UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-13603

TE Products Pipeline Company, Limited Partnership

(Exact name of Registrant as specified in its charter)

Delaware		76-0329620
(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
6.45% Senior Notes, due January 15, 2008		New York Stock Exchange
7.51% Senior Notes, due January 15, 2028		New York Stock Exchange

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 o No ý

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 o Accelerated Filer o Non-accelerated Filer ý

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

Documents Incorporated by Reference		Form 10-K Parts
TEPPCO Partners, L.P. Form 10-K		III
For the fiscal year ended December 31, 2005

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 investment in Centennial Pipeline LLC from an intangible asset with an indefinite life to an intangible asset with a definite life. The restatement caused a $3.1 million and $3.3 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 $4.1 million, of which $3.3 million relates to the first nine months of 2005. Additionally, partners’ capital at December 31, 2002, reflects a $2.4 million reduction representing the cumulative effect of this correction for the fiscal year ended December 31, 2002.

For further discussion of the effect of the restatement, see Note 19 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 year ended December 31, 2002, 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 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 and the

demand for petrochemicals is dependent upon prices for products produced from petrochemicals. 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 TE Products Pipeline Company, Limited Partnership 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

TE Products Pipeline Company, Limited Partnership (the “Partnership”), a Delaware limited partnership, was formed in March 1990. TEPPCO Partners, L.P. (the “Parent Partnership”) owns a 99.999% interest in us as the sole limited partner. TEPPCO GP, Inc. (“TEPPCO GP” or “General Partner”), a wholly owned subsidiary of the Parent Partnership, holds a 0.001% general partner interest in us. Texas Eastern Products Pipeline Company, LLC (the “Company”), a Delaware limited liability company, serves as the general partner of our Parent Partnership.

Through February 23, 2005, the Company 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 Company 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 our Parent Partnership and has the right to receive the incentive distribution rights associated with the general partner interest.

TEPPCO GP, as our general partner, performs all of the management and operating functions required for us in accordance with the Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership. We reimburse our General Partner and the Company for all reasonable direct and indirect expenses that they incur in managing us.

On May 9, 2005, we formed TEPPCO Interests, LLC (“TEPPCO Interests”), a Delaware limited liability company, of which we own 100% of the member interests. On July 15, 2005, TEPPCO Interests acquired from Texas Genco, LLC (i) 100% of its member interests in TG Pipeline GP, LLC, a Delaware limited liability company, which is the owner of 100% of the general partner interests in TG Pipeline, L.P. (“Pipeline LP”), a Texas limited partnership, and (ii) 100% of the membership interests in TG Pipeline LP, LLC, a Delaware limited liability company, which is the owner of 100% of the limited partner interests in Pipeline LP (see Note 5 in the Notes to the Consolidated Financial Statements).

On May 18, 2005, we formed TEPPCO Terminals, L.P. (“TEPPCO Terminals”), a Delaware limited partnership, and we own a 99.999% interest in TEPPCO Terminals as the sole limited partner. TEPPCO GP serves as the general partner and holds a 0.001% general partner interest in TEPPCO Terminals. On July 12, 2005, TEPPCO Terminals purchased a refined products terminal and two-bay truck loading rack in North Little Rock,

from operations, borrowings and capital contributions from our Parent Partnership, the issuance of debt in the capital markets or any combination thereof.

Recent Developments since December 31, 2004

In April 2005, we completed construction on a refined products truck loading facility in Bossier City, Louisiana. 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, TEPPCO Terminals 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 infrastructure in North Little Rock, Arkansas.

On July 15, 2005, TEPPCO Interests 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 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.

Properties and Operations

We conduct business through the following:

• TE Products;

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

• 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”).

We own, operate or have investments in properties located in 14 states. Our operations 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, we offer 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 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	%
Centennial (1)	50	%
MB Storage (2)	50	%

(1) Accounted for as an equity investment. Effective February 10, 2003, we acquired an additional 16.7% interest in Centennial, bringing our ownership percentage to 50%.

(2) Accounted for as an equity investment. Effective January 1, 2003, we contributed substantially all of our 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 Product Deliveries	205.7	196.4	196.6

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

Refined Products, LPGs and Petrochemical Pipeline Systems

We are one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. We own and operate an approximately 4,700-mile pipeline system (together with the receiving, storage and terminaling facilities mentioned below, the “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 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 Pipeline System makes deliveries to customers at 62 locations including 19 truck racks, railcar facilities and marine facilities that we own. Deliveries to other

pipelines occur at various facilities owned by third parties or us. We also own one active marine receiving terminal at Providence, Rhode Island. The Providence terminal is not physically connected to the Pipeline System.

The 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 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 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 Pipeline System’s terminal in El Dorado, Arkansas, before continuing as a 16-inch diameter line to Seymour, Indiana.

The 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 Pipeline System also has a 6-inch diameter pipeline connection to the Greater Cincinnati/Northern Kentucky International Airport.

In addition, the 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 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.

We also own 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.

Centennial Pipeline Equity Investment

We own 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 our facility in Beaumont, Texas, with an existing 720-mile, 26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois. The Centennial pipeline intersects our 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 we operate 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, we have invested $104.8 million in Centennial. We have not received any distributions from Centennial since its formation.

Mont Belvieu Storage Equity Investment

On January 1, 2003, we and Louis Dreyfus formed MB Storage, and we 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. We operate 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 Storage also provides truck and railcar 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, our 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, we 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, we 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 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 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 connecting pipelines, customer-owned terminals and us.

Our 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 Pipeline System east of Todhunter, Ohio, is devoted solely to the transportation of LPGs. Our 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 we serve. 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 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.

Our major operations 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 Product Deliveries	205.7	196.4	196.6

(1) Arkansas, Louisiana, Missouri and Texas.

(2) Illinois and Indiana.

(3) New York and Pennsylvania.

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. We depend 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, we had approximately 154 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 (54%), of which Marathon accounted for approximately 14% of total revenues. At December 31, 2004, we had approximately 138 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 (55%), of which Marathon accounted for approximately 17% of total 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 (57%), of which Marathon accounted for approximately 18% of total revenues.

Competition

The 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.

The 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 Pipeline System’s most significant competitors (other than indigenous production in its markets) are pipelines in the areas where the 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 we are 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 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 our 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.

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 $58.2 million for the year ended December 31, 2005. Revenue generating projects include those projects which expand service into new markets or expand capacity into current markets. Capital expenditures to sustain existing operations include projects required by regulatory agencies or required life-cycle replacements. System upgrade projects improve operational efficiencies or reduce cost. We capitalize interest costs incurred during the period that construction is in progress. The following table identifies capital expenditures for the year ended December 31, 2005 (in millions):

Revenue generating	$	22.5
Sustaining existing operations	19.3
System upgrades	13.4
Capitalized interest	3.0
Total	$	58.2

Revenue generating capital spending totaled $22.5 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. In order to sustain existing operations, we spent $19.3 million for various pipeline projects. An additional $13.4 million was spent on system upgrade projects.

We estimate that capital expenditures, excluding acquisitions, for 2006 will be approximately $105.4 million (including $3.4 million of capitalized interest). We expect to spend approximately $70.9 million for revenue generating projects and facility improvements. We expect to spend approximately $16.4 million to sustain existing operations, including life-cycle replacements for equipment at various facilities and pipeline and tank replacements and $14.7 million for various system upgrade projects. During the remainder of 2006, we 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 system. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or capital contributions from our Parent Partnership or any combination thereof.

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 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, 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.

As an alternative to using the PPI Index, interstate petroleum products 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.

We have been granted permission by the FERC to utilize Market-Based Rates for all of our 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, we use the PPI Index.

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.

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.

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 $1.2 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 analogous 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, 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 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

We do not have any employees. However, for organizational purposes, our General Partner has officers and directors, who are employees of EPCO. EPCO performs all management, administrative and operating functions required for TEPPCO GP, our General Partner, and our General Partner reimburses EPCO for all direct and indirect expenses that have been incurred in its management. As of December 31, 2005, EPCO had 1,270 employees dedicated to managing and operating our Parent Partnership and its subsidiaries. None of these employees are represented by labor unions, and our Parent Partnership’s 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.

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.

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.

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 and 2004, we had no expense related to uncollectible receivables. During the year ended December 31, 2003, we expensed less than $0.8 million of uncollectible receivables.

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 pipeline business depends in large part on the demand for refined petroleum products and LPGs in the markets we serve. Reductions in that demand adversely affect our pipeline business. Market demand varies based upon the different end uses of the refined 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 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 petroleum products. 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 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.

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 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.

We depend on the leadership and involvement of our General Partner’s key personnel for the success of our business.

We depend on the leadership and involvement of key personnel of our General Partner to identify and develop business opportunities and make strategic decisions. A search is currently being conducted for a permanent chief executive officer. Our General Partner’s chief financial officer was appointed in January 2006, and its general counsel was appointed effective March 1, 2006, each having twenty plus 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

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 to our Parent Partnership would be reduced substantially. One of the primary benefits of investing in us 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 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.

The Company and its affiliates may have conflicts with our partnership.

The directors and officers of the Company and its affiliates (including EPCO and other affiliates of EPCO) have duties to manage our Parent Partnership and its subsidiaries in a manner that is beneficial to its member. At the same time, the Company has duties to manage our Parent Partnership and its subsidiaries in a manner that is beneficial to us. Therefore, the Company’s duties to us may conflict with the duties of its officers and directors to its member. Provisions of our Parent Partnership’s partnership agreement, the partnership agreements for each of its operating partnerships and/or the administrative services agreement provide for a standard of care that may allow the Company 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 the Company regarding the amount and timing of cash expenditures, borrowings and issuances of other Parent Partnership debt or equity securities can affect the amount of distribution payments we make to the Parent Partnership and the amount of incentive compensation payments the Parent Partnership makes to the Company;

• decisions of the Company regarding our acquisitions or expansions, which may provide benefits to the Company and its affiliates;

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

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

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

• the directors and officers of the Company 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 the Company not made in bad faith and that is fair and reasonable to us shall be binding on us 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 Company 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 the Company and EPCO control the enforcement of obligations owed to us by the Company, EPCO and its affiliates.

In addition, the Parent Partnership’s partnership agreements grant broad rights of indemnification to the Company 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.

If EPCO or other entities that own or control the Company are presented with certain business opportunities, Enterprise Products Partners L.P. will have the first right to pursue such opportunities.

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

To the extent that the Company 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 and our Parent Partnership 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 the Company. Some of the EPCO employees providing these services 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 our Parent Partnership, us and other EPCO affiliates.

Our Parent Partnership does not have an independent compensation committee and its independent directors do not deliberate, decide or approve recommendations related to the compensation of its 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 our Parent Partnership and us.

Item 3. Legal Proceedings

In the fall of 1999 and on December 1, 2000, the Company and the Parent 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 Company and the Parent Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the Company and the Parent 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, we were 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 Company 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 Company 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 Company’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 Company has been unable to confirm involvement by the Company 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 Company 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 Company 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.

In 1991, the Company and the Parent Partnership 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, the Company and the Parent Partnership 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.

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 are included elsewhere in this Report. The selected financial data for the year ended December 31, 2002, is derived from unaudited consolidated financial statements and, in the opinion of management, has been prepared in accordance with accounting principles generally accepted in the United States of America and reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of results for 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 19 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			2001
				(as restated)			(as restated)			(as restated)
										(unaudited)
	(in thousands)
Income Statement Data: (1)
Operating revenues:
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
Mont Belvieu operations	—			—			—			15,238			14,116
Other revenues	41,780			39,542			31,254			30,247			32,979
Total operating revenues	282,629			274,758			261,967			243,538			264,233
Operating expenses	159,059			164,994			150,341			130,324			119,856
Depreciation and amortization	38,323			42,207			31,066			30,116			26,699
Gains on sales of assets	(139		)	(526		)	—			—			—
Operating income	85,386			68,083			80,560			83,098			117,678
Interest expense – net	(30,958		)	(28,843		)	(27,219		)	(22,742		)	(27,044		)
Equity losses	(2,984		)	(6,544		)	(7,384		)	(9,250		)	(1,149		)
Other income – net	755			787			226			832			1,537
Income before discontinued operations	52,199			33,483			46,183			51,938			91,022
Income from discontinued operations (2)	—			—			—			912			1,674
Net income (as restated) (3)	$	52,199		$	33,483		$	46,183		$	52,850		$	92,696

	December 31,
	2005		2004		2003		2002		2001
			(as restated)		(as restated)		(as restated)
							(unaudited)
					(in thousands)
Balance Sheet Data: (1)
Property, plant and equipment – net	$	808,761	$	722,334	$	682,385	$	722,848	$	697,178
Total assets	1,042,542		945,193		894,915		878,666		879,834
Long-term debt (net of current maturities)	595,954		695,003		603,478		557,521		420,594
Total debt	595,954		695,003		603,478		557,521		493,084
Partners’ capital	367,680		132,617		217,055		240,304		270,112

	Years Ended December 31,
	2005			2004			2003			2002			2001
				(as restated)			(as restated)			(as restated)
										(unaudited)
							(in thousands)
Cash Flow Data: (1)
Net cash provided by operating activities	$	42,841		$	132,894		$	96,088		$	107,600		$	123,070
Capital expenditures to sustain existing operations	(19,261		)	(29,372		)	(18,169		)	(13,592		)	(12,724		)
Distributions paid	(111,930		)	(117,967		)	(106,465		)	(94,921		)	(80,914		)

(1) Amounts have been reclassified to reflect TEPPCO Colorado as discontinued operations.

(2) Discontinued operations relates to the sale of TEPPCO Colorado in May 2002.

(3) See Note 19 in the Notes to the 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 $2.4 million.

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 sources of liquidity, trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.

This discussion contains forward-looking statements based on current expectations that are subject to risks and uncertainties, such as statements of our plans, objectives, expectations and intentions. 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

We are 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. The key elements of our strategy are to focus on internal

growth prospects in order to increase the pipeline system and terminal throughput, to 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 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 increased 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 one business segment: transportation and storage of refined products, LPGs and petrochemicals. We own, operate or have investments in properties located in 14 states, and our revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Our two largest operating expense items are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. Our results also include our equity investments in Centennial and MB Storage (see Note 6 in the Notes to the Consolidated Financial Statements).

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 pipelines and expanded and upgraded our existing infrastructure. In 2005, our major accomplishments included:

• 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.

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

• Growth 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.

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

accounting for this excess investment in Centennial as an intangible asset with an indefinite life, we have been testing the amount for impairment on an annual basis as opposed to amortizing it over a determinable life. We determined that it would be more appropriate to account for this excess investment as an intangible asset with a determinable life. As a result, we made a non-cash adjustment that reduced the net value of the excess investment in Centennial, and increased amortization expense allocated to our equity earnings. The effect of this restatement caused a $3.1 million and $3.3 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 $4.1 million, of which $3.3 million relates to the first nine months. Additionally, partners’ capital at December 31, 2002, reflects a $2.4 million reduction representing the cumulative effect of this correction for the fiscal year ended December 31, 2002.

While we believe the impact of this non-cash adjustment is not material to any previously issued financial statements, we determined that the cumulative adjustment for this non-cash item was too material to record in the fourth quarter of 2005, and therefore it was most appropriate to restate prior periods’ results. This non-cash adjustment 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.

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 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 products transported, adjustments to inventory and invoices for 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 and property taxes. 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 14% of our power costs are recorded using estimates. A variance of 10% in our aggregate estimate for power costs would have an approximate

$0.5 million impact on annual earnings. Property tax accruals involve significant tax rate estimates among 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 $0.8 million impact on annual earnings. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate. Each of these accruals requires management’s subjective judgments, requiring estimates regarding the effects of items that are inherently uncertain.

Environmental Costs

At December 31, 2005, we have accrued a liability of $1.2 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 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 $0.1 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.

Intangible Assets

Certain assumptions and estimates are employed in determining the estimated fair value of assets acquired including other intangible assets. 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.

At December 31, 2005, we have $20.5 million of excess investment, net of accumulated amortization, in our equity investment in Centennial, which is being amortized over periods ranging from 10 to 35 years (see Note 3 in the Notes to the Consolidated Financial Statements). The value assigned to our excess investment in Centennial was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a

unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. A variance of 10% in our amortization expense allocated to equity earnings could have up to an approximate $0.4 million impact on annual earnings.

Results of Operations

The following table 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%.

We are dependent in large part on the demand for refined products and LPGs in the markets we serve. Reductions in that demand adversely affect our pipeline business. Market demand varies based upon the different end uses of the refined products we ship. Demand for gasoline, which in recent years has 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. 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 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 in the past and will likely continue to occur in the future.

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 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 $9.4 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 $8.9 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 17 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 18 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 Parent Partnership’s compensation plans as a result of changes in ownership of the Company, 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 $3.2 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 the Company,

• 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 the Parent Partnership retirement plan settlements with DEFS and hurricane related expenses.

Depreciation expense decreased $3.9 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 10 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.

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 we 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.

Interest expense increased $3.4 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 note payable with our Parent Partnership. Capitalized interest increased $1.3 million for the year ended December 31, 2005, compared with the year ended December 31, 2004, as a result of increased balances of construction work-in-progress.

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 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 $8.3 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 $25.3 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 18 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 10 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.

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 our 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 we 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.

Interest expense increased $1.0 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to higher outstanding debt balances under the Note Payable with our Parent Partnership. Interest capitalized decreased $0.6 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, as a result of lower construction work-in-progress balances in 2004.

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.

Financial Condition and Liquidity

Cash generated from operations and from our Parent Partnership’s 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 $4.5 million and $61.9 million, respectively. Working capital deficits can occur primarily due to the timing of

operating cash receipts from customers, payments of cash distributions and the payment of normal operating expenses and capital expenditures. We are a wholly owned subsidiary of the Parent Partnership. We expect that our Parent Partnership will make capital contributions, loans or otherwise provide liquidity to us as needed, but the Parent Partnership has no contractual obligation to do so. We anticipate that the Parent Partnership will provide the necessary liquidity to protect its investment in us. At December 31, 2005, our Parent Partnership had approximately $274.6 million in available borrowing capacity under its revolving credit facility (applying the most restrictive financial covenants) to cover any working capital needs, and expects that cash flows from operating activities, the sale of additional debt or equity offerings will provide necessary liquidity to us. For further discussion regarding our Parent Partnership’s sources of liquidity, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Condition and Liquidity in our Parent Partnership’s Annual Report on Form 10-K for the Year Ended December 31, 2005. 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	$	42.8		$	132.9		$	96.1
Investing activities	(131.4		)	(105.5		)	(84.2		)
Financing activities	88.6			(27.6		)	(12.2		)

Operating Activities

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

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)

Net income	$	52.2		$	33.5		$	46.2
Depreciation and amortization	38.3			42.2			31.1
Losses in equity investments	3.0			6.5			7.4
Distributions from equity investments	12.4			10.3			5.3
Gains on sales of assets	(0.1		)	(0.5		)	—
Non-cash portion of interest expense	0.5			0.1			0.1
Cash provided by (used in) working capital and other	(63.5		)	40.8			6.0
Net cash from operating activities	$	42.8		$	132.9		$	96.1

For a discussion of changes in net income, depreciation and amortization and equity earnings, see “Results of Operations.” Cash provided by operating activities decreased for the year ended December 31, 2005, compared with the year ended December 31, 2004, primarily due to the timing of cash disbursements and cash receipts for working capital components, partially offset by higher net income. Cash provided by operating activities increased for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to the timing of cash disbursements and cash receipts for working capital components, higher depreciation and amortization expense in the 2004 period and an increase of $5.0 million in distributions received from our equity investment in MB Storage during the year ended December 31, 2004, partially offset by lower net income.

Net cash from operating activities for the years ended December 31, 2005, 2004 and 2003, included interest payments, net of amounts capitalized, of $30.1 million, $27.3 million and $30.3 million, respectively. Excluding the effects of hedging activities and interest capitalized, during the year ended December 31, 2006, we expect interest payments on our Senior Notes to be approximately $27.4 million. We expect to pay our interest payments with cash flows from operating activities.

Investing Activities

Cash flows used in investing activities totaled $131.4 million for the year ended December 31, 2005, and were comprised of $69.0 million for the acquisition of assets, $58.2 million of capital expenditures and $4.2 million of cash contributions to MB Storage for capital expenditures. Cash flows used in investing activities totaled $105.5 million for the year ended December 31, 2004, and were comprised of $81.3 million of capital expenditures, $1.5 million of cash contributions to Centennial to cover operating needs and capital expenditures, $21.4 million of cash contributions to MB Storage, of which $16.5 million was used to acquire storage assets, and $1.9 million for the acquisition of assets during the year ended December 31, 2004, partially offset by $0.6 million in net cash proceeds from the sales of various assets. Cash flows used in investing activities totaled $84.2 million for the year ended December 31, 2003, and were comprised of $58.4 million of capital expenditures, $20.0 million for our acquisition of an additional 16.7% interest in Centennial, $4.0 million of cash contributions to Centennial to cover operating needs and capital expenditures and $2.5 million of cash contributions to MB Storage for capital expenditures. These uses of cash were partially offset by $0.7 million received on matured cash investments.

Financing Activities

Cash flows provided by financing activities totaled $88.6 million for the year ended December 31, 2005, and were comprised of $294.8 million of equity contributions received from our Parent Partnership and $169.7 million of proceeds from our term loan, partially offset by $264.0 million of repayments on our term loan and $111.9 million of distributions paid to our Parent Partnership. Cash flows used in financing activities totaled $27.6 million for the year ended December 31, 2004, and were comprised of $118.0 million of distributions paid to our Parent Partnership and $36.0 million of repayments on our term loan, partially offset by $126.4 million of proceeds from our term loan. Cash flows used in financing activities totaled $12.2 million for the year ended December 31, 2003, and were comprised of $106.5 million of distributions paid to our Parent Partnership and $53.6 million of repayments on our term loan, partially offset by $110.9 million of proceeds from our term loan and $37.0 million of equity contributions received from our Parent Partnership.

During the years ended December 31, 2005, 2004 and 2003, we paid cash distributions to our Parent Partnership totaling $111.9 million, $118.0 million and $106.5 million, respectively. On February 7, 2006, we paid a cash distribution to our Parent Partnership of $16.7 million for the quarter ended December 31, 2005.

Other Considerations

Universal Shelf

Our Parent Partnership has filed with the SEC a universal shelf registration statement that, subject to agreement on terms at the time of use and appropriate supplementation, allows it 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 May 2005, our Parent Partnership issued $279.2 million of equity securities. At December 31, 2005, our Parent Partnership had $1.7 billion remaining under this shelf registration, subject to customary marketing terms and conditions.

Credit Facilities

We currently utilize debt financing available from our Parent Partnership through intercompany notes. The terms of the intercompany notes generally match the principal and interest payment dates under the Parent Partnership’s credit agreement and senior notes. The interest rates charged by the Parent Partnership include the stated interest rate of the Parent Partnership, plus a premium to cover debt issuance costs. The interest rate is also decreased or increased to cover gains and losses, respectively, on any interest rate swaps that the Parent Partnership may have in place on its credit agreement and senior notes. The Parent Partnership’s revolving credit facility is described below.

Our Parent Partnership has 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 Parent Partnership’s 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 our Parent Partnership had $274.6 million of availability under the most restrictive financial covenant. Restrictive covenants in

the credit agreement limit the Parent Partnership’s and its subsidiaries’ ability to, among other things, incur additional indebtedness, and make certain distributions, and complete mergers, acquisitions and sales of assets. In addition, the credit agreement requires our Parent Partnership to maintain certain financial ratios, which our Parent Partnership was in compliance with at December 31, 2005.

At December 31, 2005 and 2004, we had intercompany notes payable to our Parent Partnership of $206.9 million and $301.7 million, respectively, which represented borrowings under the Parent Partnership’s Revolving Credit Facility, 7.625% Senior Notes and 6.125% Senior Notes. The weighted average interest rate on the note payable to the Parent Partnership at December 31, 2005, was 4.15%. At December 30, 2005, accrued interest includes $3.5 million due to our Parent Partnership. For the year ended December 31, 2005 and 2004, interest costs incurred on the note payable to our Parent Partnership totaled $11.9 million and $12.5 million, respectively.

2006 Capital Expenditures

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 revenue generating expenditures, interest payments on our Senior Notes, interest payments on intercompany notes payable to our Parent Partnership and distributions to our Parent Partnership. Our cash requirements for 2006, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our Parent Partnership, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects, acquisitions and repayment of intercompany notes are expected to be funded by several sources, including cash flows from operating activities, borrowings under our Parent Partnership’s credit facilities and possibly the issuance by our Parent Partnership of additional equity and debt securities. The timing of any debt or offerings by our Parent Partnership will depend on various factors, including prevailing market conditions, interest rates and our Parent Partnership’s financial condition and 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.

We are contingently liable as guarantor for $500.0 million principal amount of 7.625% Senior Notes due 2012 issued in February 2002 and for $200.0 million principal amount of 6.125% Senior Notes due 2013 issued in January 2003 by our Parent Partnership.

Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2005, $150.0 million was outstanding under those credit facilities. We 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, we 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 Marathon and us is $75.0 million each at December 31, 2005.

We, 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, we have 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.

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		3-5 Years		After 5 Years

Note payable, Parent Partnership	$	206.9	$	—	$	—	$	206.9	$	—
6.45% Senior Notes due 2008 (1)	180.0		—		180.0		—		—
7.51% Senior Notes due 2028 (1)	210.0		—		—		—		210.0
Interest payments (2)	464.0		40.2		74.7		57.1		292.0
Debt and interest subtotal	1,060.9		40.2		254.7		264.0		502.0

Operating leases (3)	62.6		13.0		19.8		10.4		19.4
Capital expenditure obligations (4)	0.4		0.4		—		—		—
Other liabilities and deferred credits (5)	1.4		—		1.3		0.1		—

Total	$	1,125.3	$	53.6	$	275.8	$	274.5	$	521.4

(1) We entered into an interest rate swap agreement to hedge our exposure to changes in the fair value of our 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. At December 31, 2005, our 6.45% Senior Notes include less than $0.1 million of unamortized debt discount. The fair value adjustment and unamortized debt discount are excluded from this table.

(2) Includes interest payments due on our Senior Notes and interest payments and commitment fees due on our Note Payable to our Parent Partnership. The interest amount calculated on the Note Payable to our Parent Partnership is based on the assumption that the amount outstanding and the interest rate charged both remain at their current levels.

(3) Includes a pipeline capacity lease with Centennial. In January 2003, we 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, we exceeded the minimum throughput requirements on the lease agreement.

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

(5) Excludes approximately $8.5 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.

We expect to repay the long-term, senior unsecured obligations and note payable to our Parent Partnership through the issuance of additional long-term senior unsecured debt at the time the 2008 and 2028 debts mature, with

proceeds from the dispositions of assets, cash flows from operations, and contributions from our Parent Partnership or any combination of the above items.

Our Parent Partnership’s 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 Company 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. Our senior unsecured debt 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 Risks

Commodity Risk

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

Interest Rate Risk

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% Senior Notes, due January 2008	$	180.0	$	183.7	$	187.1
7.51% 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 fair value risks. Interest rate swap agreements are used to manage the fixed and floating interest rate mix of our debt portfolio and overall cost of borrowing. The interest rate swap related to our fair value risk is intended to reduce our exposure to changes in the fair value of our fixed rate Senior Notes. 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 October 2001, we entered into an interest rate swap agreement to hedge our exposure to changes in the fair value of our 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 our Senior Notes. Under the swap agreement, we pay a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receive 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 our 7.51% 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.

At December 31, 2005 and 2004, we had intercompany notes payable to our Parent Partnership of $206.9 million and $301.7 million, respectively, which represented borrowings under the Parent Partnership’s Revolving Credit Facility, 7.625% Senior Notes and 6.125% Senior Notes. The weighted average interest rate on the note payable to the Parent Partnership at December 31, 2005, was 4.15%. At December 31, 2005, accrued interest includes $3.5 million due to our Parent Partnership. For the year ended December 31, 2005 and 2004, interest costs incurred on the note payable to our Parent Partnership totaled $11.9 million and $12.5 million, respectively.

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.

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.

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

We do not have officers or directors, as is commonly the case with publicly traded partnerships. Our operations and activities are managed by our General Partner, a wholly owned subsidiary of our Parent Partnership. All officers and directors of the General Partner are appointed annually by the board of directors of the Company. During 2005, the directors of the General Partner, TEPPCO GP, were Barry R. Pearl, Charles H. Leonard and James C. Ruth, until Mr. Leonard’s retirement effective July 8, 2005

and Mr. Pearl’s retirement effective December 30, 2005. Mr. Ruth retired effective February 28, 2006. On February 7, 2006, the General Partner appointed William G. Manias and Patricia A. Totten to the board of directors. The Executive Officers of the General Partner are also Executive Officers of the Company. Information concerning the Executive Officers of the General Partner and the Company is contained in Item 10 of the Parent Partnership’s Annual Report on Form 10-K for the Year Ended December 31, 2005 (the “Parent Partnership Form 10-K”), and is incorporated by reference in this Report.

Item 11. Executive compensation

We do not have any officers or directors, and the General Partner manages and operates our business. The Executive Officers of the General Partner are employees of EPCO. Certain employees of EPCO may devote all or a portion of their time to us, and we reimburse EPCO for the services of these persons. The information contained in Item 11 of the Parent Partnership Form 10-K is incorporated by reference in this Report.

Item 12. Security ownership of certain beneficial owners and management and related stockholder matters

The Parent Partnership owns a 99.999% interest as the sole limited partner interest and the General Partner owns a 0.001% general partner interest in us. Information identifying security ownership of the Parent Partnership is contained in Item 12 of the Parent Partnership Form 10-K and is incorporated by reference in this Report.

Neither the General Partner, the Parent Partnership nor us has any equity compensation plan under which equity securities of any of such entities are authorized for issuance.

Item 13. Certain relationships and related transactions

Parent Partnership

The Partnership does not have any employees. We are managed by the TEPPCO GP, a wholly owned subsidiary of our Parent Partnership. Our Parent Partnership is managed by the Company, which prior to February 23, 2005, was an indirect wholly owned subsidiary of DEFS. According to the Partnership Agreement, the General Partner and the Company are entitled to reimbursement of all direct and indirect expenses related to our business activities. As a result of the change in ownership of the Company on February 24, 2005, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to an administrative services agreement. TEPPCO GP reimburses 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).

Our Parent Partnership allocates operating, general and administrative expenses to us for legal, insurance, financial, communication and other administrative services based upon the estimated level of effort devoted to our various operations. In addition, we make cash payments on behalf of the Parent Partnership for various expenses. At December 31, 2005 and 2004, we had a net payable of $18.5 million and $63.0 million, respectively, to the Parent Partnership related to these affiliated activities.

EPCO and Affiliates

We transport LPGs on our pipeline system for affiliates of EPCO. From February 24, 2005 through December 31, 2005, we recognized revenues from affiliates of EPCO for LPG transportation and other operating revenues of $4.6 million.

From February 24, 2005 through December 31, 2005, we incurred direct expenses of $30.8 million which were charged to us by EPCO. Substantially all of these costs were related to payroll and payroll related expenses.

Item 14. Principal accounting fees and services

Our Parent Partnership’s audit engagement with KPMG includes the fees for the professional services rendered to us by KPMG as we do not have a separate audit engagement with KPMG. We are allocated a portion of the audit services expense (see Note 2 in the Notes to the Consolidated Financial Statements).

The following table describes fees for professional services rendered by KPMG, our Parent Partnership’s principal accountant, for the audit of the financial statements of all of the Parent Partnership’s entities 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 Parent Partnership’s audit of internal control over financial reporting.

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

(3) Tax fees consisted 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 Auditor

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

Exhibit Number		Description

3.1		Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, effective 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).
4.1		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).
4.2		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).
4.3		First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.4		Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
4.5		Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of 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 of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.4+		Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (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+		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).
10.10+		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).
10.11+		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).
10.12+		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).
10.13+		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).
10.14+		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).
10.15		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).
10.16		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).
10.17		Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
10.18		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).

10.19+		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).
10.20+		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).
10.21+		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).
10.22+		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).
10.23+		Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002, and incorporated herein by reference).
10.24		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).
10.25		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).
10.26		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).
10.27		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).
10.28		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).
10.29		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).
10.30		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).
10.31		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).

10.32		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).
10.33+		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) dated as of December 31, 2004 and incorporated herein by reference).
10.34+		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 From 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of December 31, 2004 and incorporated herein by reference).
10.35		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).
10.36+		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).
10.37+		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).
10.38+		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).
10.39+		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).
10.40+		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).
10.41+		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).
10.42		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).

10.43		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).
10.44+		Agreement and Release between Barry R. Pearl and Texas Eastern Products Pipeline Company, LLC dated as of December 30, 2005 (Filed as Exhibit 10.52 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2005 and incorporated herein by reference).
10.45+		Agreement and Release between James C. Ruth and Texas Eastern Products Pipeline Company, LLC dated as of January 25, 2006 (Filed as Exhibit 10.53 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2005 and incorporated herein by reference).
10.46		Waiver of Provisions of the Conflicts Policies and Procedures of the third Amended and Restated Administrative Services Agreement (Filed as Exhibit 10.56 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2005 and incorporated herein by reference).
23*		Consent of KPMG LLP.
31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

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

+ A management contract or compensation plan or arrangement.

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.

		By:	/s/ LEE W. MARSHALL, SR.
Date: March 1, 2006	Lee W. Marshall, Sr.,
	Acting Chief Executive Officer
	of TEPPCO GP, Inc., General Partner

		By:	/s/ WILLIAM G. MANIAS
Date: March 1, 2006	William G. Manias,
	Director and Vice President and Chief Financial Officer
	of TEPPCO GP, Inc., General Partner

TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2005		2004
			(as restated)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—
Accounts receivable, trade (net of allowance for doubtful accounts of $45 and $56)	26,338		21,090
Accounts receivable, related parties	2,182		2,379
Inventories	16,449		10,093
Other	14,911		12,143
Total current assets	59,880		45,705
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $340,562 and $311,197)	808,761		722,334
Equity investments	157,335		160,998
Other assets	16,566		16,156
Total assets	$	1,042,542	$	945,193

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable and accrued liabilities	$	13,540	$	10,211
Accounts payable, related parties	19,973		65,375
Accrued interest	16,151		17,063
Other accrued taxes	7,524		5,605
Other	7,220		9,339
Total current liabilities	64,408		107,593
Senior Notes	389,048		393,317
Note payable, Parent Partnership	206,906		301,686
Other liabilities and deferred credits	14,500		9,980
Commitments and contingencies
Partners’ capital:
General partner’s interest	4		2
Limited partner’s interest	367,676		132,615
Total partners’ capital	367,680		132,617
Total liabilities and partners’ capital	$	1,042,542	$	945,193

See accompanying Notes to Consolidated Financial Statements.

F-3

TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF INCOME

(in thousands)

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Operating revenues:
Transportation – Refined products	$	144,552		$	148,166		$	138,926
Transportation – LPGs	96,297			87,050			91,787
Other	41,780			39,542			31,254
Total operating revenues	282,629			274,758			261,967

Costs and expenses:
Operating, general and administrative	115,626			124,496			112,683
Operating fuel and power	32,346			31,588			28,792
Depreciation and amortization	38,323			42,207			31,066
Taxes – other than income taxes	11,087			8,910			8,866
Gains on sales of assets	(139		)	(526		)	—
Total costs and expenses	197,243			206,675			181,407

Operating income	85,386			68,083			80,560

Interest expense – net	(30,958		)	(28,843		)	(27,219		)
Equity losses	(2,984		)	(6,544		)	(7,384		)
Other income – net	755			787			226

Net income	$	52,199		$	33,483		$	46,183

See accompanying Notes to Consolidated Financial Statements.

F-4

TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

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	$	52,199		$	33,483		$	46,183
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	38,323			42,207			31,066
Losses in equity investments, net of distributions	15,415			16,857			12,647
Non-cash portion of interest expense	513			30			31
Gains on sales of assets	(139		)	(526		)	—
(Increase) decrease in accounts receivable	(5,248		)	4,287			(1,334		)
(Increase) decrease in accounts receivable, related parties	197			(2,225		)	3,002
Decrease (increase) in inventories	(6,296		)	1,093			552
(Increase) decrease in other current assets	(2,768		)	(1,913		)	959
(Decrease) increase in accounts payable and accrued expenses	4,375			(5,014		)	(9,689		)
(Increase) decrease in accounts payable, related parties	(882		)	(1,013		)	2,278
Other	(52,846		)	45,628			10,393
Net cash provided by operating activities	42,843			132,894			96,088

Cash flows from investing activities:
Proceeds from cash investments	—			—			750
Proceeds from sales of assets	—			594			—
Purchase of assets	(68,969		)	(1,962		)	—
Investment in Centennial Pipeline LLC	—			(1,500		)	(4,000		)
Purchase of additional interest in Centennial Pipeline LLC	—			—			(20,000		)
Investment in Mont Belvieu Storage Partners, L.P.	(4,233		)	(21,358		)	(2,533		)
Capital expenditures	(58,235		)	(81,261		)	(58,391		)
Net cash used in investing activities	(131,437		)	(105,487		)	(84,174		)

Cash flows from financing activities:
Proceeds from note payable, Parent Partnership	169,708			126,383			110,859
Repayment of note payable, Parent Partnership	(263,978		)	(36,011		)	(53,638		)
Equity contribution – Parent Partnership	294,794			—			37,033
Distributions paid	(111,930		)	(117,967		)	(106,465		)
Net cash provided by (used in) financing activities	88,594			(27,595		)	(12,211		)

Net decrease in cash and cash equivalents	—			(188		)	(297		)

Cash and cash equivalents at beginning of period	—			188			485
Cash and cash equivalents at end of period	$	—		$	—		$	188

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)	$	30,128		$	27,338		$	30,286

See accompanying Notes to Consolidated Financial Statements.

F-5

TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands)

	General Partner’s Interest			Limited Partner’s Interest			Total

Partners’ capital at December 31, 2002 (as restated)	$	2		$	240,302		$	240,304
2003 net income allocation	1			46,182			46,183
2003 cash distributions	(1		)	(106,464		)	(106,465		)
Capital contributions	—			34,988			34,988
Option exercises	—			2,045			2,045

Partners’ capital at December 31, 2003 (as restated)	2			217,053			217,055
2004 net income allocation	1			33,482			33,483
2004 cash distributions	(1		)	(117,966		)	(117,967		)
Other	—			46			46

Partners’ capital at December 31, 2004 (as restated)	2			132,615			132,617
2005 net income allocation	1			52,198			52,199
2005 cash distributions	(1		)	(111,929		)	(111,930		)
Capital contributions	2			294,792			294,794

Partners’ capital at December 31, 2005	$	4		$	367,676		$	367,680

See accompanying Notes to Consolidated Financial Statements.

F-6

TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION

On July 26, 2001, the Company restructured its general partner ownership of us to cause us to be wholly owned by the Parent Partnership. TEPPCO GP succeeded the Company as our general partner. All of our remaining partner interests not already owned by the Parent Partnership were transferred to the Parent Partnership. In exchange for this contribution, the Company’s interest as general partner of the Parent Partnership 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 the Parent Partnership and us. As a result, the Parent Partnership holds a 99.999% limited partner interest in us and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify our required financial reporting when we issue guarantees of our Parent Partnership’s debt.

F-7

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 one business segment: transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals. 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 and petrochemicals in this Report, collectively, as “petroleum products” or “products.”

Revenue Recognition

Our 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.

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 approximates 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	$	56		$	374		$	287
Charges to costs and expenses	—			—			788
Deductions and other	(11		)	(318		)	(701		)
Balance at end of period	$	45		$	56		$	374

Inventories

Inventories consist primarily of petroleum products which are valued at the lower of cost (weighted average cost method) or market. We acquire and dispose of various products under exchange agreements. Receivables and

F-9

payables arising from these transactions are usually satisfied with 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 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 fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or 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.

Our 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.

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.

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.

F-10

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 5.5%, 5.12% and 5.69% 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 $3.0 million, $1.7 million and $2.3 million, respectively.

Intangible Assets

Intangible assets on the consolidated balance sheets consist primarily of transportation agreements with customers and are being amortized using a straight line method over the term of the related agreement (approximately 20 years). Included in equity investments on the consolidated balance sheets is excess investment in Centennial Pipeline LLC (“Centennial”). 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.

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	$	1,428		$	1,693		$	2,051
Charges to expense	1,860			745			1,490
Deductions and other	(2,123		)	(1,010		)	(1,848		)
Balance at end of period	$	1,165		$	1,428		$	1,693

Operating, General and Administrative Expenses

The Parent Partnership allocates operating, general and administrative expenses to us for legal, insurance, financial, communication and other administrative services based upon the estimated level of effort devoted to our various operations. We believe that the method for allocating corporate operating, general and administrative expenses is reasonable. Total operating, general and administrative expenses reflected in the accompanying consolidated financial statements are representative of the total operating, general and administrative costs we would have incurred as a separate entity.

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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 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.

Unit Option Plan

Our Parent Partnership has not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 15), the Parent Partnership followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, the Parent Partnership records 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 Parent Partnership’s Limited Partner 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 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 15.

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Assuming the Parent Partnership had used the fair value method of accounting for its unit option plan, pro forma net income would equal reported net income for the years ended December 31, 2005, 2004 and 2003. 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 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.

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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 consensus also requires entities to account for 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.

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NOTE 3. INTANGIBLE ASSETS

We account for our intangible assets 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. 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.

The following table reflects the components of amortized intangible assets, included in other assets on the consolidated balance sheets, and excess investment included in equity investments, 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:
Transportation agreements	$	1,328	$	(326	)	$	1,328	$	(260	)

Excess investment:
Centennial Pipeline LLC	$	33,400	$	(12,947	)	$	33,400	$	(8,875	)

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.

Amortization expense on intangible assets was $0.1 million for each of the years ended December 31, 2005, 2004 and 2003. Amortization expense on our excess investment included in equity earnings was $4.1 million, $3.1 million and $3.3 million for the years ended December 31, 2005, 2004 and 2003, respectively.

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	$	66	$	3,999
2007	66		4,422
2008	66		4,747
2009	66		6,187
2010	66		6,351

NOTE 4. INTEREST RATE SWAP

In October 2001, we entered into an interest rate swap agreement to hedge our 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 our Senior Notes. Under the swap agreement, we pay a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receive 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

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$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.

NOTE 5. ACQUISITIONS

Refined Products Terminal and Truck Rack

On July 12, 2005, TEPPCO Terminals 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 Parent Partnership’s 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 infrastructure in North Little Rock, Arkansas.

Genco Assets

On July 15, 2005, TEPPCO Interests 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 Parent Partnership’s 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 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

In August 2000, we 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, we and Marathon each acquired an additional 16.7% interest in Centennial from PEPL for $20.0 million each, increasing our ownership percentages in Centennial to 50% each. During the year ended December 31, 2005, we did not make any additional investments in Centennial. We 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. We have not received any distributions from Centennial since its formation.

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

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substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. MB Storage has no commodity trading activity. We operate the facilities for MB Storage. Effective January 1, 2003, we 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 we were 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, we 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, we received the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense. Our 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 us and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MB Storage is allocated between us 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 us and Louis Dreyfus. For the years ended December 31, 2005, 2004 and 2003, our sharing ratio in the earnings of MB Storage was approximately 64.2%, 69.4% and 70.4%, respectively. During the years ended December 31, 2005, 2004 and 2003, we 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, we 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 transfer of $1.4 million and cash contributions of $4.2 million. The contribution for 2004 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 Centennial and MB Storage. Summarized combined financial information for 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	$	74,003	$	60,717
Net Income	10,213		(273		)

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

	December 31,
	2005		2004
Current assets	$	36,647	$	39,228
Noncurrent assets	369,679		377,924
Current liabilities	33,621		36,015
Long-term debt	140,000		140,000
Noncurrent liabilities	13,522		20,383
Partners’ capital	219,183		220,754

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NOTE 8. OTHER CURRENT ASSETS

The major components of other current assets for the years ended December 31, 2005 and 2004, were as follows (in thousands):

	December 31,
	2005		2004
Insurance receivable	$	5,915	$	4,531
Reimbursable receivables	5,510		2,780
Interest receivable from interest rate swap	1,999		4,027
Prepaid insurance and other	230		299
Other	1,257		506
Total	$	14,911	$	12,143

NOTE 9. 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
Refined products	$	4,461	$	5,665
LPGs	7,403		—
Materials and supplies	4,585		4,428
Total	$	16,449	$	10,093

NOTE 10. 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	$	44,850	$	36,228
Line pipe and fittings	676,920		631,099
Storage tanks	120,831		95,765
Buildings and improvements	45,691		36,045
Machinery and equipment	183,461		191,561
Construction work in progress	77,570		42,833
Total property, plant and equipment	1,149,323		1,033,531
Less accumulated depreciation and amortization	340,562		311,197
Net property, plant and equipment	$	808,761	$	722,334

Depreciation expense, including impairment charges, on property, plant and equipment was $38.3 million, $42.1 million and $31.0 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 dehydration unit was destroyed due to the propane release and

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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 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. 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 11. OTHER CURRENT LIABILITIES

The major components of other current liabilities for the years ended December 31, 2005 and 2004, were as follows (in thousands):

	December 31,
	2005		2004
Inventory payables	$	338	$	391
Current portion of deferred revenue	1,177		1,359
McCleery litigation accrual	—		2,000
Capital expenditure accruals	398		1,568
Retainage	626		1,812
Accruals for regulatory penalties	1,750		—
Current portion of FIN 45 obligation	500		—
Other	2,431		2,209
Total	$	7,220	$	9,339

NOTE 12. DEBT

Senior Notes

On January 27, 1998, we 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 “Senior Notes”). The 6.45% 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% Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at our option, 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.

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The Senior Notes do not have sinking fund requirements. Interest on the Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The Senior Notes are unsecured obligations and rank pari passu with all other unsecured and unsubordinated indebtedness. The indenture governing the 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 the Senior Notes.

We have entered into an interest rate swap agreement to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above (see Note 4). The Senior Notes include the fair value of our interest rate swap, which was a loss of $0.9 million at December 31, 2005 and a gain of $3.4 million at December 31, 2004.

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% Senior Notes, due January 2008	$	180.0	$	183.7	$	187.1
7.51% Senior Notes, due January 2028	210.0		224.1		225.6

Other Long Term Debt and Credit Facilities

On February 20, 2002, our Parent Partnership issued $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 7.625% Senior Notes may be redeemed at any time at our Parent Partnership’s option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing the 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our Parent Partnership’s ability to incur additional indebtedness.

On January 30, 2003, our Parent Partnership issued $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 6.125% Senior Notes may be redeemed at any time at our Parent Partnership’s option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing the 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 the Parent Partnership’s ability to incur additional indebtedness.

On June 27, 2003, our Parent Partnership 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

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Facility”). The interest rate is based, at our Parent Partnership’ 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 the Parent Partnership’s and its subsidiaries’ ability to, among other things, incur additional indebtedness, make distributions in excess of Available Cash and complete mergers, acquisitions and sales of assets. On October 21, 2004, our Parent Partnership amended the 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, our Parent Partnership again amended its Revolving Credit Facility to remove the requirement that DEFS must at all times own, directly or indirectly, 100% of the Company, to allow for its acquisition by DFI (see Note 1). During the second quarter of 2005, the Parent Partnership used a portion of the proceeds from an equity offering in May 2005 to repay a portion of the Revolving Credit Facility. On December 13, 2005, the Parent Partnership amended its 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 Parent Partnership’s 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, the Parent Partnership 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.

At 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, our Parent Partnership was in compliance with the covenants of this credit agreement.

At December 31, 2005 and 2004, we had intercompany notes payable to our Parent Partnership of $206.9 million and $301.7 million, respectively, which represented borrowings under the Parent Partnership’s Revolving Credit Facility, 7.625% Senior Notes and 6.125% Senior Notes. The weighted average interest rate on the note payable to the Parent Partnership at December 31, 2005, was 4.15%. At December 31, 2005, accrued interest includes $3.5 million due to our Parent Partnership. For the year ended December 31, 2005 and 2004, interest costs incurred on the note payable to our Parent Partnership totaled $11.9 million and $12.5 million, respectively.

NOTE 13. 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 the years ended December 31, 2005, 2004 and 2003, we had one customer, Marathon Petroleum Company LLC, which accounted for 14%, 17% and 18%, respectively, of our total revenues. No other customer

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

	Options Outstanding		Options Exercisable		Exercise Range
Parent LPU 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	—		—

Our Parent Partnership has not granted options for any periods presented. During the year ended December 31, 2003, all remaining outstanding Parent LPU options were exercised. For options previously outstanding, our Parent Partnership 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 the Parent LPUs on the date of grant. Accordingly, the Parent Partnership 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 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 Parent LPU 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 the Parent Partnership paid per unit to Parent LPU unitholders. The Parent Partnership accrues compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above. We are allocated a portion of the compensation expense (see Note 2). At December 31, 2004, we had an accrued liability balance of $0.8 million for our share of compensation related to the 1999 PURP and 2002 PURP. Due to a change of ownership of the Parent Partnership’s 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 Company 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 Company, 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 Parent LPU 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 Parent Partnership’s 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

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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 of the Parent Partnership’s 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 Parent Partnership average annual EBITDA for the performance period minus the product of our Parent Partnership’s average asset base and cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our Parent Partnership earnings before net interest expense, depreciation and amortization and proportional interest in EBITDA of its joint ventures as presented in its consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion the Chief Executive Officer (“CEO”) 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. The Parent Partnership’s cost of capital is approved by its CEO at the date of award grant.

In addition to the payment described above, during the performance period, the Company will pay to the participant the amount of cash distributions that the Parent Partnership would have paid to its unitholders had the participant been the owner of the number of Parent LPUs equal to the number of phantom units granted to the participant under this award. The Parent Partnership accrues compensation expense annually based upon the terms of the 2000 LTIP discussed above. We are allocated a portion of the compensation expense (see Note 2). At December 31, 2005 and 2004, we had an accrued liability balance of $0.3 million and $0.9 million, respectively, for our share of compensation related to the 2000 LTIP.

NOTE 16. 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 $14.7 million, $13.8 million and $12.3 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	$	13,013
2007	12,416
2008	7,421
2009	5,254
2010	5,133
Thereafter	19,386
	$	62,623

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The components of net pension benefits costs allocated to us 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	$	2,817		$	2,384		$	2,160
Interest cost on projected benefit obligation	629			491			347
Expected return on plan assets	(467		)	(621		)	(432		)
Amortization of prior service cost	5			7			7
Recognized net actuarial loss	86			40			18
SFAS 88 curtailment charge	39			—			—
SFAS 88 settlement charge	160			—			—
Net pension benefits costs	$	3,269		$	2,301		$	2,100

Other Postretirement Benefits

The Parent Partnership 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. The Parent Partnership provided a fixed dollar contribution, which did not increase from year to year, towards retired employee medical costs. The retiree paid all health care cost increases due to medical inflation. The Parent Partnership 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 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, the Parent Partnership recorded a curtailment credit of approximately $1.7 million in its accumulated postretirement obligation, which reduced the Parent Partnership’s 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. Our Parent Partnership recorded a one-time settlement to DEFS in the third quarter of 2005 of $0.4 million for the remaining postretirement benefits. A portion of these charges was allocated to us.

The components of net postretirement benefits cost allocated to us 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	$	49		$	102	$	91
Interest cost on accumulated postretirement benefit obligation	57			129		117
Amortization of prior service cost	47			112		112
Recognized net actuarial loss	3			1		—
Curtailment charge	(1,318		)	—		—
Settlement charge	(3		)	—		—
Net postretirement benefits costs	$	(1,165	)	$	344	$	320

Effective June 1, 2005, the payroll functions performed by DEFS for the Company were transferred from DEFS to EPCO. For those employees who were receiving certain other postretirement benefits at the time of the acquisition of the Company 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 our Parent Partnership. As a result

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of these changes, the Parent Partnership recorded a $1.2 million reduction in its other postretirement obligation in June 2005. A portion of the reduction was allocated to us.

The Parent Partnership 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 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	%	—		—

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.

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The following table sets forth the Parent Partnership’s 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	$	10,803		$	7,704		$	2,466		$	2,088
Transfers to Parent Partnership subsidiary (1)	—			17			—			4
Service cost	2,817			2,384			49			102
Interest cost	629			491			57			129
Actuarial loss	1,672			360			371			166
Retiree contributions	—			—			56			52
Benefits paid	(657		)	(153		)	(71		)	(75		)
Impact of curtailment	(628		)	—			(2,928		)	—
Benefit obligation at end of year	$	14,636		$	10,803		$	—		$	2,466

Change in plan assets
Fair value of plan assets at beginning of year	$	10,415		$	7,673		$	—		$	—
Transfer to Parent Partnership subsidiary (1)	—			30			—			—
Actual return on plan assets	41			565			—			—
Retiree contributions	—			—			56			52
Employer contributions	5,863			2,300			15			23
Benefits paid	(657		)	(153		)	(71		)	(75		)
Fair value of plan assets at end of year	$	15,662		$	10,415		$	—		$	—

Reconciliation of funded status
Funded status	$	1,026		$	(388	)	$	—		$	(2,466	)
Unrecognized prior service cost	—			(100		)	—			889
Unrecognized actuarial loss	2,514			1,197			—			398
Net amount recognized	$	3,540		$	709		$	—		$	(1,179	)

(1) Indicates transfer of employees from us to another subsidiary of the Parent Partnership.

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

	Pension Benefits		Other Postretirement Benefits

2006	$	14,801	$	—

Plan Assets

Our Parent Partnership 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

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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	%

The Parent Partnership does not expect to make further contributions to its 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 the Company, our Parent Partnership’s 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 18. COMMITMENTS AND CONTINGENCIES

Litigation

In the fall of 1999 and on December 1, 2000, the Company 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 Company and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the Company 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.

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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. We have 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 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

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31, 2005 and 2004, we have an accrued liability of $1.2 million and $1.4 million, respectively, related to sites requiring environmental remediation activities.

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

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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 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-

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Based Rates”) or agreements between shippers and petroleum products and crude oil pipeline companies that the rate is acceptable.

Other

On February 24, 2005, the Company was acquired from DEFS by DFI. The Company owns a 2% general partner interest in our Parent Partnership and is the general partner of our Parent 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 Company 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, we had approximately 22.5 million barrels of products in our 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.

Our Parent Partnership carries insurance coverage consistent with the exposures associated with the nature and scope of its operations. Its current insurance coverage includes (1) commercial general liability insurance for liabilities to third parties for bodily injury and property damage resulting from its 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, the Parent Partnership also carries 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 are allocated a portion of the insurance premiums.

Our Parent Partnership also maintains 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 its operations. The cost of its 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 19. 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. 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 was incorrect. Through our accounting for this excess investment in Centennial as an intangible asset with an indefinite life, we have been testing the amount for impairment on an annual basis as opposed to amortizing it over a determinable life. We determined that it would be more appropriate to account for this excess investment as an intangible asset with a determinable life. As a result, we made non-cash adjustments that reduced the net value of the excess investments in Centennial, and increased amortization expense allocated to our equity earnings. The effect of this restatement caused a $3.1 million and $3.3 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 $4.1 million, of which $3.3 million relates to the first nine months. Additionally, partners’ capital at December 31, 2002, reflects a $2.4 million reduction representing the cumulative effect of this correction for the fiscal year ended December 31, 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.

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	$	169,873	$	(8,875	)	$	160,998
Total assets	$	954,068	$	(8,875	)	$	945,193

Capital:
General partner’s interest	$	2	$	—		$	2
Limited partners’ interest	141,490		(8,875		)	132,615
Total partners’ capital	141,492		(8,875		)	132,617
Total liabilities and partners’ capital	$	954,068	$	(8,875	)	$	945,193

F-37

Income Statement Amounts:

	Years Ended December 31,
	2004			2003

Equity losses as previously reported	$	(3,402	)	$	(4,086	)
Adjustment for amortization of excess investments	(3,142		)	(3,298		)
Equity losses as restated	$	(6,544	)	$	(7,384	)

Net income as previously reported	$	36,625		$	49,481
Adjustment for amortization of excess investments	(3,142		)	(3,298		)
Net income as restated	$	33,483		$	46,183

Cash Flow Amounts;

	Year Ended December 31, 2004
	As Previously Reported		Adjustment			As Restated

Cash flows from operating activities:
Net income	$	36,625	$	(3,142	)	$	33,483
Losses in equity investments, net of distributions	13,715		3,142			16,857

	Year Ended December 31, 2003
	As Previously Reported		Adjustment			As Restated

Cash flows from operating activities:
Net income	$	49,481	$	(3,298	)	$	46,183
Losses in equity investments, net of distributions	9,349		3,298			12,647

NOTE 20. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(as restated)			(as restated)			(as restated)			(as restated)
	(in thousands)
2005 (1)
Operating revenues	$	77,016		$	62,521		$	64,866		$	78,226
Operating income	30,768			14,483			13,815			26,320

Net income as previously reported	22,116			7,902			7,359			18,114
Restatement adjustment	(979		)	(1,138		)	(1,175		)	—
Net income as restated	$	21,137		$	6,764		$	6,184		$	18,114

2004 (1)
Operating revenues	$	73,662		$	61,217		$	67,365		$	72,514
Operating income	25,084			13,821			11,796			17,382

Net income as previously reported	17,209			6,904			4,698			7,814
Restatement adjustment	(540		)	(956		)	(912		)	(734		)
Net income as restated	$	16,669		$	5,948		$	3,786		$	7,080

(1) The quarterly financial information for 2004 and the first three quarters of 2005 reflect the impact of the restatement.

F-38

	Explanatory Note
	Cautionary Note Regarding Forward-Looking Statements

	PART I

ITEMS 1 AND 2.	Business and Properties
ITEM 1A.	Risk Factors
ITEM 3.	Legal Proceedings
ITEM 4.	Submission of Matters to a Vote of Security Holders

	PART II

ITEM 5.	Market for Registrant’s Common Equity and Related Partnership Interest 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 Risks
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 and Related Stockholder Matters
ITEM 13.	Certain Relationships and Related Transactions
ITEM 14.	Principal Accounting Fees and Services

	PART IV

ITEM 15.	Exhibits, Financial Statement Schedules

Consolidated Financial Statements:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2005 and 2004 (as restated)

Consolidated Statements of Income for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)

Consolidated Statements of Partners’ Capital for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)

Notes to Consolidated Financial Statements

Signature	Title	Date

/s/ LEE W. MARSHALL, SR.	Acting Chief Executive Officer	March 1, 2006
Lee W. Marshall, Sr.	of TEPPCO GP, Inc.

/s/ WILLIAM G. MANIAS	Vice President, Chief Financial Officer and	March 1, 2006
William G. Manias	Director of TEPPCO GP, Inc.

/s/ PATRICIA A. TOTTEN	Director of TEPPCO GP, Inc.	March 1, 2006
Particia A. Totten

/s/ LEE W. MARSHALL, SR.
Lee W. Marshall, Sr.
Chief Executive Officer
TEPPCO GP, Inc., General Partner

March 1, 2006

/s/ WILLIAM G. MANIAS
William G. Manias
Vice President and Chief Financial Officer
TEPPCO GP, Inc., General Partner

March 1, 2006

Items 1 and 2. Business and Properties

General

Business Strategy

Properties and Operations

Title to Properties

Capital Expenditures

Regulation

Environmental and Safety Matters

Employees

Available Information

PART II

Overview of Business

Critical Accounting Policies and Estimates

Results of Operations

Financial Condition and Liquidity

Recent Accounting Pronouncements

Item 7A. Quantitative and Qualitative Disclosures About Market Risks

Parent Partnership

EPCO and Affiliates

Duke Energy, DEFS and Affiliates

Procedures For Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor

Basis of Presentation and Principles of Consolidation

Use of Estimates

Business Segments

Revenue Recognition

Cash and Cash Equivalents

Inventories

Property, Plant and Equipment

Asset Retirement Obligations

Capitalization of Interest

Environmental Expenditures

Operating, General and Administrative Expenses

Income Taxes

Comprehensive Income

Use of Derivatives

New Accounting Pronouncements

Parent Partnership

EPCO and Affiliates

Duke Energy, DEFS and Affiliates

Centennial

MB Storage

Senior Notes

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

1994 Long Term Incentive Plan

1999 and 2002 Phantom Unit Plans

2000 Long Term Incentive Plan

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

Plan Assets