provided to EPCO and affiliates.  At December 31, 2005, we had a payable to EPCO and affiliates of $9.8 million related to direct payroll, payroll related costs and other operational related charges.

At December 31, 2004, we had a receivable from DEFS and affiliates of $10.5 million related to sales and transportation services provided to DEFS and affiliates.  Included in this receivable balance from DEFS and affiliates at December 31, 2004, is a gas imbalance receivable of $0.9 million.  At December 31, 2004, we had a payable to DEFS and affiliates of $22.4 million related to direct payroll, payroll related costs, management fees, and other operational related charges, including those for Jonah, Chaparral and Val Verde as described above.  Included in this payable balance at December 31, 2004, is a gas imbalance payable to DEFS and affiliates of $3.2 million.

From February 24, 2005 through December 31, 2005, the majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, was obtained through EPCO.  From February 24, 2005 through December 31, 2005, we incurred insurance expense related to premiums charged by EPCO of $9.8 million.  At December 31, 2005, we had insurance reimbursement receivables due from EPCO of $1.3 million.

Through February 23, 2005, we contracted with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers’ liability insurance.  Through February 23, 2005 and for the years ended December 31, 2004 and 2003, we incurred insurance expense related to premiums paid to Bison of $1.2 million, $6.5 million and $5.9 million, respectively.  At December 31, 2004, we had insurance reimbursement receivables due from Bison of $5.2 million.

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit.  The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO.

Interest of the General Partner in the Partnership

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

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

During the year ended December 31, 2005, distributions paid to the General Partner totaled $73.2 million, including incentive distributions of $69.5 million.

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Interests of DFI in the Partnership

At formation in 1990, we completed an initial public offering of 26,500,000 Units representing Limited Partner Interests.  In connection with our formation, the Company received 2,500,000 DPIs.  Effective April 1, 1994, the DPIs were converted to Units, but they have not been listed for trading on the New York Stock Exchange.  These Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000.  On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 Units for $104.0 million.  At December 31, 2005, we had outstanding 69,963,554 Units, including 2,500,000 Units held by DFI.

Item 14.  Principal Accounting Fees and Services

The following table describes fees for professional services rendered by KPMG, our principal accountant, for the audit of our financial statements for the years ended December 31, 2005 and 2004, and for fees billed for other services rendered by KPMG during those periods (in thousands):

	Years Ended December 31,
Type of Fee	2005		2004
Audit Fees (1)	$	1,773	$	2,079
Audit Related Fees (2)	26		21
Tax Fees (3)	—		88
All Other Fees	—-		—-
Total	$	1,799	$	2,188

(1)Audit fees include fees for the audits of the consolidated financial statements as well as for the audit of internal control over financial reporting.

(2)Audit related fees consist principally of fees for audits of financial statements of certain employee benefit plans and certain internal control documentation assistance.

(3)Tax Fees consist of fees for sales and use tax consultation and tax compliance services.

Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accountant

Pursuant to its charter, the Audit and Conflicts Committee of our Board is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent registered public accountants.  KPMG’s engagement and all related fees to conduct our audit were pre-approved by the Audit and Conflicts Committee on April 25, 2005.  Additionally, all permissible non-audit engagements with KPMG have been reviewed and approved by the Audit and Conflicts Committee, pursuant to pre-approval policies and procedures established by the Audit and Conflicts Committee.

PART IV

Item 15.  Exhibits, Financial Statement Schedules.

(a)The following documents are filed as a part of this Report:

(1)Financial Statements:  See Index to Consolidated Financial Statements on page F-1 of this Report for financial statements filed as part of this Report.

(2)Financial Statement Schedules:   None.

(3)Exhibits.

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Exhibit Number	Description
3.1	Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
3.2	Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
4.1	Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
4.2	Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
4.3	Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
4.4	Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.5	First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.6	Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
4.7	Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.1+	Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.2+	Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.3+	Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

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10.4+	Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).
10.5+	Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference).
10.6+	Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, C. Bruce Shaffer, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
10.7	Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
10.8	Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
10.9+	Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.10+	Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.11+	Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.12+	Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.13+	Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
10.14+	TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
10.15+	Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
10.16	Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.17	Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

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10.18	Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference).
10.19	Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).
10.20	Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.21	Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.22	Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.23	Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2002 and incorporated herein by reference).
10.24	Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.25	Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.26	Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.27+	Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.49 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.28+	Amended and Restated TEPPCO Supplemental Benefit Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.29+	Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Second Amendment and Restatement, effective January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.30+	Amended and Restated Texas Eastern Products Pipeline Company, LLC Management Incentive Compensation Plan, effective January 1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.31+	Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

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10.32	Formation Agreement between Panhandle Eastern Pipe Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.33	Amended and Restated Limited Liability Company Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.34	Guaranty Agreement, dated as of September 27, 2002, between TE Products Pipeline Company, Limited Partnership and Marathon Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.35	LLC Membership Interest Purchase Agreement By and Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.36	Joint Development Agreement between TE Products Pipeline Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and incorporated herein by reference).
10.37	Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000 Revolving Facility) (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2003 and incorporated herein by reference).
10.38	Agreement of Limited Partnership of Mont Belvieu Storage Partners, L.P. dated effective January 21, 2003 (Filed as Exhibit 10.53 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).
10.39	Letter of Agreement Clarifying Rights and Obligations of the Parties Under the Mont Belvieu Storage Partners, L.P., Partnership Agreement and the Mont Belvieu Venture, LLC, LLC Agreement, dated October 25, 2003 (Filed as Exhibit 10.54 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).
10.40	Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders dated as of October 21, 2004 ($600,000,000 Revolving Facility) (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of October 21, 2004 and incorporated herein by reference).
10.41+	Texas Eastern Products Pipeline Company Amended and Restated Non-employee Directors Deferred Compensation Plan, effective April 1, 2002 (Filed as Exhibit 10.42 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2004 and incorporated herein by reference).
10.42+	Texas Eastern Products Pipeline Company Second Amended and Restated Non-employee Directors Unit Accumulation Plan, effective January 1, 2004 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2004 and incorporated herein by reference).
10.43	First Amendment to Amended and Restated Credit Agreement, dated as of February 23, 2005, by and among TEPPCO Partners, L.P., the Borrower, several banks and other financial institutions, the Lenders, SunTrust Bank, as the Administrative Agent for the Lenders, Wachovia Bank, National Association, as Syndication Agent, and BNP Paribas, JPMorgan Chase Bank, N.A. and KeyBank, N.A. as Co-Documentation Agents (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 24, 2005 and incorporated herein by reference).

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10.44+	Supplemental Agreement to Employment Agreement between the Company and Barry R. Pearl dated as of February 23, 2005 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2005 and incorporated herein by reference).
10.45+	Supplemental Agreement to Employment and Non-Compete Agreement between the Company and J. Michael Cockrell dated as of February 23, 2005 (Filed as Exhibit 10.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2005 and incorporated herein by reference).
10.46+	Supplemental Form Agreement to Form of Employment Agreement between the Company and John N. Goodpasture, Stephen W. Russell, C. Bruce Shaffer and Barbara A. Carroll dated as of February 23, 2005 (Filed as Exhibit 10.3 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2005 and incorporated herein by reference).
10.47+	Supplemental Form Agreement to Form of Employment and Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth and Leonard W. Mallett dated as of February 23, 2005 (Filed as Exhibit 10.4 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2005 and incorporated herein by reference).
10.48+	Amendments to the TEPPCO Retirement Cash Balance Plan and the TEPPCO Supplemental Benefit Plan dated as of May 27, 2005 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2005 and incorporated herein by reference).
10.49+	Agreement and Release between Charles H. Leonard and Texas Eastern Products Pipeline Company, LLC dated as of July 11, 2005 (Filed as Exhibit 10.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2005 and incorporated herein by reference).
10.50	Third Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC and Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated August 15, 2005, but effective as of February 24, 2005 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated August 19, 2005 and incorporated herein by reference).
10.51	Second Amendment to Amended and Restated Credit Agreement, dated as of December 13, 2005, by and among TEPPCO Partners, L.P., the Borrower, several banks and other financial institutions, the Lenders, SunTrust Bank, as the Administrative Agent for the Lenders, Wachovia Bank, National Association, as Syndication Agent, and BNP Paribas, JPMorgan Chase Bank, N.A. and KeyBank, N.A., as Co-Documentation Agents (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of December 13, 2005 and incorporated herein by reference).
10.52+*	Agreement and Release between Barry R. Pearl and Texas Eastern Products Pipeline Company, LLC dated as of December 30, 2005.
10.53+*	Agreement and Release between James C. Ruth and Texas Eastern Products Pipeline Company, LLC dated as of January 25, 2006.
10.54	Letter of Intent between TEPPCO Partners, L.P. and Enterprise Products Operating, L.P. dated February 13, 2006 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated February 17, 2006 and incorporated herein by reference).
10.55+*	Directors’ Compensation Summary.
10.56*	Waiver of Provisions of the Conflicts Policies and Procedures of the Third Amended and Restated Administrative Services Agreement.
12.1*	Statement of Computation of Ratio of Earnings to Fixed Charges.
21*	Subsidiaries of TEPPCO Partners, L.P.

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23*	Consent of KPMG LLP.
24*	Powers of Attorney.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
32.1**	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*  Filed herewith.

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

+  A management contract or compensation plan or arrangement.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

						TEPPCO Partners, L.P.
			By:		/s/ LEE W. MARSHALL, SR.
						Lee W. Marshall, Sr.,
Date: March 1, 2006	Acting Chief Executive Officer and Chairman of the Board of
	Texas Eastern Products Pipeline Company, LLC, General Partner
			By:	/s/ WILLIAM G. MANIAS
						William G. Manias,
			Vice President and Chief Financial Officer of
Date: March 1, 2006		Texas Eastern Products Pipeline Company, LLC, General Partner

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Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
LEE W. MARSHALL, SR.*	Acting Chief Executive Officer and Chairman of the	March 1, 2006
Lee W. Marshall, Sr.	Board of Texas Eastern Products Pipeline Company, LLC
WILLIAM G. MANIAS	Vice President and Chief Financial Officer	March 1, 2006
William G. Manias	of Texas Eastern Products Pipeline Company, LLC
MICHAEL B. BRACY*	Director of Texas Eastern	March 1, 2006
Michael B. Bracy	Products Pipeline Company, LLC
RICHARD S. SNELL*	Director of Texas Eastern	March 1, 2006
Richard S. Snell	Products Pipeline Company, LLC
MURRAY H. HUTCHISON*	Director of Texas Eastern	March 1, 2006
Murray H. Hutchison	Products Pipeline Company, LLC
MICHAEL A. CREEL*	Director of Texas Eastern	March 1, 2006
Michael A. Creel	Products Pipeline Company, LLC
RICHARD H. BACHMANN*	Director of Texas Eastern	March 1, 2006
Richard H. Bachmann	Products Pipeline Company, LLC
W. RANDALL FOWLER*	Director of Texas Eastern	March 1, 2006
W. Randall Fowler	Products Pipeline Company, LLC

* Signed on behalf of the Registrant and each of these persons:

By:	/s/ WILLIAM G. MANIAS
	(William G. Manias, Attorney-in-fact)

85

CONSOLIDATED FINANCIAL STATEMENTS

OF TEPPCO PARTNERS, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Financial Statements:

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

TEPPCO Partners, L.P.:

We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2005 and 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. as of December 31, 2005 and 2004 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 20 to the consolidated financial statements, the Partnership has restated its consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, partners’ capital and comprehensive income and cash flows for the years ended December 31, 2004 and 2003.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of TEPPCO Partners, L.P.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2006, expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

	KPMG LLP
Houston, Texas
February 28, 2006

F-2

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2005			2004
				(as restated)
ASSETS
Current assets:
Cash and cash equivalents	$	119		$	16,422
Accounts receivable, trade (net of allowance for doubtful accounts of $250 and $112)	803,373			553,628
Accounts receivable, related parties	5,207			11,845
Inventories	29,069			19,521
Other	61,361			42,138
Total current assets	899,129			643,554
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $474,332 and $407,670)	1,960,068			1,703,702
Equity investments	359,656			363,307
Intangible assets	376,908			407,358
Goodwill	16,944			16,944
Other assets	67,833			51,419
Total assets	$	3,680,538		$	3,186,284
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	800,033		$	564,464
Accounts payable, related parties	11,836			24,654
Accrued interest	32,840			32,292
Other accrued taxes	16,532			13,309
Other	75,970			46,593
Total current liabilities	937,211			681,312
Senior Notes	1,119,121			1,127,226
Other long-term debt	405,900			353,000
Other liabilities and deferred credits	16,936			13,643
Commitments and contingencies
Partners’ capital:
Accumulated other comprehensive income	11			—
General partner’s interest	(61,487		)	(35,881		)
Limited partners’ interests	1,262,846			1,046,984
Total partners’ capital	1,201,370			1,011,103
Total liabilities and partners’ capital	$	3,680,538		$	3,186,284

See accompanying Notes to Consolidated Financial Statements.

F-3

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per Unit amounts)

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Operating revenues:
Sales of petroleum products	$	8,072,287		$	5,434,127		$	3,766,651
Transportation – Refined products	144,552			148,166			138,926
Transportation – LPGs	96,297			87,050			91,787
Transportation – Crude oil	37,614			37,177			29,057
Transportation – NGLs	43,915			41,204			39,837
Gathering – Natural gas	152,797			140,122			135,144
Other	71,026			70,346			54,430
Total operating revenues	8,618,488			5,958,192			4,255,832
Costs and expenses:
Purchases of petroleum products	7,995,433			5,372,971			3,711,207
Operating, general and administrative	219,487			220,647			198,478
Operating fuel and power	48,972			48,139			41,362
Depreciation and amortization	111,341			112,894			100,728
Taxes – other than income taxes	20,740			17,461			15,597
Gains on sales of assets	(668		)	(1,053		)	(3,948		)
Total costs and expenses	8,395,305			5,771,059			4,063,424
Operating income	223,183			187,133			192,408
Interest expense – net	(81,861		)	(72,053		)	(84,250		)
Equity earnings	20,094			22,148			12,874
Other income – net	1,135			1,320			748
Net income	$	162,551		$	138,548		$	121,780
Net Income Allocation:
Limited Partner Unitholders	$	114,972		$	98,580		$	86,357
Class B Unitholder	—			—			1,754
General Partner	47,579			39,968			33,669
Total net income allocated	$	162,551		$	138,548		$	121,780
Basic and diluted net income per Limited Partner and Class B Unit	$	1.71		$	1.56		1.47
Weighted average Limited Partner and Class B Units outstanding	67,397			62,999			59,765

See accompanying Notes to Consolidated Financial Statements.

F-4

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Cash flows from operating activities:
Net income	$	162,551		$	138,548		$	121,780
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	111,341			112,894			100,728
Earnings in equity investments, net of distributions	16,991			25,065			15,129
Gains on sales of assets	(668		)	(1,053		)	(3,948		)
Non-cash portion of interest expense	1,624			(391		)	4,793
Increase in accounts receivable	(249,745		)	(181,690		)	(100,085		)
Decrease (increase) in accounts receivable, related parties	6,638			(14,693		)	8,788
Increase in inventories	(950		)	(3,461		)	(956		)
Increase in other current assets	(19,088		)	(9,926		)	(953		)
Increase in accounts payable and accrued expenses	254,251			186,942			95,540
Increase (decrease) in accounts payable, related parties	(12,817		)	4,360			7,381
Other	(15,623		)	10,572			(5,773		)
Net cash provided by operating activities	254,505			267,167			242,424
Cash flows from investing activities:
Proceeds from sales of assets	510			1,226			8,531
Proceeds from cash investments	—			—			750
Purchase of assets	(112,231		)	(3,421		)	(27,469		)
Investment in Mont Belvieu Storage Partners, L.P.	(4,233		)	(21,358		)	(2,533		)
Investment in Centennial Pipeline LLC	—			(1,500		)	(4,000		)
Purchase of additional interest in Centennial Pipeline LLC	—			—			(20,000		)
Cash paid for linefill on assets owned	(14,408		)	(957		)	(3,070		)
Capital expenditures	(220,553		)	(164,147		)	(140,517		)
Net cash used in investing activities	(350,915		)	(190,157		)	(188,308		)
Cash flows from financing activities:
Proceeds from revolving credit facility	657,757			324,200			382,000
Issuance of Limited Partner Units, net	278,806			—			287,506
Issuance of Senior Notes	—			—			198,570
Repayments on revolving credit facility	(604,857		)	(181,200		)	(604,000		)
Repurchase and retirement of Class B Units	—			—			(113,814		)
Debt issuance costs	(498		)	—			(3,381		)
General Partner’s contributions	—			—			2
Distributions paid	(251,101		)	(233,057		)	(202,498		)
Net cash provided by (used in) financing activities	80,107			(90,057		)	(55,615		)
Net decrease in cash and cash equivalents	(16,303		)	(13,047		)	(1,499		)
Cash and cash equivalents at beginning of period	16,422			29,469			30,968
Cash and cash equivalents at end of period	$	119		$	16,422		$	29,469
Non-cash investing activities:
Net assets transferred to Mont Belvieu Storage Partners, L.P.	$	1,429		$	—		$	61,042
Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	82,315		$	77,510		$	79,930

See accompanying Notes to Consolidated Financial Statements.

F-5

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except Unit amounts)

	Outstanding Limited Partner Units	General Partner’s Interest			Limited Partners’ Interests			Accumulated Other Comprehensive (Loss) Income			Total
Partners’ capital at December 31, 2002 (as restated)	53,809,597	$	12,104		$	897,400		$	(20,055	)	$	889,449
Issuance of Limited Partner Units, net	9,101,650	—			285,461			—			285,461
Retirement of Class B units	—	—			(11,175		)	—			(11,175		)
Net income on cash flow hedge	—	—			—			16,164			16,164
Reclassification due to discontinued portion of cash flow hedge	—	—			—			989			989
2003 net income allocation	—	33,669			86,357			—			120,026
2003 cash distributions	—	(54,725		)	(145,427		)	—			(200,152		)
Issuance of Limited Partner Units upon exercise of options	87,307	2			2,045			—			2,047
Partners’ capital at December 31, 2003 (as restated)	62,998,554	(8,950		)	1,114,661			(2,902		)	1,102,809
Adjustments to issuance of Limited Partner Units, net	—	—			(99		)	—			(99		)
Net income on cash flow hedge	—	—			—			2,902			2,902
2004 net income allocation	—	39,968			98,580			—			138,548
2004 cash distributions	—	(66,899		)	(166,158		)	—			(233,057		)
Partners’ capital at December 31, 2004 (as restated)	62,998,554	(35,881		)	1,046,984			—			1,011,103
Issuance of Limited Partner Units, net	6,965,000	—			278,806			—			278,806
Changes in fair values of crude oil hedges	—	—			—			11			11
2005 net income allocation	—	47,579			114,972			—			162,551
2005 cash distributions	—	(73,185		)	(177,916		)	—			(251,101		)
Partners’ capital at December 31, 2005	69,963,554	$	(61,487	)	$	1,262,846		$	11		$	1,201,370

See accompanying Notes to Consolidated Financial Statements.

F-6

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Years Ended December 31,
	2005		2004		2003
			(as restated)		(as restated)
Net income	$	162,551	$	138,548	$	121,780
Net income on cash flow hedges	11		—		16,164
Comprehensive income	$	162,562	$	138,548	$	137,944

See accompanying Notes to Consolidated Financial Statements.

F-7

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.        PARTNERSHIP ORGANIZATION

TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990.  We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”).  Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.”  Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us.

On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly owned by us.  TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us.  In exchange for this contribution, the Company’s interest as our general partner was increased to 2%.  The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships.  As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest.  This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.

Through February 23, 2005, the General Partner was an indirect wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips.  Duke Energy held an interest of approximately 70% in DEFS, and ConocoPhillips held the remaining interest of approximately 30%.  On February 24, 2005, the General Partner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP Holdings L.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan, for approximately $1.1 billion.  As a result of the transaction, DFI owns and controls the 2% general partner interest in us and has the right to receive the incentive distribution rights associated with the general partner interest.  In conjunction with an amended and restated administrative services agreement, 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.  As a result of the sale of our General Partner, DEFS and Duke Energy continued to provide some administrative services for us for a period of up to one year after the sale, at which time, we assumed these services.  In connection with us assuming the operations of certain of the TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005.

At formation in 1990, we completed an initial public offering of 26,500,000 units representing Limited Partner Interests (“Limited Partner Units”) at $10.00 per Limited Partner Unit.  In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”).  Effective April 1, 1994, the DPIs were converted to Limited Partner Units, but they have not been listed for trading on the New York Stock Exchange.  These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000.  On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 Limited Partner Units for $104.0 million.  As of December 31, 2005, none of these Limited Partner Units had been sold by DFI.

At December 31, 2005, 2004 and 2003, we had outstanding 69,963,554, 62,998,554 and 62,998,554 Limited Partner Units, respectively.  At December 31, 2002, we had outstanding 3,916,547 Class B Limited Partner Units (“Class B Units”), which were issued to Duke Energy Transport and Trading Company, LLC (“DETTCO”) in connection with an acquisition of assets initially acquired in 1998.  On April 2, 2003, we repurchased and retired all of the 3,916,547 previously outstanding Class B Units with proceeds from the issuance of additional Limited Partner Units (see Note 11).  Collectively, the Limited Partner Units and Class B Units are referred to as “Units”.

F-8

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

We restated our consolidated financial statements and related financial information for the years ended December 31, 2004 and 2003, for an accounting correction.  In addition, the restatement adjustment impacted quarterly periods with the fiscal years ended December 31, 2005, 2004 and 2003.  See Note 20 for a discussion of the restatement adjustment and the impact on previously issued financial statements.

NOTE 2.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.

Basis of Presentation and Principles of Consolidation

Throughout the consolidated financial statements and accompanying notes, all referenced amounts related to prior periods reflect the balances and amounts on a restated basis.  The financial statements include our accounts on a consolidated basis.  We have eliminated all significant intercompany items in consolidation.  We have reclassified certain amounts from prior periods to conform to the current presentation.

Use of Estimates

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

Business Segments

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

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

Revenue Recognition

Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services.  Transportation revenues are recognized as products are delivered to customers.  Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded.  Revenues from the sale of product inventory are recognized when the products are sold.

F-9

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.  Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas.  Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, L.P. (“TCO”), which typically occurs upon our receipt of the product.  Revenues related to trade documentation and pumpover fees are recognized as services are completed.

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, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged.

Our Midstream Segment revenues are earned from the gathering of natural gas, transportation of NGLs and fractionation of NGLs.  Gathering revenues are recognized as natural gas is received from the customer.  Transportation revenues are recognized as NGLs are delivered to customers.  Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream Segment marketing affiliate.  Fractionation revenues are recognized ratably over the contract year as products are delivered.  We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances discussed in “Natural Gas Imbalances.”  Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.

Cash and Cash Equivalents

Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased.  The carrying value of cash and cash equivalents approximate fair value because of the short term nature of these investments.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance.  Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.  The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Years Ended December 31,
	2005			2004			2003
Balance at beginning of period	$	112		$	4,700		$	4,608
Charges to expense	829			536			793
Deductions and other	(691		)	(5,124		)	(701		)
Balance at end of period	$	250		$	112		$	4,700

Inventories

Inventories consist primarily of petroleum products and crude oil, which are valued at the lower of cost (weighted average cost method) or market.  Our Downstream Segment acquires and disposes of various products under exchange agreements.  Receivables and payables arising from these transactions are usually satisfied with

F-10

products rather than cash.  The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at the lower of fair value or cost.

Property, Plant and Equipment

We record property, plant and equipment at its acquisition cost.  Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost.  We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense.  Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).

We evaluate impairment of long-lived assets 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.  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 net cash flows expected to be generated by the asset.  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.

Asset Retirement Obligations

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations.  SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets.  A corresponding asset is also recorded and depreciated over the life of the asset.  After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation.  Determination of any amounts recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.

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

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

In order to determine a removal date for our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required.  As a transporter and gatherer of crude oil and natural

F-11

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

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

Capitalization of Interest

We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 5.73%, 5.74% and 6.50% for the years ended December 31, 2005, 2004 and 2003, respectively.  During the years ended December 31, 2005, 2004 and 2003, the amount of interest capitalized was $6.8 million, $4.2 million and $5.3 million, respectively.

Intangible Assets

Intangible assets on the consolidated balance sheets consist primarily of gathering contracts assumed in the acquisition of Jonah Gas Gathering System (“Jonah”) on September 30, 2001, and the acquisition of Val Verde Gathering System (“Val Verde”) on June 30, 2002, a fractionation agreement and other intangible assets (see Note 3).  Included in equity investments on the consolidated balance sheets are excess investments in Centennial Pipeline LLC (“Centennial”) and Seaway Crude Pipeline Company (“Seaway”).

In connection with the acquisitions of Jonah and Val Verde, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming, and we assumed fixed-term contracts with customers that gather coal bed methane (“CBM”) from the San Juan Basin in New Mexico and Colorado, respectively.  The value assigned to these intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production to the gathering system.  These intangible assets are amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts.  Revisions to the unit-of-production estimates may occur as additional production information is made available to us (see Note 3).

In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS.  The fractionation agreement is being amortized on a straight-line basis over a period of 20 years, which is the term of the agreement with DEFS.

In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.7 million, which are amortized on a unit-of-production basis (see Note 5).

In connection with the formation of Centennial, we recorded excess investment, the majority of which is amortized on a unit-of-production basis over a period of 10 years.  In connection with the acquisition of our interest in Seaway, we recorded excess investment, which is amortized on a straight-line basis over a period of 39 years (see Note 3).

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Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization.  We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001 (see Note 3).  SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually.  SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives.  Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill.

Environmental Expenditures

We accrue for environmental costs that relate to existing conditions caused by past operations.  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.

The following table presents the activity of our environmental reserve for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Years Ended December 31,
	2005			2004			2003
Balance at beginning of period	$	5,037		$	7,639		$	7,693
Charges to expense	2,530			5,178			6,824
Deductions and other	(5,120		)	(7,780		)	(6,878		)
Balance at end of period	$	2,447		$	5,037		$	7,639

Natural Gas Imbalances

Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated.  Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead.  If the customers supply more natural gas gathering volumes than they nominated, Val Verde and Jonah record a payable for the amount due to customers and also record a receivable for the same amount due from connecting pipeline transporters or shippers.  To the extent that these amounts are not cashed out monthly on Val Verde, if the customers supply less natural gas gathering volumes than they nominated, Val Verde and Jonah record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers.  We record natural gas imbalances using a mark-to-market approach.

Income Taxes

We are a limited partnership.  As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax.  Our taxable income or loss, which may vary substantially from

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the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder.  Accordingly, no recognition has been given to federal and state income taxes for our operations.  The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders’ tax attributes in the Partnership.

Use of Derivatives

We account for derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133.  These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities.  The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative.

Our derivative instruments consist primarily of interest rate swaps and contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities.  Substantially all derivative instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting.  SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.

For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a description of the method of measuring ineffectiveness.  This process includes linking all derivatives that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.  We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.  If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

For derivative instruments designated as fair value hedges, gains and losses on the derivative instrument are offset against related results on the hedged item in the statement of income.  Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings.  Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time.  The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.

According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer

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meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective fair value hedge, we continue to carry the derivative on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value.  The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability.  When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the derivative on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings.  When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings.  In all other situations in which hedge accounting is discontinued, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.

Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature.  The fair values of these financial instruments are represented in our consolidated balance sheets.

Net Income Per Unit

Basic net income per Unit is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 67.4 million Units, 63.0 million Units and 59.8 million Units for the years ended December 31, 2005, 2004 and 2003, respectively). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each year (see Note 11). The General Partner was allocated $47.6 million (representing 29.27%) of net income for the year ended December 31, 2005, $40.0 million (representing 28.85%) of net income for the year ended December 31, 2004, and $33.7 million (representing 27.65%) of net income for the year ended December 31, 2003.  The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our limited partnership agreement.

Diluted net income per Unit is similar to the computation of basic net income per Unit discussed above, except that the denominator is increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method.  For the year ended December 31, 2003, the denominator was increased by 11,878 Units.  For the years ended December 31, 2005 and 2004, diluted net income per Unit equaled basic net income per Unit as all remaining outstanding Unit options were exercised during the third quarter of 2003 (see Note 13).

Unit Option Plan

We have not granted options for any periods presented.  For options outstanding under the 1994 Long Term Incentive Plan (see Note 13), we followed the intrinsic value method of accounting for recognizing stock-based compensation expense.  Under this method, we record no compensation expense for Unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Units on the date of the grant.  During the year ended December 31, 2003, all remaining outstanding Unit options were exercised.

In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure was issued.  SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, and provides alternative

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methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation.  In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results.  Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002, and are included in Note 13.

Assuming we had used the fair value method of accounting for our Unit option plan, pro forma net income would equal reported net income for the years ended December 31, 2005, 2004 and 2003.  Pro forma net income per Unit would equal reported net income per Unit for the periods presented.  The adoption of SFAS 148 did not have an effect on our financial position, results of operations or cash flows.

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment.  SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements.  With limited exceptions, the amount of the compensation cost is to be measured based on the grant-date fair value of the equity or liability instruments issued.  In addition, liability awards are to be re-measured each reporting period.  Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees.  SFAS 123(R) is effective for public companies as of the first interim or annual reporting period of the first fiscal year beginning after June 15, 2005.  The Securities and Exchange Commission amended the implementation date of SFAS 123(R) to begin with the first interim or annual reporting period of the company’s first fiscal year beginning on or after June 15, 1005.  As such, we will adopt SFAS 123(R) in the first quarter of 2006.  Companies are permitted to adopt SFAS 123(R) prior to the extended date.  All public companies that adopted the fair-value-based method of accounting must use the modified prospective transition method and may elect to use the modified retrospective transition method.  We do not believe that the adoption of SFAS 123(R) will have a material effect on our financial position, results of operations or cash flows.

In November 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations, to clarify whether a component of an enterprise that is either disposed of or classified as held for sale qualifies for income statement presentation as discontinued operations.  The FASB ratified the consensus on November 30, 2004.  The consensus is to be applied prospectively with regard to a component of an enterprise that is either disposed of or classified as held for sale in reporting periods beginning after December 15, 2004.  The consensus may be applied retrospectively for previously reported operating results related to disposal transactions initiated within an enterprise’s reporting period that included the date that this consensus was ratified. The adoption of EITF 03-13 did not have an effect on our financial position, results of operations or cash flows.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”).  FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity.  Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional.  Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.  Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.  The fair value of a liability for the conditional asset

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retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset.  SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005, and early adoption of FIN 47 is encouraged.  We adopted FIN 47 in the fourth quarter of 2005.  The adoption of FIN 47 did not have a material effect on our financial position, results of operations or cash flows.

In June 2005, the EITF reached consensus in EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, to provide guidance on how general partners in a limited partnership should determine whether they control a limited partnership and therefore should consolidate it.  The EITF agreed that the presumption of general partner control would be overcome only when the limited partners have either of two types of rights. The first type, referred to as kick-out rights, is the right to dissolve or liquidate the partnership or otherwise remove the general partner without cause.  The second type, referred to as participating rights, is the right to effectively participate in significant decisions made in the ordinary course of the partnership’s business. The kick-out rights and the participating rights must be substantive in order to overcome the presumption of general partner control. The consensus is effective for general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified subsequent to the date of FASB ratification (June 29, 2005).  For existing limited partnerships that have not been modified, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005.  We do not believe that the adoption of EITF 04-5 will have a material effect on our financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29.   SFAS 153 amends APB Opinion No. 29, Accounting for Nonmonetary Exchanges, to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance.  A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange.  SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005.  We adopted SFAS 153 during the second quarter of 2005.  The adoption of SFAS 153 did not have a material effect on our financial position, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections.  SFAS 154 establishes new standards on accounting for changes in accounting principles.  All such changes must be accounted for by retrospective application to the financial statements of prior periods unless it is impracticable to do so.  SFAS 154 completely replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Periods.  However, it carries forward the guidance in those pronouncements with respect to accounting for changes in estimates, changes in the reporting entity, and the correction of errors.  SFAS 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted for changes and corrections made in years beginning after June 1, 2005. The application of SFAS 154 does not affect the transition provisions of any existing pronouncements, including those that are in the transition phase as of the effective date of SFAS 154.  We do not believe that the adoption of SFAS 154 will have a material effect on our financial position, results of operations or cash flows.

In September 2005, the EITF reached consensus in EITF 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, to define when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction subject to APB Opinion No. 29, Accounting for Nonmonetary Transactions.  Two or more inventory transactions with the same party should be combined if they are entered into in contemplation of one another.  The EITF also requires entities to account for

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exchanges of inventory in the same line of business at fair value or recorded amounts based on inventory classification.  The guidance in EITF 04-13 is effective for new inventory arrangements entered into in reporting periods beginning after March 15, 2006.  We are currently evaluating what impact EITF 04-13 will have on our financial statements, but at this time we do not believe that the adoption of EITF 04-13 will have a material effect on our financial position, results of operations or cash flows.

NOTE 3.        GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization.  We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001.  SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. We test goodwill and intangible assets for impairment annually at December 31.

To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units.  We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit.  We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred.   There have been no goodwill impairment losses recorded since the adoption of SFAS 142.

The following table presents the carrying amount of goodwill at December 31, 2005 and 2004, by business segment (in thousands):

	Downstream Segment		Midstream Segment		Upstream Segment		Segments Total
Goodwill	$	—	$	2,777	$	14,167	$	16,944

Other Intangible Assets

The following table reflects the components of intangible assets, including excess investments, being amortized at December 31, 2005 and 2004 (in thousands):

	December 31, 2005					December 31, 2004
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Intangible assets:
Gathering and transportation agreements	$	464,337	$	(118,921	)	$	464,337	$	(91,262	)
Fractionation agreement	38,000		(14,725		)	38,000		(12,825		)
Other	10,226		(2,009		)	12,262		(3,154		)
Subtotal	$	512,563	$	(135,655	)	$	514,599	$	(107,241	)
Excess investments:
Centennial Pipeline LLC	$	33,400	$	(12,947	)	$	33,400	$	(8,875	)
Seaway Crude Pipeline Company	27,100		(3,764		)	27,100		(3,072		)
Subtotal	$	60,500	$	(16,711	)	$	60,500	$	(11,947	)
Total intangible assets	$	573,063	$	(152,366	)	$	575,099	$	(119,188	)

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SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives.  If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life.  At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required.  Amortization expense on intangible assets was $30.5 million, $32.2 million and $36.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.  Amortization expense on excess investments included in equity earnings was $4.8 million, $3.8 million and $4.0 million for the years ended December 31, 2005, 2004 and 2003, respectively.

The values assigned to our intangible assets for natural gas gathering contracts on the Jonah and the Val Verde systems are amortized on a unit-of-production basis, based upon the actual throughput of the systems compared to the expected total throughput for the lives of the contracts.  On a quarterly basis, we may obtain limited production forecasts and updated throughput estimates from some of the producers on the systems, and as a result, we evaluate the remaining expected useful lives of the contract assets based on the best available information.  During the fourth quarter of 2004 and the first and second quarters of 2005, certain limited production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we increased our best estimate of future throughput on the system, which resulted in extensions in the remaining lives of the intangible assets.  During the fourth quarter of 2004 and the third quarter of 2005, certain limited coal bed methane production forecasts were obtained from some of the producers on the Val Verde system whose contracts are included in the intangible assets.  These forecasts indicated lower coal bed methane production estimates over the contract periods, and as a result, we decreased our best estimate of future throughput on the Val Verde system, which resulted in increases to amortization expense on the intangible assets.  Further revisions to these estimates may occur as additional production information is made available to us.

The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis.  Our fractionation agreement is being amortized over its contract period of 20 years.  The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years.  The value of $8.7 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis (see Note 5).

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

	Intangible Assets		Excess Investments
2006	$	32,561		$	4,691
2007	33,395		5,113
2008	32,967		5,438
2009	30,719		6,878
2010	27,338		7,042

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NOTE 4.        INTEREST RATE SWAPS

In July 2000, we entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility.  This interest rate swap matured in April 2004.  We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge.  The swap agreement was based on a notional amount of $250.0 million.  Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate.  Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings.  During the years ended December 31, 2004 and 2003, we recognized an increase in interest expense of $2.9 million and $14.4 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge.  The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes.  Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%.  During the years ended December 31, 2005, 2004 and 2003, we recognized reductions in interest expense of $5.6 million, $9.6 million and $10.0 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the years ended December 31, 2005, 2004 and 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized.  The fair value of this interest rate swap was a loss of approximately $0.9 million at December 31, 2005, and a gain of approximately $3.4 million at December 31, 2004.

During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012.  The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes.  Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%.  These swap agreements were later terminated in 2002 resulting in gains of $44.9 million.  The gains realized from the swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes.  At December 31, 2005, the unamortized balance of the deferred gains was $32.4 million.  In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

During May 2005, we executed a treasury rate lock agreement with a notional amount of $200.0 million to hedge our exposure to increases in the treasury rate that was to be used to establish the fixed interest rate for a debt offering that was proposed to occur in the second quarter of 2005.  During June 2005, the proposed debt offering was cancelled, and the treasury lock was terminated with a realized loss of $2.0 million.  The realized loss was recorded as a component of interest expense in the consolidated statements of income in June 2005.

NOTE 5.        ACQUISITIONS AND DISPOSITIONS

Rancho Pipeline

In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston, Texas.  In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of

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the owners that previously held undivided interests in the pipeline.  We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline.  We sold 183 miles of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million.  We recorded a net gain of $3.9 million on the transactions in the second quarter of 2003.  During the third quarter of 2004, we sold our remaining interest in the original Rancho Pipeline system for a net gain of $0.4 million. These gains are included in the gains on sales of assets in our consolidated statements of income in the 2004 period.

Genesis Pipeline

On November 1, 2003, we purchased crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”).  The transaction was funded with proceeds from our August 2003 equity offering (see Note 11).  We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets.  The assets acquired included approximately 150 miles of small diameter trunk lines, 26,000 barrels per day of throughput and 12,000 barrels per day of lease marketing and supply business.  We have integrated these assets into our South Texas pipeline system, which has allowed us to consolidate gathering and marketing assets in key operating areas in a cost effective manner and will provide future growth opportunities.  Accordingly, the results of the acquisition are included in the consolidated financial statements from November 1, 2003.

The following table allocates the estimated fair value of the Genesis assets acquired on November 1, 2003 (in thousands):

Property, plant and equipment	$	12,811
Intangible assets	8,742
Other	144
Total assets	21,697
Total liabilities assumed	(687		)
Net assets acquired	$	21,010

Mexia Pipeline

On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”).  The assets include approximately 158 miles of pipeline, which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston.  We funded the purchase through borrowings under our revolving credit facility.  We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting.  We have integrated these assets into our South Texas pipeline system, included in our Upstream Segment, which will allow us to realize synergies within our existing asset base and will provide future growth opportunities.

Crude Oil Storage and Terminaling Assets

On April 1, 2005, we purchased crude oil storage and terminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P. for $35.4 million.  The assets consist of eight storage tanks with 945,000 barrels of storage capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land.  We funded the purchase through borrowings under our revolving credit facility.  We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting.  The storage and terminaling assets complement our existing infrastructure in Cushing and strengthen our gathering and marketing business in our Upstream Segment.

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Refined Products Terminal and Truck Rack

On July 12, 2005, we purchased a refined products terminal and truck loading rack in North Little Rock, Arkansas, for $6.9 million from ExxonMobil Corporation.  The assets include three storage tanks and a two-bay truck loading rack.  We funded the purchase through borrowings under our revolving credit facility.  We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting.  The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.

Genco Assets

On July 15, 2005, we acquired from Texas Genco, LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $62.1 million.  We funded the purchase through borrowings under our revolving credit facility.  We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting.  The assets of the purchased companies will be integrated into our Downstream Segment origin infrastructure in Texas City and Baytown, Texas.  As a result of this acquisition, we initiated the expansion of refined products origin capabilities in the Houston and Texas City, Texas, areas.  The integration and other system enhancements should be in service by the fourth quarter of 2006, at an estimated cost of $45.0 million.  The strategic location of these assets, with refined products interconnections to major exchange terminals in the Houston area, will provide significant long-term value to our customers and our Texas Gulf Coast refining and logistics system.

NOTE 6.        EQUITY INVESTMENTS

Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway.  The remaining 50% interest is owned by ConocoPhillips.  We operate the Seaway assets.  Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas.  The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway.  From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway.  Thereafter, we will receive 40% of revenue and expense of Seaway.  During the years ended December 31, 2005, 2004 and 2003, we received distributions from Seaway of $24.7 million, $36.9 million and $22.7 million, respectively.

In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Petroleum Company LLC (“Marathon”) to form Centennial.  Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois.  Through February 9, 2003, each participant owned a one-third interest in Centennial.  On February 10, 2003, TE Products and Marathon each acquired an additional 16.7% interest in Centennial from PEPL for $20.0 million each, increasing their ownership percentages in Centennial to 50% each.  During the year ended December 31, 2005, TE Products did not make any additional investments in Centennial. TE Products invested an additional $1.5 million and $24.0 million, respectively, in Centennial, in 2004 and 2003, which is included in the equity investment balance at December 31, 2005.  The 2003 amount includes the $20.0 million paid for the acquisition of the additional ownership interest in Centennial.  TE Products has not received any distributions from Centennial since its formation.

On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”).  TE Products and Louis Dreyfus 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. 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

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NGLs, LPGs and refined products.  MB Storage has no commodity trading activity.  TE Products operates the facilities for MB Storage.  Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $67.1 million to MB Storage.  Additionally, as of the contribution date, Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was terminated by either party.  This deferred liability was also contributed and credited to the capital account of Louis Dreyfus in MB Storage.

For the year ended December 31, 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 operating agreement.  For the year ended December 31, 2004, TE Products received the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense.  TE Products’ share of MB Storage’s earnings is 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 for 2005 and $7.15 million for 2004 was 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, 2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage was 64.2%, 69.4% and 70.4%, respectively.  During the years ended December 31, 2005, 2004 and 2003, TE Products received distributions of $12.4 million, $10.3 million and $5.3 million, respectively, from MB Storage.  During the years ended December 31, 2005, 2004 and 2003, TE Products contributed $5.6 million, $21.4 million and $2.5 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.

We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage.  Summarized combined financial information for Seaway, Centennial and MB Storage for the years ended December 31, 2005 and 2004, is presented below (in thousands):

	Years Ended December 31,
	2005		2004
Revenues	$	164,494	$	149,843
Net income	52,623		52,059

Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of December 31, 2005 and 2004, is presented below (in thousands):

	December 31,
	2005		2004
Current assets	$	60,082	$	59,314
Noncurrent assets	630,212		633,222
Current liabilities	42,242		41,209
Long-term debt	140,000		140,000
Noncurrent liabilities	13,626		20,440
Partners’ capital	494,426		490,887

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NOTE 7.        RELATED PARTY TRANSACTIONS

EPCO and Affiliates and Duke Energy, DEFS and Affiliates

The Partnership does not have any employees.  We are managed by the Company, which, for all periods prior to February 23, 2005, was an indirect wholly owned subsidiary of DEFS.  According to the Partnership Agreement, the Company was entitled to reimbursement of all direct and indirect expenses related to our business activities.  As a result of the change in ownership of the General Partner on February 24, 2005, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to an administrative services agreement.  We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees (see Note 1).

The following table summarizes the related party transactions with EPCO and affiliates and DEFS and affiliates for the periods indicated (in millions):

	Years Ended December 31,
	2005		2004		2003
Revenues from EPCO and affiliates (1)
Transportation – NGLs (2)	$	7.4	$	—	$	—
Transportation – LPGs (3)	4.3		—		—
Other operating revenues (4)	0.3		—		—
Costs and Expenses from EPCO and affiliates (1)
Payroll and administrative (5)	68.2		—		—
Purchases of petroleum products (6)	3.4		—		—
Revenues from DEFS and affiliates (7)
Sales of petroleum products (8)	4.3		23.2		15.2
Transportation – NGLs (9)	2.8		16.7		17.2
Gathering – Natural gas – Jonah (10)	0.5		3.3		2.0
Transportation – LPGs (11)	0.7		2.6		2.8
Other operating revenues (12)	2.4		14.0		10.8
Costs and Expenses from DEFS and affiliates (7) (13) (14)
Payroll and administrative (5)	16.2		95.9		88.8
Purchases of petroleum products – TCO (15)	37.7		141.3		110.7
Purchases of petroleum products – Jonah (16)	0.8		5.1		—

(1)Operating revenues earned and expenses incurred from activities with EPCO and its affiliates are considered related party transactions from February 24, 2005, through December 31, 2005, as a result of the change in ownership of the General Partner (see Note 1).

(2)Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines.

(3)Includes revenues from LPG transportation on the TE Products pipeline.

(4)Includes other operating revenues on TE Products.

(5)Substantially all of these costs were related to payroll, payroll related expenses and administrative expenses incurred in managing us and our subsidiaries.

(6)Includes TCO purchases of condensate and expenses related to LSI’s use of an affiliate of EPCO as a transporter.

(7)Operating revenues earned and expenses incurred from activities with DEFS and its affiliates are considered related party transactions for all periods through February 23, 2005, as a result of the change in ownership of the General Partner (see Note 1).

(8)Includes LSI sales of lubrication oils and specialty chemicals and Jonah NGL sales in connection with Jonah’s Pioneer processing plant operations, which was constructed during the Phase III expansion and began operating in 2004.

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(9)Includes revenues from NGL transportation on the Chaparral, Panola, Dean and Wilcox NGL pipelines.

(10)Includes gas gathering revenues on the Jonah system.

(11)Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence, Rhode Island, terminal.  We operate the terminal and provide propane loading services to an affiliate of DEFS.  We recognized revenue from an affiliate of DEFS pursuant to this agreement.

(12)Includes fractionation revenues and other revenues.  Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS.  Other operating revenues also include other operating revenues on TE Products and processing and other revenues on the Jonah system.

(13)Includes operating costs and expenses related to DEFS managing and operating the Jonah and Val Verde systems and the Chaparral NGL pipeline on our behalf under a contractual agreement established at the time of acquisition of each asset.  In connection with the change in ownership of our General Partner, we have assumed these activities.

(14)Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into an Operation and Maintenance Agreement, whereby DEFS 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.

(15)Includes TCO purchases of condensate.

(16)Includes Jonah purchases of natural gas in connection with Jonah’s Pioneer processing plant operations.

At December 31, 2005, we had a receivable from EPCO and affiliates of $4.3 million related to sales and transportation services provided to EPCO and affiliates.  At December 31, 2005, we had a payable to EPCO and affiliates of $9.8 million related to direct payroll, payroll related costs and other operational related charges.

At December 31, 2004, we had a receivable from DEFS and affiliates of $10.5 million related to sales and transportation services provided to DEFS and affiliates.  Included in this receivable balance from DEFS and affiliates at December 31, 2004, is a gas imbalance receivable of $0.9 million.  At December 31, 2004, we had a payable to DEFS and affiliates of $22.4 million related to direct payroll, payroll related costs, management fees, and other operational related charges, including those for Jonah, Chaparral and Val Verde as described above.  Included in this payable balance at December 31, 2004, is a gas imbalance payable to DEFS and affiliates of $3.2 million.

From February 24, 2005 through December 31, 2005, the majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, was obtained through EPCO.  From February 24, 2005 through December 31, 2005, we incurred insurance expense related to premiums charged by EPCO of $9.8 million.  At December 31, 2005, we had insurance reimbursement receivables due from EPCO of $1.3 million.

Through February 23, 2005, we contracted with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers’ liability insurance.  Through February 23, 2005 and for the years ended December 31, 2004 and 2003, we incurred insurance expense related to premiums paid to Bison of $1.2 million, $6.5 million and $5.9 million, respectively.  At December 31, 2004, we had insurance reimbursement receivables due from Bison of $5.2 million.

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit.  The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 11).

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Seaway

We own a 50% ownership interest in Seaway, and the remaining 50% interest is owned by ConocoPhillips (see Note 6).  We operate the Seaway assets.  During the years ended December 31, 2005, 2004 and 2003, we billed Seaway $8.5 million, $7.6 million and $7.4 million, respectively, for direct payroll and payroll related expenses for operating Seaway.  Additionally, for each of the years ended December 31, 2005, 2004 and 2003, we billed Seaway $2.1 million for indirect management fees for operating Seaway.  At December 31, 2005 and 2004, we had payable balances to Seaway of $0.6 million and $0.5 million, respectively, for advances Seaway paid to us as operator for operating costs, including payroll and related expenses and management fees.

Centennial

TE Products has a 50% ownership interest in Centennial (see Note 6).  TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs, Illinois, and pipeline connection in Beaumont, Texas.  For each of the years ended December 31, 2005, 2004 and 2003, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $3.7 million, $6.9 million and $4.4 million, respectively.

TE Products also has a joint tariff with Centennial to deliver products at TE Products’ locations using Centennial’s pipeline as part of the delivery route to connecting carriers.  TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff.  In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction.  At December 31, 2005 and 2004, we had net payable balances of $1.4 million and $1.7 million, respectively, to Centennial for its share of the joint tariff deliveries and other operational related charges, partially offset by the reimbursement due to us for construction services provided to Centennial.

In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement.  For the years ended December 31, 2005, 2004 and 2003, TE Products incurred $5.9 million, $5.3 million and $3.8 million, respectively, of rental charges related to the lease of pipeline capacity on Centennial.

MB Storage

Effective January 1, 2003, TE Products entered into agreements with Louis Dreyfus to form MB Storage (see Note 6).  TE Products operates the facilities for MB Storage.  TE Products and MB Storage have entered into a pipeline capacity lease agreement, and for each of the years ended December 31, 2005, 2004 and 2003, TE Products recognized $0.1 million in rental revenue related to this lease agreement.  During the years ended December 31, 2005, 2004 and 2003, TE Products also billed MB Storage $3.6 million, $3.2 million and $2.5 million, respectively, for direct payroll and payroll related expenses for operating MB Storage.  At December 31, 2005 and 2004, TE Products had net receivable balances from MB Storage of $0.9 million and $1.3 million, respectively, for operating costs, including payroll and related expenses for operating MB Storage.

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NOTE 8.        INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market.  The costs of inventories did not exceed market values at December 31, 2005 and 2004.  The major components of inventories were as follows (in thousands):

	December 31,
	2005		2004
Crude oil	$	3,021	$	3,690
Refined products	4,461		5,665
LPGs	7,403		—
Lubrication oils and specialty chemicals	5,740		4,002
Materials and supplies	8,203		6,135
Other	241		29
Total	$	29,069	$	19,521

NOTE 9.        PROPERTY, PLANT AND EQUIPMENT

Major categories of property, plant and equipment for the years ended December 31, 2005 and 2004, were as follows (in thousands):

	December 31,
	2005		2004
Land and right of way	$	147,064	$	135,984
Line pipe and fittings	1,434,392		1,344,193
Storage tanks	189,054		140,690
Buildings and improvements	51,596		41,205
Machinery and equipment	370,439		333,363
Construction work in progress	241,855		115,937
Total property, plant and equipment	$	2,434,400	$	2,111,372
Less accumulated depreciation and amortization	474,332		407,670
Net property, plant and equipment	$	1,960,068	$	1,703,702

Depreciation expense, including impairment charges, on property, plant and equipment was $80.8 million, $80.7 million and $64.5 million for the years ended December 31, 2005, 2004 and 2003, respectively.  During the fourth quarter of 2004, we wrote off approximately $2.1 million in assets taken out of service to depreciation expense.

In September 2005, our Todhunter facility, near Middletown, Ohio, experienced a propane release and fire at a dehydration unit within the storage facility.  The facility is included in our Downstream Segment.  The dehydration unit was destroyed due to the propane release and fire, and as a result, we wrote off the remaining book value of the asset of $0.8 million to depreciation and amortization expense during the third quarter of 2005.

We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.  During the third quarter of 2005, our Upstream Segment was notified by a connecting carrier that the flow of its pipeline system would be reversed, which would directly impact the viability of one of our pipeline systems.  This system, located in East Texas, consists of approximately 45 miles of pipeline, six tanks of various sizes and other equipment and asset costs.  As a result of changes to the connecting carrier, we performed an impairment test of the system and recorded a $1.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.

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During the third quarter of 2005, we completed an evaluation of a crude oil system included in our Upstream Segment.  The system, located in Oklahoma, consists of approximately six miles of pipelines, tanks and other equipment and asset costs.  The usage of the system has declined in recent months as a result of shifting crude oil production into areas not supported by the system, and as such, it has become more economical to transport barrels by truck to our other pipeline systems.  As a result, we performed an impairment test on the system and recorded a $0.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.

During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area.  The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment.  The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational.  As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the facility.

NOTE 10.      DEBT

Senior Notes

On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”).  The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes.  The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008.  The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at our election at the following redemption prices (expressed in percentages of the principal amount) if redeemed during the twelve months beginning January 15 of the years indicated:

Year	Redemption Price
2008	103.755	%
2009	103.380	%
2010	103.004	%
2011	102.629	%
2012	102.253	%
2013	101.878	%
2014	101.502	%
2015	101.127	%
2016	100.751	%
2017	100.376	%

and thereafter at 100% of the principal amount, together in each case with accrued interest at the redemption date.

The TE Products Senior Notes do not have sinking fund requirements.  Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year.  The TE Products Senior Notes are unsecured obligations of TE Products and rank pari passu with all other unsecured and unsubordinated indebtedness of TE Products.  The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions.  However, the indenture does not limit our ability to incur additional indebtedness.  As of December 31, 2005, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012.  The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes.  The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining

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maturity plus 35 basis points.  The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions.  However, the indenture does not limit our ability to incur additional indebtedness.  As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013.  The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes.  The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points.  The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions.  However, the indenture does not limit our ability to incur additional indebtedness.  As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.

The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2005 and 2004 (in millions):

			Fair Value
	Face Value		December 31,
			2005		2004
6.45% TE Products Senior Notes, due January 2008	$	180.0	$	183.7	$	187.1
7.625% Senior Notes, due February 2012	500.0		552.0		569.6
6.125% Senior Notes, due February 2013	200.0		205.6		210.2
7.51% TE Products Senior Notes, due January 2028	210.0		224.1		225.6

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

Revolving Credit Facility

On April 6, 2001, we entered into a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”).  The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings.  The credit agreement for the Three Year Facility contained certain restrictive financial covenant ratios.  During the first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003.  On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.

On June 27, 2003, we entered into a $550.0 million unsecured revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”).  The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings.  The credit agreement for the Revolving Credit Facility contains certain restrictive financial covenant ratios.  Restrictive covenants in the Revolving Credit Facility limit our ability to, among other things, incur additional indebtedness, make distributions in excess of Available Cash (see Note 11) and complete mergers, acquisitions and sales of assets.  We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility.  On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing.  On February 23, 2005, we amended our Revolving Credit Facility to remove the requirement that DEFS must at all times own, directly or indirectly, 100% of our General Partner, to allow for its acquisition by DFI (see Note 1).  During the second quarter of 2005, we used

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a portion of the proceeds from the equity offering in May 2005 to repay a portion of the Revolving Credit Facility (see Note 11).  On December 13, 2005, we again amended our Revolving Credit Facility as follows:

•Total bank commitments increased from $600.0 million to $700.0 million.  The amendment also provided that the commitments under the credit facility may be increased up to a maximum of $850.0 million upon our request, subject to lender approval and the satisfaction of certain other conditions.

•The facility fee and the borrowing rate currently in effect were reduced by 0.275%.

•The maturity date of the credit facility was extended from October 21, 2009, to December 13, 2010.  Also under the terms of the amendment, we may request up to two, one-year extensions of the maturity date.  These extensions, if requested, will become effective subject to lender approval and satisfaction of certain other conditions.

•The amendment also removed the $100.0 million limit on the total amount of standby letters of credit that can be outstanding under the credit facility.

On December 31, 2005, $405.9 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.9%.  At December 31, 2005, we were in compliance with the covenants of this credit agreement.

The following table summarizes the principal amounts outstanding under all of our credit facilities as of December 31, 2005 and 2004 (in thousands):

	December 31,
	2005		2004
Credit Facilities:
Revolving Credit Facility, due December 2010	$	405,900	$	353,000
6.45% TE Products Senior Notes, due January 2008	179,937		179,906
7.625% Senior Notes, due February 2012	498,659		498,438
6.125% Senior Notes, due February 2013	198,988		198,845
7.51% TE Products Senior Notes, due January 2028	210,000		210,000
Total borrowings	1,493,484		1,440,189
Adjustment to carrying value associated with hedges of fair value	31,537		40,037
Total Credit Facilities	$	1,525,021	$	1,480,226

Letter of Credit

At December 31, 2005, we had an $11.5 million standby letter of credit in connection with crude oil purchases in the fourth quarter of 2005.  This amount will be paid during the first quarter of 2006.

NOTE 11.      PARTNERS’ CAPITAL AND DISTRIBUTIONS

Equity Offerings

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit.  The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO.  We received approximately $0.7 million in proceeds from the offering in excess of the amount needed to repurchase and retire the Class B Units.

On August 7, 2003, we sold in an underwritten public offering 5.0 million Units at $34.68 per Unit.  The proceeds from the offering, net of underwriting discount, totaled approximately $166.0 million.  On August 19,

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2003, 162,900 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on August 7, 2003.  Proceeds from the over-allotment sale, net of underwriting discount, totaled $5.4 million.  Approximately $53.0 million of the proceeds were used to repay indebtedness under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 5).  The remaining amount was used primarily to fund revenue-generating and system upgrade capital expenditures and for general partnership purposes.

On May 5, 2005, we sold in an underwritten public offering 6.1 million Units at $41.75 per Unit.  The proceeds from the offering, net of underwriting discount, totaled approximately $244.5 million.  On June 8, 2005, 865,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on May 5, 2005.  Proceeds from the over-allotment sale, net of underwriting discount, totaled $34.7 million.  The proceeds were used to reduce indebtedness under our Revolving Credit Facility, to fund revenue generating and system upgrade capital expenditures and for general partnership purposes.

Quarterly Distributions of Available Cash

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

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

The following table reflects the allocation of total distributions paid during the years ended December 31, 2005, 2004 and 2003 (in thousands, except per Unit amounts):

	Years Ended December 31,
	2005		2004		2003
Limited Partner Units	$	177,917	$	166,158	$	145,427
General Partner Ownership Interest	3,630		3,391		3,016
General Partner Incentive	69,554		63,508		51,709
Total Partners’ Capital Cash Distributions Paid	251,101		233,057		200,152
Class B Units	—		—		2,346
Total Cash Distributions Paid	$	251,101	$	233,057	$	202,498
Total Cash Distributions Paid Per Unit	$	2.68	$	2.64	$	2.50

On February 7, 2006, we paid a cash distribution of $0.675 per Unit for the quarter ended December 31, 2005.  The fourth quarter 2005 cash distribution totaled $66.9 million.

General Partner Interest

As of December 31, 2005 and 2004, we had deficit balances of $61.5 million and $35.9 million, respectively, in our General Partner’s equity account. These negative balances do not represent an asset to us and do not represent an obligation of the General Partner to contribute cash or other property to us. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Consolidated Statements of Partners’ Capital for a detail of the

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General Partner’s equity account).  For the years ended December 31, 2005, 2004 and 2003, the General Partner was allocated $47.6 million (representing 29.27%), $40.0 million (representing 28.85%) and $33.7 million (representing 27.65%), respectively, of our net income and received $73.2 million, $66.9 million and $54.7 million, respectively, in cash distributions.

Capital Accounts, as defined under our Partnership Agreement, are maintained for our General Partner and our limited partners.  The Capital Account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under accounting principles generally accepted in the United States in our financial statements.  Under our Partnership Agreement, the General Partner is required to make additional capital contributions to us upon the issuance of any additional Units if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners.  At December 31, 2005 and 2004, the General Partner’s Capital Account balance substantially exceeded this requirement.

Net income is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period.  This is generally consistent with the manner of allocating net income under our Partnership Agreement.  Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under accounting principles generally accepted in the United States in our financial statements.

Cash distributions that we make during a period may exceed our net income for the period.  We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion.  Cash distributions in excess of net income allocations and capital contributions during the years ended December 31, 2005 and 2004, resulted in a deficit in the General Partner’s equity account at December 31, 2005 and 2004.  Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.

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

NOTE 12.      CONCENTRATIONS OF 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 customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors.  We thoroughly analyze our customers’ historical and future credit positions prior to extending credit.  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.

For each of the years ended December 31, 2005, 2004 and 2003, Valero Energy Corp. accounted for 14%, 16% and 16% of our total consolidated revenues, respectively.  No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2005, 2004 and 2003.

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The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature.

NOTE 13.      UNIT-BASED COMPENSATION

1994 Long Term Incentive Plan

During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Units.  These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Unit options awarded.  Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted.

When our calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded.  The balance in the Performance Unit account may be used to offset the cost of exercising Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant.  Any unused balance previously credited is forfeited upon termination.  We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above.

Under the agreement for such Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant.  At December 31, 2005, all options have been fully exercised. The Performance Unit account has a minimal liability balance which may be withdrawn by the participants after December 31, 2006.

A summary of Unit options granted under the terms of the 1994 LTIP is presented below:

	Options Outstanding		Options Exercisable		Exercise Range
Unit Options:
Outstanding at December 31, 2002	90,091		90,091		$13.81 - $25.69
Exercised	(90,091	)	(90,091	)	$13.81 - $25.69
Outstanding at December 31, 2003	—		—

We have not granted options for any periods presented.  During the year ended December 31, 2003, all remaining outstanding Unit options were exercised.  For options previously outstanding, we followed the intrinsic value method for recognizing stock-based compensation expense.  The exercise price of all options awarded under the 1994 LTIP equaled the market price of our Units on the date of grant.  Accordingly, we recognized no compensation expense at the date of grant.  Had compensation expense been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, no compensation expense would have been recognized for the years ended December 31, 2005, 2004 and 2003.

1999 and 2002 Phantom Unit Plans

Effective September 1, 1999, the Company adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 PURP”).  Effective June 1, 2002, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan (“2002 PURP”). The 1999 PURP and

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the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units.  These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates.  The fair market value of each phantom unit is equal to the closing price of a Unit as reported on the New York Stock Exchange on the redemption date.

Under the agreement for the phantom units, each participant will vest 10% of the number of phantom units initially granted under his or her award at the end of each of the first four years and will vest the final 60% at the end of the fifth year.  Each participant is required to redeem their phantom units as they vest.   They are also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the amount of the cash distribution that we paid per Unit to unitholders.  We accrued compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above.  At December 31, 2004, we had an accrued liability balance of $1.6 million for compensation related to the 1999 PURP and 2002 PURP.  Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005 (see Note 1), all outstanding units under both the 1999 PURP and the 2002 PURP fully vested and were redeemed by participants.  As such, there were no outstanding units at December 31, 2005 under either the 1999 PURP or the 2002 PURP.

2000 Long Term Incentive Plan

Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance.  Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period.  Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period.  If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period.  Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005, all outstanding units under the 2000 LTIP for plan years 2003 and 2004 were fully vested and redeemed by participants.  As such, there were no outstanding units at December 31, 2005, for awards granted for the plan years ended December 31, 2004 and 2003.  At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 23,400.

Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period.  For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion the Chief Executive Officer (“CEO”) of the Company may exclude gains or losses from extraordinary, unusual or non-recurring items.  For the years ended December 31, 2005, 2004 and 2003, EBITDA means, in addition to the above definition of EBITDA, earnings before other income – net.  Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil operating oil supply and the gross value of intangibles and equity investments.  Our cost of capital is approved by our CEO at the date of award grant.

In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been

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the owner of the number of Units equal to the number of phantom units granted to the participant under this award.  We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above.  At December 31, 2005 and 2004, we had an accrued liability balance of $0.7 million and $2.4 million, respectively, for compensation related to the 2000 LTIP.

2005 Phantom Unit Plan

Effective January 1, 2005, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 PURP”) to provide key employees incentives to achieve improvements in our financial performance.  Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the grantee’s vested percentage multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period.  Generally, a participant’s vested percentage is based upon the improvement of our EBITDA (as defined below) during a three-year performance period over the target EBITDA as defined at the beginning of each year during the three-year performance period.  EBITDA means our earnings before minority interest, net interest expense, other income – net, income taxes, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion, our CEO may exclude gains or losses from extraordinary, unusual or non-recurring items.  At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 53,600.

In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award.  We accrue compensation expense annually based upon the terms of the 2005 PURP discussed above.  At December 31, 2005, we had an accrued liability balance of $0.7 million for compensation related to the 2005 PURP.

NOTE 14.              OPERATING LEASES

We use leased assets in several areas of our operations.  Total rental expense for the years ended December 31, 2005, 2004 and 2003, was $24.0 million, $22.1 million and $18.8 million, respectively.  The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands):

2006	$	19,536
2007	17,391
2008	10,863
2009	7,682
2010	6,645
Thereafter	21,544
	$	83,661

NOTE 15.      EMPLOYEE BENEFITS

Retirement Plans

The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan.  In addition, the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”) was a non-contributory, nonqualified, defined benefit retirement plan, in which certain executive officers participated.  The

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TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans.  The benefit formula for all eligible employees was a cash balance formula.  Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits.  The pay credits were based on a participant’s salary, age and service.  We used a December 31 measurement date for these plans.

On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended.  Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date.  Effective December 31, 2005, all plan benefits accrued were frozen, participants will not receive additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service.  The TEPPCO RCBP plan was terminated effective December 31, 2005, subject to IRS approval of plan termination, and plan participants will have the option to receive their benefits either through a lump sum payment in 2006 or through an annuity.  For those plan participants who elect to receive an annuity, we will purchase an annuity contract from an insurance company in which the plan participant owns the annuity, absolving us of any future obligation to the participant.  Participants in the TEPPCO SBP received pay credits through November 30, 2005, and received lump sum benefit payments in December 2005.  Both the RCBP and SBP benefit payments are discussed below.

In June 2005, we recorded a curtailment charge of $0.1 million in accordance with SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, as a result of the TEPPCO RCBP and TEPPCO SBP amendments.  As of May 31, 2005, the following assumptions were changed for purposes of determining the net periodic benefit costs for the remainder of 2005: the discount rate, the long-term rate of return on plan assets, and the assumed mortality table.  The discount rate was decreased from 5.75% to 5.00% to reflect rates of returns on bonds currently available to settle the liability.   The expected long-term rate of return on plan assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds.  The mortality table was changed to reflect overall improvements in mortality experienced by the general population.  The curtailment charge arose due to the accelerated recognition of the unrecognized prior service costs.  We recorded additional settlement charges of approximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCO SBP.  We expect to record additional settlement charges of approximately $4.0 million in 2006 relating to the TEPPCO RCBP for any existing unrecognized losses upon the plan termination and final distribution of the assets to the plan participants.

The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):

	Year Ended December 31,
	2005			2004			2003
Service cost benefit earned during the year	$	4,393		$	3,653		$	3,179
Interest cost on projected benefit obligation	934			719			504
Expected return on plan assets	(671		)	(878		)	(604		)
Amortization of prior service cost	5			7			7
Recognized net actuarial loss	129			57			24
SFAS 88 curtailment charge	50			—			—
SFAS 88 settlement charge	194			—			—
Net pension benefits costs	$	5,034		$	3,558		$	3,110

Other Postretirement Benefits

We provided certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”).  Employees became eligible for these benefits if they met certain age and service requirements at retirement, as defined in the plans.  We provided a fixed dollar contribution, which did not

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increase from year to year, towards retired employee medical costs.  The retiree paid all health care cost increases due to medical inflation.  We used a December 31 measurement date for this plan.

In May 2005, benefits provided to employees under the TEPPCO OPB were changed.  Employees eligible for these benefits received them through December 31, 2005, however, effective December 31, 2005, these benefits were terminated.  As a result of this change in benefits and in accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, we recorded a curtailment credit of approximately $1.7 million in our accumulated postretirement obligation which reduced our accumulated postretirement obligation to the total of the expected remaining 2005 payments under the TEPPCO OPB.  The current employees participating in this plan were transferred to DEFS, who will continue to provide postretirement benefits to these retirees.  We recorded a one-time settlement to DEFS in the third quarter of 2005 of $0.4 million for the remaining postretirement benefits.

The components of net postretirement benefits cost for the TEPPCO OPB for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):

	Year Ended December 31,
	2005			2004		2003
Service cost benefit earned during the year	$	81		$	165	$	137
Interest cost on accumulated postretirement benefit obligation	69			153		137
Amortization of prior service cost	53			126		126
Recognized net actuarial loss	4			1		—
Curtailment credit	(1,676		)	—		—
Settlement credit	(4		)	—		—
Net postretirement benefits costs	$	(1,473	)	$	445	$	400

Effective June 1, 2005, the payroll functions performed by DEFS for our General Partner were transferred from DEFS to EPCO.  For those employees who were receiving certain other postretirement benefits at the time of the acquisition of our General Partner by DFI, DEFS will continue to provide these benefits to those employees.  Effective June 1, 2005, EPCO began providing certain other postretirement benefits to those employees who became eligible for the benefits after June 1, 2005, and will charge those benefit related costs to us.  As a result of these changes, we recorded a $1.2 million reduction in our other postretirement obligation in June 2005.

We employed a building block approach in determining the long-term rate of return for plan assets.  Historical markets were studied and long-term historical relationships between equities and fixed-income were preserved consistent with a widely accepted capital market principle that assets with higher volatility generate a greater return over the long run.  Current market factors such as inflation and interest rates were evaluated before long-term capital market assumptions were determined.  The long-term portfolio return was established via a building block approach with proper consideration of diversification and rebalancing.  Peer data and historical returns were reviewed to check for reasonability and appropriateness.

The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2005 and 2004, were as follows:

	Pension Benefits				Other Postretirement Benefits
	2005		2004		2005		2004
Discount rate	4.59	%	5.75	%	5.75	%	5.75	%
Increase in compensation levels	—		5.00	%	—		—

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The weighted average assumptions used to determine net periodic benefit cost for the retirement plans and other postretirement benefit plans for the years ended December 31, 2005 and 2004, were as follows:

	Pension Benefits				Other Postretirement Benefits
	2005		2004		2005		2004
Discount rate (1)	5.75/5.00	%	6.25	%	5.75/5.00	%	6.25	%
Increase in compensation levels	5.00	%	5.00	%	—		—
Expected long-term rate of return on plan assets (2)	8.00%/2.00	%	8.00	%	—		—

(1)Expense was remeasured on May 31, 2005, as a result of TEPPCO RCBP and TEPPCO SBP amendments.  The discount rate was decreased from 5.75% to 5% effective June 1, 2005, to reflect rates of returns on bonds currently available to settle the liability.

(2)As a result of TEPPCO RCBP and TEPPCO SBP amendments, the expected return on assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds, effective June 1, 2005.

The following table sets forth our pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2005 and 2004 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
Change in benefit obligation
Benefit obligation at beginning of year	$	15,940		$	11,256		$	2,964		$	2,467
Service cost	4,393			3,653			81			165
Interest cost	934			719			70			153
Actuarial loss	2,740			572			76			205
Retiree contributions	—			—			64			60
Benefits paid	(910		)	(260		)	(80		)	(86		)
Impact of curtailment	(986		)	—			(3,575		)	—
Settlement	—			—			400			—
Benefit obligation at end of year	$	22,111		$	15,940		$	—		$	2,964
Change in plan assets
Fair value of plan assets at beginning of year	$	14,969		$	10,921		$	—		$	—
Actual return on plan assets	20			808			—			—
Retiree contributions	—			—			64			60
Employer contributions	9,025			3,500			16			26
Benefits paid	(910		)	(260		)	(80		)	(86		)
Fair value of plan assets at end of year	$	23,104		$	14,969		$	—		$	—
Reconciliation of funded status
Funded status	$	994		$	(971	)	$	—		$	(2,964	)
Unrecognized prior service cost	—			33			—			1,003
Unrecognized actuarial loss	4,067			2,006			—			472
Net amount recognized	$	5,061		$	1,068		$	—		$	(1,489	)

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We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid (in thousands):

	Pension Benefits		Other Postretirement Benefits
2006	$	22,360	$	—

Plan Assets

We employed a total return investment approach whereby a mix of equities and fixed income investments were used to maximize the long-term return of plan assets for a prudent level of risk.  Risk tolerance was established through careful consideration of plan liabilities, plan funded status and corporate financial condition.  The investment portfolio contained a diversified blend of equity and fixed-income investments.  Furthermore, equity investments were diversified across U.S. and non-U.S. stocks, both growth and value equity style, and small, mid and large capitalizations.  Investment risk and return parameters were reviewed and evaluated periodically to ensure compliance with stated investment objectives and guidelines.  This comprehensive review incorporated investment portfolio performance, annual liability measurements and periodic asset/liability studies.

The following table sets forth the weighted average asset allocations for the retirement plans and other postretirement benefit plans as of December 31, 2005 and 2004, by asset category (in thousands):

	December 31,
Asset Category	2005		2004
Equity securities	—		63	%
Debt securities	—		35	%
Other (money market and cash)	100	%	2	%
Total	100	%	100	%

We do not expect to make further contributions to our retirement plans and other postretirement benefit plans in 2006.

Other Plans

DEFS also sponsored an employee savings plan, which covered substantially all employees.  Effective February 24, 2005, in conjunction with the change in ownership of our General Partner, our participation in this plan ended.  Plan contributions on behalf of the Company of $0.9 million, $3.5 million and $3.2 million were recognized for the period January 1, 2005 through February 23, 2005, and during the years ended December 31, 2004 and 2003, respectively.

NOTE 16.      COMMITMENTS AND CONTINGENCIES

Litigation

In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the General Partner and Partnership).In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water.  They further contend that the release caused damages to the plaintiffs.  In

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their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages.  On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards 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 Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all 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 have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance.  We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

On April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al.  This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill.  The plaintiffs allege personal injuries, allergies, birth defects, cancer and death.  The underground injection well has been in operation since May 1976.  Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002.  Marathon has been handling this matter for Centennial under its operating agreement with Centennial.  TE Products has a 50% ownership interest in Centennial.  On November 30, 2004, the court approved a class settlement.  The time period for parties to appeal this settlement expired in March 2005, and the class settlement became final.  The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

In May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana.  There are numerous plaintiffs identified in the action that are alleged to have suffered damages as a result of alleged exposure to asbestos-containing products and materials.  According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor.  This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual.  The individual’s claims involve numerous employers and alleged job sites.  The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit.  The plaintiffs have not stipulated the amount of damages that they are seeking in this suit.  We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit.  We cannot estimate the loss, if any, associated with this pending lawsuit.  We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

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On August 5, 2005, we were named as a third-party defendant in a matter styled ConocoPhillips, et al. v. BP Amoco Seaway Products Pipeline Company as filed in the 55^th Judicial District of Harris County, Texas.  ConocoPhillips alleges a right to indemnity from BP Amoco Seaway Products Pipeline Company (“BP Amoco”) for tax liability incurred by ConocoPhillips as a result of the reverse merger of Seaway Pipeline Company (the “Original Seaway Partnership”).  The reverse merger of the Original Seaway Partnership was undertaken in preparation for our purchase of ARCO Pipe Line Company pursuant to the Amended and Restated Purchase Agreement (the “Purchase Agreement”) dated May 10, 2000, between us and Atlantic Richfield Company. BP Amoco has claimed a right to indemnity from us under the Purchase Agreement should BP Amoco have any indemnity liability to ConocoPhillips.  ConocoPhillips alleges the income tax liability to be approximately $4.0 million.  On January 20, 2006, we entered into a settlement agreement with BP Amoco dismissing and resolving all of BP Amoco’s claims.  The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26^th Judicial District Court of Bossier Parish, Louisiana.  The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants.  The former refinery is located near our Bossier City facility.  Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property.  The plaintiffs have recently pursued certification as a class and have significantly increased their demand to approximately $175.0 million.  This revised demand includes amounts for environmental restoration not previously claimed by the plaintiffs.  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.

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

Regulatory Matters

Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment and various safety matters. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities.  We believe our operations have been and are in material compliance with applicable environmental and safety laws and regulations, and that compliance with existing environmental laws and regulations are not expected to have a material adverse effect on our competitive position, financial positions, results of operations or cash flows.  However, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.  At December 31, 2005 and 2004, we have an accrued liability of $2.4 million and $5.0 million, respectively, related to sites requiring environmental remediation activities.

On March 26, 2004, a decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”).  The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged.  In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates.  The elements identified in the decision are

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volume changes, allowed total return and total cost-of-service (including major cost elements such as rate base, tax rates and tax allowances, among others).  The FERC did reject, however, the use of changes in tax rates and income tax allowances as stand-alone factors.  Judicial review of that decision, which has been sought by a number of parties to the case, is currently pending before the U.S. Court of Appeals for the District of Columbia Circuit.  We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.

On July 20, 2004, the District of Columbia Circuit issued an opinion in BP West Coast Products LLC v. FERC.  In reviewing a series of orders involving SFPP, L.P., the court held among other things that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its income attributable to partnership interests owned by corporate partners.  Under the FERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-service filing for the percentage of its net operating (pre-tax) income attributable to partnership units held by corporations, and was denied an income tax allowance equal to the percentage attributable to partnership units held by non-corporate partners.  The court remanded the case back to the FERC for further review.  As a result of the court’s remand, on May 4, 2005, the FERC issued its Policy Statement on Income Tax Allowances, which permits regulated partnerships, limited liability companies and other pass-through entities an income tax allowance on their income attributable to any owner that has an actual or potential income tax liability on that income, regardless whether the owner is an individual or corporation.  If there is more than one level of pass-through entities, the regulated company income must be traced to where the ultimate tax liability lies.  The Policy Statement is to be applied in individual cases, and the regulated entity bears the burden of proof to establish the tax status of its owners.  On December 16, 2005, the FERC issued the first of those decisions, in an order involving SFPP (the “SFPP Order”).  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.  The SFPP Order remains subject to further administrative proceedings (including compliance filings by SFPP and possible rehearing requests), as well as potential judicial review.  The ultimate outcome of the FERC’s inquiry on income tax allowance should not affect our current rates and rate structure because our rates are not based on cost-of-service methodology.  However, the outcome of the income tax allowance would become relevant to us should we (i) elect in the future to use cost-of-service to support our rates, or (ii) be required to use such methodology to defend our indexed rates.

In 1994, the Louisiana Department of Environmental Quality (“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, 2005, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility.  We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.

On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois.  As a result of the release, we have entered into an Agreed Order with the State of Illinois, which required us to conduct an environmental investigation.  At this time, we have complied with the terms of the Agreed Order, and the results of the environmental investigation indicated there were no soil or groundwater impacts from the release.  On August 30, 2005, a final settlement was reached with the State of Illinois.  The settlement included the payment of a civil penalty of $0.1 million and the requirement that we make

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certain modifications to the equipment of the facility, none of which are expected to have a material adverse effect on our financial position, results of operations or cash flows.

On July 22, 2004, we experienced a release of approximately 12 barrels of jet fuel from a sump at our Lebanon, Ohio, terminal.  The released jet fuel was contained within a storm water retention pond located on the terminal property.  Six migratory waterfowl were affected by the jet fuel and were subsequently euthanized by or at the request of the United States Fish and Wildlife Service (“USFWS”).  On October 1, 2004, the USFWS served us with a Notice of Violation, alleging that we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing] of migratory birds by illegal methods.”  On February 7, 2005, we entered into a Memorandum of Understanding with the USFWS, settling all aspects of this matter.  The terms of this settlement did not have a material 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 Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release.  We are in discussions with the DOJ regarding this matter and have responded to its request for additional information.  The maximum statutory penalty proposed by the DOJ for this alleged violation of the CWA is $2.1 million.  We do not expect any civil penalty 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. On or about February 22, 2006, we received verbal notification from a representative of the Occupational Safety and Health Administration that they intend to serve us with a citation arising out of this incident.  At this time, we have not received any citation, and we cannot predict with certainty the amount of any fine or penalty associated with any such citation; however, we do not expect any fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.

Rates of interstate petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”).  Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI – 1% to PPI.  On April 22, 2003, several shippers filed a petition in the United States Court of Appeals for the District of Columbia Circuit (the “Court”), Flying J. Inc,. Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and Marketing Company vs. Federal Energy Regulatory Commission; Docket No. 03-1107, seeking a review of whether the FERC’s adoption of the PPI Index was reasonable and supported by the evidence.  On April 9, 2004, the Court handed down a decision denying the shippers’ petition for review, stating the shippers failed to establish that any of the FERC’s methodological choices (or combination of choices) were both erroneous and harmful.

As an alternative to using the PPI Index, interstate petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and petroleum products and crude oil pipeline companies that the rate is acceptable.

Other

Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2005, $150.0 million was outstanding under those credit facilities.  TE Products and Marathon have each guaranteed one-half of the repayment of Centennial’s outstanding debt balance (plus interest) under a long-term credit agreement, which expires in 2024, and a short-term credit agreement, which expires in 2007.  The guarantees arose in order for Centennial to obtain adequate financing, and the proceeds of the credit agreements were used to fund construction

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and conversion costs of its pipeline system.  Prior to the expiration of the long-term credit agreement, TE Products could be relinquished from responsibility under the guarantee should Centennial meet certain financial tests.  If Centennial defaults on its outstanding balance, the estimated maximum potential amount of future payments for TE Products and Marathon is $75.0 million each at December 31, 2005.

TE Products, Marathon and Centennial have entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event.  There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each.  As a result of the catastrophic event guarantee, TE Products has recorded a $4.6 million obligation, which represents the present value of the estimated amount that we would have to pay under the guarantee.  If a catastrophic event were to occur and we were required to contribute cash to Centennial, contributions exceeding our deductible might be covered by our insurance.

One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various equipment.  We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements.  Generally, events of default would trigger our performance under the guarantee.  The maximum potential amount of future payments under the guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments.  We carry insurance coverage that may offset any payments required under the guarantees.

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 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 the General Partner may substantially lessen competition.  The General Partner is cooperating fully with this investigation.

Substantially all of the petroleum products that we transport and store are owned by our customers.  At December 31, 2005, TCTM and TE Products had approximately 4.0 million barrels and 22.5 million barrels, respectively, of products in their custody that was owned by customers.  We are obligated for the transportation, storage and delivery of such products on behalf of our customers.  We maintain insurance adequate to cover product losses through circumstances beyond our control.

We carry insurance coverage consistent with the exposures associated with the nature and scope of our operations.  Our current insurance coverage includes (1) commercial general liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation coverage to required statutory limits;  (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense.  For select assets, we also carry pollution liability insurance that provides coverage for historical and gradual pollution events.  All coverages are subject to certain deductibles, limits or sub-limits and policy terms and conditions.

We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance.  Limits, terms, conditions and deductibles are commensurate with the nature and scope of our operations.  The cost of our general insurance coverages has increased over the past year reflecting the changing conditions of the insurance markets.  These insurance policies, except for the pollution liability policies, are through EPCO (see Note 7).

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NOTE 17.SEGMENT INFORMATION

We have three reporting segments:

•Our Downstream Segment, which is engaged in the transportation 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, fractionation of NGLs and transportation of NGLs.

The amounts indicated below as “Partnership and Other” relate primarily to intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.

Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power.  We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating.  Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports, refinery grade propylene from Mont Belvieu to Point Comfort, Texas.  Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6).

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 of the crude oil to local refineries, marketers or other end users.  Our Upstream Segment also includes our equity investment in Seaway.  Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.

Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde.

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The tables below include financial information by reporting segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Year Ended December 31, 2005
	Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
Sales of petroleum products	$	—		$	8,062,131		$	10,479		$	8,072,610		$	(323	)	$	8,072,287
Operating revenues	287,191			48,108			214,146			549,445			(3,244		)	546,201
Purchases of petroleum products	—			7,989,682			8,995			7,998,677			(3,244		)	7,995,433
Operating expenses, including power	159,784			70,340			59,398			289,522			(323		)	289,199
Depreciation and amortization expense	39,403			17,161			54,777			111,341			—			111,341
Gains on sales of assets	(139		)	(118		)	(411		)	(668		)	—			(668)
Operating income	88,143			33,174			101,866			223,183			—			223,183
Equity earnings (losses)	(2,984		)	23,078			—			20,094			—			20,094
Other income, net	755			156			224			1,135			—			1,135
Earnings before interest	$	85,914		$	56,408		$	102,090		$	244,412		$	—		$	244,412

	Year Ended December 31, 2004
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated
	(as restated)			(as restated)					(as restated)						(as restated)
Sales of petroleum products	$	—		$	5,426,832		$	7,295	$	5,434,127		$	—		$	5,434,127
Operating revenues	279,400			49,163			198,709		527,272			(3,207		)	524,065
Purchases of petroleum products	—			5,370,234			5,944		5,376,178			(3,207		)	5,372,971
Operating expenses, including power	165,528			60,893			59,826		286,247			—			286,247
Depreciation and amortization expense	43,135			13,130			56,629		112,894			—			112,894
Gains on sales of assets	(526		)	(527		)	—		(1,053		)	—			(1,053		)
Operating income	71,263			32,265			83,605		187,133			—			187,133
Equity earnings (losses)	(6,544		)	28,692			—		22,148			—			22,148
Other income, net	787			406			127		1,320			—			1,320
Earnings before interest	$	65,506		$	61,363		$	83,732	$	210,601		$	—		$	210,601

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	Year Ended December 31, 2003
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated
	(as restated)			(as restated)					(as restated)						(as restated)
Sales of petroleum products	$	—		$	3,766,651		$	—	$	3,766,651		$	—		$	3,766,651
Operating revenues	266,427			39,564			185,105		491,096			(1,915		)	489,181
Purchases of petroleum products	—			3,713,122			—		3,713,122			(1,915		)	3,711,207
Operating expenses, including power	151,103			57,314			47,020		255,437			—			255,437
Depreciation and amortization expense	31,620			11,311			57,797		100,728			—			100,728
Gain on sale of assets	—			(3,948		)	—		(3,948		)	—			(3,948		)
Operating income	83,704			28,416			80,288		192,408			—			192,408
Equity earnings (losses)	(7,384		)	20,258			—		12,874			—			12,874
Other income, net	226			306			289		821			(73		)	748
Earnings before interest	$	76,546		$	48,980		$	80,577	$	206,103		$	(73	)	$	206,030

The following table provides the total assets, capital expenditures and significant non-cash investing activities for each segment as of and for the years ended December 31, 2005, 2004 and 2003 (in thousands):

	Downstream Segment		Upstream Segment		Midstream Segment		Segments Total		Partnership and Other			Consolidated
December 31, 2005:
Total assets	$	1,056,217	$	1,353,492	$	1,280,548	$	3,690,257	$	(9,719	)	$	3,680,538
Capital expenditures	58,609		40,954		119,837		219,400		1,153			220,553
Non-cash investing activities	1,429		—		—		1,429		—			1,429
December 31, 2004 (as restated):
Total assets	$	959,042	$	1,069,007	$	1,184,184	$	3,212,233	$	(25,949	)	$	3,186,284
Capital expenditures	80,930		37,448		45,075		163,453		694			164,147
December 31, 2003 (as restated):
Total assets	$	911,184	$	833,723	$	1,194,844	$	2,939,751	$	(5,271	)	$	2,934,480
Capital expenditures	59,061		13,427		67,882		140,370		147			140,517
Non-cash investing activities	61,042		—		—		61,042		—			61,042

The following table reconciles the segments total earnings before interest to consolidated net income for the three years ended December 31, 2005, 2004 and 2003 (in thousands):

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Earnings before interest	$	244,412		$	210,601		$	206,030
Interest expense — net	(81,861		)	(72,053		)	(84,250		)
Net income	$	162,551		$	138,548		$	121,780

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NOTE 18.COMPREHENSIVE INCOME

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement.  As of and for the year ended December 31, 2005, the components of comprehensive income were due to crude oil hedges.  The crude oil hedges mature in December 2006.  While the crude oil hedges are in effect, changes in the fair values of the crude oil hedges, to the extent the hedges are effective, are recognized in other comprehensive income until they are recognized in net income in future periods.  As of and for the year ended December 31, 2004, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which was designated as a cash flow hedge.  The interest rate swap matured in April 2004.  While the interest rate swap was in effect, changes in the fair value of the cash flow hedge, to the extent the hedge was effective, were recognized in other comprehensive income until the hedge interest costs were recognized in net income.

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

Balance at December 31, 2002 (unaudited) (as restated)	$	(20,055	)
Reclassification due to discontinued portion of cash flow hedge	989
Transferred to earnings	14,417
Change in fair value of cash flow hedge	1,747
Balance at December 31, 2003 (as restated)	$	(2,902	)
Transferred to earnings	2,939
Change in fair value of cash flow hedge	(37		)
Balance at December 31, 2004 (as restated)	$	—
Changes in fair values of crude oil cash flow hedges	11
Balance at December 31, 2005	$	11

NOTE 19.SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our significant operating subsidiaries, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P., have issued unconditional guarantees of our debt securities.  The guarantees are full, unconditional, and joint and several.  TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”

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

F-48

	December 31, 2005
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	40,977	$	107,692	$	789,486	$	(39,026	)	$	899,129
Property, plant and equipment — net	—		1,335,724		624,344		—			1,960,068
Equity investments	1,201,388		461,741		202,343		(1,505,816		)	359,656
Intercompany notes receivable	1,134,093		—		—		(1,134,093		)	—
Intangible assets	—		345,005		31,903		—			376,908
Other assets	5,532		22,170		57,075		—			84,777
Total assets	$	2,381,990	$	2,272,332	$	1,705,151	$	(2,678,935	)	$	3,680,538
Liabilities and partners’ capital
Current liabilities	$	43,236	$	140,743	$	793,683	$	(40,451	)	$	937,211
Long-term debt	1,135,973		389,048		—		—			1,525,021
Intercompany notes payable	—		635,263		498,832		(1,134,095		)	—
Other long term liabilities	1,422		14,564		950		—			16,936
Total partners’ capital	1,201,359		1,092,714		411,686		(1,504,389		)	1,201,370
Total liabilities and partners’ capital	$	2,381,990	$	2,272,332	$	1,705,151	$	(2,678,935	)	$	3,680,538

	December 31, 2004 (as restated)
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	44,125	$	85,992	$	576,365	$	(62,928	)	$	643,554
Property, plant and equipment – net	—		1,211,312		492,390		—			1,703,702
Equity investments	1,011,131		420,343		202,326		(1,270,493		)	363,307
Intercompany notes receivable	1,084,034		—		—		(1,084,034		)	—
Intangible assets	—		372,621		34,737		—			407,358
Other assets	5,980		22,183		40,200		—			68,363
Total assets	$	2,145,270	$	2,112,451	$	1,346,018	$	(2,417,455	)	$	3,186,284
Liabilities and partners’ capital
Current liabilities	$	45,255	$	142,513	$	556,474	$	(62,930	)	$	681,312
Long-term debt	1,086,909		393,317		—		—			1,480,226
Intercompany notes payable	—		676,993		407,040		(1,084,033		)	—
Other long term liabilities	2,003		9,980		1,660		—			13,643
Total partners’ capital	1,011,103		889,648		380,844		(1,270,492		)	1,011,103
Total liabilities and partners’ capital	$	2,145,270	$	2,112,451	$	1,346,018	$	(2,417,455	)	$	3,186,284

F-49

	Year Ended December 31, 2005
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	453,398		$	8,168,657		$	(3,567	)	$	8,618,488
Costs and expenses	—		295,376			8,104,164			(3,567		)	8,395,973
Gains on sales of assets	—		(551		)	(117		)	—			(668		)
Operating income	—		158,573			64,610			—			223,183
Interest expense – net	—		(54,011		)	(27,850		)	—			(81,861		)
Equity earnings	162,551		57,088			23,078			(222,623		)	20,094
Other income – net	—		901			234			—			1,135
Net income	$	162,551	$	162,551		$	60,072		$	(222,623	)	$	162,551

	Year Ended December 31, 2004 (as restated)
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	430,162		$	5,531,237		$	(3,207	)	$	5,958,192
Costs and expenses	—		301,568			5,473,751			(3,207		)	5,772,112
Gains on sales of assets	—		(526		)	(527		)	—			(1,053		)
Operating income	—		129,120			58,013			—			187,133
Interest expense – net	—		(48,902		)	(23,151		)	—			(72,053		)
Equity earnings	138,548		57,454			28,692			(202,546		)	22,148
Other income – net	—		876			444			—			1,320
Net income	$	138,548	$	138,548		$	63,998		$	(202,546	)	$	138,548

	Year Ended December 31, 2003 (as restated)
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	399,504		$	3,858,243		$	(1,915	)	$	4,255,832
Costs and expenses	—		262,971			3,806,316			(1,915		)	4,067,372
Gain on sale of assets	—		—			(3,948		)	—			(3,948		)
Operating income	—		136,533			55,875			—			192,408
Interest expense – net	—		(52,903		)	(31,420		)	73			(84,250		)
Equity earnings	121,780		37,689			20,258			(166,853		)	12,874
Other income – net	—		461			360			(73		)	748
Net income	$	121,780	$	121,780		$	45,073		$	(166,853	)	$	121,780

F-50

	Year Ended December 31, 2005
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	162,551		$	162,551		$	60,072		$	(222,623	)	$	162,551
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			83,148			28,193			—			111,341
Earnings in equity investments, net of distributions	88,550			14,598			1,576			(87,733		)	16,991
Gains on sales of assets	—			(551		)	(117		)	—			(668		)
Changes in assets and liabilities and other	(54,540		)	(57,625		)	22,884			53,571			(35,710		)
Net cash provided by operating activities	196,561			202,121			112,608			(256,785		)	254,505
Cash flows from investing activities	(278,806		)	(31,529		)	(180,486		)	139,906			(350,915		)
Cash flows from financing activities	80,107			(184,126		)	65,097			119,029			80,107
Net increase in cash and cash equivalents	(2,138		)	(13,534		)	(2,781		)	2,150			(16,303		)
Cash and cash equivalents at beginning of period	4,116			13,596			2,826			(4,116		)	16,422
Cash and cash equivalents at end of period	$	1,978		$	62		$	45		$	(1,966	)	$	119

	Year Ended December 31, 2004 (as restated)
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	138,548		$	138,548		$	63,998		$	(202,546	)	$	138,548
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	—			90,048			22,846			—			112,894
Earnings in equity investments, net of distributions	94,509			(130		)	8,208			(77,522		)	25,065
Gains on sales of assets	—			(526		)	(527		)	—			(1,053		)
Changes in assets and liabilities and other	(158,726		)	29,679			(30,930		)	151,690			(8,287		)
Net cash provided by operating activities	74,331			257,619			63,595			(128,378		)	267,167
Cash flows from investing activities	98			(34,060		)	(40,864		)	(115,331		)	(190,157		)
Cash flows from financing activities	(90,057		)	(229,206		)	(25,575		)	254,781			(90,057		)
Net decrease in cash and cash equivalents	(15,628		)	(5,647		)	(2,844		)	11,072			(13,047		)
Cash and cash equivalents at beginning of period	19,744			19,243			5,670			(15,188		)	29,469
Cash and cash equivalents at end of period	$	4,116		$	13,596		$	2,826		$	(4,116	)	$	16,422

F-51

	Year Ended December 31, 2003 (as restated)
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	121,780		$	121,780		$	45,073		$	(166,853	)	$	121,780
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	—			80,114			20,614			—			100,728
Earnings in equity investments, net of distributions	80,718			7,548			2,482			(75,619		)	15,129
Gain on sale of assets	—			—			(3,948		)	—			(3,948		)
Changes in assets and liabilities and other	48,432			5,576			1,075			(46,348		)	8,735
Net cash provided by operating activities	250,930			215,018			65,296			(288,820		)	242,424
Cash flows from investing activities	(175,568		)	(178,682		)	(37,589		)	203,531			(188,308		)
Cash flows from financing activities	(55,618		)	(25,340		)	(44,758		)	70,101			(55,615		)
Net increase (decrease) in cash and cash equivalents	19,744			10,996			(17,051		)	(15,188		)	(1,499		)
Cash and cash equivalents at beginning of period	—			8,247			22,721			—			30,968
Cash and cash equivalents at end of period	$	19,744		$	19,243		$	5,670		$	(15,188	)	$	29,469

NOTE 20.RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

We are restating our previously reported consolidated financial statements for the fiscal years ended December 31, 2003 and 2004.  For the impact of the restated consolidated financial results for the quarterly periods during the years ended December 31, 2005 and 2004, see Note 21.  We have determined that our method of accounting for the $33.4 million excess investment in Centennial, previously described as an intangible asset with an indefinite life, and the $27.1 million excess investment in Seaway, previously described as equity method goodwill, was incorrect.  Through our accounting for these excess investments in Centennial and Seaway as intangible assets with indefinite lives and equity method goodwill, respectively, we have been testing the amounts for impairment on an annual basis as opposed to amortizing them over a determinable life.  We determined that it would be more appropriate to account for these excess investments as intangible assets with determinable lives.  As a result, we made non-cash adjustments that reduced the net value of the excess investments in Centennial and Seaway, and increased amortization expense allocated to our equity earnings.  The effect of this restatement caused a $3.8 million and $4.0 million reduction to net income as previously reported for the fiscal years ended December 31, 2004 and 2003, respectively.  As a result of the accounting correction, net income for the fiscal year ended December 31, 2005, includes a charge of $4.8 million, of which $3.8 million relates to the first nine months.  Additionally, partners’ capital at December 31, 2002, reflects a $2.5 million reduction representing the cumulative effect of this correction for fiscal years ended December 31, 2000 through 2002.

While we believe the impacts of these non-cash adjustments are not material to any previously issued financial statements, we determined that the cumulative adjustment for these non-cash items was too material to record in the fourth quarter of 2005, and therefore it was most appropriate to restate prior periods’ results.  These non-cash adjustments had no effect on our operating income, compensation expense, debt balances or ability to meet all requirements related to our debt facilities.  The restatement had no impact on total cash flows from operating activities, investing activities or financing activities.  All amounts in the accompanying consolidated financial statements have been adjusted for this restatement.

F-52

We will continue to amortize the $30.0 million excess investment in Centennial related to a contract using units-of-production methodology over a 10-year life.  The remaining $3.4 million related to a pipeline will continue to be amortized on a straight-line basis over 35 years.  We will continue to amortize the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to a pipeline.

The following tables summarize the impact of the restatement adjustment on previously reported balance sheet amounts for the year ended December 31, 2004, and income statement amounts and cash flow amounts for the years ended December 31, 2004 and 2003 (in thousands):

Balance Sheet Amounts;

	December 31, 2004
	As Previously Reported				Adjustment			As Restated
Equity investments	$		373,652		$	(10,345	)	$	363,307
Total assets	$	3,196,629			$	(10,345	)	$	3,186,284
Capital:
General partner’s interest	$	(33,006		)	$	(2,875	)	$	(35,881	)
Limited partners’ interest	1,054,454				(7,470		)	1,046,984
Total partners’ capital	1,021,448				(10,345		)	1,011,103
Total liabilities and partners’ capital	$	3,196,629			$	(10,345	)	$	3,186,284

Income Statement Amounts:

	Years Ended December 31,
	2004			2003
Equity earnings as previously reported	$	25,981		$	16,863
Adjustment for amortization of excess investments	(3,833		)	(3,989		)
Equity earnings as restated	$	22,148		$	12,874
Net income as previously reported	$	142,381		$	125,769
Adjustment for amortization of excess investments	(3,833		)	(3,989		)
Net income as restated	$	138,548		$	121,780
Net Income Allocation as previously reported:
Limited Partner Unitholders	$	101,307		$	89,191
Class B Unitholder	—			1,806
General Partner	41,074			34,772
Total net income allocated	$	142,381		$	125,769
Basic and diluted net income per Limited Partner and Class B Unit as previously reported	$	1.61		$	1.52
Net Income Allocation as restated:
Limited Partner Unitholders	$	98,580		$	86,357
Class B Unitholder	—			1,754
General Partner	39,968			33,669
Total net income allocated as restated	$	138,548		$	121,780
Basic and diluted net income per Limited Partner and Class B Unit as restated	$	1.56		$	1.47

F-53

Cash Flow Amounts;

	Year Ended December 31, 2004
	As Previously Reported		Adjustment			As Restated
Cash flows from operating activities:
Net income	$	142,381	$	(3,833	)	$	138,548
Earnings in equity investments, net of distributions	21,232		3,833			25,065

	Year Ended December 31, 2003
	As Previously Reported		Adjustment			As Restated
Cash flows from operating activities:
Net income	$	125,769	$	(3,989	)	$	121,780
Earnings in equity investments, net of distributions	11,140		3,989			15,129

Partners’ Capital Amounts:

	Outstanding Limited Partner Units	General Partner’s Interest			Limited Partners’ Interests			Accumulated Other Comprehensive Loss			Total
2002:
Partners’ capital at December 31, 2002 as previously reported	53,809,597	$	12,770		$	899,127		$	(20,055	)	$	891,842
Restatement adjustment	—	(666		)	(1,727		)	—			(2,393		)
Partners’ capital at December 31, 2002 as restated (unaudited)	53,809,597	$	12,104		$	897,400		$	(20,055	)	$	889,449
2003:
Partners’ capital at December 31, 2003 as previously reported	62,998,554	$	(7,181	)	$	1,119,404		$	(2,902	)	$	1,109,321
Restatement adjustment	—	(1,769		)	(4,743		)	—			(6,512		)
Partners’ capital at December 31, 2003 as restated	62,998,554	$	(8,950	)	$	1,114,661		$	(2,902	)	$	1,102,809
2004:
Partners’ capital at December 31, 2004 as previously reported	62,998,554	$	(33,006	)	$	1,054,454		$	—		$	1,021,448
Restatement adjustment	—	(2,875		)	(7,470		)	—			(10,345		)
Partners’ capital at December 31, 2004 as restated	69,963,554	$	(35,881	)	$	1,046,984		$	—		$	1,011,103

F-54

NOTE 21.QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(as restated)			(as restated)			(as restated)			(as restated)
	(in thousands, except per Unit amounts)
2005
Operating revenues	$	1,526,605		$	2,090,380		$	2,503,796		$	2,497,707
Operating income	62,356			54,663			44,070			62,094
Net income as previously reported	$	48,581		$	42,233		$	30,923		$	44,625
Restatement adjustment	(1,152		)	(1,311		)	(1,348		)	—
Net income as restated (1)	$	47,429		$	40,922		$	29,575		$	44,625
Basic and diluted income per Limited Partner Unit as previously reported (2)(3)	$	0.55		$	0.45		$	0.31		$	0.45
Restatement adjustment	(0.01		)	(0.02		)	(0.01		)	—
Basic and diluted income per Limited Partner Unit as restated (1)(2)(3)	$	0.54		$	0.43		$	0.30		$	0.45
2004
Operating revenues	$	1,318,061		$	1,354,564		$	1,490,010		$	1,795,557
Operating income	53,901			42,401			37,081			53,750
Net income as previously reported	$	40,433		$	37,759		$	25,855		$	38,334
Restatement adjustment	(713		)	(1,129		)	(1,085		)	(906		)
Net income as restated (1)	$	39,720		$	36,630		$	24,770		$	37,428
Basic and diluted income per Limited Partner Unit as previously reported	$	0.46		$	0.43		$	0.29		$	0.43
Restatement adjustment	(0.01		)	(0.02		)	(0.01		)	(0.01		)
Basic and diluted income per Limited Partner Unit as restated (1)	$	0.45		$	0.41		$	0.28		$	0.42

(1)The quarterly financial information for 2004 and the first three quarters of 2005 reflect the impact of the restatement.

(2)The sum of the four quarters does not equal the total year due to rounding.

(3)Per Unit calculation includes 6,965,000 Units issued in May and June 2005.

NOTE 22.SUBSEQUENT EVENTS

In January 2006, we entered into interest rate swaps with a total notional amount of $200.0 million, whereby we will receive a floating rate of interest and will pay a fixed rate of interest for a two-year term.  These interest rate swaps were executed to decrease the exposure to potential increases in floating interest rates.  Using the balances of outstanding debt at December 31, 2005, these interest rate swaps decrease the level of floating interest rate debt from 41% to 29% of total outstanding debt.

On January 26, 2006, we announced the execution of a letter of intent to sell our ownership interest in the Pioneer silica gel natural gas processing plant located in Opal, Wyoming, to an affiliate of Enterprise Products Partners L.P., including all of Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields.  The proposed sale of the Pioneer plant is subject to the execution of definitive agreements and to regulatory approvals.  The proposed sale is expected to be completed by the middle of 2006.  The Pioneer plant is not an integral part of our Midstream Segment operations, and natural gas processing is not a core business.  The anticipated sales proceeds would be used to fund organic growth projects, retire debt, or for other general partnership purposes.  The carrying value of the Pioneer plant at December 31, 2005, was $19.8 million.

F-55

On February 13, 2006, we and an affiliate of Enterprise Products Partners L.P. (“Enterprise”) entered into a letter agreement related to an additional expansion (the “Jonah Expansion”) of the Jonah system (the “Letter Agreement”).  The Jonah Expansion will consist of the installation of approximately 90,000 horsepower of gas turbine compression at a new compression station, related new piping and certain related facilities, which is expected to increase capacity of the Jonah system from 1.5 billion cubic feet per day to 2.0 billion cubic feet per day.  We expect to enter into a joint venture (“Joint Venture”) agreement with Enterprise relating to the construction and financing of the Jonah Expansion.  Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million).  Such advance will constitute a subscription for an equity interest in the proposed Joint Venture (the “Subscription”).  We expect the Jonah Expansion to be put into service in late 2006.  We have the option to return to Enterprise up to 100% of the amount of the Subscription.  If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly.  The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.

F-56

EX-10.52

Exhibit 10.52

AGREEMENT AND RELEASE

This Agreement and Release (“Agreement”) is between Barry R. Pearl (“EMPLOYEE”) and Texas Eastern Products Pipeline Company, LLC (“COMPANY”).

WITNESSETH

1.             Whereas, EMPLOYEE and COMPANY entered into an employment agreement on February 12, 2001 (hereinafter ^“Employment Agreement”), and various supplemental agreements dated February 23, 2005, June 1, 2005 (hereinafter mutually called the “Supplemental Agreements”).

2.             Whereas, EMPLOYEE is retiring from the COMPANY effective December 31, 2005, subject to Section 1 below.

3.             Whereas, EMPLOYEE and COMPANY desire to resolve any and all disputes about EMPLOYEE’s entitlement to severance benefits under the Employment Agreement.

4.             Whereas, EMPLOYEE, during his employment had access to trade secrets and/or proprietary and confidential information belonging to the COMPANY.

5.             Whereas, EMPLOYEE and COMPANY desire to clarify EMPLOYEE’s obligations with respect to any trade secrets and/or proprietary and confidential information acquired during EMPLOYEE’s employment.

6.             Whereas, EMPLOYEE and the COMPANY desire to avoid the expense, delay and uncertainty attendant to any claims which may arise from EMPLOYEE’s employment with and retirement from the COMPANY, the Employment Agreement, or the Supplemental Agreement, as well as any claims which may arise from the disclosure of any trade secrets and/or proprietary and confidential information that EMPLOYEE acquired during his employment with the Company.

7.             Whereas, EMPLOYEE desires to release any claims or causes of action EMPLOYEE may have arising from EMPLOYEE’s employment with, or his retirement from the COMPANY, including any claims or causes of action arising out of his Employment Agreement or Supplemental Agreement.

Now, therefore, for and in consideration of the mutual covenants and promises hereinafter set forth, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, EMPLOYEE and the COMPANY hereby agree:

1

Section 1.               Severance and Other Payments. The COMPANY, in exchange for the promises of EMPLOYEE contained below, agrees as follows:

A.            COMPANY agrees to pay EMPLOYEE the lump sum amount of $1,512,326.58 less legal standard deductions. This amount represents three (3) times EMPLOYEE’s base salary plus three (3) times his target bonus. The payment will be made within seven (7) days after the expiration of the EMPLOYEE’s revocation option in Section 5(C) below.

B.            COMPANY agrees to pay COBRA insurance premiums (medical and/or dental) for up to 36 months, as set forth in the Supplemental Agreement. In the event that EMPLOYEE’s entitlement to COBRA coverage should cease before that time (as set forth in the Supplemental Agreement), COMPANY will have no obligation to continue payment of EMPLOYEE’s COBRA premiums.

C.            COMPANY agrees that EMPLOYEE shall receive (less applicable legal standard deductions in each case, if any) an amount of $49,683.80, as liquidated unused vacation days and the following payments pursuant to the following plans:

1.             COMPANY’s 2000 Long Term Compensation Plan: $325,322.00

2.             COMPANY’s Management Incentive Compensation Plan:  EMPLOYEE shall be paid his MICP bonus for 2005, determined as per the terms of the plan document (as applicable to all other participants), provided that the personal performance portion (25% of total bonus at the target award level) shall be determined as equal to the target.  Payment shall occur as and when 2005 MICP payments are made generally.

D.            COMPANY agrees that EMPLOYEE shall also receive all amounts accrued for the benefit of EMPLOYEE, which, except as otherwise provided below, shall be payable (if not already paid) as soon as administratively possible after December 31, 2005, pursuant to the following plans, subject to EMPLOYEE’s (and his spouse’s, if applicable) completion of all necessary election forms and documentation which may be required. All such amounts accrued and payable shall be calculated and determined by Hewitt & Associates, actuary for the plans. EMPLOYEE is hereby electing to take a lump sum payment representing his entire benefit under the COMPANY’s Supplemental Benefit Plan, notwithstanding any prior election regarding the form of such benefit payment which EMPLOYEE may have made.

1.             COMPANY’ s Retirement Cash Balance Plan; and

2.             COMPANY’s Supplemental Benefit Plan

The benefit under the Company’s Supplemental Benefits Plan will be paid before December 31, 2005.

 E.            COMPANY acknowledges and agrees that EMPLOYEE shall remain covered by COMPANY’S or any affiliates’, as applicable, Directors and Officers Errors and Omissions Liability Insurance on the same basis as applicable to other officers of the Company (or any successor) in regard to claims pertaining to the time when EMPLOYEE was employed by the

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COMPANY or was a director of the Company.  EMPLOYEE shall continue to be indemnified by the COMPANY, or any affiliates thereof as applicable, in regard to any claims pertaining to the time when EMPLOYEE was employed by or a director of the COMPANY, on the same basis as in effect immediately prior to his termination.

Section 2.               Prior Rights and Obligations_,. Except as provided for in this Agreement, this Agreement extinguishes all rights, if any, which EMPLOYEE may have, contractual or otherwise, relating to his employment with, or retirement from the COMPANY, including any rights to severance benefits under the Employment Agreement or Supplemental Agreement.

Section 3.Retirement. EMPLOYEE agrees that his retirement date is December 31, 2005.

Section 4.               Release. Except for obligations of the COMPANY created in this Agreement, EMPLOYEE hereby releases and discharges the COMPANY and all affiliated companies, and their officers, directors, employees, agents, attorneys, and insurers, from any and all claims, demands and causes of action arising from his employment at the COMPANY or such affiliate and his retirement from the COMPANY or such affiliate, including, but not limited to, any claims or causes of action under the Age Discrimination in Employment Act (ADEA).

Section 5.               ADEA Rights. EMPLOYEE further acknowledges that:

A.          He has been advised in writing by virtue of this AGREEMENT that he has the right to seek legal counsel before signing this AGREEMENT.

B.           He has been given twenty-one (21) days within which to consider the waivers included in this AGREEMENT. If EMPLOYEE chooses to sign the AGREEMENT at any time prior to that date, it is agreed that EMPLOYEE signs willingly and voluntarily and expressly waives his right to wait the entire twenty-one (21) day period as provided in the law.

C.           EMPLOYEE has seven (7) days after signing this AGREEMENT to revoke it. This Agreement will not become effective or enforceable until the revocation period has expired. Any notice of revocation of the AGREEMENT is effective only if given to James Ruth, Esq., General Counsel (at the address of the COMPANY set forth below), in writing by the close of business at 4:30 p.m. on the seventh (7^th) day after the signing of this AGREEMENT.

D.          EMPLOYEE agrees that he is receiving, pursuant to this Agreement, consideration which is in addition to that which he is already entitled to under the Employment Agreement and the Supplemental Agreement or otherwise.

Section 6.               Proprietary and Confidential Information. EMPLOYEE agrees and acknowledges that, because of his employment with the COMPANY, he has acquired information regarding the COMPANY’s trade secrets and/or proprietary and confidential information related to the COMPANY’s past, present or anticipated business. Therefore, except as may be required by law, EMPLOYEE acknowledges that EMPLOYEE will not, at any time, disclose to others, permit to be disclosed, used, permit to be used, copy or permit to be copied, any trade secrets and/or proprietary and confidential information acquired during his employment with the COMPANY unless such information has ceased to be confidential other than through an action of the Employee in violation of this paragraph. EMPLOYEE agrees that in the event of an actual breach by EMPLOYEE of the provisions of this paragraph, the COMPANY shall be entitled to inform all potential or new employers of this AGREEMENT.

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Section 7.               Non-solicitation of COMPANY’s employees and customers. EMPLOYEE agrees not to solicit or help solicit any employees or customers of the COMPANY or any affiliated entity to cease employment or cease doing business with the COMPANY or any affiliated entity.

Section 8.               Amendments. This AGREEMENT may only be amended in writing signed by EMPLOYEE and an authorized officer of the COMPANY.

Section 9.               Confidentiality, EMPLOYEE agree that he or any persons acting on his behalf will not, directly or indirectly, speak about, disclose or in any way, shape or form communicate to anyone, except as permitted in this Section, the terms of this AGREEMENT or the consideration received from the COMPANY. EMPLOYEE agrees that the above described information may be disclosed only as follows:

A.            to the extent as may be required by law to support the filing of EMPLOYEE’S income tax returns;

B.            to the extent as may be compelled by legal process;

C.            to the extent necessary to EMPLOYEE’s legal or financial advisors, but only after such person to whom the disclosure is to be made agrees to maintain the confidentiality of such information and to refrain from making further disclosures or use of such information.

D.            to the extent necessary to enforce or comply with this AGREEMENT.

Section 10.             Non-disparagement. EMPLOYEE and the COMPANY shall jointly draft a press release regarding EMPLOYEES retirement, which release shall be reasonably acceptable to EMPLOYEE; provided, however, the COMPANY reserves the right to timely comply with applicable securities laws regarding said press release in the event the EMPLOYEE and COMPANY fail to mutually agree. EMPLOYEE agrees that he will not disparage, criticize, condemn or impugn the business or personal reputation or character of the COMPANY or any affiliated company, or any present or former COMPANY employees or board members, or any employees or board members of any affiliated companies, or any of the actions which are, have been or may be taken by the COMPANY with respect to or based upon matters, events, facts or circumstances arising or occurring prior to the date of execution of this AGREEMENT. In response to inquiries by potential employers, EMPLOYEE may respond that he retired. Further inquiries by a potential employer shall be met with advice of the dates of EMPLOYEE’s employment, his job title and functions in factually accurate terms.  Any such response shall be consistent with the press release.  The COMPANY shall have no obligation to respond to any inquiries from prospective employers unless they are made in writing and addressed specifically to the COMPANY and in response to such inquiries shall not be obligated to provide any information other than to confirm dates of employment and job title. COMPANY shall not make any unfavorable or unflattering statements about the EMPLOYEE. COMPANY agrees that it will not disparage, criticize, condemn or impugn the business or personal reputation or character of the EMPLOYEE.

Section 11.             Cooperation. EMPLOYEE shall cooperate with the COMPANY to the extent reasonably required by the COMPANY in all matters relating to the winding up of his pending work on behalf of the Company and the orderly transfer of any such pending work. COMPANY hereby agrees to indemnify EMPLOYEE in connection with all such lawful actions which EMPLOYEE shall take after the effective date hereof in performing such cooperation requested by

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the COMPANY. EMPLOYEE agrees to immediately notify the COMPANY, if he is served with legal process to compel him to disclose any information related to his employment with the Company, unless prohibited to do so by law.

Section 12.             Documents. EMPLOYEE agrees to deliver at the termination of employment all correspondence, memoranda, notes, records, data, or information, analysis, or other documents and all copies thereof, including information in electronic form, which are related in any manner to the past, present or anticipated business of the COMPANY or its affiliated companies.

Section 13.             Enforcement of Agreement and Release. Should any provisions of this AGREEMENT be held to be invalid or wholly or partially unenforceable, such holdings shall not invalidate or void the remainder of this AGREEMENT. Portions held to be invalid or unenforceable shall be revised and reduced in scope as to be valid and enforceable, or if such is not possible, then such portion shall be deemed to have been wholly excluded with the same force and effect as if they had never been included herein.

Section 14.             Notices. Any notice, request, demand, waiver or consent required or permitted hereunder shall be in writing and shall be given by prepaid registered or certified mail, with return receipt requested, addressed as follows:

For the COMPANY:

Texas Eastern Products Pipeline Company, LLC

P.O. Box 2521

Houston, Texas 77252-2521

Attn: Chief Executive Officer

With a copy to the General Counsel

For the EMPLOYEE:

Barry R. Pearl

[Address]

The date of any such notice and of such service thereof shall be deemed to be the date of mailing. Each party may change its address for the purpose of notice by giving notice to the other in writing.

Section 15.             Choice of Law. It is agreed that the laws of Texas shall govern this AGREEMENT.

Section 16.             Remedies. The Parties agree that because damages at law for any breach or nonperformance of this AGREEMENT by EMPLOYEE, while recoverable, will be inadequate, this AGREEMENT may be enforced in equity by specific performance, injunction, or otherwise. Should any provisions of this AGREEMENT be held to be invalid, such holdings shall not invalidate or void the remainder of this AGREEMENT. EMPLOYEE shall be entitled to enforce his rights and the COMPANY’s obligations under this Agreement by any and all applicable actions at law or equity.

Section 17. Announcement. EMPLOYEE shall be entitled to review and comment upon the 8K Notice of his retirement and any press release by the COMPANY of his retirement.

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IN WITNESS WHEREOF THE PARTIES HAVE EXECUTED THIS AGREEMENT AND RELEASE AS OF DECEMBER 31, 2005.

By:		/s/ BARRY R. PEARL
		Barry R. Pearl
DATE:						December 30, 2005
TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC
By:	/s/ JAMES C. RUTH
Name:				/s/ James C. Ruth
Title:			Senior Vice President
DATE:					December 30, 2005

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EX-10.53

Exhibit 10.53

AGREEMENT AND RELEASE

This Agreement and Release (“Agreement”) is between James C. Ruth (“EMPLOYEE”) and Texas Eastern Products Pipeline Company, LLC (“COMPANY”).

WITNESSETH

1.             Whereas, EMPLOYEE and COMPANY entered into an employment agreement on December 22, 1998 (hereinafter ^“Employment Agreement”), and various supplemental agreements dated February 23, 2005, and June 1, 2005 (hereinafter mutually called the “Supplemental Agreements”).

2.             Whereas, EMPLOYEE is retiring from the COMPANY effective February 28, 2006, subject to Section 1 below.

3.             Whereas, EMPLOYEE and COMPANY desire to resolve any and all disputes about EMPLOYEE’s entitlement to severance benefits under the Employment Agreement.

4.             Whereas, EMPLOYEE, during his employment had access to trade secrets and/or proprietary and confidential information belonging to the COMPANY.

5.             Whereas, EMPLOYEE and COMPANY desire to clarify EMPLOYEE’s obligations with respect to any trade secrets and/or proprietary and confidential information acquired during EMPLOYEE’s employment.

6.             Whereas, EMPLOYEE and the COMPANY desire to avoid the expense, delay and uncertainty attendant to any claims which may arise from EMPLOYEE’s employment with and retirement from the COMPANY, the Employment Agreement, or the Supplemental Agreement, as well as any claims which may arise from the disclosure of any trade secrets and/or proprietary and confidential information that EMPLOYEE acquired during his employment with the Company.

7.             Whereas, EMPLOYEE desires to release any claims or causes of action EMPLOYEE may have arising from EMPLOYEE’s employment with, or his retirement from the COMPANY, including any claims or causes of action arising out of his Employment Agreement or Supplemental Agreement.

Now, therefore, for and in consideration of the mutual covenants and promises hereinafter set forth, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, EMPLOYEE and the COMPANY hereby agree:

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Section 1.               Severance and Other Payments. The COMPANY, in exchange for the promises of EMPLOYEE contained below, agrees as follows:

A.            COMPANY agrees to pay EMPLOYEE the lump sum amount of $1,058,929.71 less legal standard deductions. This amount represents three (3) times EMPLOYEE’s base salary plus three (3) times his target bonus. The payment will be made within seven (7) days after the later of (i) the expiration of the EMPLOYEE’s revocation option in Section 5(C) below or (ii) EMPLOYEE’S retirement on February 28, 2006.

B.            COMPANY agrees to pay COBRA insurance premiums (medical and/or dental) for up to 36 months, as set forth in the Supplemental Agreement. In the event that EMPLOYEE’s entitlement to COBRA coverage should cease before that time (as set forth in the Supplemental Agreement), COMPANY will have no obligation to continue payment of EMPLOYEE’s COBRA premiums.

C.            COMPANY agrees that EMPLOYEE shall receive (less applicable legal standard deductions in each case, if any) an amount of $32,769.71, as liquidated unused vacation days and the following payments pursuant to the following plans:

1.             COMPANY’s 1994 Long Term Compensation Plan:  $16,241.00; and

2.             COMPANY’s 2000 Long Term Compensation Plan: $98,832.00.

D.            COMPANY agrees that EMPLOYEE shall also receive all amounts accrued for the benefit of EMPLOYEE, which, except as otherwise provided below, shall be payable (if not already paid) as soon as administratively possible after February 28, 2006, pursuant to the following plan, subject to EMPLOYEE’s (and his spouse’s, if applicable) completion of all necessary election forms and documentation which may be required. All such amounts accrued and payable shall be calculated and determined by Hewitt & Associates, actuary for the plans.

1.             COMPANY’ s Retirement Cash Balance Plan.

E.             COMPANY acknowledges and agrees that EMPLOYEE shall remain covered by COMPANY’S or any affiliates’, as applicable, Directors and Officers Errors and Omissions Liability Insurance on the same basis as applicable to other officers of the Company (or any successor) in regard to claims pertaining to the time when EMPLOYEE was employed by the COMPANY or was a director of the Company.  EMPLOYEE shall continue to be indemnified by the COMPANY, or any affiliates thereof as applicable, in regard to any claims pertaining to the time when EMPLOYEE was employed by or a director of the COMPANY, on the same basis as in effect immediately prior to his termination.

Section 2.               Prior Rights and Obligations_,. Except as provided for in this Agreement, this Agreement extinguishes all rights, if any, which EMPLOYEE may have, contractual or otherwise, relating to his employment with, or retirement from the COMPANY, including any rights to severance benefits under the Employment Agreement or Supplemental Agreement.

Section 3.               Retirement. EMPLOYEE agrees that his retirement date is February 28, 2006.

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Section 4.               Release. Except for obligations of the COMPANY created in this Agreement, EMPLOYEE hereby releases and discharges the COMPANY and all affiliated companies, and their officers, directors, employees, agents, attorneys, and insurers, from any and all claims, demands and causes of action arising from his employment at the COMPANY or such affiliate and his retirement from the COMPANY or such affiliate, including, but not limited to, any claims or causes of action under the Age Discrimination in Employment Act (ADEA).

Section 5.               ADEA Rights. EMPLOYEE further acknowledges that:

A.          He has been advised in writing by virtue of this AGREEMENT that he has the right to seek legal counsel before signing this AGREEMENT.

B.           He has been given twenty-one (21) days within which to consider the waivers included in this AGREEMENT. If EMPLOYEE chooses to sign the AGREEMENT at any time prior to that date, it is agreed that EMPLOYEE signs willingly and voluntarily and expressly waives his right to wait the entire twenty-one (21) day period as provided in the law.

C.           EMPLOYEE has seven (7) days after signing this AGREEMENT to revoke it. This Agreement will not become effective or enforceable until the revocation period has expired. Any notice of revocation of the AGREEMENT is effective only if given to William G. Manias, Chief Financial Officer (at the address of the COMPANY set forth below), in writing by the close of business at 4:30 p.m. on the seventh (7^th) day after the signing of this AGREEMENT.

D.          EMPLOYEE agrees that he is receiving, pursuant to this Agreement, consideration which is in addition to that which he is already entitled to under the Employment Agreement and the Supplemental Agreement or otherwise.

Section 6.               Proprietary and Confidential Information. EMPLOYEE agrees and acknowledges that, because of his employment with the COMPANY, he has acquired information regarding the COMPANY’s trade secrets and/or proprietary and confidential information related to the COMPANY’s past, present or anticipated business. Therefore, except as may be required by law, EMPLOYEE acknowledges that EMPLOYEE will not, at any time, disclose to others, permit to be disclosed, used, permit to be used, copy or permit to be copied, any trade secrets and/or proprietary and confidential information acquired during his employment with the COMPANY unless such information has ceased to be confidential other than through an action of the Employee in violation of this paragraph. EMPLOYEE agrees that in the event of an actual breach by EMPLOYEE of the provisions of this paragraph, the COMPANY shall be entitled to inform all potential or new employers of this AGREEMENT.

Section 7.               Non-solicitation of COMPANY’s employees and customers. EMPLOYEE agrees not to solicit or help solicit any employees or customers of the COMPANY or any affiliated entity to cease employment or cease doing business with the COMPANY or any affiliated entity.

Section 8.               Amendments. This AGREEMENT may only be amended in writing signed by EMPLOYEE and an authorized officer of the COMPANY.

Section 9.               Confidentiality, EMPLOYEE agree that he or any persons acting on his behalf will not, directly or indirectly, speak about, disclose or in any way, shape or form communicate to anyone, except as permitted in this Section, the terms of this AGREEMENT or the consideration received from the COMPANY. EMPLOYEE agrees that the above described information may be disclosed only as follows:

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A.            to the extent as may be required by law to support the filing of EMPLOYEE’S income tax returns;

B.            to the extent as may be compelled by legal process;

C.            to the extent necessary to EMPLOYEE’s legal or financial advisors, but only after such person to whom the disclosure is to be made agrees to maintain the confidentiality of such information and to refrain from making further disclosures or use of such information.

D.            to the extent necessary to enforce or comply with this AGREEMENT.

Section 10.             Non-disparagement. EMPLOYEE and the COMPANY shall jointly draft a press release regarding EMPLOYEES retirement, which release shall be reasonably acceptable to EMPLOYEE; provided, however, the COMPANY reserves the right to timely comply with applicable securities laws regarding said press release in the event the EMPLOYEE and COMPANY fail to mutually agree. EMPLOYEE agrees that he will not disparage, criticize, condemn or impugn the business or personal reputation or character of the COMPANY or any affiliated company, or any present or former COMPANY employees or board members, or any employees or board members of any affiliated companies, or any of the actions which are, have been or may be taken by the COMPANY with respect to or based upon matters, events, facts or circumstances arising or occurring prior to the date of execution of this AGREEMENT. In response to inquiries by potential employers, EMPLOYEE may respond that he retired. Further inquiries by a potential employer shall be met with advice of the dates of EMPLOYEE’s employment, his job title and functions in factually accurate terms.  Any such response shall be consistent with the press release.  The COMPANY shall have no obligation to respond to any inquiries from prospective employers unless they are made in writing and addressed specifically to the COMPANY and in response to such inquiries shall not be obligated to provide any information other than to confirm dates of employment and job title. COMPANY shall not make any unfavorable or unflattering statements about the EMPLOYEE. COMPANY agrees that it will not disparage, criticize, condemn or impugn the business or personal reputation or character of the EMPLOYEE.

Section 11.             Cooperation. EMPLOYEE shall cooperate with the COMPANY to the extent reasonably required by the COMPANY in all matters relating to the winding up of his pending work on behalf of the Company and the orderly transfer of any such pending work. COMPANY hereby agrees to indemnify EMPLOYEE in connection with all such lawful actions which EMPLOYEE shall take after the effective date hereof in performing such cooperation requested by the COMPANY. EMPLOYEE agrees to immediately notify the COMPANY, if he is served with legal process to compel him to disclose any information related to his employment with the Company, unless prohibited to do so by law.

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Section 12.             Documents. EMPLOYEE agrees to deliver at the termination of employment all correspondence, memoranda, notes, records, data, or information, analysis, or other documents and all copies thereof, including information in electronic form, which are related in any manner to the past, present or anticipated business of the COMPANY or its affiliated companies.

Section 13.             Enforcement of Agreement and Release. Should any provisions of this AGREEMENT be held to be invalid or wholly or partially unenforceable, such holdings shall not invalidate or void the remainder of this AGREEMENT. Portions held to be invalid or unenforceable shall be revised and reduced in scope as to be valid and enforceable, or if such is not possible, then such portion shall be deemed to have been wholly excluded with the same force and effect as if they had never been included herein.

Section 14.             Notices. Any notice, request, demand, waiver or consent required or permitted hereunder shall be in writing and shall be given by prepaid registered or certified mail, with return receipt requested, addressed as follows:

For the COMPANY:

Texas Eastern Products Pipeline Company, LLC

P.O. Box 2521

Houston, Texas 77252-2521

Attn: Chief Executive Officer

With a copy to the General Counsel

For the EMPLOYEE:

James C. Ruth

[Address]

The date of any such notice and of such service thereof shall be deemed to be the date of mailing. Each party may change its address for the purpose of notice by giving notice to the other in writing.

Section 15.             Choice of Law. It is agreed that the laws of Texas shall govern this AGREEMENT.

Section 16.             Remedies. The Parties agree that because damages at law for any breach or nonperformance of this AGREEMENT by EMPLOYEE, while recoverable, will be inadequate, this AGREEMENT may be enforced in equity by specific performance, injunction, or otherwise. Should any provisions of this AGREEMENT be held to be invalid, such holdings shall not invalidate or void the remainder of this AGREEMENT. EMPLOYEE shall be entitled to enforce his rights and the COMPANY’s obligations under this Agreement by any and all applicable actions at law or equity.

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Section 17. Announcement. EMPLOYEE shall be entitled to review and comment upon the 8K Notice of his retirement and any press release by the COMPANY of his retirement.

IN WITNESS WHEREOF THE PARTIES HAVE EXECUTED THIS AGREEMENT AND RELEASE AS OF JANUARY 25, 2006.

By.	/s/ JAMES C. RUTH			January 25, 2006
James C. Ruth				DATE
TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC
By:	/s/ LEE W. MARSHALL, SR.			January 25, 2006
Name:			Lee W. Marshall, Sr.	DATE
Title:		Chairman and Chief Executive Officer

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EX-10.55

Exhibit 10.55

Director Compensation Summary

Each non-employee director of our General Partner is reimbursed for any travel, lodging and other out-of-pocket expenses related to meeting attendance or otherwise related to service on the board (including, without limitation, reimbursement for continuing education expenses). Each non-employee director who is not the chairman of a committee receives an annual retainer of $50,000. The chairman of the Audit and Conflicts Committee receives an annual retainer of $60,000, and the chairman of the Board receives an annual retainer of $300,000. One twelfth of each of these annual retainers is paid on a monthly basis to the appropriate board member. Directors who are either officers or full-time employees of DFI, EPCO, or the General Partner or any of their affiliates are not compensated for their services as directors.

EX-10.56

Exhibit 10.56

WAIVER OF PROVISIONS OF THE

CONFLICTS POLICIES AND PROCEDURES OF THE
THIRD AMENDED AND RESTATED
ADMINISTRATIVE SERVICES AGREEMENT

Effective as of February 13, 2006, each of the undersigned hereby waive the provisions of the Conflicts Policies and Procedures to the Third Amended and Restated Administrative Services Agreement dated August 15, 2005, to the extent that they prohibit or restrict (i) a majority of the members of the boards of directors any of Texas Eastern Products Pipeline Company, LLC, EPE Holdings, LLC and Enterprise Products GP, LLC (the “Affected Entities”) being non-independent directors or (ii) any person from serving as a director of more than one of the boards of directors of the Affected Entities, with respect to the election, whether prior to, on or after the date hereof, as a director of, and/or a member (including a chairman) of a committee of the boards of directors of, more than one of the Affected Entities, of Richard S. Snell, Dan L. Duncan, Robert G. Phillips, Michael A. Creel, W. Randall Fowler and/or Richard H. Bachmann.

IN WITNESS WHEREOF, the undersigned have caused this waiver to be duly executed by their respective authorized officers as of February 24, 2006, to be effective as of February 13, 2006.

EPCO, INC. (formerly known as Enterprise Products Company, a Texas corporation)
By:	/s/ RICHARD H. BACHMANN
	Richard H. Bachmann
	Executive Vice President and
	Chief Legal Officer
ENTERPRISE GP HOLDINGS L.P.
EPE HOLDINGS, LLC,
Individually and as Sole General Partner of
Enterprise GP Holdings L.P.
By:	/s/ W. RANDALL FOWLER
	W. Randall Fowler
	Senior Vice President and
	Chief Financial Officer
ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
ENTERPRISE PRODUCTS GP, LLC,
Individually and as Sole General Partner of
Enterprise Products Partners L.P., and
ENTERPRISE PRODUCTS OLPGP, INC.,
Individually and as Sole General Partner of
Enterprise Products Operating L.P.
By:	/s/ W. RANDALL FOWLER
	W. Randall Fowler
	Senior Vice President and Treasurer

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TEPPCO PARTNERS, L.P.
TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC,
Individually and as Sole General Partner of TEPPCO Partners, L.P.
By:	/s/ WILLIAM G. MANIAS
	William G. Manias
	Vice President and Chief Financial Officer
TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP
TEPPCO MIDSTREAM COMPANIES, L.P.
TCTM, L.P.
TEPPCO GP, Inc.,
Individually and as Sole General Partner of TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P. and TCTM, L.P.
By:	/s/ WILLIAM G. MANIAS
	William G. Manias
	Vice President and Chief Financial Officer

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EX-12.1

Exhibit 12.1

Statement of Computation of Ratio of Earnings to Fixed Charges

	2001		2002		2003		2004		2005
	(as restated)		(as restated)		(as restated)		(as restated)
					(in thousands)
Earnings
Income From Continuing Operations *	92,533		105,882		104,958		115,347		141,789
Fixed Charges	68,217		73,381		93,294		80,695		93,414
Distributed Income of Equity Investment	40,800		30,938		28,003		47,213		37,085
Capitalized Interest	(4,000	)	(4,345	)	(5,290	)	(4,227	)	(6,759	)
Total Earnings	197,550		205,856		220,965		239,028		265,529
Fixed Charges
Interest Expense	62,057		66,192		84,250		72,053		81,861
Capitalized Interest	4,000		4,345		5,290		4,227		6,759
Rental Interest Factor	2,160		2,844		3,754		4,415		4,794
Total Fixed Charges	68,217		73,381		93,294		80,695		93,414
Ratio: Earnings / Fixed Charges	2.90		2.81		2.37		2.96		2.84

*Excludes minority interest, extraordinary loss, gain on sale of assets and undistributed equity earnings.

EX-21

Exhibit 21

Subsidiaries of the Partnership

TEPPCO Partners, L.P. (Delaware)

TEPPCO GP, Inc. (Delaware)

TE Products Pipeline Company, Limited Partnership (Delaware)

TEPPCO Terminals Company, L.P. (Delaware)

TEPPCO Interests, LLC (Delaware)

TG Pipeline GP, LLC (Delaware)

TG Pipeline LP, LLC (Delaware)

TP Pipeline, L.P. (Texas)

TEPPCO Colorado, LLC (Delaware)

TEPPCO Midstream Companies, L.P. (Delaware)

TEPPCO NGL Pipelines, LLC (Delaware)

Chaparral Pipeline Company, L.P. (Delaware)

Quanah Pipeline Company, L.P. (Delaware)

Panola Pipeline Company, L.P. (Delaware)

Dean Pipeline Company, L.P. (Delaware)

Wilcox Pipeline Company, L.P. (Delaware)

Val Verde Gas Gathering Company, L.P. (Delaware)

Jonah Gas Gathering Company (Wyoming general partnership)

Jonah Gas Marketing, LLC (Delaware)

TCTM, L.P. (Delaware)

TEPPCO Crude GP, LLC (Delaware)

TEPPCO Crude Pipeline, L.P. (Delaware)

TEPPCO Seaway, L.P. (Delaware)

TEPPCO Crude Oil, L.P. (Delaware)

Lubrication Services, L.P. (Delaware)

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Partners of

TEPPCO Partners, L.P.:

We consent to the incorporation by reference in the registration statement (No. 333-110207) on Form S-3, the registration statement (No. 33-81976) on Form S-3, and the registration statement (No. 333-82892) on Form S-8 of TEPPCO Partners, L.P. of our reports dated February 28, 2006, with respect to the consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2005 and 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005, and  management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, and the effectiveness of internal control over financial reporting as of December 31, 2005, which appear in the December 31, 2005 annual report on Form 10-K of TEPPCO Partners, L.P.

Our report dated February 28, 2006, with respect to the consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2005 and 2004 and the related consolidated statements of income, partners’ capital and comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2005, contains a separat e paragraph that states that as discussed in Note 20 to the consolidated financial statements, TEPPCO Partners, L.P. has restated its consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, partners’ capital and comprehensive income and cash flows for the years ended December 31, 2004 and 2003.

KPMG LLP

Houston, Texas

February 28, 2006

EX-24

Exhibit 24

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned directors and/or officers of TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC (the “Company”), a Delaware limited liability company, acting in its capacity as general partner of TEPPCO Partners, L.P., and TE Products Pipeline Company, Limited Partnership, each a Delaware limited partnership (collectively, “Partnership”), does hereby appoint WILLIAM G. MANIAS, his true and lawful attorney and agent to do any and all acts and things, and execute any and all instruments which, with the advice and consent of Counsel, said attorney and agent may deem necessary or advisable to enable the Company and Partnership to comply with the Securities Act of 1934, as amended, and any rules, regulations, and requirements thereof, to sign his name as a director and/or officer of the Company to the Form 10-K Report for TEPPCO Partners, L.P. and for TE Products Pipeline Company, Limited Partnership, each for the year ended December 31, 2005, and to any instrument or document filed as a part of, or in accordance with, each said Form 10-K or amendment thereto; and the undersigned do hereby ratify and confirm all that said attorney and agent shall do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have subscribed these presents this 1^st day of March, 2006.

/s/ MICHAEL B. BRACY	/s/ MURRAY H. HUTCHISON
Michael B. Bracy	Murray H. Hutchison
Director	Director
/s/ LEE W. MARSHALL, SR.	/s/ RICHARD S. SNELL
Lee W. Marshall, Sr.	Richard S. Snell
Director	Director
/s/ WILLIAM G. MANIAS	/s/ RICHARD H. BACHMANN
William G. Manias	Richard H. Bachmann
Vice President and	Director
Chief Financial Officer
/s/ MICHAEL A. CREEL	/s/ W. RANDALL FOWLER
Michael A. Creel	W. Randall Fowler
Director	Director

EX-31.1

Exhibit 31.1

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) / Rule 15d-14(a),
promulgated under the Securities Exchange Act of 1934, as amended

I, Lee W. Marshall, Sr., certify that:

1.I have reviewed this annual report on Form 10-K of TEPPCO Partners, L.P.;

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

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

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 1, 2006	/s/ LEE W. MARSHALL, SR.
	Lee W. Marshall, Sr. Chairman and Acting Chief Executive Officer Texas Eastern Products Pipeline Company, LLC, as General Partner

EX-31.2

Exhibit 31.2

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) / Rule 15d-14(a),
promulgated under the Securities Exchange Act of 1934, as amended

I, William G. Manias, certify that:

1.             I have reviewed this annual report on Form 10-K of TEPPCO Partners, L.P.;

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

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

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 1, 2006	/s/ WILLIAM G. MANIAS
	William G. Manias Vice President and Chief Financial Officer Texas Eastern Products Pipeline Company, LLC, as General Partner

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of TEPPCO Partners, L.P. (the “Company”) on Form 10-K for the year ended December 31, 2005 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Lee W. Marshall, Sr., Chairman and Acting Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ LEE W. MARSHALL, SR.

Lee W. Marshall, Sr.
 Chairman and Acting Chief Executive Officer
Texas Eastern Products Pipeline Company, LLC, General Partner

March 1, 2006

A signed original of this written statement required by Section 906 has been provided to TEPPCO Partners, L.P. and will be retained by TEPPCO Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of TEPPCO Partners, L.P. (the “Company”) on Form 10-K for the year ended December 31, 2005 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, William G. Manias, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ WILLIAM G. MANIAS

William G. Manias
Vice President and Chief Financial Officer
Texas Eastern Products Pipeline Company, LLC, General Partner

March 1, 2006

A signed original of this written statement required by Section 906 has been provided to TEPPCO Partners, L.P. and will be retained by TEPPCO Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.