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, 2004

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 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 an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o No ý

Documents Incorporated by Reference: None

TABLE OF CONTENTS

	PART I
ITEMS 1.	Business and Properties
AND 2.
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

FORWARD-LOOKING STATEMENTS

The matters discussed in this Report include “forward-looking statements” within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than statements of historical facts, 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. However, 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. 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.

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 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. The Company is 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 holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 30%. TEPPCO GP, as 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 (the “Partnership Agreement”). We reimburse our General Partner and the Company for all reasonable direct and indirect expenses that they incur in managing us.

As used in this Report, “we,” “us,” and “our” means TE Products Pipeline Company, Limited Partnership.

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.”

Effective January 1, 2002, our Parent Partnership realigned its business segments to reflect its entry into the natural gas gathering business and the expanded scope of its natural gas liquids (“NGLs”) operations. As part of this realignment, on May 31, 2002, we transferred our investment in TEPPCO Colorado, LLC (“TEPPCO Colorado”), which fractionates NGLs, to TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”) for the book value of TEPPCO Colorado’s net assets, which was $4.1 million. In connection with the transfer, we received $4.1 million in cash from TEPPCO Midstream. As a result of the transfer, the results of operations of TEPPCO Colorado for the periods presented are reflected as discontinued operations (see Note 18. Discontinued Operations). We have reclassified prior periods presented to reflect the current presentation.

Our strategy is to expand and improve service in our current markets, maintain the integrity of our pipeline systems and pursue growth initiatives that are balanced between internal projects and acquisitions. We intend to leverage the advantages inherent in our pipeline systems to maintain our status as a preferred provider in our market areas. We also intend to grow by acquiring assets, from both third parties and affiliates, which complement existing businesses or by establishing new core businesses. We routinely evaluate opportunities to acquire assets and businesses that will complement existing operations with a view to increasing earnings and cash available for distribution. We may fund additional acquisitions with cash flow from operations, borrowings and capital contributions from our Parent Partnership, the issuance of debt in the capital markets or any combination thereof.

Operations

We own, operate or have investments in properties located in 14 states. We also conduct business through our 50% owned equity investments in Centennial Pipeline LLC (“Centennial”) and Mont Belvieu Storage Partners, L.P. (“MB Storage”). 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.

As an interstate common carrier, our pipeline offers interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined petroleum products and LPGs who requests these services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. In addition to the revenues received by our pipeline system from our interstate tariffs, we also provide storage and other related services at key points along our pipeline systems. Substantially all of the petroleum products transported and stored in our pipeline systems are owned by our customers. Petroleum products are received at terminals located principally on the southern end of the pipeline system, stored, 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. Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of petroleum products. Our pipeline system is the only pipeline that transports LPGs from the upper Texas Gulf Coast to the Northeast.

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. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, governmental 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.

The following table lists the material properties and investments of and ownership percentages in our assets as of December 31, 2004:

	Our Ownership
Refined products and LPGs pipelines	100	%
Mont Belvieu, Texas, to Port Arthur, Texas, petrochemical pipelines	100	%
Centennial Pipeline LLC (1)	50	%
Mont Belvieu Storage Partners, L.P. (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”).

Centennial Pipeline Equity Investment

In August 2000, we entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial. Each participant originally owned a one-third interest in Centennial. 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.

Our interest in Centennial is not subject to any encumbrances from mortgages or other secured debt. Centennial has unsecured debt, one third of which, up to $50.0 million in principal, was originally guaranteed by each owner, including us. 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 percentage ownerships in Centennial to 50% each. We and Marathon have each guaranteed one-half of Centennial’s debt, up to a maximum of $75.0 million each. Through December 31, 2004, including the amount paid for the acquisition of the 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. The purpose of MB Storage is to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. MB Storage is a service-oriented, fee-based venture with 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.

Our interest in MB Storage is not subject to any encumbrances from mortgages or other secured debt. We receive the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the operating agreement. Any amount of MB Storage’s annual income before depreciation expense in excess of $7.15 million is allocated evenly between Louis Dreyfus and us. Depreciation expense on assets each originally contributed to MB Storage is allocated between Louis Dreyfus and us based upon 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 Louis Dreyfus and us. For the years ended December 31, 2004 and 2003, our sharing ratio in the earnings of MB Storage was approximately 69.4% and 70.4%, respectively. For the years ended December 31, 2004 and 2003, excluding the contribution of property and equipment upon formation of the partnership, we have contributed $21.4 million and $2.5 million, respectively, to MB Storage. The 2004 amount includes a contribution of $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures in both periods. During the years ended December 31, 2004 and 2003, we received distributions of $10.3 million and $5.3 million, respectively, from MB Storage.

MB Storage’s asset base in the Mont Belvieu fractionation and storage complex, which is the largest complex of its kind in the United States, serving the fractionation, refining and petrochemical industries, provides substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. MB Storage receives revenue from the shuttling of product from refineries and fractionators to pipelines, refineries and petrochemical facilities on the upper Texas Gulf Coast.

On April 1, 2004, MB Storage acquired storage and pipeline assets at Mont Belvieu from ConocoPhillips for approximately $34.0 million. The acquisition included three salt dome storage wells with a total storage capacity of 5.6 million barrels, various pipeline assets and a 200-acre parcel of property for future expansion. The acquisition

also included 2.6 million barrels of brine storage capacity. The acquisition supports MB Storage’s strategy of increasing the productivity of the Mont Belvieu assets by expanding its product and service base to include the storage and transportation of ethane and the storage of ethylene.

Including the capacity acquired from ConocoPhillips, 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, at the Mont Belvieu fractionation and storage complex. MB Storage includes a short-haul transportation shuttle system, consisting of a complex system of pipelines and interconnects, that ties Mont Belvieu to virtually every refinery and petrochemical facility on the upper Texas Gulf Coast. MB Storage also provides truck and rail car loading capability. Total shuttle volumes for the three years ended December 31, 2004, 2003 and 2002, were 39.3 million barrels, 33.1 million barrels and 28.9 million barrels, respectively.

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 4,500-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. Our Pipeline System includes delivery terminals for outloading product to other pipelines, tank trucks, rail cars or barges, and substantial storage facilities at numerous locations. We also own one active marine receiving terminal at Providence, Rhode Island. The Providence terminal is not physically connected to our Pipeline System. Our Pipeline System also includes three parallel 12-inch diameter petrochemical pipelines between Mont Belvieu and Port Arthur, each approximately 70 miles in length.

All properties comprising our Pipeline System are wholly owned by us and none are mortgaged or encumbered to secure funded debt. We have guaranteed up to $75.0 million of Centennial’s unsecured debt (see Centennial Pipeline Equity Investment above) and have also guaranteed the unsecured debt of our Parent Partnership (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Condition and Liquidity).

Products are transported in liquid form from the upper Texas Gulf Coast through two parallel underground pipelines that extend to Seymour, Indiana. From Seymour, segments of the Pipeline System extend to the Chicago, Illinois; Lima, Ohio; Selkirk, New York; and Philadelphia, Pennsylvania, areas. Our Pipeline System east of Todhunter, Ohio, is dedicated solely to LPGs transportation and storage services, primarily for propane.

Excluding the storage facilities of Centennial and MB Storage, our Pipeline System includes 27 storage facilities with an aggregate storage capacity of 16 million barrels of refined petroleum products and 6 million barrels of LPGs including storage capacity leased to outside parties. Our Pipeline System makes deliveries to customers at 56 locations including 19 truck racks, rail car facilities and marine facilities that we own. Deliveries to other pipelines occur at various facilities owned by third parties or us.

Our 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. A second line, which also originates at Baytown, is 16 inches in diameter until it reaches Beaumont, 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 our Pipeline System’s terminal in El Dorado, Arkansas, before continuing as a 16-inch diameter line to Seymour. Our 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. Our 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. Our Pipeline System also has a 6-inch diameter pipeline connection to the Greater Cincinnati/Northern Kentucky International Airport and an 8-inch diameter pipeline connection to the George Bush Intercontinental Airport in Houston. In addition, our 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.

Our 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). Our 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.

In 2003, we increased the delivery capability between Todhunter, Ohio, and Coshocton, Ohio, by 8,000 to 10,000 barrels per day and increased storage and improved loading capability at Oneonta, New York. In 2004, we also completed a Phase II project to further extend beyond Coshocton our delivery capacity of LPGs to the Northeast by 8,000 to 10,000 barrels per day. The Phase II expansion included the construction of three pump stations between Coshocton and Greensburg, Pennsylvania, and two stations from Greensburg to Watkins Glen, New York. Additional work on the pipeline segment between Greensburg and Philadelphia, Pennsylvania, to increase delivery rates to the Philadelphia area has been completed. Improvements were also completed during the fourth quarter of 2004 at our Dubois, Pennsylvania, terminal, and additional improvements are expected to be completed during the first quarter of 2005 at our Eagle, Pennsylvania, terminal.

We also own three 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 and natural gasoline. We entered into a 20-year agreement in 2002 with a major petrochemical producer for guaranteed throughput commitments. During the years ended December 31, 2004, 2003, and 2002, we recognized $12.0 million, $11.9 million and $11.9 million, respectively, of revenue under the throughput and deficiency contract.

We believe that our Pipeline System is in compliance with applicable federal, state and local laws and regulations and accepted industry standards and practices. We perform regular maintenance on all the facilities of our Pipeline System and have an ongoing process of inspecting our Pipeline System and making repairs and replacements when necessary or appropriate. In addition, we conduct periodic air patrols of our Pipeline System to monitor pipeline integrity and third-party right of way encroachments.

Major Business Sector Markets

Our major operations are 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, 2004, 2003 and 2002, were as follows:

	Years Ended December 31,
	2004	2003	2002
Refined Products Mainline Transportation:
Central (1)	69.0	67.0	62.9
Midwest (2)	53.5	57.7	49.6
Ohio and Kentucky	29.9	29.4	25.7
Subtotal	152.4	154.1	138.2
LPGs Mainline Transportation:
Central, Midwest and Kentucky (1)(2)	27.0	23.4	25.4
Ohio and Northeast (3)	17.0	19.1	15.1
Subtotal	44.0	42.5	40.5
Total Product Deliveries	196.4	196.6	178.7

(1) Arkansas, Louisiana, Missouri and Texas.

(2) Illinois and Indiana.

(3) New York and Pennsylvania.

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. 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.

Refined products and LPGs deliveries in MMBbls for the years ended December 31, 2004, 2003 and 2002, were as follows:

	Years Ended December 31,
	2004	2003	2002
Refined Products Mainline Transportation:
Gasoline	89.3	89.8	81.9
Jet Fuels	25.6	26.4	25.3
Distillates (1)	37.5	37.9	31.0
Subtotal	152.4	154.1	138.2
LPGs Mainline Transportation:
Propane	34.3	34.5	32.9
Butanes	9.7	8.0	7.6
Subtotal	44.0	42.5	40.5
Total Product Deliveries	196.4	196.6	178.7

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

Refined Products Mainline Transportation

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 that we own, connecting pipelines and customer-owned terminals.

The volume of refined petroleum products transported by our Pipeline System is directly affected by the demand for refined products in the geographic regions that our system serves. This market demand varies based upon the different end uses to which the refined products deliveries are applied. Demand for gasoline, which accounted for approximately 59% of the volume of refined products transported through the Pipeline System during 2004, depends upon price, prevailing economic conditions and demographic changes in the markets that 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 depends upon prevailing economic conditions and military usage.

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. As a result, market price volatility may affect transportation volumes and revenues from period to period.

LPGs Mainline Transportation

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

Our ability to serve propane markets in the Northeast is enhanced by our marine import terminal at Providence. This facility includes a 400,000-barrel refrigerated storage tank along with ship unloading and truck loading facilities. Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. The agreement was renegotiated in May 2004. During the years ended December 31, 2004, 2003, and 2002, revenues of $4.3 million, $3.2 million and $2.3 million, respectively, from an affiliate of DEFS were recognized pursuant to this agreement.

Other Operating Revenues

We also earn revenue from terminaling activities and other ancillary services associated with the transportation and storage of refined petroleum products and LPGs. From time to time, we sell excess product inventory. Other operating revenues include revenues related to the intrastate transportation of petrochemicals under a throughput and deficiency contract.

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, as well as utilities who use propane as a back-up fuel source. 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.

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 Ashland Petroleum LLC 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 Ashland Petroleum LLC accounted for approximately 18% of total revenues. During the year ended December 31, 2002, total revenues (and percentage of total revenues) attributable to the top 10 customers were $101.6 million (51%). During the year ended December 31, 2002, no single customer accounted for 10% or more of our total revenues.

Credit Policies and Procedures

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 the years ended December 31, 2004, we expensed a minimal amount of uncollectible receivables. During the years ended December 31, 2003 and 2002, a few small to medium-sized customers filed for bankruptcy protection, and as a result, we expensed approximately $0.8 million and $0.7 million, respectively, of uncollectible receivables related to customer bankruptcies or other non-payments.

Competition

Our 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.

Because pipelines are generally the lowest cost method for intermediate and long-haul overland movement of refined petroleum products and LPGs, our Pipeline System’s most significant competitors (other than indigenous production in our 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 our Pipeline System is competitive with other pipelines serving the same markets; however, comparison of different pipelines is difficult due to varying product mix and operations.

Trucks, barges and railroads competitively deliver products in some of the areas served by our 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 movements of LPGs from Sarnia, Ontario, Canada, and waterborne imports into New Hampshire.

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 customary interests generally contracted in connection 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 $81.3 million for the year ended December 31, 2004. 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, 2004 (in millions):

Revenue generating	$	40.8
Sustaining existing operations	29.4
System upgrades	9.4
Capitalized interest	1.7
Total	$	81.3

Revenue generating capital spending totaled $40.8 million and was used primarily for the expansion of our pipelines extending from Seymour to Indianapolis, Indiana, further expansions of our Northeast pipeline system and construction of a new truck loading terminal in Bossier City, Louisiana. In order to sustain existing operations, we spent $29.4 million for various pipeline projects. An additional $9.4 million was spent on system upgrade projects.

We estimate that capital expenditures, excluding acquisitions, for 2005 will be approximately $59.6 million (which includes $2.3 million of capitalized interest). We expect to spend approximately $22.7 million for revenue generating projects and facility improvements. We expect to spend approximately $20.0 million to sustain existing operations, including life-cycle replacements for equipment at various facilities and pipeline and tank replacements and $14.6 million for various system upgrade projects. 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, 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 FERC’s methodological choices (or combination of choices) was both erroneous and harmful.

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 between shippers and petroleum products pipeline companies 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, an initial decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, et al. 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 of rate base such as tax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rate and income tax allowances as standalone factors. It appears likely that the decision will be appealed. We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.

On July 20, 2004, the Court of Appeals for the District of Columbia Circuit issued an opinion in BP West Coast Producers 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 limited 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 42.7% of the net operating (pre-tax) income expected from operations and was denied an income tax allowance equal to 57.3% of its limited partnership interests that were 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, the FERC on December 2, 2004, issued a Request for Comments seeking comments on whether the court’s ruling applies only to the specific facts of the SFPP, L.P. proceeding or also extends to other capital structures involving partnerships and other forms of ownership. 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 Matters

it is possible that other developments, such as increasingly strict environmental 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. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.

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.

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 assure you 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 appropriate federal agency being either the United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety (“OPS”) or the Environmental Protection Agency (“EPA”). 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.

The 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.

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 requires a regulated source, in excess of threshold quantities, to develop and implement a risk

management program that includes a five-year accident history, an offsite consequence analysis, a prevention program and an emergency response program. We believe the operating expenses of the RMP regulations will not have a material adverse effect on our financial position, results of operations or cash flows.

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. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and gas wastes. The adoption of such stricter standards for non-hazardous wastes, or any future re-designation of non-hazardous wastes as hazardous wastes will likely increase our operating expenses as well as for the industry in general.

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.

Other Environmental Proceedings

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. At December 31, 2004, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. 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 is has accepted shared responsibility. 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. We are in the process of negotiating a final settlement with the State of Illinois, and we do not expect that compliance with the settlement will have a future material adverse effect on our financial position, results of operations or cash flows.

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 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. The maximum statutory penalty calculated for this alleged violation of the CWA is $2.8 million. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. We do not expect a civil penalty, if any, to have a material adverse effect on our financial position, results of operations or cash flows.

At December 31, 2004, we have an accrued liability of $1.4 million related to sites requiring environmental remediation activities. We do not expect that the completion of remediation programs associated with these activities will have a future material adverse effect on our financial position, results of operations or cash flows.

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. The HLPSA was reauthorized in 2002. 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. A written qualification program was completed in April 2001, and our employees performing a covered task were qualified by the October 2002 deadline. 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 with greater than 500 miles of pipeline 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 developed an IMP by the March 31, 2002 deadline. The regulations require that initial HCA baseline integrity assessments must be conducted within seven years, with all subsequent assessments conducted on a five-year cycle. Additionally, 50% of all HCA pipeline miles must be assessed by September 30, 2004. We exceeded this requirement by the imposed deadline. In 2003 and 2004, we continued with the baseline evaluation efforts initiated in 2002 and completed the assessment of approximately 1,300 and 1,360 miles, respectively, of our pipeline system. In accordance with our IMP program, we perform the appropriate repairs following each assessment.

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 a flammable liquid or gas, as defined in the regulations, stored on-site in one location, in a quantity of 10,000 pounds or more. We utilize certain covered processes and maintain storage of LPGs in pressurized tanks, caverns and wells, in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without benefit of chilling or refrigeration are exempt. We believe we are in material compliance with the OSHA regulations.

In general, we expect to increase our expenditures during the next decade to comply with stricter industry and regulatory safety standards such as those described above. While such expenditures cannot be accurately estimated at this time, we do not believe that they will have a future material adverse effect on our financial position, results of operations or cash flows.

Employees

We do not have any employees, officers or directors. The General Partner is responsible for our management. The Company is responsible for the management of our Parent Partnership. As of December 31, 2004, the Company had 1,104 employees. None of the employees of the Company were represented by labor unions, and the Company considers its employee relations to be good.

Available Information

We file annual, quarterly and other reports and other information with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including us.

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

Item 3. Legal Proceedings

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. The settlement terms include a $2.0 million payment to the plaintiffs, which has been accrued for in our consolidated financial statements. The terms of the settlements 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 the 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.

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 has not expired, however, and the settlement will not be final until it does so. If the approved class settlement becomes final, the terms of the settlement will not have a material adverse effect on our financial position, results of operations or cash flows.

On December 16, 2003, Centennial, the Company, the Parent Partnership and other Parent Partnership entities were named as defendants in a lawsuit in the 128th District Court of Orange County, Texas, styled Elwood Karr et al. v. Centennial Pipeline, LLC et al. In this case, the plaintiffs contend that our pipeline leaked toxic substances on their property, causing them property damage. On October 29, 2004, the parties entered into a

Settlement Agreement, dismissing all claims. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

On February 4, 2005, we received a letter notifying us of a claim for approximately $1.45 million in damages allegedly due to a shipper being delivered off-specification gasoline during November 2004. We are contesting liability for this matter, and to the extent there may be liability, we would seek reimbursement from the third party refiner who supplied the gasoline into our pipeline system. We do not believe that the outcome of this matter will have a future material adverse effect on our consolidated 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.

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

None.

PART II

Item 5. Market for Registrant’s Common Equity and Related Partnership Interest Matters

TEPPCO Partners, L.P. owns a 99.999% interest as the sole limited partner interest and TEPPCO GP, Inc. owns a 0.001% general partner interest in us. There is no established public trading market for our ownership interests.

We make periodic distributions of our available cash to our partners. Available cash consists generally of all cash receipts less cash disbursements and cash reserves necessary for working capital, anticipated capital expenditures and contingencies we deem appropriate and necessary.

We are a limited partnership, and we are not subject to federal income tax. Instead, the partners are required to report their allocable share of our income, gain, loss, deduction and credit, regardless of whether we make distributions.

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 financial data was derived from our consolidated financial statements and 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,
	2004			2003			2002			2001			2000
	(in thousands)
Income Statement Data: (1)
Operating revenues:
Transportation – refined products	$	148,166		$	138,926		$	123,476		$	139,315		$	119,331
Transportation – LPGs	87,050			91,787			74,577			77,823			73,896
Mont Belvieu operations	—			—			15,238			14,116			13,334
Other	39,542			31,254			30,247			32,979			22,673
Total operating revenues	274,758			261,967			243,538			264,233			229,234
Operating expenses	164,994			150,341			130,324			119,856			118,065
Depreciation and amortization	42,207			31,066			30,116			26,699			25,728
Gains on sales of assets	(526		)	—			—			—			—
Operating income	68,083			80,560			83,098			117,678			85,441
Interest expense – net	(28,843		)	(27,219		)	(22,742		)	(27,044		)	(27,529		)
Equity losses	(3,402		)	(4,086		)	(6,815		)	(1,149		)	—
Other income – net	787			226			832			1,537			1,651
Income before discontinued operations	36,625			49,481			54,373			91,022			59,563
Income from discontinued operations (2)	—			—			912			1,674			1,751
Net income	$	36,625		$	49,481		$	55,285		$	92,696		$	61,314

	December 31,
	2004		2003		2002		2001		2000
	(in thousands)
Balance Sheet Data: (1)
Property, plant and equipment – net	$	722,334	$	682,385	$	722,848	$	697,178	$	640,656
Total assets	955,144		900,648		881,101		879,834		755,507
Long-term debt (net of current maturities)	695,003		603,478		557,521		420,594		437,820
Total debt	695,003		603,478		557,521		493,084		437,820
Partners’ capital	141,492		222,788		242,739		270,112		234,915

	Years Ended December 31,
	2004			2003			2002			2001			2000
	(in thousands)
Cash Flow Data: (1)
Net cash provided by operating activities	$	132,894		$	96,088		$	107,600		$	123,070		$	87,456
Capital expenditures to sustain existing operations	(29,372		)	(18,169		)	(13,592		)	(12,724		)	(15,402		)
Distributions paid	(117,967		)	(106,465		)	(94,921		)	(80,914		)	(70,767		)

(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.

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

The following information is intended to provide investors with an increased understanding of our 2004, 2003 and 2002 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 and 2004 Results.

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

Overview of Business and 2004 Results

TE Products Pipeline Company, Limited Partnership, a Delaware limited partnership, was formed in March 1990. TEPPCO Partners, L.P. owns a 99.999% interest in us as the sole limited partner. TEPPCO GP, a subsidiary of the Parent Partnership, holds a 0.001% General Partner interest in us. Texas Eastern Products Pipeline Company, LLC, a Delaware limited liability company, serves as the general partner of our Parent Partnership. The Company is an indirect wholly owned subsidiary of Duke Energy Field Services, LLC, a joint venture between Duke Energy and ConocoPhillips. Duke Energy holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 30%. TEPPCO GP, as general partner, performs all of our management and operating functions required according to 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.

We are one of three operating subsidiaries of our Parent Partnership. Our Parent Partnership is managed by its general partner, the Company, which has approximately 1,000 employees dedicated to the operations and management of the operating subsidiaries. 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. We believe that the method for allocating corporate operating, general and administrative expenses to us is reasonable.

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 5. Equity Investments).

We are subject to economic and other factors that affect our industry. 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 which have an effect on the amounts we are allowed to charge our customers for the services we provide on our regulated pipeline systems.

Certain factors are inherent in our business as discussed in this Report. 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.

Our net income for the year ended December 31, 2004, was $36.6 million, compared with $49.5 million for the year ended December 31, 2003. We had increased revenues from our refined products business, and we recognized $4.1 million of deferred revenue, despite the impact of challenging market conditions for both our refined products and LPG movements. We have continued to utilize Centennial’s capacity in a manner that has provided additional delivery capability for our customers. Centennial has provided additional capacity through our lease agreement, enabling us to transport additional refined product volumes in 2004. During the third quarter of 2004, Centennial was able to transport jet fuel for the first time. These increases were partially offset by higher pipeline integrity expenses of $6.2 million and an asset impairment charge of $4.4 million related to a marine facility in Beaumont, Texas.

Our costs were higher than expected, largely as a result of pipeline integrity expenses. The goal of our on-going pipeline integrity program has always been to maintain the long-term reliability and safety of our pipeline systems, while minimizing the impact to our customers. Our operating costs were also impacted by increased consulting and contract services of $1.3 million related to compliance with the Sarbanes-Oxley Act of 2002. During the year, we spent $40.8 million on revenue generating capital projects, which we believe will provide earnings, cash flow and growth opportunities. We funded these projects by cash generated from operations and from our Parent Partnership’s credit facilities.

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. Among the highlights of 2004:

• During the fourth quarter of 2004, we completed a Phase II project to further extend beyond Coshocton, Ohio, our delivery capacity of LPGs to the Northeast by 8,000 to 10,000 barrels per day. The Phase II expansion included the construction of three pump stations between Coshocton and Greensburg, Pennsylvania, and two stations from Greensburg to Watkins Glen, New York. Additional work on the pipeline segment between Greensburg and Philadelphia, Pennsylvania, to increase delivery rates to the Philadelphia area has been completed. Improvements were also completed during the fourth quarter of 2004 at our Dubois, Pennsylvania, terminal, and additional improvements are expected to be completed during the first quarter of 2005 at our Eagle, Pennsylvania, terminal.

• MB Storage acquired salt dome storage and LPGs pipeline assets in Mont Belvieu, Texas, that will enable future expansion and provide a broader platform for growth.

• We are in the process of constructing a new refined products truck loading terminal in Bossier City, Louisiana, to provide the Shreveport, Louisiana, and East Texas markets with access to Gulf Coast sourced gasoline and diesel fuel. The terminal is scheduled to be complete in the first quarter of 2005.

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

We remain confident that our current strategy and focus will provide continued growth in earnings and cash distributions. With respect to 2005, these opportunities include continued growth of our business, resulting from our recent expansion and grass roots facility investments and growing demand for Gulf Coast sourced products.

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. Summary of Significant Accounting Policies).

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 about the effect of matters that are inherently uncertain. Our most critical accounting policies pertain to revenue and expense accruals, environmental costs and property, plant and equipment.

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 received 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, 2004, approximately 13% of our power costs are recorded using estimates. A variance of 10% in our aggregate estimate for power costs would have an approximate $0.4 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 $0.6 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, 2004, we have accrued a liability of $1.4 million for our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs 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 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. 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. Estimates of future net cash flows include anticipated future revenues, expected future operating costs and other estimates. 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.

Results of Operations

The following table presents volumes delivered in barrels and average tariff per barrel for the years ended December 31, 2004, 2003 and 2002 (in thousands, except tariff information):

	Years Ended December 31,						Percentage Increase (Decrease)
	2004		2003		2002		2004		2003
Volumes Delivered:
Refined products	152,437		154,061		138,164		(1	)%	12	%
LPGs	43,982		42,543		40,490		3	%	5	%
Total	196,419		196,604		178,654		—		10	%

Average Tariff per Barrel:
Refined products	$	0.97	$	0.90	$	0.89	8	%	1	%
LPGs	1.98		2.16		1.84		(8	)%	17	%
Average system tariff per barrel	$	1.20	$	1.17	$	1.11	3	%	5	%

We are dependent in large part on the demand for refined petroleum products in the markets served by our pipelines. Reductions in that demand adversely affect our pipeline business. Market demand varies based upon the different end uses of the refined products we ship. Demand for gasoline, which in recent years has accounted for approximately one-half 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 one-quarter 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, 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. 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.

Refined products transportation revenues also increased due to the recognition of $4.1 million of deferred revenue 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 the current period. This additional revenue increased the refined products average tariff for the year ended December 31, 2004, by $0.02 per barrel, or 2%.

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 17. Commitments and Contingencies), a $1.5 million increase in rental expense from the Centennial pipeline capacity lease agreement that we entered into in February 2003, a $1.3 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002 and a $1.1 million increase in costs related to unsuccessful acquisition evaluations. These increases were partially offset by $0.8 million of lower expenses in the 2004 period associated with the write-off of receivables related to customer bankruptcies and non-payments in 2003. Depreciation expense increased from the prior year period because of a $4.4 million charge resulting from the impairment of marine assets in the Beaumont area (see Note 9. Property, Plant and Equipment). 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.

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.

Net losses from equity investments decreased $0.7 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,						Increase
	2004			2003			(Decrease)

Centennial	$	(11,237	)	$	(11,373	)	$	136
MB Storage	7,874			7,354			520
Other	(39		)	(67		)	28
Total equity losses	$	(3,402	)	$	(4,086	)	$	684

Equity losses in Centennial for the year ended December 31, 2004, compared with the year ended December 31, 2003, decreased $0.1 million, 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 from our 50% ownership interest 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 $34.0 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.

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.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Revenues from refined products transportation increased $15.5 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to an overall increase of 12% in the refined products volumes delivered. This increase in volumes delivered was primarily due to deliveries of products received into our pipeline from Centennial at Creal Springs, Illinois. Centennial, which began operations in April 2002, has provided our system with additional pipeline capacity for products originating in the U.S. Gulf Coast area. In February 2003, we entered into a lease agreement with Centennial that increased our capacity to deliver refined products to our market areas. Prior to the lease agreement with Centennial, deliveries on our pipeline system were based upon a proration policy, which limited customer transportation. During 2003, with the expanded capacity through our lease agreement with Centennial, our pipeline system was not prorated during portions of 2003 and was better able to serve markets which increased transportation on our system. In addition, in December 2002, we raised the operating pressure of our Chicago lateral pipeline which resulted in an increase in capacity for deliveries into the Indianapolis and Chicago markets. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs. 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 increased 1% from the prior year period primarily due higher market-based tariff rates which went into effect in July 2003, partially offset by the impact of the Midwest origin point for barrels received from Centennial, which resulted in an increase in short-haul barrels transported on our system.

Revenues from LPGs transportation increased $17.2 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to increased deliveries of propane in the upper Midwest and Northeast market areas attributable to colder than normal weather during the first quarter of 2003 and due to low inventories at competing supply locations during the second and third quarters of 2003. The U.S. Gulf Coast had higher propane inventory during 2003 as compared to the previous year because of higher than normal foreign propane imports at Mont Belvieu, which resulted in a lower propane price in this market area. This lower price contributed to increased transportation deliveries to the mid-continent market areas. Additional pipeline capacity for expanded propane movements was available due to a shift of refined product volumes to Centennial. Butane deliveries also increased due to the increased demand by refineries for normal butane for use in gasoline blending and increased isobutane deliveries to Chicago area refineries. The LPGs average rate per barrel increased 17% from the prior year period as a result of an increased percentage of long-haul deliveries during the year ended December 31, 2003, and an increase in LPG tariff rates, which went into effect in July 2003.

Effective January 1, 2003, our 50% ownership interest in MB Storage is accounted for as an equity investment. Revenues and expenses related to Mont Belvieu operations are now recorded within equity earnings. See discussion regarding changes in equity earnings/losses below.

Other operating revenues increased $1.0 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to higher propane deliveries at our Providence, Rhode Island import facility and higher refined product loading fees, partially offset by lower revenues from product location exchanges which are used to position product in the Midwest market area and lower volume of product inventory sales.

Costs and expenses increased $21.0 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to increased operating, general and administrative expenses and increased depreciation and amortization expense, partially offset by decreased taxes – other than income taxes and decreased operating fuel and power. Operating, general and administrative expenses increased primarily due to higher pipeline maintenance expenses, due in part to pipeline rehabilitation expenses associated with our integrity management program, increased consulting and contract services, increased labor costs primarily due to an increase in the number of employees between years, increased insurance expense, expense from the Centennial pipeline capacity lease agreement that we entered into in 2003 and the write-off of receivables of $0.8 million related to customer bankruptcies or other customer non-payments. Depreciation and amortization expense increased from the prior year period because of assets placed in service during the year. In addition, we wrote off assets taken out of service during the period to depreciation expense, which also increased depreciation expense. These increases in depreciation expense were partially offset by lower depreciation expense from assets retired during the year, which reduced the asset base, and due to the transfer of assets to MB Storage. Taxes – other than income taxes decreased as a result of actual property taxes being lower than previously estimated and due to the transfer of assets to MB Storage. Operating fuel and power expense decreased as a result of lower power costs due to a slight decrease in the price of natural gas, partially offset by increased mainline throughput.

Interest expense increased $3.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, as a result of higher outstanding debt balances under the note payable with our Parent Partnership, and an increased percentage of fixed-rate debt in 2003 by the Parent Partnership. Interest capitalized decreased $0.9 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, as a result of decreased construction work-in-progress balances.

Net losses from equity investments decreased $2.7 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, as shown below (in thousands):

	Years Ended December 31,						Increase
	2003			2002			(Decrease)
Centennial	$	(11,373	)	$	(6,716	)	$	(4,657	)
MB Storage	7,354			—			7,354
Other	(67		)	(99		)	32
Total equity losses	$	(4,086	)	$	(6,815	)	$	2,729

Other income – net increased $0.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to lower interest income earned on cash investments.

Discontinued Operations

Effective January 1, 2002, our Parent Partnership realigned its business segments to reflect its entry into the natural gas gathering business and the expanded scope of its NGLs operations. As part of this realignment, on May 31, 2002, we entered into an Assignment and Assumption Agreement with TEPPCO Midstream to transfer our investment in TEPPCO Colorado, which fractionates NGLs, to TEPPCO Midstream at the book value of TEPPCO Colorado’s net assets (see Note 18. Discontinued Operations). SFAS 144 requires that long-lived assets to be disposed of should be recorded at the lower of their carrying amount or fair value less costs to sell. As a result, in the quarter ended June 30, 2002, we compared the fair value of TEPPCO Colorado to its carrying value and noted no indication of impairment.

As a result of the transfer, our financial position and results of operations have been reclassified to reflect revenue, expenses, assets and liabilities of TEPPCO Colorado as discontinued operations. A condensed statement of income is shown below for TEPPCO Colorado for the year ended December 31, 2002 (in thousands):

Revenues	$	3,115
Operating, general and administrative	369
Depreciation and amortization	840
Operating income	1,906

Interest expense	(1,015		)
Other income – net	21
Net income	$	912

The following table presents volumes fractionated and average rate per barrel for TEPPCO Colorado for the year ended December 31, 2002:

Fractionation – NGLs:
Thousand barrels	2,043
Average rate per barrel	$	1.827

Financial Condition and Liquidity

Cash flows for the years ended December 31, 2004, 2003 and 2002, were as follows (in millions):

	Years Ended December 31,
	2004			2003			2002
Cash provided by (used in):
Operating activities	$	132.9		$	96.1		$	107.6
Investing activities	(105.5		)	(84.2		)	(64.3		)
Financing activities	(27.6		)	(12.2		)	(46.5		)

Operating Activities

Net cash from operating activities for the years ended December 31, 2004, 2003 and 2002, were comprised of the following (in millions):

	Years Ended December 31,
	2004			2003		2002
Net income	$	36.6		$	49.5	$	54.4
Depreciation and amortization	42.2			31.1		30.1
Losses in equity investments	3.4			4.1		6.8
Distributions from equity investments	10.3			5.3		—
Gains on sales of assets	(0.5		)	—		—
Non-cash portion of interest expense	0.1			0.1		0.1
Cash provided by working capital and other	40.8			6.0		15.0
Net cash provided by continuing operations	132.9			96.1		106.4
Net cash provided by discontinued operations	—			—		1.2
Net cash from operating activities	$	132.9		$	96.1	$	107.6

For a discussion of changes in net income, depreciation and amortization and equity earnings, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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. Cash provided by operating activities decreased for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to the timing of cash disbursements and cash receipts for working capital components and lower net income, partially offset by an increase of $5.3 million in distributions received from our equity investment in MB Storage during the year ended December 31, 2003, and lower losses in equity investments.

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 and on borrowings under our Parent Partnership’s credit facilities and distributions to our Parent Partnership. Short-term cash requirements, such as operating expenses, quarterly distributions to our Parent Partnership and a portion of capital expenditures are expected to be funded through operating cash flows. Borrowings under our Parent Partnership’s credit facilities and the issuance by our Parent Partnership of additional equity and debt securities are expected to be used for our remaining cash requirements. 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.

At December 31, 2004 and 2003, we had working capital deficits of $61.9 million and $12.3 million, respectively. Cash generated from operations and from our Parent Partnership’s credit facilities and debt and equity offerings are our primary sources of liquidity. Working capital deficits can occur primarily due to the timing of operating cash receipts from customers, payments of cash distribution 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, 2004, our Parent Partnership had approximately $132.0 million in available borrowing capacity under its revolving credit facility 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, 2004.

Net cash from operating activities for the years ended December 31, 2004, 2003 and 2002, included interest payments, net of amounts capitalized, of $27.3 million, $30.3 million and $25.0 million, respectively. Excluding the effects of hedging activities and interest capitalized, during the year ended December 31, 2005, 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 $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, $21.4 million of cash contributions to MB Storage and $1.9 million for the acquisition of assets acquired 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 and $2.5 million of cash contributions to MB Storage. These uses of cash were partially offset by $0.7 million received on matured cash investments. Cash flows used in investing activities totaled $64.3 million for the year ended December 31, 2002, and were comprised of $60.9 million of capital expenditures and $10.9 million of cash contributions to Centennial, partially offset by $3.4

million of cash proceeds from the sale of assets and $4.1 million of cash proceeds from the sale of TEPPCO Colorado.

Financing Activities

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. Cash flows used in financing activities totaled $46.5 million for the year ended December 31, 2002, and were comprised of $94.9 million of distributions paid to our Parent Partnership and $150.0 million of repayments on our term loan, partially offset by $186.1 million of proceeds from our term loan and $12.3 million of equity contributions received from our Parent Partnership.

Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2004, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. We and Marathon have each guaranteed one-half of Centennial’s debt, up to a maximum of $75.0 million each.

Parent Partnership 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 agreements. 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 respective credit agreements. These credit facilities of the Parent Partnership are described below.

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

On June 27, 2003, our Parent Partnership entered into a $550.0 million revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). The interest rate is based, at our Parent Partnership’s 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. Our Parent Partnership borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. 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 December 31, 2004, $353.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 3.0%.

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.

At December 31, 2004 and 2003, we had intercompany notes payable to our Parent Partnership of $301.7 million and $211.3 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, 2004, was 4.9%. At December 31, 2004, accrued interest includes $4.5 million due to our Parent Partnership. For the years ended December 31, 2004 and 2003, interest costs incurred on the note payable to our Parent Partnership totaled $12.5 million and $11.1 million, respectively.

Cash Distributions

For the years ended December 31, 2004, 2003 and 2002, cash distributions paid to our Parent Partnership totaled $118.0 million, $106.5 million and $94.9 million, respectively. On February 7, 2005, we paid a cash distribution to our Parent Partnership of $29.7 million for the quarter ended December 31, 2004.

Future Capital Needs and Commitments

Our debt repayment obligations consist of payments for principal and interest on (i) our $180.0 million 6.45% Senior Notes due January 15, 2008, (ii) $301.7 million principal amount due to the Parent Partnership related to our share of the Parent Partnership’s Revolving Credit Facility due in October 2009, 7.625% Senior Notes due in February 2012 and 6.125% Senior Notes due in February 2013, and (iii) our $210.0 million 7.51% Senior Notes due January 15, 2028.

We are also contingently liable as guarantor for the lesser of one-half or $75.0 million principal amount (plus interest) of the borrowings of 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. During the year ended December 31, 2004, we exceeded the minimum throughput requirements on the lease agreements. On February 10, 2003, we acquired an additional 16.7% interest in Centennial, bringing our ownership percentage to 50%. We are also 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.

During the years ended December 31, 2004, 2003 and 2002, we contributed $1.5 million, $4.0 million and $10.9 million, respectively, to Centennial to cover operating needs and capital expenditures. During the years ended December 31, 2004 and 2003, we contributed $21.4 million to MB Storage, of which $16.5 million was used for its acquisition of storage and pipeline assets in April 2004, and $2.5 million, respectively, for capital expenditures. During 2005, 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.

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 the Centennial debt, the Parent Partnership debt and leases covering assets utilized in several areas of our operations.

Contractual Obligations

The following table summarizes our debt repayment obligations and material contractual commitments as of December 31, 2004 (in millions):

	Amount of Commitment Expiration Per Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Note payable, Parent Partnership	$	301.7	$	—	$	—	$	301.7	$	—
6.45% Senior Notes due 2008 (1)	180.0		—		—		180.0		—
7.51% Senior Notes due 2028 (1)	210.0		—		—		—		210.0
Debt subtotal	691.7		—		—		481.7		210.0

Operating leases	59.6		12.1		21.2		9.9		16.4
Capital expenditure obligations (2)	1.6		1.6		—		—		—
Other liabilities and deferred credits (3)	0.7		—		0.6		0.1		—
Total	$	753.6	$	13.7	$	21.8	$	491.7	$	226.4

(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, 2004, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $3.4 million related to this interest rate swap agreement. At December 31, 2004, our 6.45% Senior Notes include $0.1 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and the unamortized debt discounts are excluded from this table.

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

(3) Excludes approximately $9.3 million of long-term deferred revenue payments, which are being transferred to income over the term of the respective revenue contracts. 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, contributions from our Parent Partnership or any combination of the above items.

Sources of Future Capital

We expect that our cash flow from operating activities will be adequate to fund cash distributions and capital additions necessary to sustain existing operations. However, expansionary capital projects and acquisitions may require additional capital contributions from our Parent Partnership. The Parent Partnership has funded its capital commitments from operating cash flow, borrowings under bank credit facilities, the issuance of long term debt in capital markets and the public offering of Limited Partner Units. We expect future capital needs would be similarly funded.

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. At December 31, 2004, our Parent Partnership has $2.0 billion available under this shelf registration, subject to customary marketing terms and conditions.

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”). Our senior unsecured debt is also rated BBB by S&P and Baa3 by Moody’s. Both ratings are stable. 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.

Other Considerations

Credit Risks

Risks of non-payment and nonperformance by customers are a major consideration in our business. Our credit procedures and policies do not fully eliminate customer credit risk. During the year ended December 31, 2004, we expensed a minimal amount of uncollectible receivables. During the years ended December 31, 2003, and 2002, a few small to medium-sized customers filed for bankruptcy protection, and as a result, we expensed approximately $0.8 million and $0.7 million, respectively, of uncollectible receivables due to customer bankruptcies and other customer non-payments.

Terrorist Threats

On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, could be a future target of terrorist organizations. These developments have subjected our operations to increased risks. Any terrorist attack on our facilities, customers’ facilities and, in some cases, those of other pipelines, could have a material adverse effect on our business. We have increased security initiatives and are working with various governmental agencies to minimize risks associated with additional terrorist attacks.

Environmental

Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. 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. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental 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. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.

In 1994, the LDEQ issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. At December 31, 2004, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. 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. 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 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 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 settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

On July 27, 2004, we received notice from the United States 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. The maximum statutory penalty calculated for this alleged violation of the CWA is $2.8 million. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. We do not expect a civil penalty, if any, to have a material adverse effect on our financial position, results of operations or cash flows.

At December 31, 2004, we have an accrued liability of $1.4 million related to various sites requiring environmental remediation activities. We do not expect that the completion of remediation programs associated with these activities will have a future material adverse effect on our financial position, results of operations or cash flows.

Recent Accounting Pronouncements

See discussion of new accounting pronouncements in Note 2. Summary of Significant Accounting Policies - New Accounting Pronouncements in the accompanying consolidated financial statements.

Disclosures About Effects of Transactions with Related Parties

We have no employees and are managed by TEPPCO GP, a wholly owned subsidiary of our Parent Partnership. The Parent Partnership is managed by the Company, which is an indirect wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 30%. See Item 10. Directors and Executive Officers of the Registrant and Item 13. Certain Relationships and Related Transactions for discussion regarding transactions between us, our Parent Partnership, DEFS, Duke Energy and ConocoPhillips.

Subsequent Event

On February 24, 2005, Texas Eastern Products Pipeline Company, LLC, the General Partner of our Parent Partnership, was acquired by EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan. The acquisition was valued at $1.1 billion. Additionally, in a separate transaction, EPCO and its affiliates have agreed to purchase 2.5 million of our Parent Partnership’s Limited Partner Units, valued at approximately $100.0 million, from Duke Energy. EPCO and its affiliates own the general partner of Enterprise Products Partners L.P. (“Enterprise”) and approximately 145 million Enterprise common units. Enterprise is one of the largest publicly traded master limited partnerships. The general partners of both our Parent Partnership and Enterprise will continue to operate independently and will maintain separate boards of directors, management teams and offices.

Item 7A. Quantitative and Qualitative Disclosures About Market Risks

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.

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 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. The interest rate swap agreement involves 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.

At December 31, 2004, we had outstanding $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. At December 31, 2004, the estimated fair values of the 6.45% Senior Notes and 7.51% Senior Notes were approximately $187.1 million and $225.6 million, respectively.

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 the 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, 2004, 2003 and 2002, we recognized reductions in interest expense of $9.6 million, $10.0 million and $8.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended December 31, 2004, 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 gain of approximately $3.4 million at December 31, 2004, and a gain of approximately $2.3 million at December 31, 2003. Utilizing the balance of our 7.51% Senior Notes outstanding at December 31, 2004, 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.

As of December 31, 2004 and 2003, we had intercompany notes payable to our Parent Partnership of $301.7 million and $211.3 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, 2004, was 4.9%. At December 31, 2004, accrued interest includes $4.5 million due to our Parent Partnership. For the years ended December 31, 2004 and 2003, interest costs incurred on the note payable to our Parent Partnership totaled $12.5 million and $11.1 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

The principal executive officer and principal financial officer of our General Partner, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2004, have concluded that, as of such date, our disclosure controls and procedures are adequate and effective to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. As a result, no corrective actions were required or undertaken.

Item 9B. Other Information

None.

PART III

Item 10. Directors and Executive Officers of the Registrant

We do not have employees, officers or directors, as is commonly the case with publicly traded partnerships. Our operations and activities are managed by the General Partner, an indirect wholly owned subsidiary of our Parent Partnership. All officers and directors of the General Partner are appointed annually by the Parent Partnership by action of the board of directors of the Company. The directors of the General Partner, TEPPCO GP, are Barry R. Pearl, James C. Ruth and Charles H. Leonard. 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, 2004 (the “Parent Partnership Form 10-K”), and is incorporated by reference in this Report.

Item 11. Executive Compensation

We do not have any employees, officers or directors, and the General Partner manages and operates our business. The Executive Officers of the General Partner are employees of the Company. Certain employees of the Company may devote all or a portion of their time to us, and we reimburse the Company 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

Our Management

We have no employees, and we are managed by TEPPCO GP, a wholly owned subsidiary of our Parent Partnership. The Parent Partnership is managed by the Company, which is an indirect wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 30%. 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.

For the years ended December 31, 2004, 2003 and 2002, we incurred direct expenses of $45.5 million, $48.1 million and $46.6 million, respectively, which were charged to us by DEFS. Substantially all of these costs were related to payroll and payroll related expenses. For the years ended December 31, 2004, 2003 and 2002, expenses for administrative services and overhead allocated to us by the Company (including Duke Energy and its affiliates) were $0.4 million, $1.0 million and $0.8 million, respectively.

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, 2004 and 2003, we had net payables of $63.0 million and $8.9 million, respectively, to the Parent Partnership related to these affiliated activities.

Transactions with DEFS

Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado received a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $3.1 million for the year ended December 31, 2002. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operated and maintained the fractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado paid DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.4 million for the year ended December 31, 2002. On May 31, 2002, TEPPCO Colorado was transferred to TEPPCO Midstream.

Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. The agreement was renegotiated in May 2004. During the years ended December 31, 2004, 2003 and 2002, revenues of $4.3 million, $3.2 million and $2.3 million, respectively, from an affiliate of DEFS were recognized pursuant to this agreement.

At December 31, 2004 and 2003, we had receivables from DEFS of $1.1 million and $0.2 million, respectively, related to revenues recognized from DEFS. At December 31, 2004 and 2003, we had payables to DEFS of $0.7 million and $0.8 million, respectively, related to administrative services provided by DEFS.

The Parent Partnership contracts with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers insurance coverage. For the years ended December 31, 2004, 2003 and 2002, we incurred insurance expense related to premiums paid to Bison of $2.8 million, $2.6 million and $1.9 million, respectively. At December 31, 2004 and 2003, we had insurance reimbursement receivables due from Bison of $4.5 million and $4.2 million, respectively.

Interests of Duke Energy in the Parent Partnership

In connection with the formation of our Parent Partnership, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to the Parent Partnership’s Limited Partner Units and are treated as Limited Partner Units. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. Pursuant to our Parent Partnership’s Partnership Agreement, the Parent Partnership has registered the resale by Duke Energy of these Limited Partner Units with the SEC. As of December 31, 2004, none of the Limited Partner Units had been sold by Duke Energy.

On February 24, 2005, the General Partner of our Parent Partnership was acquired by EPCO, a privately held company controlled by Dan L. Duncan. Additionally, in a separate transaction, EPCO and its affiliates have agreed to purchase the 2.5 million Units from Duke Energy, valued at approximately $100.0 million (see Note 20. Subsequent Event).

Item 14. Principal Accounting Fees and Services

Our Parent Partnership’s audit engagement with KPMG includes the fees for the professional audit 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. Summary of Significant Accounting Policies).

The following table describes fees for professional audit 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, 2004 and 2003, and for fees billed for other services rendered by KPMG during those periods (in thousands):

	Years Ended December 31,
Type of Fee	2004		2003
Audit Fees (1)	$	2,079	$	953
Audit Related Fees (2)	21		58
Tax Fees (3)	88		183
All Other Fees (4)	—		656
Total	$	2,188	$	1,850

(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.

(4) All Other Fees include the aggregate fees our Parent Partnership paid during the year ended December 31, 2003, for products and services provided by KPMG, other than the services reported above. The majority of the other fees are fees in 2003 for litigation support services related to the Parent Partnership’s legal proceedings.

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

Pursuant to its charter, the Audit Committee of the Parent Partnership’s Board of Directors 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 to conduct our audit was approved by the Parent Partnership’s Audit Committee on April 26, 2004. Additionally, all permissible non-audit engagements with KPMG and the Parent Partnership have been reviewed and approved by the Parent Partnership’s Audit Committee, pursuant to pre-approval policies and procedures established by the Parent Partnership’s Audit 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 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+		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).
10.7+		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).
10.8+		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).
10.9+		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).
10.10+		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).
10.11		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).
10.12		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).
10.13+		Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
10.14+		TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
10.15		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 13, 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 10.41 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 10.42 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).
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.

	TE Products Pipeline Company, Limited Partnership
		(Registrant)
		(A Delaware Limited Partnership)

		By:	TEPPCO GP, Inc.,
			as General Partner

		By:	/s/ BARRY R. PEARL
			Barry R. Pearl,
			President, Chief Executive
			Officer and Director

		By:	/s/ CHARLES H. LEONARD
		Charles H. Leonard,
		Senior Vice President, Chief Financial
		Officer and Director

Dated: March 2, 2005

CONSOLIDATED FINANCIAL STATEMENTS

OF TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Financial Statements:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2004 and 2003

Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

Consolidated Statements of Partners’ Capital for the years ended December 31, 2004, 2003 and 2002

Notes to Consolidated Financial Statements

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

TE Products Pipeline Company, Limited Partnership:

We have audited the accompanying consolidated balance sheets of TE Products Pipeline Company, Limited Partnership as of December 31, 2004 and 2003, and the related consolidated statements of income, cash flows and partners’ capital for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TE Products Pipeline Company, Limited Partnership as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

KPMG LLP

Houston, Texas

February 24, 2005

F-2

TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2004		2003
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	188
Accounts receivable, trade (net of allowance for doubtful accounts of $56 and $374)	21,090		25,377
Accounts receivable, related parties	3,455		154
Inventories	10,093		11,186
Other	12,143		10,230
Total current assets	46,781		47,135
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $311,197 and $279,395)	722,334		682,385
Equity investments	169,873		155,861
Other assets	16,156		15,267
Total assets	$	955,144	$	900,648

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable and accrued liabilities	$	10,211	$	9,710
Accounts payable, related parties	66,451		12,277
Accrued interest	17,063		15,877
Other accrued taxes	5,605		5,732
Other	9,339		15,791
Total current liabilities	108,669		59,387
Senior Notes	393,317		392,164
Note payable, Parent Partnership	301,686		211,314
Other liabilities and deferred credits	9,980		14,995
Commitments and contingencies
Partners’ capital:
General partner’s interest	2		2
Limited partner’s interest	141,490		222,786
Total partners’ capital	141,492		222,788
Total liabilities and partners’ capital	$	955,144	$	900,648

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,
	2004			2003			2002
Operating revenues:
Transportation – Refined products	$	148,166		$	138,926		$	123,476
Transportation – LPGs	87,050			91,787			74,577
Mont Belvieu operations	—			—			15,238
Other	39,542			31,254			30,247
Total operating revenues	274,758			261,967			243,538

Costs and expenses:
Operating, general and administrative	124,496			112,683			90,034
Operating fuel and power	31,588			28,792			28,998
Depreciation and amortization	42,207			31,066			30,116
Taxes – other than income taxes	8,910			8,866			11,292
Gains on sales of assets	(526		)	—			—
Total costs and expenses	206,675			181,407			160,440

Operating income	68,083			80,560			83,098

Interest expense – net	(28,843		)	(27,219		)	(22,742		)
Equity losses	(3,402		)	(4,086		)	(6,815		)
Other income – net	787			226			832
Income before discontinued operations	36,625			49,481			54,373

Income from discontinued operations	—			—			912
Net income	$	36,625		$	49,481		$	55,285

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,
	2004			2003			2002
Cash flows from operating activities:
Net income from continuing operations	$	36,625		$	49,481		$	54,373
Adjustments to reconcile net income from continuing operations to cash provided by operating activities:
Depreciation and amortization	42,207			31,066			30,116
Losses in equity investments, net of distributions	13,715			9,349			6,815
Non-cash portion of interest expense	30			31			31
Gains on sales of assets	(526		)	—			—
Decrease (increase) in accounts receivable	4,287			(1,334		)	(3,402		)
Decrease (increase) in inventories	1,093			552			(3,182		)
(Increase) decrease in other current assets	(1,913		)	959			(369		)
(Decrease) increase in accounts payable and accrued expenses	(5,013		)	(9,689		)	7,265
Other	42,389			15,673			14,775
Net cash provided by continuing operations	132,894			96,088			106,422
Net cash provided by discontinued operations	—			—			1,178
Net cash provided by operating activities	132,894			96,088			107,600

Cash flows from investing activities:
Proceeds from cash investments	—			750			—
Proceeds from sales of assets	594			—			3,380
Proceeds from sale of TEPPCO Colorado, LLC	—			—			4,096
Purchase of assets	(1,962		)	—			—
Investment in Centennial Pipeline LLC	(1,500		)	(4,000		)	(10,882		)
Acquisition of additional interest in Centennial Pipeline LLC	—			(20,000		)	—
Investment in Mont Belvieu Storage Partners, L.P.	(21,358		)	(2,533		)	—
Capital expenditures	(81,261		)	(58,391		)	(60,898		)
Net cash used in investing activities	(105,487		)	(84,174		)	(64,304		)

Cash flows from financing activities:
Proceeds from note payable, Parent Partnership	126,383			110,859			186,099
Repayment of note payable, Parent Partnership	(36,011		)	(53,638		)	(149,906		)
Equity contribution – Parent Partnership	—			37,033			12,263
Distributions paid	(117,967		)	(106,465		)	(94,921		)
Net cash used in financing activities	(27,595		)	(12,211		)	(46,465		)

Net decrease in cash and cash equivalents	(188		)	(297		)	(3,169		)

Cash and cash equivalents at beginning of period	188			485			3,654
Cash and cash equivalents at end of period	$	—		$	188		$	485

Non-cash investing activities:
Net assets transferred to Mont Belvieu Storage Partners, L.P.	$	—		$	61,042		$	—

Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	27,338		$	30,286		$	24,975

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, 2001	$	3		$	270,109		$	270,112
2002 net income allocation	1			55,284			55,285
2002 cash distributions	(2		)	(94,919		)	(94,921		)
Capital contributions	—			9,816			9,816
Option exercises	—			2,447			2,447
Partners’ capital at December 31, 2002	2			242,737			242,739
2003 net income allocation	1			49,480			49,481
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	2			222,786			222,788
2004 net income allocation	1			36,624			36,625
2004 cash distributions	(1		)	(117,966		)	(117,967		)
Other	—			46			46
Partners’ capital at December 31, 2004	$	2		$	141,490		$	141,492

See accompanying Notes to Consolidated Financial Statements.

F-6

TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION

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 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. The Company is 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 holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 30%. TEPPCO GP, as general partner, performs all of the management and operating functions required for us according to the Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership (the “Partnership Agreement”). We reimburse our General Partner and the Company for all reasonable direct and indirect expenses that they incur in managing us.

As used in this Report, “we,” “us,” and “our” means TE Products Pipeline Company, Limited Partnership.

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.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Basis of Presentation and Principles of Consolidation

The financial statements include our accounts and the accounts of TEPPCO Colorado, LLC (“TEPPCO Colorado”) on a consolidated basis until its sale in May 2002. All amounts relating to TEPPCO Colorado have been reclassified to reflect TEPPCO Colorado as discontinued operations for all periods presented (see Note 18. Discontinued Operations). We have eliminated all significant intercompany items in consolidation. We have reclassified certain amounts from prior periods to conform with the current presentation.

F-7

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

Effective January 1, 2002, our Parent Partnership realigned its business segments to reflect its entry into the natural gas gathering business and the expanded scope of its natural gas liquids (“NGLs”) operations. As part of this realignment, on May 31, 2002, we transferred our investment in TEPPCO Colorado, which fractionates NGLs, to TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). As a result of the transfer, the results of operations of TEPPCO Colorado for the periods presented are reflected as discontinued operations (see Note 18. Discontinued Operations). We have reclassified prior periods presented to reflect the current presentation.

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, 2004, 2003 and 2002 (in thousands):

	Years Ended December 31,
	2004			2003			2002
Balance at beginning of period	$	374		$	287		$	—
Charges to costs and expenses	(10		)	788			287
Deductions and other	(308		)	(701		)	—
Balance at end of period	$	56		$	374		$	287

F-8

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 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 and interstate pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate. It is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.

F-9

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

Capitalization of Interest

We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 5.12%, 5.69% and 5.47% for the years ended December 31, 2004, 2003 and 2002, respectively. During the years ended December 31, 2004, 2003 and 2002, the amount of interest capitalized was $1.7 million, $2.3 million and $3.3 million, respectively.

Intangible Assets

Intangible assets at December 31, 2004, consist of transportation agreements with customers and are being amortized using a straight line method over the term of the related agreement (approximately 20 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, 2004, 2003 and 2002 (in thousands):

	Years Ended December 31,
	2004			2003			2002
Balance at beginning of period	$	1,693		$	2,051		$	1,222
Charges to expense	745			1,490			2,901
Deductions and other	(1,010		)	(1,848		)	(2,072		)
Balance at end of period	$	1,428		$	1,693		$	2,051

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.

F-10

Income Taxes

We are a limited partnership. As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for our operations. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders’ tax attributes in the Partnership.

Comprehensive Income

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. For the years ended December 31, 2004, 2003, and 2002, our comprehensive income equaled our reported net income.

Use of Derivatives

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

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

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

F-11

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 14. Unit-Based Compensation), 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 14. Unit-Based Compensation.

Assuming the Parent Partnership had used the fair value method of accounting for its unit option plan, pro forma net income for the year ended December 31, 2002, would be lower than reported net income by an immaterial amount. Pro forma net income would equal reported net income for the years ended December 31, 2004 and 2003. The adoption of SFAS 148 did not have an effect on our financial position, results of operations or cash flows.

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New Accounting Pronouncements

In December 2003, the FASB revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”). FIN 46, issued by the FASB in January 2003, requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. The revised statement, FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46(R)”), clarifies some of the requirements of FIN 46, eases some implementation problems that companies experienced implementing FIN 46, adds new scope exceptions and makes the probability more likely for many companies that potential variable interest entities will be identified and consolidated. We adopted the new requirements detailed in FIN 46(R) as of March 31, 2004. In connection with our adoption of FIN 46(R), we evaluated our investments in Centennial Pipeline LLC and Mont Belvieu Storage Partners, L.P. and determined that these entities are not materially affected by our adoption of FIN 46(R), and thus we have accounted for them as equity method investments (see Note 5. Equity Investments). Our adoption of FIN 46(R) did not have an effect on our financial position, results of operations or cash flows.

On December 8, 2003, President Bush signed into law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We anticipate that the benefits we pay after 2006 could be lower as a result of the new Medicare provisions; however, at this time the retiree medical obligations and costs reported do not reflect any changes as a result of this legislation. Deferring the recognition of the new Medicare provisions’ impact was permitted by FASB Staff Position (“FSP”) Nos. 106-1 and 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, due to open questions about some of the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information. We adopted the provisions of these FSPs in the quarter ended September 30, 2004. This regulation did not have a material adverse effect on our financial position, results of operations or cash flows.

In December 2003, the FASB issued a revision SFAS No. 132, Employers’ Disclosures about Pensions and Other Post-Retirement Benefits. This revision required that companies provide more details about their plan assets, benefit obligations, cash flows, benefit costs and other relevant information. A description of investment policies and strategies and target allocation percentages, or target ranges, for these asset categories also is required in financial statements. Cash flows will include projections of future benefit payments and an estimate of contributions to be made in the next year to fund pension and other postretirement benefit plans. In addition to expanded annual disclosures, the FASB is requiring companies to report the various elements of pension and other postretirement benefit costs on a quarterly basis. The guidance is effective for fiscal years ending after December 15, 2003, and for quarters beginning after December 15, 2003. We adopted the provisions of the revised SFAS 132 effective December 31, 2003, and certain provisions regarding disclosure of information about estimated future benefit payments in the first quarter of 2004.

In April 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128, to clarify what is meant by a participating security as described in SFAS No. 128, Earnings Per Share. The consensus also provides guidance on applying the two-class method for computing earnings per share. The two-class method is an earnings allocation formula for computing earnings per share and is the required method prescribed by SFAS 128 for companies with participating securities or more than one class of common stock. The consensus primarily affects companies that issue securities that are entitled to participate in dividends with common shares and would cause affected companies to report lower earnings per share amounts. The consensus is to be applied retroactively for periods beginning after March 31, 2004. The adoption of EITF 03-06 did not have an effect on our financial position, results of operations or cash flows.

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In July 2004, the EITF reached consensus in EITF 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock, to clarify whether Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock applies to joint ventures with ownership not represented by common stock. APB Opinion No. 18 scopes out investments with ownership not represented by common stock. EITF 02-14 clarifies that joint ventures with ownership represented by in-substance common stock, as defined by EITF 02-14, are subject to the requirements of APB Opinion No. 18. We do not have common stock ownership in our joint ventures, Centennial Pipeline LLC and Mont Belvieu Storage Partners, L.P. We have assessed the impact of EITF 02-14 on these joint ventures and have determined that we have in-substance common stock ownership for these ventures. However, similar to other companies with ownership structures in joint ventures not represented by common stock, we have historically accounted for these joint ventures under the guidance of APB Opinion No. 18 due to a lack of other authoritative guidance. The consensuses in this EITF should be applied in reporting periods beginning after September 15, 2004. The adoption of EITF 02-14 did not have an effect on our financial position, results of operations or cash flows.

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 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123(R) is effective for public companies as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. 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.

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 at December 31, 2004 and 2003 (in thousands):

	December 31, 2004					December 31, 2003
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Intangible assets being amortized:
Transportation agreements	$	1,328	$	(260	)	$	1,328	$	(194	)

At December 31, 2004, we have $33.4 million of excess investment in our equity investment in Centennial Pipeline LLC, which was created upon formation of the company. The excess investment is included in our equity investments account at December 31, 2004. This excess investment is accounted for as an intangible asset with an indefinite life. We assess the intangible asset for impairment on an annual basis.

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Amortization expense on intangible assets was $0.1 million for each of the years ended December 31, 2004, 2003 and 2002.

Estimated amortization expense on intangible assets will be $0.1 million for each of the years ending December 31, 2005 through 2009.

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 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 the 7.51% 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, 2004, 2003, and 2002, we recognized reductions in interest expense of $9.6 million, $10.0 million and $8.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended December 31, 2004, 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 gain of approximately $3.4 million at December 31, 2004, and a gain of approximately $2.3 million at December 31, 2003.

NOTE 5. EQUITY INVESTMENTS

In August 2000, we entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial Pipeline LLC (“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 interest in Centennial from PEPL for $20.0 million each, increasing our ownership percentages in Centennial to 50% each. During the years ended December 31, 2004 and 2003, we invested $1.5 million and $24.0 million, respectively, in Centennial, which is included in the equity investment balance at December 31, 2004. 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. The purpose of MB Storage is to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. MB Storage is a service-oriented, fee-based venture with 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.

We receive the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the operating agreement. Any amount of MB Storage’s annual income before depreciation expense in excess of $7.15 million is allocated evenly between Louis Dreyfus and us. Depreciation expense on assets each originally contributed to MB Storage is allocated between Louis Dreyfus and us based on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by

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MB Storage subsequent to formation is allocated evenly between Louis Dreyfus and us. For the years ended December 31, 2004 and 2003, our sharing ratio in the earnings of MB Storage was approximately 69.4% and 70.4%, respectively. For the years ended December 31, 2004 and 2003, excluding the contribution of property and equipment upon formation of the partnership, we contributed $21.4 million and $2.5 million, respectively, to MB Storage. The 2004 amount includes a contribution of $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures in both periods. During the years ended December 31, 2004 and 2003, we received distributions of $10.3 million and $5.3 million, respectively, from MB Storage.

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, 2004 and 2003, is presented below (in thousands):

	Years Ended December 31,
	2004			2003
Revenues	$	60,717		$	54,035
Net loss	(273		)	(5,111		)

Summarized combined balance sheet information for Centennial and MB Storage as of December 31, 2004 and 2003, is presented below (in thousands):

	December 31,
	2004		2003
Current assets	$	39,228	$	26,771
Noncurrent assets	377,924		351,241
Current liabilities	36,015		35,032
Long-term debt	140,000		140,000
Noncurrent liabilities	20,383		13,182
Partners’ capital	220,754		189,798

NOTE 6. RELATED PARTY TRANSACTIONS

Parent Partnership, Duke Energy, DEFS and Affiliates

For the years ended December 31, 2004, 2003 and 2002, we incurred direct expenses of $45.5 million, $48.1 million and $46.6 million, respectively, which were charged to us by DEFS. Substantially all of these costs were related to payroll and payroll related expenses. For the years ended December 31, 2004, 2003 and 2002, expenses for administrative services and overhead allocated to us by the Company (including Duke Energy and its affiliates) were $1.0 million, $1.0 million and $0.8 million, respectively.

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At December 31, 2003, we had a loan of propane outstanding to DEFS with a total value of $1.4 million. We earned a nominal rental fee of $0.1 million on this transaction. This propane was returned to us in February 2004. We regularly loan inventory for a fee to third parties and affiliates as part of our inventory management practice.

Centennial

In August 2000, we entered into agreements with PEPL and Marathon to form Centennial (see Note 5. Equity Investments). At December 31, 2004, we had a 50% ownership interest in Centennial. We have entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs, Illinois, and pipeline connection in Beaumont, Texas. For each of the years ended December 31, 2004, 2003 and 2002, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $6.9 million, $4.4 million and $4.0 million, respectively.

We also have a joint tariff with Centennial to deliver products at our locations using Centennial’s pipeline as part of the delivery route to connecting carriers. As the delivering pipeline, we invoice the shippers for the entire delivery rate, record only the net rate attributable to us as transportation revenues and record a liability for the amounts due to Centennial for its share of the tariff. At December 31, 2004 and 2003, we had payable balances of $2.8 million and $2.3 million, respectively, to Centennial for its share of the joint tariff deliveries and other

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operational related charges. In addition, we perform ongoing construction services for Centennial and bill Centennial for labor and other costs to perform the construction. At December 31, 2004 and 2003, we had receivable balances of $1.1 million and $1.3 million, respectively, due from Centennial for reimbursement of construction services provided to 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 years ended December 31, 2004 and 2003, we incurred $5.3 million and $3.8 million, respectively, of rental charges related to the lease of pipeline capacity on Centennial.

MB Storage

Effective January 1, 2003, we entered into agreements with Louis Dreyfus to form MB Storage (see Note 5. Equity Investments). We operate the facilities for MB Storage. We and MB Storage have entered into a pipeline capacity lease agreement, and for each of the years ended December 31, 2004 and 2003, we recognized $0.1 million in rental revenue related to this lease agreement. During the years ended December 31, 2004 and 2003, we also billed MB Storage $3.2 million and $2.5 million, respectively, for direct payroll and payroll related expenses for operating MB Storage. At December 31, 2004, we had a net receivable balance from MB Storage of $1.3 million for operating costs, including payroll and related expenses for operating MB Storage. At December 31, 2003, we had a net payable balance to MB Storage of $0.2 million for advances MB Storage paid to us for operating costs.

NOTE 7. OTHER CURRENT ASSETS

The major components of other current assets for the years ended December 31, 2004 and 2003, were as follows (in thousands):

	December 31,
	2004		2003
Insurance receivable	$	4,531	$	1,933
Interest receivable from interest rate swap	4,027		4,680
Reimbursable receivables	2,780		1,378
Prepaid insurance and other	299		1,449
Other	506		790
Total	$	12,143	$	10,230

NOTE 8. INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at December 31, 2004 and 2003. The major components of inventories were as follows (in thousands):

	December 31,
	2004		2003
Refined products	$	5,665	$	6,632
LPGs	—		517
Materials and supplies	4,428		4,037
Total	$	10,093	$	11,186

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NOTE 9. PROPERTY, PLANT AND EQUIPMENT

Major categories of property, plant and equipment for the years ended December 31, 2004 and 2003, were as follows (in thousands):

	December 31,
	2004		2003
Land and right of way	$	36,228	$	34,203
Line pipe and fittings	631,099		575,656
Storage tanks	95,765		96,036
Buildings and improvements	36,045		30,055
Machinery and equipment	191,561		161,613
Construction work in progress	42,833		64,217
Total property, plant and equipment	1,033,531		$	961,780
Less accumulated depreciation and amortization	311,197		279,395
Net property, plant and equipment	$	722,334	$	682,385

Depreciation expense on property, plant and equipment was $42.1 million, $31.0 million and $30.1 million for the years ended December 31, 2004, 2003 and 2002, respectively. During the fourth quarter of 2004, we wrote off approximately $2.1 million in assets taken out of service to depreciation expense.

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 fair value of the facility.

NOTE 10. OTHER CURRENT LIABILITIES

The major components of other current liabilities for the years ended December 31, 2004 and 2003, were as follows (in thousands):

	December 31,
	2004		2003

Compensation accruals (1)	$	—	$	8,168
Inventory payables	391		417
Current portion of deferred revenue	1,359		1,013
McCleery litigation accrual	2,000		—
Capital expenditure accruals	1,568		2,633
Retainage	1,812		631
Other	2,209		2,929
Total	$	9,339	$	15,791

(1) Compensation accruals are now accounted for at the Parent Partnership level.

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NOTE 11. 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 a premium.

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 on a parity with all of our 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, 2004, 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. At December 31, 2004 and 2003, the Senior Notes include the fair value of our interest rate swap of $3.4 million and $2.3 million, respectively (see Note 4. Interest Rate Swap).

The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2004 and 2003 (in millions):

			Fair Value
	Face		December 31,
	Value		2004		2003
6.45% Senior Notes, due January 2008	$	180.0	$	187.1	$	190.1
7.51% Senior Notes, due January 2028	210.0		225.6		222.4

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

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face value over the term of the notes. The Parent Partnership used the proceeds from the offering to reduce a portion of the outstanding balances of its credit facilities. The 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 these 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 Parent Partnership used $182.0 million of the proceeds from the offering to reduce the outstanding principal on the Three Year Facility to $250.0 million. The balance of the net proceeds received was used for general Parent Partnership purposes. The 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.

NOTE 12. CONCENTRATIONS OF CREDIT RISK

Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future credit positions prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.

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For the years ended December 31, 2004 and 2003, we had one customer, Marathon Ashland Petroleum LLC, which accounted for 17% and 18%, respectively, of our total revenues. No other customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2004, 2003 or 2002.

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

NOTE 13. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH

We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. We pay distributions of 99.999% to the Parent Partnership and 0.001% to the General Partner.

NOTE 14. UNIT-BASED Compensation

1994 Long Term Incentive Plan

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

When our Parent Partnership’s calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account may be used to offset the cost of exercising Parent LPU options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Any unused balance previously credited is forfeited upon termination. The Parent Partnership accrues compensation expense for the performance units awarded annually based upon the terms of the plan discussed above. We are allocated a portion of the compensation expense (see Note 2. Summary of Significant Accounting Policies).

Under the agreement for such Parent LPU options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. At December 31, 2004, all options have been fully exercised. The Performance Unit account has a minimal liability balance which may be withdrawn by the participants after December 31, 2006.

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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, 2001	189,688		143,822		$13.81 - $25.69
Became exercisable	—		45,866		$25.25
Exercised	(99,597	)	(99,597	)	$13.81 - $25.69
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, compensation expense related to option grants would have been immaterial for the year ended December 31, 2002, and no compensation expense would have been recognized for the years ended December 31, 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. A total of 1,800 phantom units granted under the 1999 PURP remain outstanding at December 31, 2004. A total of 57,600 phantom units granted under the 2002 PURP remain outstanding at December 31, 2004. 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. Summary of Significant Accounting Policies). At December 31, 2004 and 2003, we had an accrued liability balance of $0.8 million and $1.6 million, respectively, for our share of compensation related to the 1999 PURP and 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

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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 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. At December 31, 2004, phantom units outstanding were 23,600, 30,600 and 21,200 for awards granted for the years ended December 31, 2004, 2003 and 2002, respectively.

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 in its discretion the Compensation Committee of the Company may exclude gains or losses from extraordinary, unusual or non-recurring items. For the years ended December 31, 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 the Compensation Committee 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. Summary of Significant Accounting Policies). At December 31, 2004 and 2003, we had an accrued liability balance of $0.9 million and $1.2 million, respectively, for our share of compensation related to the 2000 LTIP.

NOTE 15. OPERATING LEASES

We use leased assets in several areas of our operations. Total rental expense for the years ended December 31, 2004, 2003 and 2002, was $13.8 million, $12.3 million and $8.5 million, respectively. The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands):

2005	$	12,121
2006	11,018
2007	10,210
2008	5,716
2009	4,187
Thereafter	16,341
	$	59,593

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NOTE 16. Employee Benefits

Retirement Plans

The Parent Partnership has adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”), which is a non-contributory, trustee-administered pension plan. In addition, certain executive officers participate in the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”), which is a non-contributory, nonqualified, defined benefit retirement plan. The TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. The benefit formula for all eligible employees is a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit based upon pay credits and current interest credits. The pay credits are based on a participant’s salary, age and service. The Parent Partnership uses a December 31 measurement date for these plans.

The components of net pension benefits costs allocated to us for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2004, 2003 and 2002, were as follows (in thousands):

	2004			2003			2002
Service cost benefit earned during the year	$	2,384		$	2,160		$	1,957
Interest cost on projected benefit obligation	491			347			221
Expected return on plan assets	(621		)	(432		)	(291		)
Amortization of prior service cost	7			7			7
Recognized net actuarial loss	40			18			7
Net pension benefits costs	$	2,301		$	2,100		$	1,901

Other Postretirement Benefits

Effective January 1, 2001, the Parent Partnership provides employees with certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees become eligible for these benefits if they meet certain age and service requirements at retirement, as defined in the plans. The Parent Partnership provides a fixed dollar contribution, which does not increase from year to year, towards retired employee medical costs. The retiree pays all health care cost increases due to medical inflation. The Parent Partnership uses a December 31 measurement date for this plan.

The components of net postretirement benefits cost allocated to us for the TEPPCO OPB for the years ended December 31, 2004, 2003 and 2002, were as follows (in thousands):

	2004		2003		2002
Service cost benefit earned during the year	$	102	$	91	$	75
Interest cost on accumulated postretirement benefit obligation	129		117		101
Amortization of prior service cost	112		112		112
Recognized net actuarial loss	1		—		—
Net postretirement benefits costs	$	344	$	320	$	288

The Parent Partnership employs a building block approach in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed-income are 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 are evaluated before long-term capital market assumptions are determined. The long-term portfolio return is established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

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The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2004 and 2003, were as follows:

	Pension Benefits				Other Postretirement Benefits
	2004		2003		2004		2003
Discount rate	5.75	%	6.25	%	5.75	%	6.25	%
Increase in compensation levels	5.00	%	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, 2004 and 2003, were as follows:

	Pension Benefits				Other Postretirement Benefits
	2004		2003		2004		2003
Discount rate	6.25	%	6.75	%	6.25	%	6.75	%
Increase in compensation levels	5.00	%	5.00	%	—		—
Expected long-term rate of return on plan assets	8.00	%	8.00	%	—		—

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, 2004 and 2003 (in thousands):

	Pension Benefits						Other Postretirement Benefits
	2004			2003			2004			2003
Change in benefit obligation
Benefit obligation at beginning of year	$	7,704		$	5,231		$	2,088		$	1,691
Transfers to Parent Partnership subsidiary (1)	17			—			4			—
Service cost	2,384			2,160			102			91
Interest cost	491			347			129			117
Actuarial (gain)/loss	360			186			166			204
Retiree contributions	—			—			52			47
Benefits paid	(153		)	(220		)	(75		)	(62		)
Benefit obligation at end of year	$	10,803		$	7,704		$	2,466		$	2,088

Change in plan assets
Fair value of plan assets at beginning of year	$	7,673		$	4,867		$	—		$	—
Transfer to Parent Partnership subsidiary (1)	30			—			—			—
Actual return on plan assets	565			459			—			—
Retiree contributions	—			—			52			47
Employer contributions	2,300			2,567			23			15
Benefits paid	(153		)	(220		)	(75		)	(62		)
Fair value of plan assets at end of year	$	10,415		$	7,673		$	—		$	—

Reconciliation of funded status
Funded status	$	(388	)	$	(30	)	$	(2,466	)	$	(2,088	)
Unrecognized prior service cost	33			40			889			1,001
Unrecognized actuarial loss	1,301			924			398			233
Net amount recognized	$	946		$	934		$	(1,179	)	$	(854	)

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

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Plan Assets

Our Parent Partnership employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are 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 are reviewed and evaluated periodically to ensure compliance with stated investment objectives and guidelines. This comprehensive review incorporates 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, 2004 and 2003, by asset category (in thousands):

	December 31,
Asset Category	2004		2003
Equity securities	63	%	47	%
Debt securities	35	%	30	%
Other (money market and cash)	2	%	23	%
Total	100	%	100	%

The Parent Partnership expects to contribute approximately $3.5 million to the retirement plans and other postretirement benefit plans in 2005. We expect to be allocated a share of these contributions (see Note 2. Summary of Significant Accounting Policies).

Other Plans

DEFS also sponsors an employee savings plan, which covers substantially all employees. Plan contributions on behalf of the Company of $3.5 million, $3.2 million and $2.8 million were recognized during the years ended December 31, 2004, 2003 and 2002, respectively.

NOTE 17. COMMITMENTS AND CONTINGENCIES

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. The settlement terms include a $2.0 million payment to the plaintiffs, which has been accrued for in our consolidated financial statements. The terms of the settlements did not have a material adverse effect on our financial position, results of operations or cash flows.

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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. At December 31, 2004, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. 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. 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. We are in the process of negotiating a final settlement with the State of Illinois, and we do not expect that compliance with the settlement will have a future 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 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 Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release. The maximum statutory penalty calculated for this alleged violation of the CWA is $2.8 million. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. We do not expect a civil penalty, if any, to have a material adverse effect on our financial position, results of operations or cash flows.

At December 31, 2004, we have an accrued liability of $1.4 million related to various sites requiring environmental remediation activities. We do not expect that the completion of remediation programs associated these activities will have a future material adverse effect on our financial position, results of operations or cash flows.

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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.

Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2004, we had approximately 20.8 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. Our Parent Partnership maintains insurance adequate to cover product losses through circumstances beyond our control.

Our Parent Partnership carries insurance coverage consistent with companies engaged in similar operations with similar type properties. The Parent Partnership allocates insurance expense to us, and we believe that the total insurance expense allocated to us is representative of the insurance costs we would have incurred as a separate entity. Our insurance coverage includes (1) commercial general public liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability 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, our Parent Partnership also carries pollution liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

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 comparable to those carried by other energy companies of similar size. The cost of our general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are with Bison Insurance Company Limited, an insurance company that is wholly owned by Duke Energy (see Note 6. Related Party Transactions).

NOTE 18. Discontinued Operations

Effective January 1, 2002, our Parent Partnership realigned its business segments to reflect its entry into the natural gas gathering business and the expanded scope of its NGLs operations. As part of this realignment, on May 31, 2002, we entered into an Assignment and Assumption Agreement with TEPPCO Midstream to transfer our investment in TEPPCO Colorado to TEPPCO Midstream at the book value of TEPPCO Colorado’s net assets. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets requires that long-lived assets to be disposed of should be recorded at the lower of their carrying amount or fair value less costs to sell. As a result, in the quarter ended June 30, 2002, we compared the fair value of TEPPCO Colorado to its carrying value and noted no indication of impairment.

The transfer of TEPPCO Colorado to TEPPCO Midstream was recorded at the book value of TEPPCO Colorado’s net assets, which was $4.1 million. In connection with the transfer, we received $4.1 million in cash from TEPPCO Midstream. TEPPCO Midstream assumed the outstanding debt of TEPPCO Colorado of $32.0 million as part of the transaction. As a result of the transfer, our financial position and results of operations have

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been reclassified to reflect revenue, expenses, assets and liabilities of TEPPCO Colorado as discontinued operations for the periods presented.

A condensed statement of income is shown below for TEPPCO Colorado for the year ended December 31, 2002 (in thousands):

Revenues	$	3,115
Operating, general and administrative	369
Depreciation and amortization	840
Operating income	1,906
Interest expense	(1,015		)
Other income – net	21
Net income	$	912

NOTE 19. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(in thousands)
2004
Operating revenues	$	73,662	$	61,217	$	67,365	$	72,514
Operating income	25,084		13,821		11,796		17,382
Net income	17,209		6,904		4,698		7,814

2003
Operating revenues	$	66,969	$	58,805	$	63,741	$	72,452
Operating income	28,634		15,899		16,625		19,402
Net income	20,567		8,773		8,796		11,345

NOTE 20. SUBSEQUENT EVENT

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TE PRODUCTS PIPELINE CO LP 10-K