**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**FORM 10-K**

 

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

**SECURITIES EXCHANGE ACT OF 1934**

 

**For the fiscal year ended December 31, 2004**

 

**OR**

 

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

**OF THE SECURITIES EXCHANGE ACT OF 1934**

 

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**Commission File Number 1-10403**

 

**TEPPCO Partners, L.P.**

(Exact name of Registrant as specified in itscharter)

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

 

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

 

Securitiesregistered pursuant to Section 12(g) of the Act: **None**

 

Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding twelvemonths (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements for thepast 90 days. Yes ý No o

 

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-Kis not contained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form10-K.  o

 

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2of the Act).  Yes ýNo o

 

At June 30,2004, the aggregate market value of the registrant’s Limited Partner Units heldby non-affiliates was $2,394,335,251, which was computed using the average ofthe high and low sales prices of the Limited Partner Units on June 30,2004.

 

Limited PartnerUnits outstanding as of February 25, 2005: **62,998,554**.

 

DocumentsIncorporated by Reference:  **None**

 

 

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**TABLE OF CONTENTS**

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

 

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****FORWARD-LOOKINGSTATEMENTS****

 

*The matters discussed in thisReport include “forward-looking statements” within the meaning of variousprovisions of the Securities Act of 1933 and the Securities Exchange Act of1934.  All statements, other thanstatements of historical facts, included in this document that addressactivities, events or developments that we expect or anticipate will or mayoccur in the future, including such things as estimated future capitalexpenditures (including the amount and nature thereof), business strategy andmeasures to implement strategy, competitive strengths, goals, expansion andgrowth of our business and operations, plans, references to future success,references to intentions as to future matters and other such matters areforward-looking statements.  Thesestatements are based on certain assumptions and analyses made by us in light ofour experience and our perception of historical trends, current conditions andexpected future developments as well as other factors we believe areappropriate under the circumstances. However, whether actual results and developments will conform with ourexpectations 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, competitiveactions by other pipeline companies, changes in laws or regulations and otherfactors, many of which are beyond our control. Consequently, all of the forward-looking statements made in thisdocument are qualified by these cautionary statements, and we cannot assure youthat actual results or developments that we anticipate will be realized or,even if substantially realized, will have the expected consequences to oreffect on us or our business or operations.*

 

# **Items 1 and 2. *Business and Properties***

 

## **General**

 

TEPPCO Partners, L.P.(the “Partnership”), a Delaware limited partnership, is a master limitedpartnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TEProducts”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCOMidstream”).  Collectively, TE Products,TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.”  Texas Eastern Products Pipeline Company, LLC(the “Company” or “General Partner”), a Delaware limited liability company,serves as our general partner and owns a 2% general partner interest in us.  The General Partner is an indirect wholly ownedsubsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture betweenDuke Energy Corporation (“Duke Energy”) and ConocoPhillips.  Duke Energy holds an interest of approximately70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 30%.  The Company, as general partner, performs allmanagement and operating functions required for us, except for the managementand operations of certain of the TEPPCO Midstream assets that are managed byDEFS on our behalf.  We reimburse theGeneral Partner for all reasonable direct and indirect expenses incurred inmanaging us.  TEPPCO GP, Inc. (“TEPPCO GP”),our subsidiary, is the general partner of our Operating Partnerships.  We hold a 99.999% limited partner interest inthe Operating Partnerships and TEPPCO GP holds a 0.001% general partnerinterest.

 

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

 

We operate and report inthree business segments: transportation and storage of refined products,  liquefied petroleum gases (“LPGs”) andpetrochemicals (“Downstream Segment”); gathering, transportation, marketing andstorage of crude oil and distribution of lubrication oils and specialtychemicals (“Upstream Segment”); and gathering of natural gas, fractionation ofnatural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”).  Our reportable segments offer differentproducts and services and are managed separately because each requiresdifferent business strategies.

 

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

 

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At December 31, 2004and 2003, we had outstanding 62,998,554 Limited Partner Units.  At December 31, 2002, we had outstanding3,916,547 Class B Limited Partner Units (“Class B Units”), which were issued toDuke Energy Transport and Trading Company, LLC (“DETTCO”) in connection with anacquisition of assets initially acquired in the Upstream Segment in 1998.  On April 2, 2003, we repurchased andretired all of the 3,916,547 previously outstanding Class B Units with proceedsfrom the issuance of additional Limited Partner Units (see Note 11.  Partners’ Capital and Distributions).  Collectively, the Limited Partner Units andClass B Units are referred to as “Units.”

 

Our strategy is to expandand improve service in our current markets, maintain the integrity of ourpipeline systems and pursue growth initiatives that are balanced betweeninternal projects and acquisitions. We intend to leverage the advantagesinherent in our pipeline systems to maintain our status as a preferred providerin our market areas.  We also intend to growby acquiring assets, from both third parties and affiliates, which complementexisting businesses or by establishing new core businesses.  We routinely evaluate opportunities toacquire assets and businesses that will complement existing operations with aview to increasing earnings and cash available for distribution to ourunitholders.  We may fund additionalacquisitions with cash flow from operations, borrowings under existing creditfacilities, the issuance of debt in the capital markets, the sale of additionalUnits, or any combination thereof.

 

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

 

*Operations*

* *

We conduct business inour Downstream Segment through the following:

 

•                  TE Products,

 

•                  a subsidiarywhich owns the northern portion of the Dean Pipeline (“Dean North”),

 

•                  our 50% ownedequity investment in Centennial Pipeline LLC (“Centennial”), and

 

•                  our 50% ownedequity investment in Mont Belvieu Storage Partners, L.P. (“MB Storage”).

 

Our Downstream Segmentowns, operates or has investments in properties located in 14 states.  The operations of the Downstream Segmentconsist of interstate transportation, storage and terminaling of petroleumproducts; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas,complex through MB Storage; intrastate transportation of petrochemicals andother ancillary services.

 

As an interstate commoncarrier, our TE Products pipeline offers interstate transportation services,pursuant to tariffs filed with the FERC, to any shipper of refined petroleumproducts and LPGs who requests these services, provided that the productstendered for transportation satisfy the conditions and specifications containedin the applicable tariff.  In addition tothe revenues received by our pipeline system from our interstate tariffs, wealso provide storage and other related services at key points along ourpipeline systems.  Substantially all ofthe petroleum products transported and stored in our pipeline systems are ownedby our customers.  Petroleum products arereceived at terminals located principally on the southern end of the pipelinesystem, stored, scheduled into the pipeline in accordance with customernominations and shipped to delivery terminals for ultimate delivery to thefinal distributor (including gas stations and retail propane distributioncenters) or to other pipelines. Pipelines are generally the lowest cost method for intermediate andlong-haul overland transportation of petroleum products.  The TE Products pipeline system is the onlypipeline that transports LPGs from the upper Texas Gulf Coast to the Northeast.

 

Our Downstream Segmentdepends in large part on the level of demand for refined petroleum products andLPGs in the geographic locations that we serve and the ability and willingnessof customers having access to the pipeline system to supply this demand.  We cannot predict the impact of future fuelconservation measures, alternate fuel requirements, governmental regulation ortechnological advances in fuel economy and energy-generation devices, all ofwhich could reduce the demand for refined petroleum products and LPGs in theareas we serve.

 

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The following table liststhe material properties and investments of and ownership percentages in theDownstream Segment assets as of December 31, 2004:

 
| ** **                                                           | ** ** | **Our  Ownership** | ** ** |
|----------------------------------------------------------------------|------------|--------------------|------------|
| Refined products and LPGs pipelines                                  |       | 100                | %          |
| Mont Belvieu, Texas, to Port Arthur, Texas,  petrochemical pipelines |       | 100                | %          |
| Northern portion of Dean Pipeline (1)                                |       | 100                | %          |
| Centennial Pipeline LLC (2)                                          |       | 50                 | %          |
| Mont Belvieu Storage Partners, L.P. (3)                              |       | 50                 | %          |

 

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

 

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

 

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

 

*Centennial Pipeline EquityInvestment*

* *

In August 2000,TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”),a former subsidiary of CMS Energy Corporation, and Marathon Ashland PetroleumLLC (“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 upperTexas Gulf Coast to central Illinois. Centennial constructed a 74-mile, 24-inch diameter pipeline connectingTE Products’ facility in Beaumont, Texas, with an existing 720-mile, 26-inchdiameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois.The Centennial pipeline intersects TE Products’ existing mainline pipeline nearCreal Springs, Illinois, where Centennial constructed a two million barrelrefined petroleum products storage terminal. Marathon operates the mainline Centennial pipeline, and TE Productsoperates the Beaumont origination point and the Creal Springs terminal.

 

TE Products’interest in Centennial is not subject to any encumbrances from mortgages orother secured debt.  Centennial hasunsecured debt, one third of which, up to $50.0 million in principal, wasoriginally guaranteed by each owner, including TE Products.  On February 10, 2003, TE Products andMarathon each acquired an additional 16.7% interest in Centennial from PEPL for$20.0 million each, increasing their percentage ownerships in Centennial to 50%each.  TE Products and Marathon have eachguaranteed one-half of Centennial’s debt, up to a maximum of $75.0 millioneach.  Through December 31, 2004, includingthe amount paid for the acquisition of the additional ownership interest in February 2003,TE Products has invested $104.8 million in Centennial.  TE Products has not received anydistributions from Centennial since its formation.

 

*Mont Belvieu StorageEquity Investment*

* *

On January 1,2003, TE Products and Louis Dreyfus formed MB Storage.  TE Products and Louis Dreyfus each own a 50%ownership interest in MB Storage.  Thepurpose of MB Storage is to expand services to the upper Texas Gulf Coastenergy marketplace by increasing pipeline throughput and the mix of productshandled through the existing system and establishing new receipt and deliveryconnections.  MB Storage is aservice-oriented, fee-based venture with no commodity trading activity.  TE Products operates the facilities for MBStorage.  Effective January 1, 2003,TE Products contributed property and equipment with a net book value of $67.1million to MB Storage.  Additionally, asof the contribution date, Louis Dreyfus had invested $6.1 million for expansionprojects for MB Storage that TE Products was required to reimburse if theoriginal joint development and marketing agreement was terminated by eitherparty.  This deferred liability was alsocontributed and credited to the capital account of Louis Dreyfus in MB Storage.

 

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TEProducts’ interest in MB Storage is not subject to any encumbrances frommortgages or other secured debt.  TEProducts receives the first $1.8 million per quarter (or $7.15 million on anannual basis) of MB Storage’s income before depreciation expense, as defined inthe operating agreement.  Any amount ofMB Storage’s annual income before depreciation expense in excess of $7.15million is allocated evenly between TE Products and Louis Dreyfus.  Depreciation expense on assets eachoriginally contributed to MB Storage is allocated between TE Products and LouisDreyfus based upon the net book value of the assets contributed.  Depreciation expense on assets constructed oracquired by MB Storage subsequent to formation is allocated evenly between TEProducts and Louis Dreyfus.  For the yearsended December 31, 2004 and 2003, TE Products’ sharing ratio in theearnings of MB Storage was approximately 69.4% and 70.4%, respectively.  For the years ended December 31, 2004and 2003, excluding the contribution of property and equipment upon formationof the partnership, TE Products has contributed $21.4 million and $2.5 million,respectively, to MB Storage.  The 2004amount includes a contribution of $16.5 million for the acquisition of storage andpipeline assets in April 2004.  Theremaining contributions have been for capital expenditures in bothperiods.  During the years ended December 31,2004 and 2003, TE Products received distributions of $10.3 million and $5.3million, respectively, from MB Storage.

 

MBStorage’s asset base in the Mont Belvieu fractionation and storage complex, whichis the largest complex of its kind in the United States, serving thefractionation, refining and petrochemical industries, provides substantialcapacity and flexibility for the transportation, terminaling and storage ofNGLs, LPGs and refined products.  MBStorage receives revenue from the shuttling of product from refineries andfractionators to pipelines, refineries and petrochemical facilities on theupper Texas Gulf Coast.

 

On April 1,2004, MB Storage acquired storage and pipeline assets at Mont Belvieu fromConocoPhillips for approximately $34.0 million. The acquisition included three salt dome storage wells with a totalstorage capacity of 5.6 million barrels, various pipeline assets and a 200-acreparcel of property for future expansion. The acquisition also included 2.6 million barrels of brine storagecapacity.  The acquisition supports MBStorage’s strategy of increasing the productivity of the Mont Belvieu assets byexpanding its product and service base to include the storage and transportationof ethane and the storage of ethylene.

 

Includingthe capacity acquired from ConocoPhillips, MB Storage has approximately 36million barrels of LPGs storage capacity and approximately 7 million barrels ofrefined products storage capacity, including storage capacity leased to outsideparties, at the Mont Belvieu fractionation and storage complex.  MB Storage includes a short-haultransportation shuttle system, consisting of a complex system of pipelines andinterconnects, that ties Mont Belvieu to virtually every refinery andpetrochemical facility on the upper Texas Gulf Coast.  MB Storage also provides truck and rail carloading capability.  Total shuttlevolumes for the three years ended December 31, 2004, 2003 and 2002, were 39.3million barrels, 33.1 million barrels and 28.9 million barrels, respectively.

 

*Refined Products, LPGsand Petrochemical Pipeline Systems*

* *

TE Products is one of thelargest pipeline common carriers of refined petroleum products and LPGs in theUnited States. The Downstream Segment, primarily through TE Products, owns and operatesan approximately 4,600-mile pipeline system (together with the receiving,storage and terminaling facilities mentioned below, the “Products PipelineSystem”) extending from southeast Texas through the central and midwesternUnited States to the northeastern United States.  The Products Pipeline System includesdelivery terminals for outloading product to other pipelines, tank trucks, railcars or barges, and substantial storage facilities at numerous locations.  TE Products also owns one active marinereceiving terminal at Providence, Rhode Island. The Providence terminal is not physically connected to the ProductsPipeline System.  The Products PipelineSystem also includes three parallel 12-inch diameter petrochemical pipelinesbetween Mont Belvieu and Port Arthur, each approximately 70 miles in length,and 138 miles of pipeline from Mont Belvieu to Point Comfort (the northernportion of the Dean Pipeline).

 

All properties comprisingthe Products Pipeline System are wholly owned by our subsidiaries and none aremortgaged or encumbered to secure funded debt. TE Products has guaranteed up to $75.0 million of Centennial’s unsecureddebt (see –*Centennial Pipeline Equity Investment*above)and has also guaranteed our unsecured debt (see Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operations – Financial Condition andLiquidity).

 

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Products are transportedin liquid form from the upper Texas Gulf Coast through two parallel undergroundpipelines that extend to Seymour, Indiana. From Seymour, segments of the Products Pipeline System extend to theChicago, Illinois; Lima, Ohio; Selkirk, New York; and Philadelphia,Pennsylvania, areas. The Products Pipeline System east of Todhunter, Ohio, isdedicated solely to LPGs transportation and storage services, primarily forpropane.

 

Excluding the storagefacilities of Centennial and MB Storage, the Products Pipeline System includes27 storage facilities with an aggregate storage capacity of 16 million barrelsof refined petroleum products and 6 million barrels of LPGs, including storagecapacity leased to outside parties.  TheProducts Pipeline System makes deliveries to customers at 56 locationsincluding 19 truck racks, rail car facilities and marine facilities that we own.  Deliveries to other pipelines occur atvarious facilities owned by TE Products or by third parties.

 

The Products PipelineSystem is comprised of a 20-inch diameter line extending in a generallynortheasterly direction from Baytown, Texas (located approximately 30 mileseast of Houston), to a point in southwest Ohio near Lebanon and Todhunter.  A second line, which also originates atBaytown, is 16 inches in diameter until it reaches Beaumont, at which point itreduces to a 14-inch diameter line.  Thissecond line extends along the same path as the 20-inch diameter line to theProducts Pipeline System’s terminal in El Dorado, Arkansas, before continuingas a 16-inch diameter line to Seymour. The Products Pipeline System also has smaller diameter lines that extendlaterally from El Dorado to Helena, Arkansas, from Shreveport, Louisiana, to ElDorado and from McRae, Arkansas, to West Memphis, Arkansas.  The line from El Dorado to Helena has a10-inch diameter.  The line from Shreveportto El Dorado varies in diameter from 8 inches to 10 inches.  The line from McRae to West Memphis has a12-inch diameter.  The Products PipelineSystem 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 tothe Buckeye Pipe Line Company system that serves, among others, markets inMichigan and eastern Ohio.  The ProductsPipeline System also has a 6-inch diameter pipeline connection to the GreaterCincinnati/Northern Kentucky International Airport and an 8-inch diameterpipeline connection to the George Bush Intercontinental Airport terminal inHouston.  In addition, the ProductsPipeline System contains numerous lines, ranging in size from 6 inches to 20 inchesin diameter, associated with the gathering and distribution system, extendingfrom Baytown to Beaumont; Texas City to Baytown; Pasadena, Texas, to Baytownand Baytown to Mont Belvieu.

 

The Products PipelineSystem continues eastward from Todhunter, Ohio, to Greensburg, Pennsylvania, atwhich point it branches into two segments, one ending in Selkirk, New York(near Albany), and the other ending at Marcus Hook, Pennsylvania (nearPhiladelphia).  The Products PipelineSystem east of Todhunter and ending in Selkirk is an 8-inch diameter line, andthe line starting at Greensburg and ending at Marcus Hook varies in diameterfrom 6 inches to 8 inches.

 

****In2003, we increased the delivery capability between Todhunter, Ohio, andCoshocton, Ohio, by 8,000 to 10,000 barrels per day and increased storage andimproved loading capability at Oneonta, New York.  In 2004, we also completed a Phase II projectto further extend beyond Coshocton our delivery capacity of LPGs to theNortheast by 8,000 to 10,000 barrels per day. The Phase II expansion included the construction of three pump stationsbetween Coshocton and Greensburg, Pennsylvania, and two stations fromGreensburg to Watkins Glen, New York. Additional work on the pipeline segment between Greensburg andPhiladelphia, Pennsylvania, to increase delivery rates to the Philadelphia areahas been completed.  Improvements werealso completed during the fourth quarter of 2004 at our Dubois, Pennsylvania, terminal,and additional improvements are expected to be completed during the firstquarter of 2005 at our Eagle, Pennsylvania, terminal****.

 

TE Products also ownsthree 12-inch diameter common carrier petrochemical pipelines between MontBelvieu and Port Arthur.  Each of thesepipelines is approximately 70 miles in length. The pipelines transport ethylene, propylene and natural gasoline.  We entered into a 20-year agreement in 2002 witha 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.

 

Our Downstream Segmentalso includes the operations of the northern portion of the Dean Pipeline.  Beginning in January 2003, the northernportion of the Dean Pipeline was converted to transport RGP from Mont

 

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Belvieu to PointComfort.  The northern portion of theDean Pipeline consists of 138 miles of pipeline from Mont Belvieu to PointComfort.

 

We believe that ourProducts Pipeline System is in compliance with applicable federal, state andlocal laws and regulations and accepted industry standards and practices.  We perform regular maintenance on all of thefacilities of the Products Pipeline System and have an ongoing process ofinspecting the Products Pipeline System and making repairs and replacementswhen necessary or appropriate.  In addition,we conduct periodic air patrols of the Products Pipeline System to monitorpipeline integrity and third-party right-of-way encroachments.

 

*Major BusinessSector Markets*

* *

Our major operations inthe Downstream Segment consist of the transportation, storage and terminalingof refined petroleum products and LPGs along our mainline system. Productdeliveries, in millions of barrels (MMBbls) on a regional basis, for the yearsended 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 Mainline Transportation             |       | 196.4                             |       | 196.6 |   | 178.7 |   |
| Petrochemical Transportation (4)          |       | 3.6                               |       | 3.4 |   | — |   |
| Total Product Deliveries                  |       | 200.0                             |       | 200.0 |   | 178.7 |   |

 

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(1)                                  Arkansas, Louisiana, Missouriand Texas.

 

(2)                                  Illinois and Indiana.

 

(3)                                  New York and Pennsylvania.

 

(4)                                  Includes Dean North RGPvolumes.  Petrochemical transportationbetween Mont Belvieu and Port Arthur, Texas, has not been included as thosevolumes are with one customer.

 

The mix of productsdelivered varies seasonally.  Gasolinedemand is generally stronger in the spring and summer months and LPGs demand isgenerally stronger in the fall and winter months. Weather and economicconditions in the geographic areas served by our Products Pipeline System alsoaffect the demand for, and the mix of, the products delivered.

 

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Refined products and LPGsdeliveries 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 Mainline Transportation             |       | 196.4                             |       | 196.6 |   | 178.7 |   |
| Petrochemical Transportation              |       | 3.6                               |       | 3.4 |   | — |   |
| Total Product Deliveries                  |       | 200.0                             |       | 200.0 |   | 178.7 |   |

 

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

 

*Refined Products MainlineTransportation*

* *

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

 

The volume of refinedpetroleum products transported by our Products Pipeline System is directlyaffected by the demand for refined products in the geographic regions that oursystem serves.  This market demand variesbased upon the different end uses to which the refined products deliveries areapplied.  Demand for gasoline, whichaccounted for approximately 59% of the volume of refined products transportedthrough the Products Pipeline System during 2004, depends upon price,prevailing economic conditions and demographic changes in the markets that weserve.  Demand for distillates isaffected by truck and railroad freight, the price of natural gas used byutilities, which use distillates as a substitute for natural gas when the priceof natural gas is high, and usage for agricultural operations, which isaffected by weather conditions, government policy and crop prices.  Demand for jet fuel depends upon prevailingeconomic conditions and military usage.

 

Market prices for refinedpetroleum products affect the demand in the markets served by our DownstreamSegment.  Therefore, quantities and mixof products transported may vary. Transportation tariffs of refined petroleum products vary among specificproduct types.  As a result, market pricevolatility may affect transportation volumes and revenues from period to period.

 

*LPGs MainlineTransportation*

* *

Our Products PipelineSystem transports LPGs from the upper Texas Gulf Coast to the Central, Midwestand Northeast regions of the United States. The Products Pipeline System eastof Todhunter, Ohio, is devoted solely to the transportation of LPGs.  Because propane demand is generally sensitiveto weather in the winter months, year-to-year variations of propane deliverieshave occurred and will likely continue to occur.  Our Products Pipeline System also transportsnormal butane and isobutane in the Midwest and Northeast for use in theproduction of motor gasoline.

 

Our ability in theDownstream Segment to serve propane markets in the Northeast is enhanced by ourmarine import terminal at Providence.  Thisfacility includes a 400,000-barrel refrigerated storage tank along with shipunloading and truck loading facilities. Effective May 2001, we entered into an agreement with an affiliate of 

 

7

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DEFS to commit to it soleutilization of our Providence terminal. We operate the terminal and provide propane loading services to anaffiliate of DEFS.  The agreement wasrenegotiated in May 2004.  During theyears ended December 31, 2004, 2003, and 2002, revenues of $4.3 million, $3.2million and $2.3 million, respectively, from an affiliate of DEFS wererecognized pursuant to this agreement.

 

*Other OperatingRevenues*

* *

Our Downstream Segmentalso earns revenue from terminaling activities and other ancillary servicesassociated with the transportation and storage of refined petroleum productsand LPGs.  From time to time, we sellexcess product inventory.  Otheroperating revenues include revenues related to the intrastate transportation ofpetrochemicals under a throughput and deficiency contract.

 

*Customers*

* *

Our customers for thetransportation of refined petroleum products include major integrated oilcompanies, independent oil companies, the airline industry and wholesalers.  End markets for these deliveries areprimarily retail service stations, truck stops, railroads, agricultural enterprises,refineries and military and commercial jet fuel users.

 

Propane customers includewholesalers and retailers who, in turn, sell to commercial, industrial,agricultural and residential heating customers, as well as utilities who usepropane as a back-up fuel source. Refineries constitute our major customers forbutane and isobutane, which are used as a blend stock for gasolines and as afeed stock for alkylation units, respectively.

 

At December 31, 2004,our Downstream Segment had approximately 139 customers.  During the year ended December 31, 2004,total revenues (and percentage of total revenues) attributable to the top 10customers were $151.7 million (54%), of which Marathon Ashland Petroleum LLCaccounted for approximately 17% of total Downstream Segment revenues.  During the year ended December 31, 2003,total revenues (and percentage of total revenues) attributable to the top 10customers were $149.5 million (56%), of which Marathon Ashland Petroleum LLCaccounted for approximately 18% of total Downstream Segment revenues.  During the year ended December 31, 2002,total revenues (and percentage of total revenues) attributable to the top 10customers were $101.6 million (51%).  Duringthe year ended December 31, 2002, no single customer accounted for 10% ormore of total Downstream Segment’s revenues. During each of the three years ended December 31, 2004, 2003 and2002, no single customer of the Downstream Segment accounted for 10% or more oftotal consolidated revenues.

 

*CreditPolicies and Procedures*

 

We manage our exposure tocredit risk through credit analysis, credit approvals, credit limits andmonitoring procedures.  We utilizeletters of credit and guarantees for certain of our receivables.  However, these procedures and policies do notfully eliminate customer credit risk. During the year ended December 31, 2004, we expensed a minimalamount of uncollectible receivables of the Downstream Segment.  During the years ended December 31, 2003and 2002, a few small to medium-sized customers of the Downstream Segment filedfor bankruptcy protection, and as a result, we expensed approximately $0.8million and $0.7 million, respectively, of uncollectible receivables of theDownstream Segment related to customer bankruptcies or other non-payments.

 

*Competition*

* *

The Products PipelineSystem conducts operations without the benefit of exclusive franchises fromgovernment entities.  Interstate commoncarrier transportation services are provided through the system pursuant to tariffsfiled with the FERC.

 

Because pipelines aregenerally the lowest cost method for intermediate and long-haul overlandmovement of refined petroleum products and LPGs, the Products Pipeline System’smost significant competitors (other than indigenous production in its markets)are pipelines in the areas where the Products Pipeline System deliversproducts. Competition among common carrier pipelines is based primarily ontransportation charges, quality of customer service and proximity to end users.  We believe our Downstream Segment iscompetitive with other

 

8

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pipelines servingthe same markets; however, comparison of different pipelines is difficult dueto varying product mix and operations.

 

Trucks, barges andrailroads competitively deliver products in some of the areas served by theProducts Pipeline System.  Truckingcosts, however, render that mode of transportation less competitive for longerhauls or larger volumes.  Barge fees forthe transportation of refined products are generally lower than TE Products’tariffs.  We face competition from railmovements of LPGs from Sarnia, Ontario, Canada, and waterborne imports into NewHampshire.

 

*Financial Informationabout the Downstream Segment*

 

See Note 17.  Segment Information in the Notes to theConsolidated Financial Statements for financial information about theDownstream Segment.

 

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

## ** **

*Operations*

* *

We conduct business inour Upstream Segment through the following:

 

•                  TCTM,

 

•                  TEPPCO CrudePipeline, L.P. (“TCPL”), TEPPCO Crude Oil, L.P. (“TCO”) and LubricationServices, L.P. (“LSI”), wholly owned subsidiaries of TCTM, and

 

•                  our 50% ownedequity investment in Seaway Crude Pipeline Company (“Seaway”).

 

Our Upstream Segment gathers,transports, markets and stores crude oil, and distributes lubrication oils andspecialty chemicals, principally in Oklahoma, Texas, New Mexico and the RockyMountain region.  We commenced ourUpstream Segment business in connection with the acquisition of assets from anaffiliate of DEFS in November 1998. Our Upstream Segment uses its asset base to aggregate crude oil andprovide transportation and specialized services to its regional customers.  Our Upstream Segment purchases crude oil fromvarious producers and operators at the wellhead and makes bulk purchases ofcrude oil at pipeline and terminal facilities. The crude oil is then sold to refiners and other customers.  The Upstream Segment transports crude oilthrough equity owned pipelines, its trucking operations and third partypipelines.

 

Margins in the UpstreamSegment, as used throughout this Report, are calculated as revenues generatedfrom the sale of crude oil and lubrication oil, and transportation of crude oil,less the costs of purchases of crude oil and lubrication oil.  Margins are a more meaningful measure offinancial performance than sales and purchases of crude oil and lubrication oildue to the significant fluctuations in sales and purchases caused by variationsin the level of volumes marketed and prices for products marketed (see Item7.  Management’s Discussion and Analysisof Financial Condition and Results of Operations – Upstream Segment for marginand volume information).  Additionally,we use margin internally to evaluate the financial performance of the UpstreamSegment as we believe margin is a better indicator of performance thanoperating income as operating, general and administrative expenses, operatingfuel and power and depreciation expense are not directly related to the marginactivities.

 

TCO purchases crude oiland simultaneously establishes a margin by selling crude oil for physicaldelivery to third party users.  We seekto maintain a balanced marketing position until we make physical delivery ofthe crude oil, thereby minimizing or eliminating our exposure to pricefluctuations occurring after the initial purchase.  However, certain basis risks, which are therisks that price relationships between delivery points, classes of products ordelivery periods will change, cannot be completely hedged or eliminated.  Risk management policies have beenestablished by the Risk Management Committee to monitor and control marketrisks. The Risk Management Committee is comprised, in part, of certain seniorexecutives of the Company.

 

9

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Product deliveries on TCPL’s100% owned pipeline systems, undivided joint interest pipelines and Seaway forthe years ended December 31, 2004, 2003 and 2002, were as follows (in millions):

 
| ** **                               | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------|------------|-----------------------------------|------------|
| ** **                               | ** ** | **2004**                          | ** ** | **2003** | ** ** | **2002** | ** ** |
| Barrels Delivered:                       |       |                              |       |   |   |   |   |
| Crude oil transportation                 |       | 101.5                             |       | 95.5 |   | 82.8 |   |
| Crude oil marketing                      |       | 177.3                             |       | 159.7 |   | 139.2 |   |
| Crude oil terminaling                    |       | 113.2                             |       | 115.1 |   | 127.4 |   |
|                                     |       |                              |       |   |   |   |   |
| Lubricants and chemicals (total gallons) |       | 14.0                              |       | 10.4 |   | 9.6 |   |
|                                     |       |                              |       |   |   |   |   |
| Seaway:                                  |       |                              |       |   |   |   |   |
| Long-haul                                |       | 94.3                              |       | 71.0 |   | 62.6 |   |
| Short-haul                               |       | 215.8                             |       | 179.8 |   | 183.8 |   |

 

*Properties*

* *

The major crude oilpipelines and pipeline systems of our Upstream Segment are set forth in thefollowing table, which include pipelines owned jointly with other industryparticipants or producers:

 
| **Crude Oil  Pipeline**  | ** ** | **Our  Ownership**               | ** ** | **Operator**                       | ** ** | **Description**                                                                                                                       |
|--------------------------|------------|----------------------------------|------------|------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------|
| Red River System         |       | 100%                             |       | TCPL                               |       | 1,690 miles of  pipeline; 1,484,000 barrels of storage – North Texas to South Oklahoma                                           |
|                     |       |                             |       |                               |       |                                                                                                                                  |
| South Texas  System (1)  |       | 100%                             |       | TCPL                               |       | 900 miles of  pipeline; 780,000 barrels of storage – South Central Texas to Houston, Texas  area                                 |
|                     |       |                             |       |                               |       |                                                                                                                                  |
| West Texas Trunk  System |       | 100%                             |       | TCPL                               |       | 250 miles of  smaller diameter pipeline – connecting West Texas and Southeast New Mexico to  TCPL’s Midland, Texas terminal |
|                     |       |                             |       |                               |       |                                                                                                                                  |
| Seaway (2)               |       | 50% general partnership interest |       | TCPL                               |       | 500-mile,  30-inch diameter pipeline; 6,320,000 barrels of storage – Texas Gulf Coast to  Cushing, Oklahoma                      |
|                     |       |                             |       |                               |       |                                                                                                                                  |
| Basin                    |       | 13% joint ownership              |       | Plains All American Pipeline, L.P. |       | 416-mile  pipeline – Permian Basin (New Mexico and Texas) to Cushing, Oklahoma                                                   |

 

----

(1)Includes assets that were previously part of the Rancho Pipeline and ouracquisition of the Genesis assets.

 

(2) TCPL’s participation in revenues and expenses of Seaway vary asdescribed below in “-*Seaway Crude PipelineEquity Investment*.”

 

None of these pipelinesor systems are mortgaged or encumbered to secure funded debt.  TCTM has provided guarantees of our unsecureddebt (see Item 7.  Management’sDiscussion and Analysis of Financial Condition and Results of Operations).

 

The majority of the RedRiver System crude oil is delivered to Cushing, Oklahoma, via third party pipelines,or to two local refineries.  The majorityof the crude oil on the South Texas System is delivered on a tariff basis toHouston area refineries.  The West TexasTrunk System is a fee based system which connects gathering

 

10

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systems to TCPL’sMidland, Texas terminal.  Other crude oilassets, located primarily in Texas and Oklahoma, consist of 310 miles ofpipeline and 295,000 barrels of storage capacity.

 

Inconnection with our acquisition of ARCO Pipe Line Company (“ARCO”), a whollyowned subsidiary of Atlantic Richfield Company, in 2000, we acquired anapproximate 23.5% undivided joint interest in the Rancho Pipeline, which was acrude oil pipeline system from West Texas to Houston.  In March 2003, the Rancho Pipelineceased operations, and segments of the pipeline were sold to certain of theowners that previously held undivided interests in the pipeline.  We acquired 241 miles of the pipeline inexchange for cash of $5.5 million and our interests in other portions of theRancho Pipeline.  We sold 183 miles ofthe segment we acquired to other entities for cash and assets valued atapproximately $8.5 million.  We recordeda net gain of $3.9 million on the transactions in the second quarter of2003.  During the third quarter of 2004,we sold our remaining interest in the original Rancho Pipeline system for a netgain of $0.4 million.  These gains areincluded in the gains on sales of assets in our consolidated statements ofincome.

 

On November 1,2003, we purchased crude supply and transportation assets along the upper TexasGulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis PipelineTexas, L.P. (“Genesis”).  The transactionwas funded with proceeds from our August 2003 equity offering (see Note 11.  Partners’ Capital and Distributions).  We allocated the purchase price, net ofliabilities assumed, primarily to property, plant and equipment and intangibleassets (see Note 5.  Acquisitions andDispositions).  The assets acquiredincluded approximately 150 miles of small diameter trunk lines, 26,000 barrelsper day of throughput and 12,000 barrels per day of lease marketing and supplybusiness.  We have integrated theseassets into our South Texas pipeline system, which has allowed us toconsolidate gathering and marketing assets in key operating areas in a costeffective manner and will provide future growth opportunities.  Accordingly, the results of the acquisitionare included in the consolidated financial statements from November 1,2003.

 

TCOpurchases condensate from DEFS and its affiliates.  For the years ended December 31, 2004,2003, and 2002, TCO’s purchases from DEFS and its affiliates were $141.3million, $110.7 million, and $80.5 million, respectively.

 

*Seaway CrudePipeline Equity Investment*

* *

Seaway is a partnershipbetween a subsidiary of TCTM, TEPPCO Seaway, L.P. (“TEPPCO Seaway”), and ConocoPhillips.  TCTM acquired its 50% ownership interest inSeaway on July 20, 2000, as part of its purchase of ARCO.  We assumed ARCO’s role as operator of thispipeline. The 30-inch diameter, 500-mile pipeline transports crude oil from theU.S. Gulf Coast to Cushing, a central crude distribution point for the centralUnited States and a delivery point for the New York Mercantile Exchange (“NYMEX”).  The Freeport, Texas, marine terminal is theorigin point for the 30-inch diameter crude pipeline.  Three large diameter lines carry crude oilfrom the Freeport marine terminal to the adjacent Jones Creek Tank Farm, whichhas six tanks capable of handling approximately 2.6 million barrels of crudeoil.  A crude oil marine terminalfacility at Texas City, Texas, is used to supply refineries in the Houstonarea.  Two pipelines connect the TexasCity marine terminal to storage facilities in Texas City and Galena Park,Texas, where there are seven tanks with a combined capacity of approximately 3million barrels.  Seaway has thecapability to provide marine terminaling and crude oil storage services for allHouston area refineries.

 

The Seaway partnershipagreement provides for varying participation ratios throughout the life ofSeaway. From July 20, 2000, through May 2002, we received 80% of revenueand expense of Seaway.  From June 2002through May 2006, we receive 60% of revenue and expense of Seaway.  Thereafter, we will receive 40% of revenueand expense of Seaway.  For the yearended December 31, 2002, our portion of equity earnings on a pro-ratedbasis averaged approximately 67%.  Duringthe years ended December 31, 2004 and 2003, we received distributions fromSeaway of $36.9 million and $22.7 million, respectively.

 

*Line Transfers,Pumpovers and Other*

* *

Our Upstream Segmentprovides trade documentation services to its customers, primarily at Cushingand Midland.  TCPL documents the transferof crude oil in its terminal facilities between contracting buyers andsellers.  This line transferdocumentation service is related to the trading activity by TCPL’s customers ofNYMEX open-interest

 

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crude oilcontracts and other physical trading activity. This service provides adocumented record of receipts, deliveries and transactions to each customer,including confirmation of trade matches, inventory management and scheduledmovements.  Line transfer revenues areincluded as part of other operating revenues in our consolidated statements ofincome.

 

The line transferservices also attract physical barrels to TCPL’s facilities for final deliveryto the ultimate owner.  A pumpover occurswhen the last title transfer is executed and the physical barrels are deliveredout of TCPL’s custody.  TCPL owns andoperates storage facilities primarily in Midland and Cushing with anoperational capacity of approximately 1.1 million barrels to facilitate thepumpover business.  Revenues frompumpover services are included as part of crude oil transportation revenues inour consolidated statements of income and represent the crude oil terminalingcomponent.  The line transfer andpumpover operations were acquired as part of our purchase of ARCO in 2000.

 

LSI distributes lubricationoils and specialty chemicals to natural gas pipelines, gas processors andindustrial and commercial accounts.  LSI’sdistribution networks are located in Colorado, Wyoming, Oklahoma, Kansas, NewMexico, Texas and Louisiana.  LSI alsosells lubrication oils and specialty chemicals to DEFS.  For the years ended December 31, 2004,2003, and 2002, revenues recognized by LSI included $16.1 million, $15.2million and $14.6 million, respectively, for the sale of lubrication oils andspecialty chemicals to DEFS.

 

*Customers*

* *

TCO purchases crude oilprimarily from major integrated oil companies and independent oilproducers.  Crude oil sales are primarilyto major integrated oil companies and independent refiners.  Gross sales revenue of the Upstream Segmentattributable to the top 10 customers was $3.8 billion (70%), $2.6 billion (67%)and $1.9 billion (66%) for the years ended December 31, 2004, 2003 and2002, respectively.  For the years ended December 31,2004, 2003 and 2002, Valero Energy Corp. (“Valero”) accounted for 17%, 18% and18%, respectively, of the Upstream gross sales revenue.  For each of the years ended December 31,2004, 2003 and 2002, Valero accounted for 16% of our total consolidatedrevenues.

 

*Competition*

* *

The most significantcompetitors in pipeline operations in our Upstream Segment are primarily commoncarrier and proprietary pipelines owned and operated by major oil companies,large independent pipeline companies and other companies in the areas where ourpipeline systems deliver crude oil. Competition among common carrier pipelines is based primarily on postedtariffs, quality of customer service, knowledge of products and markets, andproximity to refineries and connecting pipelines.  The crude oil gathering and marketingbusiness is characterized by thin margins and intense competition for suppliesof crude oil at the wellhead. Declines in domestic crude oil production haveintensified competition among gatherers and marketers.

 

A significant portion ofthe growth in our Upstream Segment has occurred through acquisitions ofpipeline gathering systems.  Ouracquisitions in this segment have provided increased efficiencies for thegathering and transportation of crude oil with our existing pipeline systems aswell as expansion into new market areas. We experience competition from other gatherers and marketers in biddingfor potential acquisitions.  Within thepast few years, the number of companies involved in the gathering of crude oilin the United States has decreased as a result of business consolidations andbankruptcies, which may decrease the number of potential acquisitions of crudegathering systems available to us.

 

*Credit Policiesand Procedures*

* *

Ascrude oil or lubrication oils are marketed or transported, we must determinethe amount, if any, of credit to be extended to any given customer.  Due to the nature of individual salestransactions, risk of non-payment and non-performance by customers is a majorconsideration in our business.  We manageour exposure to credit risk through credit analysis, credit approvals, creditlimits and monitoring procedures.  Weutilize letters of credit and guarantees for certain of our receivables.  However, these procedures and policies do notfully eliminate customer credit risk.  Duringthe years ended December 31, 2004 and 2002, we expensed approximately $0.1million and $0.2

 

12

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million, respectively, ofuncollectible receivables of the Upstream Segment.  During the year ended December 31, 2003,no additional reserves were necessary for uncollectible receivables of theUpstream Segment.

 

*Financial* Information about the Upstream Segment

 

SeeNote 17.  Segment Information in theNotes to the Consolidated Financial Statements for financial information aboutthe Upstream Segment.

 

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

## ** **

*Operations*

* *

We conduct business inour Midstream Segment through the following:

 

•                  Jonah GasGathering Company (“Jonah”) and Val Verde Gas Gathering Company, L.P. (“ValVerde”), which gather natural gas,

 

•                  TEPPCO Midstreamand its wholly owned subsidiaries, Chaparral Pipeline Company, L.P. and QuanahPipeline Company, L.P. (collectively referred to as “Chaparral” or “ChaparralNGL system”), Panola Pipeline Company, L.P. (“Panola Pipeline”), Dean PipelineCompany, L.P. (“Dean Pipeline”) and Wilcox Pipeline Company, L.P. (“WilcoxPipeline”), which transport NGLs, and

 

•                  TEPPCO Colorado,LLC (“TEPPCO Colorado”), which fractionates NGLs.

 

Revenues of our MidstreamSegment are earned from gathering fees based on the volume and pressure ofnatural gas gathered, transportation of NGLs and fractionation of NGLs inColorado.  Gathering and transportationrevenues are recognized as natural gas or NGLs are delivered to customers.  Revenues are also earned from the sale ofcondensate liquid extracted from the natural gas stream to an Upstream Segmentmarketing affiliate.  Fractionationrevenues are recognized ratably over the contract year as products aredelivered to DEFS.  We generally do nottake title to the natural gas gathered, NGLs transported or NGLs fractionated;therefore, the results of operations of our Midstream Segment are not directlyaffected by changes in the prices of natural gas or NGLs.  Our Midstream Segment has multiple long-termcontracts with producers connected to the Jonah and Val Verde systems.  We cannot influence or control the operation,development or production levels of the gas fields served by the Jonah and ValVerde systems, which may be affected by price and price volatility, marketdemand, depletion rates of existing wells and changes in laws and regulations.

 

None of these pipelinesor systems are mortgaged or encumbered to secure funded debt.  TEPPCO Midstream, Jonah and Val Verde haveeach provided guarantees of our unsecured debt (see Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operations).

 

Volume information forthe years ended December 31, 2004, 2003 and 2002, is presented below:

 
| ** **                                                                        | ** ** | **Years Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                        | ** ** | **2004**                          | ** ** | **2003** | ** ** | **2002** | ** ** |
| Gathering – Natural Gas – Jonah (billion cubic feet  (“Bcf”)) |       | 354.5                             |       | 303.0 |   | 248.4 |   |
| Gathering – Natural Gas – Val Verde (Bcf)                               |       | 144.5                             |       | 158.3 |   | 92.3 |   |
| Transportation – NGLs (million barrels)                                      |       | 59.5                              |       | 57.9 |   | 54.0 |   |
| Fractionation – NGLs  (million barrels)                                      |       | 4.1                               |       | 4.1 |   | 4.1 |   |

* *

*TheJonah Gas Gathering System*

* *

On September 30,2001, we purchased Jonah from Alberta Energy Company for $359.8 million, withan additional payment of $7.3 million made on February 4, 2002, for finalpurchase adjustments related primarily to construction projects in progress atthe time of closing.  The acquisitionserved as our entry into the natural gas

 

13

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gatheringindustry.  Under a contractual agreement,DEFS manages and operates Jonah on our behalf. During the years ended December 31, 2004, 2003 and 2002, werecognized $4.1 million, $3.7 million and $3.3 million, respectively, ofexpenses related to the operation and management of the Jonah assets by DEFS.

 

Since the acquisition, wehave expanded both the pipeline capacity and processing capacity of the Jonahsystem.  In 2002, we completed the PhaseI and Phase II expansions of Jonah, which nearly doubled the capacity of the Jonahsystem.  The Phase I expansion wascompleted in May 2002 at a cost of approximately $25.0 million and increasedsystem capacity by 62%, from approximately 450 million cubic feet per day (“MMcf/day”)to approximately 730 MMcf/day.  In October 2002,the Phase II expansion project was completed at a cost of approximately $35.3million, which increased the capacity of the Jonah system from 730 MMcf/day toapproximately 880 MMcf/day.  In 2003, theJonah system was again expanded by a Phase III project to include an 80-mile pipelineloop and 3,700 horsepower of new compression on the system and the building ofa new 250 MMcf/day gas processing plant near Opal, Wyoming.  Phase III was substantially completed duringthe fourth quarter of 2003, and the system was operational, with systemcapacity increasing to 1,180 MMcf/day at a cost of approximately $53.4 million.  Additional capacity of 100 MMcf/day wascompleted during the fourth quarter of 2004, at a cost of approximately $13.0million.  In 2005, a Phase IV expansionproject is planned, which is expected to increase system capacity to 1.5billion cubic feet per day with the addition of 33,300 horsepower andapproximately 45 miles of pipeline.  ThePhase IV expansion is expected to be completed in late 2005 at a cost ofapproximately $122.0 million.

 

The Jonah system consistsof approximately 500 miles of pipelines ranging in size from three inches to 24inches in diameter, three compressor stations with an aggregate ofapproximately 62,000 horsepower and related metering facilities.  Gas gathered on the Jonah system is collectedfrom approximately 640 producing wells in southwestern Wyoming’s Green RiverBasin, which is one of the most prolific natural gas basins in the UnitedStates.  The system also includes twoprocessing facilities that extract condensate prior to delivery of natural gasto DEFS, Northwest, Kern River and Questar. Gas is also delivered to gas processing facilities owned by others.  From these processing facilities, the naturalgas is delivered to several interstate pipeline systems located in the regionfor transportation to end-use markets throughout the Midwest, the West Coastand the Rocky Mountain regions. Interstate pipelines in the region include Kern River, Northwest,Colorado Interstate Gas and Questar.

 

Jonah provides gasgathering services to an affiliate of DEFS. The gathering fees paid to us by an affiliate of DEFS totaled $3.3million, $2.0 million, and $1.2 million for the years ended December 31, 2004,2003 and 2002, respectively.  Inconnection with Jonah’s Pioneer processing plant operations, which wasconstructed during the Phase III expansion and began operating in 2004, Jonah sellsNGLs to, and purchases gas from, an affiliate of DEFS.  For the year ended December 31, 2004,Jonah’s sales to DEFS and its affiliates were $7.1 million, and purchases fromDEFS and its affiliates were $5.1 million. In addition, the processing fees we received from an affiliate of DEFS forgas processing services at the Pioneer plant totaled $0.6 million for the yearended December 31, 2004.

 

*TheVal Verde Gas Gathering System*

* *

On June 30, 2002, wepurchased Val Verde for $444.2 million from Burlington Resources GatheringInc., a subsidiary of Burlington Resources Inc., including acquisition relatedcosts of approximately $1.2 million.  Wefunded the purchase primarily through borrowings under bank credit facilities.  We allocated the purchase price, net ofliabilities assumed, primarily to property, plant and equipment and intangibleassets for gas gathering contracts (see Note 5. Acquisitions and Dispositions).  Weaccounted for the acquisition of these assets under the purchase method ofaccounting.  Accordingly, the results ofthe acquisition have been included in our consolidated financial statementsfrom June 30, 2002.  Under acontractual agreement, DEFS manages and operates Val Verde on our behalf.  During the years ended December 31,2004, 2003, and 2002, we recognized $3.8 million, $3.0 million and $1.2 million,respectively, of expenses related to the operation and management of the ValVerde assets by DEFS.

 

The Val Verde systemconsists of approximately 400 miles of pipeline ranging in size from fourinches to 36 inches in diameter, 14 compressor stations operating over 93,000horsepower of compression and a large amine treating facility for the removalof carbon dioxide.  The system has apipeline capacity of approximately one billion cubic feet of gas per day.  The Val Verde system gathers coal bed methane(“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexicoand Colorado, a long-term source of natural gas supply in North

 

14

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America.  The basin is one of the most prolific sourcesof CBM and also contains significant conventional gas reserves.  The system is one of the largest CBMgathering and treating facilities in the United States, gathering CBM from morethan 500 separate wells throughout northern New Mexico and southern Colorado, andprovides gathering and treating services pursuant to 60 long-term contractswith approximately 40 different natural gas producers in the San JuanBasin.  Gas transported on the Val Verdesystem is delivered to several interstate pipeline systems serving the westernUnited States, as well as local New Mexico markets.

 

In December 2004, wecompleted a project to connect Val Verde with a third party gathering systemoriginating in Colorado.  Val Verdeconstructed approximately 16 miles of pipeline and entered into a multi-year agreementto transport and treat natural gas.  Naturalgas from this interconnection will increase the utilization of Val Verde’scapacity by up to 125 MMcf/day.  ValVerde transported and treated an average of 40 MMcf/day of natural gas in December 2004and received a nomination to handle 80 MMcf/day of natural gas starting in January 2005.

 

In July 2003, theNew Mexico Oil Conservation Division approved an application for infilldrilling to allow two wells per standard 320-acre gas spacing unit in theFruitland Coal Formation of the San Juan Basin. This approval of infill drilling will provide potential opportunitiesfor long-term growth and increased throughput on the Val Verde system.

 

*NGLTransportation and Fractionation*

* *

The NGL pipelines of theMidstream Segment are located along the Texas Gulf Coast, East Texas and from southeasternNew Mexico and West Texas to Mont Belvieu. They are all wholly owned andoperated by either our subsidiaries or under a contractual agreement with DEFS.  Information about these NGL pipelines is setforth in the following table:

 
| **NGL Pipeline**                            | ** ** | **Capacity (barrels/day)** | ** ** | **Description**                                                                                  | ** ** |
|---------------------------------------------|------------|----------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| Chaparral                                   |       | 135,000                    |       | 845 miles of pipeline –  West Texas and New Mexico to Mont Belvieu, Texas                   |       |
|                                        |       |                       |       |                                                                                             |       |
| Quanah                                      |       | 22,000                     |       | 180 miles of pipeline –  Sutton County, Texas to the Chaparral Pipeline near Midland, Texas |       |
|                                        |       |                       |       |                                                                                             |       |
| Panola                                      |       | 43,000                     |       | 189 miles of pipeline –  Carthage, Texas to Mont Belvieu, Texas                             |       |
|                                        |       |                       |       |                                                                                             |       |
| San  Jacinto                                |       | 12,000                     |       | 34 miles of pipeline –  Carthage, Texas to Longview, Texas                                  |       |
|                                        |       |                       |       |                                                                                             |       |
| The  southern portion  of the Dean Pipeline |       | 10,000                     |       | 155 miles of  pipeline – South Texas to Point Comfort, Texas                                |       |
|                                        |       |                       |       |                                                                                             |       |
| Wilcox                                      |       | 7,500                      |       | 103 miles of pipeline –  Southeast Texas                                                    |       |

 

On March 1, 2002, wepurchased the Chaparral NGL system for $132.4 million from Diamond-Koch II,L.P. and Diamond-Koch III, L.P., including acquisition related costs ofapproximately $0.4 million.  TheChaparral NGL system extends from West Texas and New Mexico to MontBelvieu.  The pipeline delivers NGLs tofractionators and to MB Storage’s existing storage facilities in Mont Belvieu.  We funded the purchase through borrowingsunder a bank credit facility.  Weallocated the purchase price to property, plant and equipment, and we accountedfor the acquisition of these assets under the purchase method ofaccounting.  Accordingly, the results ofthe acquisition have been included in our consolidated financial statementsfrom March 1, 2002.  Under acontractual agreement, DEFS manages and operates Chaparral on our behalf.  During the years ended December 31,2004, 2003 and 2002, we recognized $2.3 million, $2.1 million and $1.7 million,respectively, of expenses related to the operation and management of theChaparral assets by DEFS.  An affiliateof DEFS transports NGLs on the Chaparral NGL system.  The fees paid to us by an affiliate of DEFSfor NGL transportation on the Chaparral NGL system totaled $3.8 million, $5.5million and $4.5 million for the years ended December 31, 2004, 2003 and2002, respectively.

 

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The Panola Pipeline andSan Jacinto Pipeline originate at DEFS’ East Texas Plant Complex in PanolaCounty, Texas, and transport NGLs for DEFS and other major integrated oil andgas companies.  Revenues recognized from anaffiliate of DEFS for NGL transportation totaled $11.3 million, $9.2 millionand $12.0 million for the years ended December 31, 2004, 2003 and 2002,respectively.

 

The southern portion ofthe Dean Pipeline originates in South Texas and transports NGLs for DEFS into itspipeline in Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation totaled $0.2million, $1.0 million and $2.9 million for the years ended December 31,2004, 2003 and 2002, respectively.

 

The Wilcox Pipelinetransports NGLs for DEFS from two of its natural gas processing plants and iscurrently supported by a throughput agreement with DEFS through November 2005.  The fees paid to us by DEFS under theagreement were $1.4 million, $1.5 million and $1.2 million for the years ended December 31,2004, 2003 and 2002, respectively.

 

TEPPCO Colorado has twoNGL fractionation facilities which separate NGLs into individual components. TEPPCOColorado is currently supported by a fractionation agreement with DEFS through2018, under which TEPPCO Colorado receives a variable fee for all fractionatedvolumes delivered to DEFS.  Revenuesrecognized from the fractionation facilities totaled $7.5 million, $7.4 millionand $7.4 million for the years ended December 31, 2004, 2003 and 2002,respectively. Under an operation and maintenance agreement, DEFS also operatesand maintains the fractionation facilities for TEPPCO Colorado.  For these services, TEPPCO Colorado pays DEFSa set volumetric rate for all fractionated volumes delivered to DEFS.  Expenses related to the Operation and MaintenanceAgreement totaled $0.9 million for each of the years ended December 31,2004, 2003 and 2002.

 

*Customers*

* *

The Midstream Segment’scustomers for the gathering of natural gas include major integrated oil and gascompanies and large to medium-sized independent producers.  Natural gas from Jonah and Val Verde isdelivered into major interstate gas pipelines for delivery primarily to marketsin the western United States.  TheMidstream Segment’s customers for the transporting of NGLs include DEFS and itsaffiliates and other major integrated oil and gas companies.  Condensate sales from the Jonah system areprimarily to an Upstream Segment marketing affiliate.

 

At December 31,2004, the Midstream Segment had approximately 75 customers.  Revenue attributable to the top 10 customerswas $172.8 million (83%) for the year ended December 31, 2004, of whichEnCana Corporation (formerly Alberta Energy Company), DEFS and its affiliatesand Burlington Resources Inc. accounted for approximately 21%, 18% and 16%,respectively, of revenues of the Midstream Segment.  At December 31, 2003, the MidstreamSegment had approximately 70 customers. Revenue attributable to the top 10 customers was $155.9 million (84%)for the year ended December 31, 2003, of which EnCana Corporation,Burlington Resources Inc. and DEFS and its affiliates accounted forapproximately 21%, 18% and 14%, respectively, of revenues of the MidstreamSegment.  At December 31, 2002, theMidstream Segment had approximately 70 customers.  Revenue attributable to the top 10 customerswas $117.5 million (85%) for the year ended December 31, 2002, of which DEFSand its affiliates, EnCana Corporation and Burlington Resources Inc. accountedfor approximately 21%, 19% and 15%, respectively, of revenues of the MidstreamSegment.  During each of the three yearsended December 31, 2004, 2003 and 2002, no single customer of theMidstream Segment accounted for 10% or more of total consolidated revenues.

 

*CreditPolicies and Procedures*

 

We manage our exposure tocredit risk through credit analysis, credit approvals, credit limits andmonitoring procedures.  We utilizeletters of credit and guarantees for certain of our receivables.  However, these procedures and policies do notfully eliminate customer credit risk.  Duringthe years ended December 31, 2004, 2003 and 2002, no additional reserveswere necessary for uncollectible receivables of the Midstream Segment.  In December 2001, we expensedapproximately $4.3 million of uncollected transportation deficiency revenuesdue to the bankruptcy of Enron Corp. and certain of its subsidiaries, whichoccurred in December 2001.  Duringthe second quarter of 2004, we sold our Enron Corp. receivable and received$0.6 million.

 

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*Competition*

* *

The most significantcompetition for the NGL pipeline operations of our Midstream Segment comes fromproprietary pipelines owned and operated by major oil and gas companies andother large independent pipeline companies with contiguous operations.  The ability to compete in the NGL pipelinearea is based primarily on the quality of customer service and knowledge ofproducts and markets.

 

The majority of therecent growth in the Midstream Segment is due to the acquisition and expansionsof Jonah in the Green River Basin in southwestern Wyoming and the acquisitionof Val Verde in the San Juan Basin in New Mexico and Colorado.  Typically, new supplies of natural gas arenecessary to offset the natural declines in production from wells connected toany gathering system.  The Jonah andPinedale fields that are the focus of the Jonah system in Wyoming are bothrelatively young producing areas, characterized by long-lived productionprofiles with many years of significant growth potential ahead.

 

Competition in thenatural gas gathering operations of our Midstream Segment is based largely onreputation, efficiency, system reliability and system capacity.  Key competitors in the gathering and treatingsegment include independent gas gatherers as well as other major integratedenergy companies.   Alternate gathering facilities may beavailable to producers served by our Midstream Segment, and those producerscould also elect to construct proprietary gas gathering systems.  Success in the gas gathering and treatingbusiness segment is based primarily on a thorough understanding of the needs ofthe producers served, as well as a strong commitment to providing responsive,high-quality customer service.

 

If the productionultimately delivered to one of our gathering systems declines, revenues fromsuch operations would also be adversely affected.  If these declines are sustained orsubstantial, we could experience a material adverse effect on our financial position,results of operations or cash flows.

 

*FinancialInformation about the Midstream Segment*

 

See Note 17.  Segment Information in the Notes to theConsolidated Financial Statements for financial information about the MidstreamSegment.

 

## ****Title to Properties****

 

We believe we have satisfactorytitle to all of our assets. The properties are subject to liabilities incertain cases, such as customary interests generally contracted in connectionwith 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 ourproperties or our interest in the properties or will materially interfere with theiruse in the operation of our business.

 

## ****Capital Expenditures****

 

Capital expenditures,excluding acquisitions, totaled $164.1 million for the year ended December 31,2004.  Revenue generating projectsinclude those projects which expand service into new markets or expand capacityinto current markets.  Capitalexpenditures to sustain existing operations include projects required byregulatory agencies or required life-cycle replacements.  System upgrade projects improve operationalefficiencies or reduce cost.  Wecapitalize interest costs incurred during the period that construction is inprogress.  The following table identifiescapital expenditures by segment for the year ended December 31, 2004 (inmillions):

 
| ** **         | ** ** | **Revenue  Generating** | ** ** | **Sustaining  Existing  Operations** | ** ** | **System  Upgrades** | ** ** | **Capitalized  Interest** | ** ** | **Total** | ** ** |
|--------------------|------------|-------------------------|------------|--------------------------------------|------------|----------------------|------------|---------------------------|------------|-----------|------------|
| Downstream Segment |       | $                       | 40.7       |                                 | $          | 29.5                 |       | $                         | 9.4        |      | $          | 1.3 |   | $ | 80.9 |   |
| Midstream Segment  |       | 40.6                    |       | 1.1                                  |       | 1.2                  |       | 2.2                       |       | 45.1      |       |
| Upstream Segment   |       | 23.1                    |       | 10.9                                 |       | 2.7                  |       | 0.7                       |       | 37.4      |       |
| Other              |       | —                  |       | 0.3                                  |       | 0.4                  |       | —                    |       | 0.7       |       |
| Total              |       | $                       | 104.4      |                                 | $          | 41.8                 |       | $                         | 13.7       |      | $          | 4.2 |   | $ | 164.1 |   |

 

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Revenue generatingcapital spending by the Downstream Segment totaled $40.7 million and was used primarilyfor the expansion of our pipelines extending from Seymour to Indianapolis,Indiana, further expansions of our Northeast pipeline system and constructionof a new truck loading terminal in Bossier City, Louisiana.  Revenue generating capital spending by theMidstream Segment totaled $40.6 million and was used primarily for the expansionof the Jonah system, new connections to the Red Cedar and Black Hills gatheringsystems on the Val Verde system and additional well connections on both theJonah and Val Verde systems.  Revenuegenerating capital spending by the Upstream Segment totaled $23.1 million andwas used primarily for the expansion of our South Texas system and connectionsto various other production facilities and pipelines.  In order to sustain existing operations, wespent $29.5 million for various Downstream Segment pipeline projects, $1.1million for the Midstream Segment and $10.9 million for Upstream Segmentfacilities.  An additional $13.7 millionwas spent on system upgrade projects among all of our business segments.

 

We estimate that capitalexpenditures, excluding acquisitions, for 2005 will be approximately $236.0 million(which includes $6.0 million of capitalized interest).  We expect to spend approximately $168.0million for revenue generating projects and facility improvements.  Capital spending on revenue generating projectsand facility improvements will include approximately $23.0 million for theexpansion of our Downstream Segment facilities. We expect to spend $5.0 million to expand our Upstream Segment pipelinesand facilities in West Texas and Oklahoma and approximately $140.0 million toexpand our Midstream Segment assets, with further expansions on our Jonahsystem.  We expect to spend approximately$44.0 million to sustain existing operations, including life-cycle replacementsfor equipment at various facilities and pipeline and tank replacements amongall of our business segments.  We expectto spend approximately $18.0 million to improve operational efficiencies andreduce costs among all of our business segments.  We continually review and evaluate potentialcapital improvements and expansions that would be complementary to our presentbusiness operations.  These expenditurescan vary greatly depending on the magnitude of our transactions.  We may finance capital expenditures throughinternally generated funds, debt or the issuance of additional equity.

 

## ****Regulation****

 

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

 

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

 

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

 

TEProducts has been granted permission by the FERC to utilize Market-Based Ratesfor all of its refined products movements other than the Little Rock, Arkansas,Arcadia and Shreveport-Arcadia, Louisiana destination markets, which arecurrently subject to the PPI Index.  Withrespect to LPG movements, TE Products uses the PPI Index.  All interstate transportation movements ofcrude oil by TCPL are subject to the PPI Index as are the NGL interstatetransportation movements on the Chaparral NGL system.

 

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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, whichmade several significant determinations with respect to finding “changedcircumstances” under the Energy Policy Act of 1992 (“EP Act”).  The decision largely clarifies, but does notfully quantify, the standard required for a complainant to demonstrate that anoil pipeline’s rates are no longer subject to the rate protection of the EP Actby demonstrating that a substantial change in circumstances has occurred since1992 with respect to the basis of the rates being challenged.  In the decision, the FERC found that alimited number of rate elements will significantly affect the economic basisfor a pipeline company’s rates.  Theelements identified in the decision are volume changes, allowed total returnand total cost-of-service (including major cost elements of rate base such astax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rate and incometax allowances as standalone factors.  Itappears likely that the decision will be appealed.  We have not yet determined the impact, ifany, that the decision, if it is ultimately upheld, would have on our rates ifthey 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 involvingSFPP, L.P. the court held among other things that the FERC had not adequatelyjustified its policy of providing an oil pipeline limited partnership with anincome tax allowance equal to the proportion of its limited partnershipinterests owned by corporate partners. Under the FERC’s initial ruling, SFPP, L.P. was permitted an income taxallowance on its cost-of-service filing for 42.7% of the net operating(pre-tax) income expected from operations and was denied an income taxallowance equal to 57.3% of its limited partnership interests that were held bynon-corporate partners.  The courtremanded the case back to the FERC for further review.  As a result of the court’s remand, the FERCon December 2, 2004, issued a Request for Comments seeking comments onwhether the court’s ruling applies only to the specific facts of the SFPP, L.P.proceeding or also extends to other capital structures involving partnershipsand other forms of ownership.  Theultimate outcome of the FERC’s inquiry on income tax allowance should notaffect our current rates and rate structure because our rates are not based oncost-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) berequired to use such methodology to defend our indexed rates.

 

The natural gas gatheringoperations of the Jonah and Val Verde systems are exempt from FERC regulationunder the Natural Gas Act of 1938 since they are intrastate gas gatheringsystems rather than interstate transmission pipelines.  However, the FERC regulation stillsignificantly affects the Midstream Segment, directly or indirectly, by its influenceson the parties that produce the natural gas gathered on the Jonah and Val Verdesystems.  In addition, in recent years, theFERC has pursued pro-competition policies in its regulation of interstatenatural gas pipelines.  If the FERC doesnot continue the pro-competition policies as it considers pipeline rate caseproposals, revisions to rules and policies that affect shipper rights of accessto interstate natural gas transportation capacity or proposals by natural gaspipelines to allow natural gas pipelines to charge negotiated rates withoutrate ceiling limits, such policy changes could have an adverse effect on thegathering rates the Midstream Segment is able to charge in the future.

 

## ****Environmental Matters****

 

Our operations aresubject to federal, state and local laws and regulations governing thedischarge of materials into the environment.  Failure to comply with these laws andregulations may result in the assessment of administrative, civil and criminalpenalties, imposition of injunctions delaying or prohibiting certain activitiesand the need to perform investigatory and remedial activities.  Although we believe our operations are inmaterial compliance with applicable environmental laws and regulations, risksof significant costs and liabilities are inherent in pipeline operations, and wecannot assure you that significant costs and liabilities will not be incurred.  Moreover, it is possible that otherdevelopments, such as increasingly strict environmental laws and regulationsand enforcement policies thereunder, and claims for damages to property orpersons resulting from our operations, could result in substantial costs andliabilities to us.  We believe that changesin environmental laws and regulations will not have a material adverse effecton our financial position, results of operations or cash flows in the nearterm.

 

*Water*

* *

The Federal Water PollutionControl Act of 1972, as renamed and amended as the Clean Water Act (“CWA”), andanalogous state laws impose strict controls against the discharge of oil andits derivatives into navigable waters.  TheCWA provides penalties for any discharges of petroleum products in reportablequantities

 

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and imposessubstantial potential liability for the costs of removing petroleum or otherhazardous substances.  State laws for thecontrol of water pollution also provide varying civil and criminal penaltiesand liabilities in the case of a release of petroleum or its derivatives innavigable waters or into groundwater. Spill prevention control andcountermeasure requirements of federal laws require appropriate containmentberms and similar structures to help prevent a petroleum tank release fromimpacting navigable waters.

 

Contamination resultingfrom spills or releases of petroleum products is an inherent risk within thepetroleum pipeline industry.  To the extentthat groundwater contamination requiring remediation exists along our pipelinesystems as a result of past operations, we believe any such contamination couldbe controlled or remedied without having a material adverse effect on ourfinancial position, but such costs are site specific, and we cannot assure youthat the effect will not be material in the aggregate.

 

The primary federal lawfor oil spill liability is the Oil Pollution Act of 1990 (“OPA”), whichaddresses three principal areas of oil pollution — prevention, containment andcleanup, and liability.  OPA applies tovessels, offshore platforms and onshore facilities, including terminals,pipelines and transfer facilities.  Inorder to handle, store or transport oil, shore facilities are required to fileoil spill response plans with the appropriate federal agency being either theUnited States Coast Guard, the United States Department of TransportationOffice of Pipeline Safety (“OPS”) or the Environmental Protection Agency (“EPA”).Numerous states have enacted laws similar to OPA.  Under OPA and similar state laws, responsibleparties for a regulated facility from which oil is discharged may be liable forremoval costs and natural resource damages.

 

The EPA has adoptedregulations that require us to have permits in order to discharge certain stormwater run-off.  Storm water dischargepermits may also be required by certain states in which we operate.  These permits may require us to monitor andsample the storm water run-off.

 

*Air Emissions*

* *

Our operations aresubject to the federal Clean Air Act (the “Clean Air Act”) and comparable statelaws.  Amendments to the Clean Air Act,as well as recent or soon to be adopted changes to state implementation plansfor controlling air emissions in regional, non-attainment areas, may require ouroperations to incur future capital expenditures in connection with the additionor modification of existing air emission control equipment and strategies.  In addition, some of our facilities areincluded within the categories of hazardous air pollutant sources, which aresubject to increasing regulation under the Clean Air Act.  The Clean Air Act requires federal operatingpermits for major sources of air emissions. Under this program, a federal operating permit (a “Title V” permit) maybe issued.  The permit acts as anumbrella that includes other federal, state and local preconstruction and/oroperating permit provisions, emission standards, grandfathered rates and recordkeeping, reporting and monitoring requirements in a single document. Thefederal operating permit is the tool that the public and regulatory agenciesuse to review and enforce a site’s compliance with all aspects of clean airregulation at the federal, state and local level. We have completed applicationsfor the facilities for which these regulations apply.

 

*Risk ManagementPlans*

* *

We are subject to the EPA’sRisk Management Plan (“RMP”) regulations at certain locations.  This regulation is intended to work with theOccupational Safety and Health Act (“OSHA”) Process Safety Managementregulation (see “Safety Matters” below) to minimize the offsite consequences ofcatastrophic releases.  The regulationrequires a regulated source, in excess of threshold quantities, to develop andimplement a risk management program that includes a five-year accident history,an offsite consequence analysis, a prevention program and an emergency responseprogram. We believe the operating expensesof the RMP regulations will not have a material adverse effect on our financialposition, results of operations or cash flows.

 

*Solid Waste*

* *

We generate hazardous andnon-hazardous solid wastes that are subject to requirements of the federalResource Conservation and Recovery Act (“RCRA”) and comparable state statutes. Wealso utilize waste minimization and recycling processes to reduce the volumesof our waste.  Amendments to RCRArequired the EPA to promulgate regulations banning the land disposal of allhazardous wastes unless the wastes meet certain treatment

 

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standards or theland-disposal method meets certain waste containment criteria. From time totime, the EPA considers the adoption of stricter disposal standards fornon-hazardous wastes, including crude oil and gas wastes.  The adoption of such stricter standards fornon-hazardous wastes, or any future re-designation of non-hazardous wastes ashazardous wastes will likely increase our operating expenses as well as for theindustry in general.

 

*Superfund*

* *

The ComprehensiveEnvironmental Response, Compensation and Liability Act (“CERCLA”), also knownas “Superfund,” imposes liability, without regard to fault or the legality ofthe original act, on certain classes of persons who contributed to the releaseof a “hazardous substance” into the environment. These persons include theowner or operator of a facility where a release occurred and companies thatdisposed or arranged for the disposal of the hazardous substances found at afacility. Under CERCLA, these persons may be subject to joint and severalliability for the costs of cleaning up the hazardous substances that have beenreleased into the environment, for damages to natural resources and for thecosts of certain health studies.  CERCLAalso authorizes the EPA and, in some instances, third parties to take actionsin response to threats to the public health or the environment and to seek torecover the costs they incur from the responsible classes of persons.  It is not uncommon for neighboring landownersand other third parties to file claims for personal injury and property damageallegedly caused by hazardous substances or other pollutants released into theenvironment.  In the course of ourordinary operations, our pipeline systems generate wastes that may fall within CERCLA’sdefinition of a “hazardous substance.”  Inthe event a disposal facility previously used by us requires clean up in thefuture, we may be responsible under CERCLA for all or part of the costsrequired to clean up sites at which such wastes have been disposed.

 

*OtherEnvironmental Proceedings*

 

In 1994, the LouisianaDepartment of Environmental Quality (“LDEQ”) issued a compliance order forenvironmental contamination at our Arcadia, Louisiana, facility.  In 1999, our Arcadia facility and adjacent terminalswere directed by the Remediation Services Division of the LDEQ to pursueremediation of this contamination.  At December 31,2004, we have an accrued liability of $0.2 million for remediation costs at ourArcadia facility.  Effective in March 2004,we executed an access agreement with an adjacent industrial landowner who islocated upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediationactivities at our Arcadia facility for which it has accepted shared responsibility.  We do not expect that the completion of theremediation program proposed to the LDEQ will have a future material adverseeffect on our financial position, results of operations or cash flows.

 

OnMarch 17, 2003, we experienced a release of 511 barrels of jet fuel from astorage tank at our Blue Island terminal located in Cook County, Illinois.  As a result of the release, we have enteredinto an Agreed Order with the State of Illinois, which required us to conductan environmental investigation.  At thistime, we have complied with the terms of the Agreed Order, and the results ofthe environmental investigation indicated there were no soil or groundwaterimpacts from the release.  We are in theprocess of negotiating a final settlement with the State of Illinois, and wedo not expect that compliance with the settlement will have a future materialadverse effect on our financial position, results of operations or cash flows.

 

OnJuly 22, 2004, we experienced a release of approximately 12 barrels of jetfuel from a sump at our Lebanon, Ohio, terminal.  The released jet fuel was contained within astorm water retention pond located on the terminal property.  Six migratory waterfowl were affected by thejet fuel and were subsequently euthanized by or at the request of the UnitedStates 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.”  OnFebruary 7, 2005, we entered into a Memorandum of Understanding with theUSFWS, settling all aspects of this matter. The terms of this settlement did not have a material adverse effect onour financial position, results of operations or cash flows.

 

OnJuly 27, 2004, we received notice from the United States Department ofJustice (“DOJ”) of its intent to seek a civil penalty against us related to ourNovember 21, 2001, release of approximately 2,575 barrels of jet fuel fromour 14-inch diameter pipeline located in Orange County, Texas.  The DOJ, at the request of the EPA, isseeking a civil penalty against us for alleged violations of the CWA arisingout of this release.  The maximumstatutory penalty calculated for this alleged violation of the CWA is $2.8million.  We are in discussions with the

 

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DOJ regarding this matter and have responded to its request foradditional information.  We do not expecta civil penalty, if any, to have a material adverse effect on our financialposition, results of operations or cash flows.

 

At December 31,2004, we have an accrued liability of $5.0 million, related to various TCTM andTE Products sites requiring environmental remediation activities.   At December 31,2003, we had an accrued liability of $5.9 million related to various TCTM sitesrequiring environmental remediation activities. Under the terms of a 1998 agreement through which we acquired variouscrude oil assets from DETTCO, we received a five year contractual indemnityobligation for certain environmental liabilities attributable to the operationsof the assets prior to our acquisition.  Concurrentwith the expiration of this indemnity in 2003, we entered into a SettlementAgreement and Release with DETTCO releasing DETTCO from future obligationspertaining to certain environmental liabilities, requiring us to share incertain costs for the remediation of a crude oil site in Oklahoma, and theassumption of responsibility by DETTCO for environmental liabilities associatedwith three sites located in Texas and Oklahoma. We do not expect that the completion of remediation programs associatedwith TCTM and TE Products activities will have a future material adverse effecton our financial position, results of operations or cash flows.

 

## ****DOT Pipeline ComplianceMatters****

 

We are subject toregulation by the United States Department of Transportation (“DOT”) under theAccountable Pipeline and Safety Partnership Act of 1996, sometimes referred toas the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable statestatutes relating to the design, installation, testing, construction,operation, replacement and management of our pipeline facilities. The HLPSAcovers petroleum and petroleum products and requires any entity that owns oroperates pipeline facilities to comply with such regulations, to permit accessto and copying of records and to file certain reports and provide informationas required by the Secretary of Transportation. The HLPSA was reauthorized in 2002. We believe that we are in material compliance with these HLPSAregulations.

 

We are subject to the DOTregulation requiring qualification of pipeline personnel.  The regulation requires pipeline operators todevelop and maintain a written qualification program for individuals performingcovered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and toreduce the probability and consequence of incidents caused by human error.  The regulation establishes qualificationrequirements for individuals performing covered tasks.  A written qualification program was completedin April 2001, and our employees performing a covered task were qualifiedby the October 2002 deadline.  Webelieve that we are in material compliance with these DOT regulations.

 

We are also subject tothe DOT Integrity Management regulations, which specify how companies withgreater than 500 miles of pipeline should assess, evaluate, validate andmaintain 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 environmentalareas and commercially navigable waterways. The regulation requires the development and implementation of anIntegrity Management Program (“IMP”) that utilizes internal pipelineinspection, pressure testing, or other equally effective means to assess theintegrity of HCA pipeline segments.  Theregulation also requires periodic review of HCA pipeline segments to ensureadequate preventative and mitigative measures exist and that companies takeprompt action to address integrity issues raised by the assessment andanalysis.  In compliance with these DOTregulations, we identified our HCA pipeline segments and developed an IMP bythe March 31, 2002 deadline. The regulations require that initial HCAbaseline integrity assessments must be conducted within seven years, with allsubsequent assessments conducted on a five-year cycle.  Additionally, 50% of all HCA pipeline milesmust have been assessed by September 30, 2004.  We exceeded this requirement by the imposeddeadline.  In 2003 and 2004, we continuedwith the baseline evaluation efforts initiated in 2002 and completed the assessmentof approximately 1,300 and 2,070 miles, respectively, of our pipelinesystem.  In accordance with our IMPprogram, we perform the appropriate repairs following each assessment.

 

## ****Safety Matters****

 

We are also subject tothe requirements of the federal OSHA and comparable state statutes.  We believe we are in material compliance withOSHA and state requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposures.

 

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The OSHA hazardcommunication standard, the EPA community right-to-know regulations under TitleIII of the federal Superfund Amendment and Reauthorization Act and comparablestate statutes require us to organize and disclose information about thehazardous materials used in our operations. Certain parts of this information must be reported to employees, stateand local governmental authorities and local citizens upon request.  We are subject to OSHA Process SafetyManagement (“PSM”) regulations, which are designed to prevent or minimize theconsequences of catastrophic releases of toxic, reactive, flammable orexplosive chemicals.  These regulationsapply to any process which involves a chemical at or above the specifiedthresholds or any process which involves a flammable liquid or gas, as definedin the regulations, stored on-site in one location, in a quantity of 10,000pounds or more.  We utilize certaincovered processes and maintain storage of LPGs in pressurized tanks, cavernsand wells, in excess of 10,000 pounds at various locations.  Flammable liquids stored in atmospheric tanksbelow their normal boiling point without benefit of chilling or refrigerationare exempt.  We believe we are inmaterial compliance with the OSHA regulations.

 

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

 

## ****Employees****

 

The Partnership does nothave any employees.  However, fororganizational purposes, TEPPCO GP, TEPPCO NGL Pipelines, LLC and TEPPCO CrudeGP, LLC have officers and directors, who are employees of the GeneralPartner.   The General Partner is responsible for themanagement of us and our subsidiaries. As of December 31, 2004, the General Partner had 1,104 employees.  None of the employees of our General Partnerwere represented by labor unions, and our General Partner considers itsemployee relations to be good.

 

## ****Available Information****

 

We file annual, quarterlyand other reports and other information with the Securities and ExchangeCommission (“SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”).  You may read and copy any materials that wefile with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW,Washington, DC 20549.  You may obtainadditional information about the Public Reference Room by calling the SEC at1-800-SEC-0330.  In addition, the SECmaintains an Internet site (http://www.sec.gov) that contains reports, proxyand information statements, and other information regarding issuers that fileelectronically with the SEC, including us.

 

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

 

***Item 3.***           Legal Proceedings

 

In the fall of 1999 andon December 1, 2000, the General Partner and the Partnership were named asdefendants in two separate lawsuits in Jackson County Circuit Court, JacksonCounty, Indiana, styled *Ryan E. McCleery andMarcia S. McCleery, et al. v. Texas Eastern Corporation, et al.*(includingthe General Partner and Partnership) and*Gilbert Richards and JeanRichards v. Texas Eastern Corporation, et al.*(including the GeneralPartner and Partnership).* *In both cases, the plaintiffscontend, among other things, that we and other defendants stored and disposedof toxic and hazardous substances and hazardous wastes in a manner that causedthe materials to be released into the air, soil and water.  They further contend that the release causeddamages to the plaintiffs.  In theircomplaints, the plaintiffs allege strict liability for both personal injury andproperty damage together with gross negligence, continuing nuisance, trespass,criminal mischief and loss of consortium. The plaintiffs are seekingcompensatory, punitive and treble damages. On January 27, 2005, we entered into Release and SettlementAgreements with the McCleery plaintiffs and the Richards plaintiffs dismissingall of these plaintiffs’ claims.  Thesettlement terms include a $2.0 million payment to the plaintiffs, which hasbeen accrued for in our consolidated

 

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financialstatements.  The terms of the settlementsdid not have a material adverse effect on our financial position, results ofoperations or cash flows.

 

Although we did notsettle with all plaintiffs and we therefore remain named parties in the *Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas EasternCorporation, et al*. action, a co-defendant has agreed to indemnifyus for all remaining claims asserted against us.  Consequently, we do not believe that theoutcome of these remaining claims will have a material adverse effect on ourfinancial position, results of operations or cash flows.

 

On December 21,2001, TE Products was named as a defendant in a lawsuit in the 10th JudicialDistrict, Natchitoches Parish, Louisiana, styled *Rebecca L.Grisham et al. v.  TE Products PipelineCompany, Limited Partnership*. In this case, the plaintiffs contend that our pipeline, which crossesthe plaintiffs’ property, leaked toxic products onto their property and,consequently caused damages to them.  Wehave filed an answer to the plaintiffs’ petition denying the allegations, andwe are defending ourselves vigorously against the lawsuit.  The plaintiffs have not stipulated the amountof damages they are seeking in the suit; however, this case is covered byinsurance.  We do not believe that theoutcome of this lawsuit will have a material adverse effect on our financialposition, results of operations or cash flows.

 

In May 2003, the GeneralPartner was named as a defendant in a lawsuit styled *John R.James, et al. v. J Graves Insulation Company, et al.* as filed in thefirst Judicial District Court, Caddo Parish, Louisiana.  There are numerous plaintiffs identified inthe action that are alleged to have suffered damages as the result of allegedexposure to asbestos-containing products and materials.  According to the petition and as a result ofa preliminary investigation, the General Partner believes that the only claimasserted against it results from one individual for the period from July 1971through June 1972, who is alleged to have worked on a facility owned bythe General Partner’s predecessor.  Thisperiod represents a small portion of the total alleged exposure period from January 1964through December 2001 for this individual. The individual’s claims involve numerous employers and alleged jobsites.  The General Partner has beenunable to confirm involvement by the General Partner or its predecessors withthe alleged location, and it is uncertain at this time whether this case iscovered by insurance.  Discovery isplanned, and the General Partner intends to defend itself vigorously againstthis lawsuit.  The plaintiffs have notstipulated the amount of damages that they are seeking in this suit.  We are obligated to reimburse the GeneralPartner for any costs it incurs related to this lawsuit.  We cannot estimate the loss, if any,associated with this pending lawsuit.  Wedo not believe that the outcome of this lawsuit will have a material adverseeffect 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, etal. v. Centennial Pipeline Company LLC, et al*.  This matter involves approximately 2,000plaintiffs who allege that over 200 defendants, including Centennial,generated, transported, and/or disposed of hazardous and toxic waste at twosites in Bayou Sorrell, Louisiana, an underground injection well and alandfill.  The plaintiffs allege personalinjuries, allergies, birth defects, cancer and death.  The underground injection well has been inoperation since May 1976.  Based upon currentinformation, Centennial appears to be a *de minimis*contributor, having used the disposal site during the two month time period of December 2001to January 2002.  Marathon has been handlingthis matter for Centennial under its operating agreement with Centennial.  TE Products has a 50% ownership interest inCentennial.  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 approvedclass settlement becomes final, the terms of the settlement will not have amaterial adverse effect on our financial position, results of operations orcash flows.

 

On December 16, 2003,Centennial, the General Partner, the Partnership and other Partnership entitieswere named as defendants in a lawsuit in the 128th District Court of OrangeCounty, Texas, styled *Elwood Karr et al. v.Centennial Pipeline, LLC et al*. In this case, the plaintiffs contend that our pipeline leaked toxicsubstances on their property, causing them property damage.  On October 29, 2004, the parties enteredinto a Settlement Agreement, dismissing all claims.  The terms of the settlement did not have amaterial adverse effect on our financial position, results of operations orcash flows.

 

On February 4, 2005, wereceived a letter notifying us of a claim for approximately $1.45 million indamages allegedly due to a shipper being delivered off-specification gasolineduring November 2004.  We are contestingliability for this matter, and to the extent there may be liability, we wouldseek reimbursement from the third party refiner who supplied the gasoline intoour pipeline system. We do not believe that the outcome of this matter willhave a future material adverse effect on our consolidated financial position,results of operations or cash flows.

 

On February 7, 2005, wereceived a letter from BP Amoco’s counsel placing us on notice of a lawsuitfiled by ConocoPhillips against BP Amoco Seaway Products Pipeline Company.  Pursuant to provisions of the Amended andRestated Purchase Agreement dated May 10, 2000, between us and ARCO (BP Amoco),BP Amoco requested indemnity should BP Amoco have any liability toConocoPhillips.  The litigation arisesout of an income tax liability alleged by ConocoPhillips due to a partnershipmerger.  The plaintiff estimates theincome tax liability to be $3,964,788.  Wehave requested information from BP Amoco that will allow us to assessliability, if any, that we may have in this matter.  We do not believe that the outcome of thislawsuit will have a future material adverse effect on our consolidatedfinancial position, results of operations or cash flows.

 

In addition to thelitigation discussed above, we have been, in the ordinary course of business, adefendant in various lawsuits and a party to various other legal proceedings,some of which are covered in whole or in part by

 

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insurance.  We believe that the outcome of these lawsuitsand other proceedings will not individually or in the aggregate have a futurematerial adverse effect on our consolidated financial position, results ofoperations or cash flows.

 

***Item 4.***           Submission of Matters to a Vote of SecurityHolders

 

None.

 

**PART II**

 

***Item 5.***           Market for Registrant’s Units and RelatedUnitholder Matters

 

Our Units are listed andtraded on the New York Stock Exchange under the symbol “TPP”.  The high and low trading prices of our Unitsin 2004 and 2003, respectively, as reported in *The New YorkTimes*, were as follows:

 
| ** **  | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------|------------|----------|------------|----------|------------|
| **Quarter** | ** ** | **High** | ** ** | **Low**  | ** ** | **High** | ** ** | **Low** | ** ** |
| First       |       | $        | 41.99      |     | $          | 34.50 |   | $ | 31.64 |   | $ | 28.05 |   |
| Second      |       | 42.05    |       | 32.75    |       | 37.00 |   | 30.35 |   |
| Third       |       | 41.75    |       | 37.96    |       | 37.69 |   | 34.00 |   |
| Fourth      |       | 42.36    |       | 37.44    |       | 41.15 |   | 35.22 |   |
|             |            |          |            |          |            |  |  |  |  |  |  |  |  |

 

On February 25,2005, the closing market price for our Units was $43.10 per Unit.  Based on the information received from ourtransfer agent and from brokers and nominees, we estimate the number ofbeneficial holders of our Units as of February 25, 2005, to beapproximately 73,000.

 

The quarterly cash distributionsfor the years ended December 31, 2004 and 2003, were as follows:

 
| **Record Date**       | ** ** | **Payment Date**       | ** **     | **Amount  Per Unit** | ** ** |
|-----------------------|------------|------------------------|----------------|----------------------|------------|
| April 30, 2003   |       | May 9, 2003            |           | $                    | 0.625      |   |
| July 31, 2003    |       | August 8,  2003   |           | 0.625                |       |
| October 31, 2003 |       | November 7,  2003 |  

  | 0.650                |       |
| January 30, 2004 |       | February 6,  2004 |           | 0.650                |       |
|                  |       |                   |           |                 |       |
| April 30, 2004   |       | May 7, 2004            |           | $                    | 0.6625     |   |
| July 30, 2004    |       | August 6,  2004   |           | 0.6625               |       |
| October 29, 2004 |       | November 5,  2004 |           | 0.6625               |       |
| January 31, 2005 |       | February 7,  2005 |           | 0.6625               |       |

 

We make quarterly cashdistributions of all of our Available Cash, generally defined as consolidated cashreceipts less consolidated cash disbursements and cash reserves established by theGeneral Partner in its sole discretion.  Pursuantto the Partnership Agreement, the Company receives incremental incentive cashdistributions when cash distributions exceed certain target thresholds (seeNote 11.  Partner’s Capital andDistributions).

 

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

 

Distributions of cash paidby us to a unitholder will not result in taxable gain or income except to theextent the aggregate amount distributed exceeds the tax basis of the Units ownedby the unitholder.

 

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***Item 6.***           Selected Financial Data

 

The following tables setforth, for the periods and at the dates indicated, our selected consolidatedfinancial and operating data. The financial data was derived from ourconsolidated financial statements and should be read in conjunction with our auditedconsolidated financial statements included in the Index to Consolidated FinancialStatements on page F-1 of this Report. See also Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operations.

 
| ** **                                     | ** ** | **Years Ended December 31,**            | ** ** |
|------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                     | ** ** | **2004**                                     | ** ** | **2003** | ** ** | **2002 (1)** | ** ** | **2001 (2)** | ** ** | **2000 (3)** | ** ** |
| ** **                                     | ** ** | **(in thousands, except per Unit  amounts)** | ** ** |
| **Income Statement Data:**                     |       |                                         |       |   |   |   |   |   |   |   |   |
| Operating revenues:                            |       |                                         |       |   |   |   |   |   |   |   |   |
| Sales of petroleum products                    |       | $                                            | 5,434,127  |   | $ | 3,766,651 |   | $ | 2,823,800 |   | $ | 3,219,816 |   | $ | 2,821,943 |   |
| 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 |   |
| Transportation – Crude oil                |       | 37,177                                       |       | 29,057 |   | 27,414 |   | 24,223 |   | 17,524 |   |
| Transportation – NGLs                     |       | 41,204                                       |       | 39,837 |   | 38,870 |   | 20,702 |   | 7,009 |   |
| Gathering – Natural gas                   |       | 140,122                                      |       | 135,144 |   | 90,053 |   | 8,824 |   | — |   |
| Mont Belvieu operations                        |       | —                                       |       | — |   | 15,238 |   | 14,116 |   | 13,334 |   |
| Other revenues                                 |       | 70,346                                       |       | 54,430 |   | 48,735 |   | 51,594 |   | 34,904 |   |
| Total operating revenues                       |       | 5,958,192                                    |       | 4,255,832 |   | 3,242,163 |   | 3,556,413 |   | 3,087,941 |   |
| Purchases of petroleum products                |       | 5,372,971                                    |       | 3,711,207 |   | 2,772,328 |   | 3,172,805 |   | 2,793,643 |   |
| Operating expenses                             |       | 286,247                                      |       | 255,437 |   | 213,556 |   | 185,918 |   | 150,149 |   |
| Depreciation and amortization                  |       | 112,894                                      |       | 100,728 |   | 86,032 |   | 45,899 |   | 35,163 |   |
| Gains on sales of assets                       |       | (1,053                                       | )          | (3,948 | ) | — |   | — |   | — |   |
| Operating income                               |       | 187,133                                      |       | 192,408 |   | 170,247 |   | 151,791 |   | 108,986 |   |
| Interest expense – net                    |       | (72,053                                      | )          | (84,250 | ) | (66,192 | ) | (62,057 | ) | (44,423 | ) |
| Equity earnings                                |       | 25,981                                       |       | 16,863 |   | 11,980 |   | 17,398 |   | 12,214 |   |
| Other income – net                        |       | 1,320                                        |       | 748 |   | 1,827 |   | 1,999 |   | 599 |   |
| Net income (as reported)                       |       | 142,381                                      |       | 125,769 |   | 117,862 |   | 109,131 |   | 77,376 |   |
| Amortization of goodwill and excess investment |       | —                                       |       | — |   | — |   | 2,396 |   | 767 |   |
| Adjusted net income                            |       | $                                            | 142,381    |   | $ | 125,769 |   | $ | 117,862 |   | $ | 111,527 |   | $ | 78,143 |   |
|                                           |       |                                         |       |   |   |   |   |   |   |   |   |
| Basic and diluted income per Unit: (4)         |       |                                         |       |   |   |   |   |   |   |   |   |
| As reported                                    |       | $                                            | 1.61       |   | $ | 1.52 |   | $ | 1.79 |   | $ | 2.18 |   | $ | 1.89 |   |
| Amortization of goodwill and excess investment |       | —                                       |       | — |   | — |   | 0.05 |   | 0.02 |   |
| Adjusted net income per Unit                   |       | $                                            | 1.61       |   | $ | 1.52 |   | $ | 1.79 |   | $ | 2.23 |   | $ | 1.91 |   |

 
| ** **                                 | ** ** | **December 31,** | ** ** |
|--------------------------------------------|------------|-----------------------|------------|
| ** **                                 | ** ** | **2004**              | ** ** | **2003** | ** ** | **2002 (1)** | ** ** | **2001 (2)** | ** ** | **2000 (3)** | ** ** |
| ** **                                 | ** ** | **(in thousands)**    | ** ** |
| **Balance Sheet Data:**                    |       |                  |       |   |   |   |   |   |   |   |   |
| Property, plant and equipment – net   |       | $                     | 1,703,702  |   | $ | 1,619,163 |   | $ | 1,587,824 |   | $ | 1,180,461 |   | $ | 949,705 |   |
| Total assets                               |       | 3,197,705             |       | 2,940,992 |   | 2,768,422 |   | 2,065,348 |   | 1,622,810 |   |
| Long-term debt (net of current maturities) |       | 1,480,226             |       | 1,339,650 |   | 1,377,692 |   | 715,842 |   | 835,784 |   |
| Total debt                                 |       | 1,480,226             |       | 1,339,650 |   | 1,377,692 |   | 1,075,842 |   | 835,784 |   |
| Class B Units held by related party        |       | —                |       | — |   | 103,363 |   | 105,630 |   | 105,411 |   |
| Partners’ capital                     |       | 1,021,448             |       | 1,109,321 |   | 891,842 |   | 543,181 |   | 315,057 |   |
|                                            |            |                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                                          | ** ** | **Years Ended December 31,**            | ** ** |
|-----------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                          | ** ** | **2004**                                     | ** ** | **2003** | ** ** | **2002 (1)** | ** ** | **2001 (2)** | ** ** | **2000 (3)** | ** ** |
| ** **                                          | ** ** | **(in thousands, except per Unit  amounts)** | ** ** |
| **Cash Flow Data:**                                 |       |                                         |       |   |   |   |   |   |   |   |   |
| Net cash provided by operating activities           |       | $                                            | 266,210    |   | $ | 239,354 |   | $ | 234,917 |   | $ | 169,148 |   | $ | 108,045 |   |
| Capital expenditures to sustain existing operations |       | (41,733                                      | )          | (32,864 | ) | (21,978 | ) | (18,578 | ) | (21,859 | ) |
| Distributions paid                                  |       | (233,057                                     | )          | (202,498 | ) | (151,853 | ) | (104,412 | ) | (82,231 | ) |
| Distributions paid per Unit (4)                     |       | $                                            | 2.64       |   | $ | 2.50 |   | $ | 2.35 |   | $ | 2.15 |   | $ | 2.00 |   |

 

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

 

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

 

(3)          Datareflects the operations of the ARCO assets acquired on July 20, 2000.

 

(4)          Per Unitcalculation includes 3,700,000 Units issued in 2000, 7,750,000 Units issued in2001, 13,359,597 Units issued in 2002 and 9,188,957 Units issued in 2003, netof retirement of Class B Units of 3,916,547. No Units were issued in 2004.

 

***Item 7.***           Management’s Discussion and Analysis of FinancialCondition and Results of Operations

 

The following informationis intended to provide investors with an increased understanding of our 2004,2003 and 2002 consolidated financial statements and our accompanying noteslisted in the Index to Consolidated Financial Statements on page F-1 of thisReport.  Our discussion and analysis includesthe following:

 

•                  Overview ofBusiness and 2004 Results.

 

•                  CriticalAccounting Policies and Estimates – Presents accounting policies that are amongthe most critical to the portrayal of our financial condition and results of operations.

 

•                  Results ofOperations – Discusses material period-to-period variances in the consolidatedstatements of income.

 

•                  FinancialCondition and Liquidity – Analyzes cash flows and financial position.

 

•                  OtherConsiderations – Addresses trends, future plans and contingencies that arereasonably likely to materially affect future liquidity or earnings.

 

## ****Overview of Business and2004 Results****

 

TEPPCO Partners, L.P., aDelaware limited partnership, is a publicly traded master limited partnershipformed in March 1990.  See Items 1and 2. Business and Properties – General. We operate and report in three business segments.  Our Downstream Segment owns, operates or hasinvestments in properties located in 14 states, transports, stores and providesterminal services for petroleum products, transports LPGs in the Mont Belvieuarea, transports petrochemicals in southeast Texas and provides other ancillaryservices.  Our Upstream Segment gathers,transports, markets and stores crude oil and distributes lubrication oils andspecialty chemicals in Oklahoma, Texas, New Mexico and the Rocky Mountainregion.  Our Midstream Segment gathersnatural gas in the Green River Basin in southwestern Wyoming and in the SanJuan Basin in northwestern New Mexico and southwestern Colorado, transports NGLsfrom southeastern New Mexico, East Texas and West Texas to Mont Belvieu, Texas,and fractionates NGLs at two facilities in Colorado.  We earn revenues and income and generate cashby charging our customers a fee for the transportation, storage, gathering,terminaling, fractionation and other services we provide.  In our Upstream Segment, we seek to maintaina balanced marketing position until we make physical delivery of the crude oil,thereby minimizing or eliminating our exposure to price fluctuations occurringafter the initial purchase.

 

We are subject toeconomic and other factors that affect our industry.  The demand for refined products is dependentupon the price, prevailing economic conditions and demographic changes in themarkets served, trucking and railroad freight, agricultural usage and militaryusage; the demand for propane is sensitive to the weather and prevailingeconomic conditions; the demand for petrochemicals is dependent upon prices forproducts produced from petrochemicals; the demand for crude oil and petroleumproducts is dependent upon the price of crude oil and the products producedfrom the refining of crude oil; and the demand for natural gas is dependentupon the price of natural gas and the locations in which natural gas isdrilled.  We are also subject to regulatoryfactors such as the amounts we are allowed to charge our customers for theservices we provide on our regulated pipeline systems.

 

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Certain factors areinherent in our business segments as discussed in this Report.  These include the safe, reliable andefficient operation of the pipelines and facilities that we own or operatewhile meeting increased regulations that govern the operation of our assets andthe costs associated with such regulations. We are also focused on our continued growth through expansion of theassets that we own and through the acquisition of assets that complement ourcurrent operations.

 

Our 2004 results illustrate the strength and diversity of ourasset portfolio.  In 2004, solidoperating performance across all of our business segments contributed to a strong year for volumes, netincome and earnings before interest, taxes, depreciation and amortization.  Our net income for the year ended December 31,2004, was $142.3 million, compared with $125.8 million for the year ended December 31,2003.  We raised our annual distribution toour unitholders by $0.05 per Unit to an annualized rate of $2.65 per Unit atyear end, continuing our twelve year track record of distributionincreases.  Distributions have increased approximately35% over the past five years.

 

Our Downstream Segmenthad increased revenues from our refined products business and the recognitionof $4.1 million of deferred revenue, despite the impact of challenging marketconditions for both our refined products and LPGs movements.  We have continued to utilize Centennial’scapacity in a manner that has provided additional delivery capability for ourcustomers.  Centennial hasprovided additional capacity through our lease agreement, enabling us totransport additional refined product volumes in 2004.  During the third quarter of 2004, Centennialwas able to transport jet fuel for the first time.  MB Storage also continued its solid performance,in part due to storage and pipeline assets acquired in April 2004.  These increases were partially offset by higherpipeline integrity expenses of $6.2 million and an asset impairment charge of$4.4 million related to a marine facility in Beaumont, Texas.

 

Our Upstream Segment had astrong year, with increased transportation volumes and strong margins in ourgathering and marketing business. Transportation volumes on our South Texas system were higher than theprior year, primarily as a result of our November 2003 acquisition of theGenesis assets.  We also had a recordyear for gallons delivered by LSI as a result of acquisitions of lubricationoil distributors in December 2003 and August 2004.  These increases were partially offset byincreased pipeline integrity expenses of $3.9 million.  Seaway had an outstanding year as well, with significantincreases in long-haul movements of crude oil.

 

Our Midstream Segment benefitedfrom increased volumes on Jonah, resulting from our recent Phase III expansion,partially offset by the impact of reduced volumes on Val Verde primarily due tothe natural decline of CBM production and slower than anticipated completionand connection of new wells.  OurMidstream Segment was impacted by higher operating fuel and power costs, whichincreased $2.2 million from 2003 primarily due to higher variable power ratesand increased NGL volumes transported during times of peak power rates.

 

We ended 2004 in a solid financialposition.  Our operating costs overallwere higher than expected, largely as a result of pipeline integrity expensesin our Downstream and Upstream Segments. The goal of our on-going pipeline integrity program is to maintain thelong-term reliability and safety of our pipeline systems, while minimizing theimpact to our customers.  Our operatingcosts were also impacted by increased consulting and contract services of $3.2million related to compliance with the Sarbanes-Oxley Act of 2002.  During the year, we spent $104.4 million on revenuegenerating capital projects, which we believe will provide earnings, cash flowand growth opportunities.  We amended ourrevolving credit facility in October 2004 to (i) increase the facilitysize from $550.0 million to $600.0 million, (ii) extend the term to October 21,2009, (iii) remove certain restrictive covenants, (iv) increase the availableamount 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.

 

Wecontinued building a base for long-term growth by enhancing existing systemsand pursuing new business opportunities. We increased throughput on ourpipeline systems, constructed new pipeline and gathering systems, and expandedand upgraded our existing infrastructure. Among the highlights of 2004:

 

•                 During the fourthquarter of 2004, we completed a Phase II project to further extend beyondCoshocton, Ohio, our delivery capacity of LPGs to the Northeast by 8,000 to10,000 barrels per day.  The Phase IIexpansion included the construction of three pump stations between Coshoctonand Greensburg, Pennsylvania, and two stations from Greensburg to Watkins Glen,New York.  Additional work on the

 

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pipeline segment betweenGreensburg and Philadelphia, Pennsylvania, to increase delivery rates to thePhiladelphia area has been completed. Improvements were also completed during the fourth quarter of 2004 atour Dubois, Pennsylvania, terminal, and additional improvements are expected tobe completed during the first quarter of 2005 at our Eagle, Pennsylvania,terminal.

•                 MB Storageacquired 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 theprocess of constructing a new refined products truck loading terminal inBossier City, Louisiana, to provide the Shreveport, Louisiana, and East Texasmarkets with access to Gulf Coast sourced gasoline and diesel fuel.  This terminal is scheduled to be completed inthe first quarter of 2005.

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

•                 Weare in the process of integrating a strategic 58-mile pipeline segment fromHouston, Texas, to Katy, Texas, to facilitate Seaway’s connectivity to Gulf ofMexico production and our South Texas system.

•                 In 2004, wecompleted the integration of the Genesis assets into our South Texassystem.  The $21.0 million acquisitionhas strengthened our existing South Texas market position and improved ourphysical asset base.

•                 The Basin system,which is a part of our Upstream Segment, was expanded between Midland, Texas,and Wichita Falls, Texas, resulting in an additional capacity of ten thousandbarrels per day on the system.

•                 Additionalcapacity of 100 MMcf/day by installing compression facilities on the Jonahsystem was completed at a cost of approximately $13.0 million.  The additional capacity will enable loweroperating pressures in the Jonah and Pinedale fields, allowing for improvedservice and increased throughput.

•                 We connected ValVerde to two new sources of natural gas production in southern Colorado andnorthwest New Mexico.  Both connectionswill increase the utilization of the Val Verde assets by up to 150 MMcf/day.

•                 We inspected morethan 2,000 miles of pipeline and completed rehabilitation and enhancement workon an additional 2,000 miles of pipeline as part of our integrity managementprogram.

 

We remain confident thatour current strategy and focus will provide continued growth in earnings andcash distributions.  With respect to 2005,these opportunities include:

 

•                 Continued solidperformance in our Upstream Segment, as we build on our existing asset base andconcentrate on acquisitions in our core operating areas;

•                 Continueddevelopment of the Jonah system which serves the Jonah and Pinedale fields;

•                 Gathering ofvolumes from infill drilling of CBM by producers and new connections ofconventional gas in the San Juan Basin, where our Val Verde system is located;

•                 Growth in ourDownstream Segment, resulting from our recent capacity expansion and grassroots facility investments and growing demand for Gulf Coast sourced products.

 

Consistent with our business strategy, we continuouslyevaluate possible acquisitions of assets that would complement our currentoperations.  Such acquisition effortsinvolve participation by us in processes that have been made public and involvea number of potential buyers, as well as situations in which we believe we arethe only party or one of a very limited number of potential buyers innegotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, wouldhave a material effect on our financial position, results of operations or cashflows.

 

## ****General****

 

We operate and report inthree business segments:

 

•                  DownstreamSegment – transportation and storage of refined products, LPGs andpetrochemicals;

 

•                  Upstream Segment– gathering, transportation, marketing and storage of crude oil anddistribution of lubrication oils and specialty chemicals; and

 

•                  MidstreamSegment – gathering of natural gas, transportation of NGLs and fractionation ofNGLs.

 

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Our reportable segmentsoffer different products and services and are managed separately because eachrequires different business strategies.  TEPPCOGP, our wholly owned subsidiary, acts as managing general partner of ourOperating Partnerships, with a 0.001% general partner interest and manages oursubsidiaries.

 

Our Downstream Segmentrevenues are earned from transportation and storage of refined products andLPGs, intrastate transportation of petrochemicals, sale of product inventory andother ancillary services.  The twolargest operating expense items of the Downstream Segment are labor andelectric power.  We generally realizehigher revenues during the first and fourth quarters of each year since ouroperations are somewhat seasonal. Refined products volumes are generally higherduring the second and third quarters because of greater demand for gasolinesduring the spring and summer driving seasons. LPGs volumes are generally higher from November through March dueto higher demand in the Northeast for propane, a major fuel for residentialheating.  Our Downstream Segment alsoincludes the results of operations of the northern portion of the Dean Pipeline,which transports RGP from Mont Belvieu to Point Comfort, Texas.  Our Downstream Segment also includes ourequity investments in Centennial and MB Storage (see Note 6.  Equity Investments).

 

OurUpstream Segment revenues are earned from gathering, transportation, marketingand storage of crude oil and distribution of lubrication oils and specialtychemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountainregion.  Marketing operations consistprimarily of aggregating purchased crude oil along our pipeline systems, orfrom third party pipeline systems, and arranging the necessary transportation logisticsfor the ultimate sale of the crude oil to local refineries, marketers or otherend users.  Our Upstream Segment alsoincludes our equity investment in Seaway (see Note 6.  Equity Investments).  Seaway consists of large diameter pipelinesthat transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coastto Cushing, Oklahoma, a crude oil distribution point for the central UnitedStates, and to refineries in the Texas City and Houston areas.

 

OurMidstream Segment revenues are earned from the fractionation of NGLs inColorado, transportation of NGLs from two trunkline NGL pipelines in SouthTexas, two NGL pipelines in East Texas and a pipeline system (Chaparral) fromWest Texas and New Mexico to Mont Belvieu; the gathering of natural gas in theGreen River Basin in southwestern Wyoming, through Jonah, and the gathering of CBMand conventional natural gas in the San Juan Basin in New Mexico and Colorado,through Val Verde.  DEFS manages andoperates the Val Verde, Jonah and Chaparral assets for us under contractualagreements.  The results of operations ofthe acquisitions are included in our consolidated financial statements inperiods subsequent to their respective acquisition dates (see Note 5.  Acquisitions and Dispositions).

 

## ****Critical AccountingPolicies and Estimates****

 

The preparation offinancial statements in accordance with accounting principles generallyaccepted in the United States requires management to make estimates andassumptions that affect the reported amounts of assets and liabilities as wellas the disclosure of contingent assets and liabilities at the date of thefinancial statements.  Such estimates andassumptions also affect the reported amounts of revenues and expenses duringthe reporting period.  Changes in theseestimates could materially affect our financial position, results of operationsor cash flows.  Although we believe thatthese estimates are reasonable, actual results could differ from theseestimates.  Significant accounting policiesthat we employ are presented in the notes to the consolidated financialstatements (see Note 2.  Summary ofSignificant Accounting Policies).

 

Critical accountingpolicies are those that are most important to the portrayal of our financialposition and results of operations. These policies require management’s most difficult, subjective orcomplex judgments, often employing the use of estimates about the effect ofmatters that are inherently uncertain. Our most critical accounting policies pertain to revenue and expenseaccruals, environmental costs, property, plant and equipment and goodwill andintangible assets.

 

*Revenue andExpense Accruals*

* *

We routinely makeaccruals based on estimates for both revenues and expenses due to the timing ofcompiling billing information, receiving certain third party information andreconciling our records with those of third parties.  The delayed information from third partiesincludes, among other things, actual volumes of crude oil purchased,transported or sold, adjustments to inventory and invoices for purchases andother operating expenses.

 

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We make accrualsto reflect estimates for these items based on our internal records andinformation from third parties.  Most ofthe estimated accruals are reversed in the following month when actualinformation is received from third parties and our internal records have beenreconciled.

 

The most difficultaccruals to estimate are power costs, property taxes and crude oil margins.  Power cost accruals generally involve a twoto three month estimate, and the amount varies primarily for actual powerusage.  Power costs are dependent uponthe actual volumes transported through our pipeline systems and the variouspower rates charged by numerous power companies along the pipeline system.  Peak demand rates, which are difficult topredict, drive the variability of the power costs.  For the year ended December 31, 2004,approximately 11% of our power costs are recorded using estimates.  A variance of 10% in our aggregate estimatefor power costs would have an approximate $0.5 million impact on annual earnings.  Property tax accruals involve significant taxrate estimates among numerous jurisdictions. Actual property taxes are often not known until the tax bill is settledin subsequent periods, and the tax amount can vary for tax rate changes andchanges in tax methods or elections.  Avariance of 10% in our aggregate estimate for property taxes could have up to anapproximate $1.2 million impact on annual earnings.  Crude oil margin estimates are based upon anaverage of the past twelve months of crude oil marketing volumes, factoring incurrent market events, and prices of crude oil. We use an average of prices that were in effect during the applicablemonth to determine the expected revenue amount, and we determine the margin byevaluating the actual margins of the prior twelve months.  As of December 31, 2004, approximately 10%of our annual crude oil margin is recorded using estimates.  A variance from this estimate of 10% wouldimpact the respective line items by approximately $1.0 million on an annual basis.  Although the resolution of theseuncertainties has not historically had a material impact on our reportedresults of operations or financial condition, because of the high volume, lowmargin nature of our business, we cannot provide assurance that actual amountswill not vary significantly from estimated amounts.  Variances from estimates are reflected in theperiod actual results become known, typically in the month following theestimate. Each of these accruals requires management’s subjective judgments,requiring estimates regarding the effects of items that are inherentlyuncertain.

 

*EnvironmentalCosts*

* *

At December 31, 2004,we have accrued a liability of $5.0 million for our estimate of the futurepayments we expect to pay for environmental costs to remediate existingconditions attributable to past operations. Environmental costs include initial site surveys and environmentalstudies of potentially contaminated sites, costs for remediation andrestoration of sites determined to be contaminated and ongoing monitoringcosts, as well as damages and other costs, when estimable.  We monitor the balance of accruedundiscounted environmental liabilities on a regular basis.  We record liabilities for environmental costsat a specific site when our liability for such costs is probable and areasonable estimate of the associated costs can be made.  Adjustments to initial estimates arerecorded, from time to time, to reflect changing circumstances and estimatesbased upon additional information developed in subsequent periods.  Estimates of our ultimate liabilitiesassociated with environmental costs are particularly difficult to make withcertainty due to the number of variables involved, including the early stage ofinvestigation at certain sites, the lengthy time frames required to completeremediation alternatives available and the evolving nature of environmentallaws and regulations. A variance of 10% in our aggregate estimate forenvironmental costs would have an approximate $0.5 million impact on annual earnings.  For information concerning environmentalregulation and environmental costs and contingencies, see Items 1 and 2. Businessand Properties – Environmental Matters.

 

*Property, Plantand Equipment*

* *

We regularly reviewlong-lived assets for impairment in accordance with Statement of FinancialAccounting Standards (“SFAS”) No. 144, *Accounting for theImpairment or Disposal of Long-Lived Assets. *Long-lived assets are reviewed for impairment whenever eventsor changes in circumstances indicate that the carrying amount of an asset maynot be recoverable.  Recoverability ofthe carrying amount of assets to be held and used is measured by a comparisonof the carrying amount of the asset to future net cash flows expected to begenerated by the asset.  Estimates offuture net cash flows include anticipated future revenues, expected future operatingcosts and other estimates.  If suchassets are considered to be impaired, the impairment to be recognized ismeasured by the amount by which the carrying amount of the assets exceeds thefair value of the assets.  Assets to bedisposed of are reported at the lower of the carrying amount or fair value lesscosts to sell.

 

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*Goodwill andIntangible Assets*

 

Goodwill and intangibleassets represent the excess of consideration paid over the fair value oftangible net assets acquired.  Certainassumptions and estimates are employed in determining the fair value of assetsacquired including goodwill and other intangible assets as well as determiningthe allocation of goodwill to the appropriate reporting unit.  In addition, we assess the recoverability ofthese intangibles by determining whether the amortization of these intangiblesover their remaining useful lives can be recovered through undiscounted futurenet cash flows of the acquired operations. The amount of impairment, if any, is measured by the amount by which thecarrying amounts exceed the projected discounted future operating cashflows.  During 2002, we adopted SFAS No.142, *Goodwill and Other Intangible Assets*,which discontinues the amortization of goodwill and intangible assets that haveindefinite lives and requires an annual test of impairment based on acomparison of fair value to carrying values. The evaluation of impairment under SFAS 142 requires the use ofprojections, estimates and assumptions as to the future performance of theoperations, including anticipated future revenues, expected future operatingcosts and the discount factor used. Actual results could differ from projections resulting in revisions toour assumptions and, if required, recognizing an impairment loss.  Based on our assessment, we do not believeour goodwill is impaired, and we have not recorded a charge from the adoptionof SFAS 142 (see Note 3.  Goodwill andOther Intangible Assets).  At December 31,2004, the recorded value of goodwill and equity method goodwill was $16.9million and $25.5 million, respectively. In addition, we have $33.4 million of excess investment in our equityinvestment in Centennial, which is being accounted for as an intangible assetwith an indefinite life.

 

At December 31, 2004,we have $371.6 million of intangible assets related to natural gastransportation contracts which were recorded as part of our acquisitions ofJonah on September 30, 2001, and Val Verde on June 30, 2002 (see Note5.  Acquisitions and Dispositions).  The value assigned to the natural gastransportation contracts required management to make estimates regarding thefair value of the assets acquired.  Inconnection with the acquisition of Jonah, we assumed contracts that dedicatefuture production from natural gas wells in the Green River Basin inWyoming.  We assigned $222.8 million ofthe purchase price to these production contracts based upon a fair valueappraisal at the time of the acquisition. In connection with the acquisition of Val Verde, we assumed fixed-termgas transportation contracts with customers in the San Juan Basin in New Mexicoand Colorado.  We assigned $239.6 millionof the purchase price to these fixed term contracts based upon a fair valueappraisal at the time of the acquisition. The value assigned to intangible assets is amortized on a unit-of-productionbasis, based upon the actual throughput of the system over the expected totalthroughput for the lives of the contracts. The amortization of the Jonah and Val Verde systems are expected toaverage approximately 35 years and 30 years, respectively.  On a quarterly basis, we update throughput estimatesand evaluate the remaining expected useful life of the contract assets basedupon the best available information.  Avariance of 10% in our aggregate production estimate for the Jonah and ValVerde systems would have an approximate $2.3 million impact on annualearnings.  Changes in the estimatedremaining production will impact the timing of amortization expense reportedfor future periods.

 

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**Resultsof Operations**

 

The following tablesummarizes financial information by business segment for the years ended December 31,2004, 2003 and 2002 (in thousands):

 
| ** **                     | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------|------------|-----------------------------------|------------|
| ** **                     | ** ** | **2004**                          | ** ** | **2003** | ** ** | **2002** | ** ** |
| Operating revenues:            |       |                              |       |   |   |   |   |
| Downstream Segment             |       | $                                 | 279,400    |   | $ | 266,427 |   | $ | 243,538 |   |
| Upstream Segment               |       | 5,475,995                         |       | 3,806,215 |   | 2,861,700 |   |
| Midstream Segment              |       | 206,004                           |       | 185,105 |   | 138,922 |   |
| Intercompany eliminations      |       | (3,207                            | )          | (1,915 | ) | (1,997 | ) |
| Total operating revenues       |       | 5,958,192                         |       | 4,255,832 |   | 3,242,163 |   |
|                           |       |                              |       |   |   |   |   |
| Operating income:              |       |                              |       |   |   |   |   |
| Downstream Segment             |       | 71,263                            |       | 83,704 |   | 83,098 |   |
| Upstream Segment               |       | 32,265                            |       | 28,416 |   | 26,408 |   |
| Midstream Segment              |       | 83,605                            |       | 80,288 |   | 60,741 |   |
| Total operating income         |       | 187,133                           |       | 192,408 |   | 170,247 |   |
|                           |       |                              |       |   |   |   |   |
| Earnings before interest:      |       |                              |       |   |   |   |   |
| Downstream Segment             |       | 68,648                            |       | 79,844 |   | 77,115 |   |
| Upstream Segment               |       | 62,054                            |       | 49,671 |   | 46,735 |   |
| Midstream Segment              |       | 83,732                            |       | 80,577 |   | 61,010 |   |
| Intercompany eliminations      |       | —                            |       | (73 | ) | (806 | ) |
| Total earnings before interest |       | 214,434                           |       | 210,019 |   | 184,054 |   |
|                           |       |                              |       |   |   |   |   |
| Interest expense               |       | (76,280                           | )          | (89,540 | ) | (70,537 | ) |
| Interest capitalized           |       | 4,227                             |       | 5,290 |   | 4,345 |   |
| Net income                     |       | $                                 | 142,381    |   | $ | 125,769 |   | $ | 117,862 |   |

 

Below is adetailed analysis of the results of operations, including reasons for changesin results, by each of our operating segments.

 

## **Downstream Segment**

 

The following tableprovides financial information for the Downstream Segment for the years ended December 31,2004, 2003 and 2002 (in thousands):

 
| ** **                             | ** ** | **Years Ended December 31,** | ** ** | **Increase (Decrease)** | ** ** |
|----------------------------------------|------------|-----------------------------------|------------|-------------------------|------------|
| ** **                             | ** ** | **2004**                          | ** ** | **2003**                | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** |
| Transportation – Refined products |       | $                                 | 148,166    |                    | $          | 138,926 |   | $ | 123,476 |   | $ | 9,240 |   | $ | 15,450 |   |
| Transportation – LPGs             |       | 87,050                            |       | 91,787                  |       | 74,577 |   | (4,737 | ) | 17,210 |   |
| Mont Belvieu operations                |       | —                            |       | —                  |       | 15,238 |   | — |   | (15,238 | ) |
| Other                                  |       | 44,184                            |       | 35,714                  |       | 30,247 |   | 8,470 |   | 5,467 |   |
| Total operating revenues               |       | 279,400                           |       | 266,427                 |       | 243,538 |   | 12,973 |   | 22,889 |   |
| Operating, general and administrative  |       | 124,905                           |       | 113,389                 |       | 90,034 |   | 11,516 |   | 23,355 |   |
| Operating fuel and power               |       | 31,706                            |       | 28,806                  |       | 28,998 |   | 2,900 |   | (192 | ) |
| Depreciation and amortization          |       | 43,135                            |       | 31,620                  |       | 30,116 |   | 11,515 |   | 1,504 |   |
| Taxes – other than income taxes   |       | 8,917                             |       | 8,908                   |       | 11,292 |   | 9 |   | (2,384 | ) |
| Gains on sales of assets               |       | (526                              | )          | —                  |       | — |   | (526 | ) | — |   |
| Total costs and expenses               |       | 208,137                           |       | 182,723                 |       | 160,440 |   | 25,414 |   | 22,283 |   |
| Operating income                       |       | 71,263                            |       | 83,704                  |       | 83,098 |   | (12,441 | ) | 606 |   |
| Equity losses                          |       | (3,402                            | )          | (4,086                  | )          | (6,815 | ) | 684 |   | 2,729 |   |
| Other income – net                |       | 787                               |       | 226                     |       | 832 |   | 561 |   | (606 | ) |
| Earnings before interest               |       | $                                 | 68,648     |                    | $          | 79,844 |   | $ | 77,115 |   | $ | (11,196 | ) | $ | 2,729 |   |

 

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The following tablepresents volumes delivered in barrels and average tariff per barrel for the yearsended December 31, 2004, 2003 and 2002 (in thousands, except tariffinformation):

 
| ** **                       | ** ** | **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 | % |

 

TheDownstream Segment is dependent in large part on the demand for refinedpetroleum products in the markets served by its pipelines.  Reductions in that demand adversely affectthe pipeline business of the Downstream Segment.  Market demand varies based upon the differentend uses of the refined products shipped in the Downstream Segment.  Demand for gasoline, which in recent yearshas accounted for approximately one-half of the Downstream Segment’s refinedproducts transportation revenues, depends upon price, prevailing economicconditions and demographic changes in the markets served in the DownstreamSegment.  Demand for distillates isaffected by truck and railroad freight, the price of natural gas used byutilities, which use distillates as a substitute for natural gas when the priceof natural gas is high, and usage for agricultural operations, which isaffected by weather conditions, government policy and crop prices.  Demand for jet fuel, which in recent yearshas accounted for approximately one-quarter of the Downstream Segment’s refinedproducts revenues, depends on prevailing economic conditions and militaryusage.  Propane deliveries are generallysensitive to the weather and meaningful year-to-year variances have occurred inthe past and will likely continue to occur in the future.

 

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

 

Revenuesfrom 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 revenuesincreased primarily due to higher market-based tariff rates which went intoeffect in July 2003 and May 2004 and a shift in the distribution ofproduct moved by us to favor longer haul, higher tariff movements.  These changes resulted in a 5% increase inthe refined products average rate per barrel from the prior year and offset theeffect of a 1% decrease in refined products delivery volumes.  In February 2003, we entered into alease agreement with Centennial that increased our flexibility to deliverrefined products to our market areas. Volumes transported on Centennial increased due to increased demand andmarket share for products supplied from the U.S. Gulf Coast into Midwestmarkets.  Centennial has provided oursystem with additional pipeline capacity for products originating in the U.S.Gulf Coast area.  Prior to the constructionof Centennial, deliveries on our pipeline system were limited by our pipelinecapacity, and transportation services for our customers were allocated inaccordance with a proration policy.  Withthis incremental pipeline capacity, our previously constrained system hasexpanded deliveries in markets both south and north of Creal Springs.

 

Refinedproducts transportation revenues also increased due to the recognition of $4.1million of deferred revenue related to the expiration of two customer transportationagreements.  Under some of ourtransportation agreements with customers, the contracts specify minimumpayments for transportation services.  Ifthe transportation services paid for are not used, the unused transportationservice is recorded as deferred revenue. The contracts generally specify a subsequent period of time in which thecustomer can transport excess products to recover the amount recorded as deferredrevenue.  During the third quarter of2004, the time limit under two transportation agreements expired without thecustomers recovering the unused transportation services.  As a result, we recognized the deferredrevenue as refined products revenue in the current period.  This additional revenue increased the refinedproducts average tariff for the year ended December 31, 2004, by $0.02 perbarrel, or 2%.

 

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  Revenuesfrom LPGs transportation decreased $4.7 million for the year ended December 31,2004, compared with the year ended December 31, 2003, due to lowerdeliveries of propane in the upper Midwest and Northeast market areasattributable to warmer weather during the first and fourth quarters of2004.  Additionally, in late February 2004,the Mont Belvieu propane price spiked, which resulted in TEPPCO sourced propanebeing less competitive than propane from other source points.  Also contributing to the decrease were lessfavorable price differentials between Mont Belvieu and other supply centers duringthe second and third quarters of 2004.   Highpropane prices in 2004 also reduced the summer and early fall fill of consumerstorage of propane during 2004.  Thesedecreases were partially offset by increased deliveries of isobutane to Chicagoarea refineries and increased short-haul propane deliveries to U.S. Gulf Coastpetrochemical customers.  The LPGsaverage rate per barrel decreased 8% from the prior year period primarily as aresult of increased short-haul deliveries during 2004.

 

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

 

Costs andexpenses increased $25.4 million for the year ended December 31, 2004,compared with the year ended December 31, 2003, due to increased operating,general and administrative expenses, increased depreciation and amortizationexpense and increased operating fuel and power, partially offset by net gainson the sales of assets.  Operating,general and administrative expenses increased primarily due to a $6.2 millionincrease in pipeline inspection and repair costs associated with our integritymanagement program, a $2.0 million increase in legal accruals related to thesettlement of a lawsuit (see Note 16. Commitments and Contingencies), a $1.5 million increase in rentalexpense from the Centennial pipeline capacity lease agreement that we enteredinto in February 2003, a $1.3 million increase in consulting and contractservices related to compliance with the Sarbanes-Oxley Act of 2002 and a $1.1million increase in costs related to unsuccessful acquisition evaluations.  These increases were partially offset by $0.8million of lower expenses in the 2004 period associated with the write-off ofreceivables related to customer bankruptcies and non-payments in 2003.  Depreciation expense increased from the prioryear period because of a $4.4 million charge resulting from the impairment ofmarine assets in the Beaumont area (see Note 9. Property, Plant and Equipment). In addition, we wrote off approximately $2.1 million in assets taken outof 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 ofour pipeline system in the Northeast, resulting from pipeline capitalimprovements made as part of our integrity management program.  Operating fuel and power expense increasedprimarily as a result of higher power rates during the 2004 period.  In addition, we recognized net gains of $0.5million during 2004 from the sales of various assets in the Downstream Segment.

 

Netlosses 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 (inthousands):

 
| ** **          | ** ** | **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 |   |

 

Equitylosses in Centennial for the year ended December 31, 2004, compared withthe year ended December 31, 2003, decreased $0.1 million, primarily due toincreased transportation revenues and volumes and lower operating expenses.  During 2003, we acquired an additional 16.7%interest in Centennial on February 10, 2003, bringing TE Products’ownership interest to 50%.  Included inthe equity loss for the year ended December 31, 2004, is $1.2 million ofequity income relating to the settlement of certain transmix matters recognizedin previous periods.

 

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Equityearnings from our 50% ownership interest in MB Storage increased $0.5 millionfor the year ended December 31, 2004, compared with the year ended December 31,2003.  In April 2004, MB Storageacquired storage and pipeline assets and contracts for approximately $34.0million, of which TE Products contributed $16.5 million.  The increase in equity earnings is due toincreased storage revenue, shuttle revenue and rental revenue primarily fromthe acquired contracts and lower pipeline rehabilitation expenses on the MBStorage system, partially offset by increased amortization and depreciationexpense on storage assets and contracts acquired.

 

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

* *

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

* *

Revenuesfrom refined products transportation increased $15.5 million for the year endedDecember 31, 2003, compared with the year ended December 31, 2002, dueto an overall increase of 12% in the refined products volumes delivered.  This increase in volumes delivered wasprimarily due to deliveries of products received into our pipeline fromCentennial at Creal Springs, Illinois. Centennial, which began operations in April 2002, has provided oursystem with additional pipeline capacity for products originating in the U.S.Gulf Coast area.  In February 2003, weentered into a lease agreement with Centennial that increased our capacity todeliver refined products to our market areas. Prior to the lease agreement withCentennial, deliveries on our pipeline system were based upon a prorationpolicy, which limited customer transportation. During 2003, with the expanded capacity through our lease agreement withCentennial, our pipeline system was not prorated during portions of 2003 andwas better able to serve markets which increased transportation on oursystem.  In addition, in December 2002, we raised theoperating pressure of our Chicago lateral pipeline, which resulted in an increasein capacity for deliveries into the Indianapolis and Chicago markets.  With thisincremental pipeline capacity, our previously constrained system has expandeddeliveries in markets both south and north of Creal Springs.  Volume increases were due to increased demandand market share for products supplied from the U.S. Gulf Coast into Midwestmarkets.  The refined products averagerate per barrel increased 1% from the prior year period primarily due to highermarket-based tariff rates which went into effect in July 2003, partiallyoffset by the impact of the Midwest origin point for barrels received fromCentennial, which resulted in an increase in short-haul barrels transported onour system.

 

Revenuesfrom LPGs transportation increased $17.2 million for the year ended December 31,2003, compared with the year ended December 31, 2002, primarily due toincreased deliveries of propane in the upper Midwest and Northeast market areasattributable to colder than normal weather during the first quarter of 2003 anddue to low inventories at competing supply locations during the second andthird quarters of 2003.  The U.S. GulfCoast had higher propane inventory during 2003 as compared to the previous yearbecause of higher than normal foreign propane imports at Mont Belvieu, whichresulted in a lower propane price in this market area.  This lower price contributed to increasedtransportation deliveries to the mid-continent market areas.  Additional pipeline capacity for expandedpropane movements was available due to a shift of refined product volumes toCentennial.  Butane deliveries alsoincreased due to the increased demand by refineries for normal butane for usein gasoline blending and increased isobutane deliveries to Chicago arearefineries.  The LPGs average rate perbarrel increased 17% from the prior year period as a result of an increasedpercentage 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.

 

EffectiveJanuary 1, 2003, TE Products’ 50% ownership interest in MB Storage isaccounted for as an equity investment as a result of the formation of MBStorage.  Revenues and expenses relatedto Mont Belvieu operations are now recorded within equity earnings.  See discussion regarding changes in equityearnings/losses below.

 

Other operatingrevenues increased $5.4 million for the year ended December 31, 2003,compared with the year ended December 31, 2002, primarily due to theaddition of the northern portion of the Dean Pipeline to the Downstream Segmentin January 2003, which increased other operating revenues by $4.5 millionas the pipeline began transporting RGP in January 2003.  The increase was also due to higher propanedeliveries at our Providence, Rhode Island import facility and higher refinedproduct loading fees.  These increaseswere partially offset by lower revenues from product location exchanges whichare used to position product in the Midwest market area and lower volume ofproduct inventory sales.

 

36

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Costs andexpenses increased $22.3 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 amortizationexpense, partially offset by decreased taxes – other than income taxes anddecreased operating fuel and power. Operating, general and administrative expenses increased primarily dueto higher pipeline maintenance expenses, due in part to pipeline rehabilitationexpenses associated with our integrity management program, increased consultingand contract services, increased labor costs primarily due to an increase inthe number of employees between years, increased insurance expense, expensefrom the Centennial pipeline capacity lease agreement that we entered into in2003 and the write-off of receivables of $0.8 million related to customerbankruptcies or other customer non-payments. The addition of the northern portion of the Dean Pipeline to theDownstream Segment increased operating, general and administrative expense by $0.7million.  Depreciation expense increasedfrom the prior year period because of assets placed in service during the year.  In addition, we wrote off assets taken out ofservice during the period to depreciation expense, which also increaseddepreciation expense.  These increases indepreciation expense were partially offset by lower depreciation expense from assetsretired during the year, which reduced the asset base, and due to the transferof assets to MB Storage.  Taxes – otherthan income taxes decreased as a result of actual property taxes being lowerthan previously estimated and due to the transfer of assets to MB Storage.  Operating fuel and power expense decreased asa result of lower power costs due to a slight decrease in the price of naturalgas, partially offset by increased mainline throughput.

 

Netlosses 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 (inthousands):

 
| ** **          | ** ** | **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 |   |

 

Equitylosses in Centennial for the year ended December 31, 2003, increased $4.7million compared with the year ended December 31, 2002, due to higheroperating expenses primarily as a result of a full year of operating costs in2004, partially offset by higher transportation volumes and revenues.  Centennial commenced operations in April 2002.  On February 10, 2003, TE Productsacquired an additional 16.7% interest in Centennial, bringing its ownershipinterest to 50%.  In April 2003, TEProducts entered into a pipeline capacity lease with Centennial for a period offive years in order to expand its capacity to deliver refined products to itsmarket areas.

 

Equityearnings from our 50% ownership interest in MB Storage was $7.4 million for theyear ended December 31, 2003.  Amountsin the prior year period related to Mont Belvieu operations, which wererecorded to revenues and costs and expenses are now being recorded withinequity earnings based upon our 50% ownership interest in MB Storage, effectivewith its formation on January 1, 2003. If the 2002 revenues and costs and expenses from the Mont Belvieuoperations had been accounted for under the same method as in 2003, equityearnings from MB Storage would have increased $0.2 million in 2003, comparedwith the prior year, due to increased shuttle deliveries and increased storagerevenue, partially offset by increases in depreciation expense andrehabilitation expenses on MB Storage assets.

 

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

 

37

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****Upstream Segment****

 

The following tableprovides financial information for the Upstream Segment for the years ended December 31,2004, 2003 and 2002 (in thousands):    

 
| ** **                            | ** ** | **Years Ended December 31,** | ** ** | **Increase (Decrease)** | ** ** |
|---------------------------------------|------------|-----------------------------------|------------|-------------------------|------------|
| ** **                            | ** ** | **2004**                          | ** ** | **2003**                | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** |
| Sales of petroleum products           |       | $                                 | 5,426,832  |                    | $          | 3,766,651 |   | $ | 2,823,800 |   | $ | 1,660,181 |   | $ | 942,851 |   |
| Transportation – Crude oil       |       | 37,177                            |       | 29,057                  |       | 27,414 |   | 8,120 |   | 1,643 |   |
| Other                                 |       | 11,986                            |       | 10,507                  |       | 10,486 |   | 1,479 |   | 21 |   |
| Total operating revenues              |       | 5,475,995                         |       | 3,806,215               |       | 2,861,700 |   | 1,669,780 |   | 944,515 |   |
|                                  |       |                              |       |                    |       |   |   |   |   |   |   |
| Purchases of petroleum products       |       | 5,370,234                         |       | 3,713,122               |       | 2,774,325 |   | 1,657,112 |   | 938,797 |   |
| Operating, general and administrative |       | 51,424                            |       | 50,471                  |       | 43,362 |   | 953 |   | 7,109 |   |
| Operating fuel and power              |       | 5,490                             |       | 3,672                   |       | 3,378 |   | 1,818 |   | 294 |   |
| Depreciation and amortization         |       | 13,130                            |       | 11,311                  |       | 11,186 |   | 1,819 |   | 125 |   |
| Taxes – other than income taxes  |       | 3,979                             |       | 3,171                   |       | 3,041 |   | 808 |   | 130 |   |
| Gains on sales of assets              |       | (527                              | )          | (3,948                  | )          | — |   | 3,421 |   | (3,948 | ) |
| Total costs and expenses              |       | 5,443,730                         |       | 3,777,799               |       | 2,835,292 |   | 1,665,931 |   | 942,507 |   |
| Operating income                      |       | 32,265                            |       | 28,416                  |       | 26,408 |   | 3,849 |   | 2,008 |   |
| Equity earnings                       |       | 29,383                            |       | 20,949                  |       | 18,795 |   | 8,434 |   | 2,154 |   |
| Other income – net               |       | 406                               |       | 306                     |       | 1,532 |   | 100 |   | (1,226 | ) |
| Earnings before interest              |       | $                                 | 62,054     |                    | $          | 49,671 |   | $ | 46,735 |   | $ | 12,383 |   | $ | 2,936 |   |

 

Informationpresented in the following table includes the margin of the Upstream Segment,which may be viewed as a non-GAAP (Generally Accepted Accounting Principles)financial measure under the rules of the SEC. We calculate the margin of the Upstream Segment as revenues generatedfrom the sale of crude oil and lubrication oil, and transportation of crudeoil, less the costs of purchases of crude oil and lubrication oil.  We believe that margin is a more meaningfulmeasure of financial performance than sales and purchases of crude oil andlubrication oil due to the significant fluctuations in sales and purchases causedby variations in the level of volumes marketed and prices for products marketed.  Additionally, we use margin internally toevaluate the financial performance of the Upstream Segment as we believe marginis a better indicator of performance than operating income as operating,general and administrative expenses, operating fuel and power and depreciationexpense are not directly related to the margin activities.  Margin and volume information for the yearsended December 31, 2004, 2003 and 2002 is presented below (in thousands,except per barrel and per gallon amounts):    

 
| ** **                             | ** ** | **Years Ended December 31,** | ** ** | **Percentage  Increase (Decrease)** | ** ** |
|----------------------------------------|------------|-----------------------------------|------------|-------------------------------------|------------|
| ** **                             | ** ** | **2004**                          | ** ** | **2003**                            | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** |
| Margins: (1)                           |       |                              |       |                                |       |   |   |   |   |   |   |
| Crude oil transportation               |       | $                                 | 55,425     |                                | $          | 45,794 |   | $ | 39,025 |   | 21 | % | 17 | % |
| Crude oil marketing                    |       | 22,468                            |       | 22,017                              |       | 22,914 |   | 2 | % | (4 | )% |
| Crude oil terminaling                  |       | 9,388                             |       | 9,403                               |       | 10,124 |   | — |   | (7 | )% |
| Lubrication oil sales                  |       | 6,494                             |       | 5,372                               |       | 4,826 |   | 21 | % | 11 | % |
| Total margin                           |       | $                                 | 93,775     |                                | $          | 82,586 |   | $ | 76,889 |   | 14 | % | 7 | % |
|                                   |       |                              |       |                                |       |   |   |   |   |   |   |
| Total barrels:                         |       |                              |       |                                |       |   |   |   |   |   |   |
| Crude oil transportation               |       | 101,462                           |       | 95,541                              |       | 82,813 |   | 6 | % | 15 | % |
| Crude oil marketing                    |       | 177,273                           |       | 159,710                             |       | 139,182 |   | 11 | % | 15 | % |
| Crude oil terminaling                  |       | 113,197                           |       | 115,076                             |       | 127,376 |   | (2 | )% | (10 | )% |
|                                   |       |                              |       |                                |       |   |   |   |   |   |   |
| Lubrication oil volume (total gallons) |       | 13,964                            |       | 10,449                              |       | 9,648 |   | 34 | % | 8 | % |
|                                   |       |                              |       |                                |       |   |   |   |   |   |   |
| Margin per barrel:                     |       |                              |       |                                |       |   |   |   |   |   |   |
| Crude oil transportation               |       | $                                 | 0.546      |                                | $          | 0.479 |   | $ | 0.471 |   | 14 | % | 2 | % |
| Crude oil marketing                    |       | 0.127                             |       | 0.138                               |       | 0.165 |   | (8 | )% | (16 | )% |
| Crude oil terminaling                  |       | 0.083                             |       | 0.082                               |       | 0.080 |   | 1 | % | 3 | % |
|                                   |       |                              |       |                                |       |   |   |   |   |   |   |
| Lubrication oil margin (per gallon):   |       | $                                 | 0.465      |                                | $          | 0.514 |   | $ | 0.500 |   | (10 | )% | 3 | % |

 

38

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----

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

 

Thefollowing table reconciles the Upstream Segment margin to operating income in theconsolidated statements of income using the information presented in the tablesabove, in the consolidated statements of income and in the statements of incomein Note 17.  Segment Information (inthousands):

 
| ** **                            | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------------|------------|-----------------------------------|------------|
| ** **                            | ** ** | **2004**                          | ** ** | **2003** | ** ** | **2002** | ** ** |
| Sales of petroleum products           |       | $                                 | 5,426,832  |   | $ | 3,766,651 |   | $ | 2,823,800 |   |
| Transportation – Crude oil       |       | 37,177                            |       | 29,057 |   | 27,414 |   |
| Less: Purchases of petroleum products |       | (5,370,234                        | )          | (3,713,122 | ) | (2,774,325 | ) |
| Total margin                          |       | 93,775                            |       | 82,586 |   | 76,889 |   |
| Other operating revenues              |       | 11,986                            |       | 10,507 |   | 10,486 |   |
| Total operating revenues              |       | 105,761                           |       | 93,093 |   | 87,375 |   |
| Operating, general and administrative |       | 51,424                            |       | 50,471 |   | 43,362 |   |
| Operating fuel and power              |       | 5,490                             |       | 3,672 |   | 3,378 |   |
| Depreciation and amortization         |       | 13,130                            |       | 11,311 |   | 11,186 |   |
| Taxes – other than income taxes  |       | 3,979                             |       | 3,171 |   | 3,041 |   |
| Gains on sales of assets              |       | (527                              | )          | (3,948 | ) | — |   |
| Operating income                      |       | $                                 | 32,265     |   | $ | 28,416 |   | $ | 26,408 |   |

 

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

 

Ourmargin increased $11.2 million for the year ended December 31, 2004,compared with the year ended December 31, 2003.  Crude oil transportation margin increased $9.6million primarily due to an increase in transportation volumes and revenues onour South Texas system and our Red River system.  Our Basin system also had increasedtransportation volumes and revenues primarily due to the expansion of thesystem between Midland, Texas, and Wichita Falls, Texas, resulting in anadditional capacity of ten thousand barrels per day on the system, and movementsof barrels on higher tariff segments. During the fourth quarter of 2003, we completed the purchase of crudesupply and transportation assets (Genesis), which have been integrated into ourSouth Texas system (see Note 5. Acquisitions and Dispositions). Lubrication oil sales margin increased $1.1 million due to increasedsales of chemical volumes and increased volumes related to the acquisitions oflubrication oil distributors in Abilene, Texas, in December 2003 and inCasper, Wyoming, in August 2004. Crude oil marketing margin increased $0.5 million as a result of increasedvolumes marketed, partially offset by an unfavorable invoicing settlement on amarketing contract in the first quarter of 2003, which reduced the marketingmargin in 2003, and increased transportation costs.  Crude oil terminaling margin remainedunchanged as a result of higher pumpover volumes at Cushing, Oklahoma, offsetby lower pumpover volumes at Midland, Texas.

 

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

 

Costs andexpenses, excluding expenses associated with purchases of crude oil andlubrication oil, increased $5.4 million for the year ended December 31,2004, compared with the year ended December 31, 2003, due to increased operatingfuel and power, increased depreciation and amortization expense, increasedoperating, general and administrative expenses and increased taxes – other thanincome taxes.  Operating fuel and powerincreased $1.8 million primarily as a result of the acquisition of the Genesisassets and higher volumes in 2004. Depreciation and amortization expense increased $1.8 million primarilydue to the assets acquired from Genesis. Operating, general and administrative expenses increased $1.0 millionfrom the prior year primarily due to a $3.9 million increase in pipelineinspection and repair costs associated with our integrity management program, a$2.0 million increase in expenses related to the Genesis acquisition, a $1.4million increase in labor and benefits expense related to incentivecompensation plans and an increase in the number of employees between periods, a$0.7 million increase in consulting and contract services related to compliancewith the Sarbanes-Oxley Act of 2002 and a $0.6

 

39

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million increase in rental expense dueto our pipeline lease at Freeport, Texas, with Seaway.  These increases were partially offset by $3.8million of higher environmental assessment and remediation costs in 2003, $1.7million of expense in 2003 from the net settlement of crude oil imbalances withcustomers, $1.5 million of higher legal costs in 2003 related to the litigationand settlement with D.R.D. Environmental Services, Inc. (“D.R.D.”) and $0.5million of lower expenses in 2004 from the sale of the Rancho assets in2003.  Taxes – other than income taxesincreased $0.8 million due to increases in property tax accruals.

 

In June 2003,we recorded a net gain of $3.9 million, included in the gain on sale of assetsin our consolidated statements of income, on the sale of certain of the assetsof the Rancho Pipeline.  During the year endedDecember 31, 2004, we recorded net gains of $0.5 million, included in thegains on sales of assets in our consolidated statements of income, primarilyrelated to the sale of our remaining interest in the original Rancho Pipelinesystem (see Note 5.  Acquisitions andDispositions).

 

Equityearnings from our investment in Seaway increased $8.4 million for the yearended December 31, 2004, compared with the year ended December 31,2003, due to higher transportationvolumes, gains on crude oil inventory sales, a settlement with a former ownerof Seaway’s crude oil assets regarding inventory imbalances that were not acquiredby us and lower operating, general andadministrative expenses.

 

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

 

Ourmargin increased $5.7 million for the year ended December 31, 2003,compared with the year ended December 31, 2002. Crude oil transportationmargin increased $6.8 million primarily due to increased revenues on our RedRiver, Basin, South Texas and West Texas systems resulting from a 15% increasein transportation volumes on these systems partially due to the acquisition ofthe Genesis assets.  During the fourthquarter of 2003, we completed the purchase of crude supply and transportationassets (Genesis), which was integrated into our South Texas system.  The acquisition of the Genesis assets increasedour transportation and marketing margins by approximately $1.2 million and thebarrels transported and marketed by approximately 1.6 million barrels during2003.  Lubrication oil sales marginincreased $0.5 million due to increased sales of chemical volumes, highermargins on lubrication sales and increased volumes related to the acquisitionof a lubrication oil distributor in Abilene, Texas, in December 2003.  Crude oil marketing margin decreased $0.9million primarily due to an invoicing settlement on a marketing contract in thefirst quarter of 2003, partially offset by increased volumes marketed,renegotiated supply contracts, lower trucking expenses and more favorable crudeoil price differentials.  Crude oil terminalingmargin decreased $0.7 million as a result of a 10% decrease in volumes atMidland, Texas, and Cushing, Oklahoma.

 

Costs andexpenses, excluding expenses associated with purchases of crude oil andlubrication oil, increased $7.6 million for the year ended December 31, 2003,compared with the year ended December 31, 2002.  Operating, general and administrativeexpenses increased $7.1 million from the prior year period.  The increase includes a $2.4 million increasein environmental assessment and remediation costs in 2003, higher legal costsrelated to the litigation and settlement with D.R.D. and other legal costs (seeNote 16.  Commitments and Contingencies),$1.7 million of expense from the net settlement of crude oil imbalances withcustomers, higher pipeline rehabilitation expenses associated with our integritymanagement program and increased labor costs due to an increase in the numberof employees between periods, partially offset by lower general andadministrative supplies expenses during the period.  In addition, the acquisition of the Genesisassets and integration into our South Texas system during the fourth quarterincreased operating, general and administrative expenses by approximately $0.5million.  Operating fuel and powerincreased $0.3 million due to higher power costs and higher volumes in2003.  Depreciation and amortizationexpense increased $0.1 million due to assets placed in service in 2002 and 2003and due to asset retirements.  Taxes –other than income taxes increased $0.1 million due to slight increases inproperty tax accruals.

 

Equity earningsfrom our investment in Seaway increased $2.2 million for the year ended December 31,2003, compared with the year ended December 31, 2002, due to a favorable crude oil imbalancesettlement, a gain on the sale of inventory, lower general and administrativeexpenses and higher long-haul transportation volumes, partially offset by ourportion of equity earnings which decreased from 80% to 60% on a pro-rated basisin 2002 (averaging approximately 67% for the year ended December 31, 2002),to 60% in 2003.

 

40

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In June 2003,we recorded a net gain of $3.9 million, included in the gain on sale of assetsin our consolidated statements of income, on the sale of certain of the assetsof the Rancho Pipeline.  In connectionwith our acquisition of crude oil assets in 2000, we acquired an approximate 23.5%undivided joint interest in the Rancho Pipeline, which was a crude oil pipelinesystem from West Texas to Houston.  In March 2003,the Rancho Pipeline ceased operations, and segments of the pipeline were soldto certain of the current owners that previously held undivided interests inthe pipeline.  We acquired 241 miles ofthe pipeline in exchange for cash of $5.5 million and our interests in otherportions of the Rancho Pipeline.  We sold183 miles of the segment we acquired to other entities for cash and assetsvalued at approximately $8.5 million.

 

Other income – netdecreased $1.2 million for the year ended December 31, 2003, compared withthe year ended December 31, 2002, primarily due to lower interest incomereceived on intercompany borrowings.

 

****Midstream Segment****

 

The following tableprovides financial information for the Midstream Segment for the years ended December 31,2004, 2003 and 2002 (in thousands):

 
| ** **                            | ** ** | **Years Ended December 31,** | ** ** | **Increase (Decrease)** | ** ** |
|---------------------------------------|------------|-----------------------------------|------------|-------------------------|------------|
| ** **                            | ** ** | **2004**                          | ** ** | **2003**                | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** |
| Sales of petroleum products           |       | $                                 | 7,295      |                    | $          | — |   | $ | — |   | $ | 7,295 |   | $ | — |   |
| Gathering – Natural gas          |       | 140,122                           |       | 135,144                 |       | 90,053 |   | 4,978 |   | 45,091 |   |
| Transportation – NGLs            |       | 41,204                            |       | 39,837                  |       | 38,870 |   | 1,367 |   | 967 |   |
| Other                                 |       | 17,383                            |       | 10,124                  |       | 9,999 |   | 7,259 |   | 125 |   |
| Total operating revenues              |       | 206,004                           |       | 185,105                 |       | 138,922 |   | 20,899 |   | 46,183 |   |
|                                  |       |                              |       |                    |       |   |   |   |   |   |   |
| Purchases of petroleum products       |       | 5,944                             |       | —                  |       | — |   | 5,944 |   | — |   |
| Operating, general and administrative |       | 47,053                            |       | 37,469                  |       | 25,357 |   | 9,584 |   | 12,112 |   |
| Operating fuel and power              |       | 8,208                             |       | 6,033                   |       | 4,438 |   | 2,175 |   | 1,595 |   |
| Depreciation and amortization         |       | 56,629                            |       | 57,797                  |       | 44,730 |   | (1,168 | ) | 13,067 |   |
| Taxes – other than income taxes  |       | 4,565                             |       | 3,518                   |       | 3,656 |   | 1,047 |   | (138 | ) |
| Total costs and expenses              |       | 122,399                           |       | 104,817                 |       | 78,181 |   | 17,582 |   | 26,636 |   |
| Operating income                      |       | 83,605                            |       | 80,288                  |       | 60,741 |   | 3,317 |   | 19,547 |   |
| Other income – net               |       | 127                               |       | 289                     |       | 269 |   | (162 | ) | 20 |   |
| Earnings before interest              |       | $                                 | 83,732     |                    | $          | 80,577 |   | $ | 61,010 |   | $ | 3,155 |   | $ | 19,567 |   |

 

41

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Thefollowing table presents volume and average rate information for the yearsended December 31, 2004, 2003 and 2002 (in thousands, except average feeand average rate amounts):

 
| ** **                                        | ** ** | **Years Ended December 31,** | ** ** | **Percentage  Increase (Decrease)** | ** ** |
|---------------------------------------------------|------------|-----------------------------------|------------|-------------------------------------|------------|
| ** **                                        | ** ** | **2004**                          | ** ** | **2003**                            | ** ** | **2002** | ** ** | **2004** |   | **2003** |   |
| Gathering – Natural Gas – Jonah:        |       |                              |       |                                |       |   |   |   |   |   |   |
| Million cubic feet                                |       | 354,546                           |       | 302,951                             |       | 248,360 |   | 17 | % | 22 | % |
| Million British thermal units (“MMBtu”) |       | 392,154                           |       | 336,032                             |       | 275,831 |   | 17 | % | 22 | % |
| Average fee per MMBtu                             |       | $                                 | 0.194      |                                | $          | 0.193 |   | $ | 0.182 |   | 1 | % | 6 | % |
|                                              |       |                              |       |                                |       |   |   |   |   |   |   |
| Gathering – Natural Gas – Val Verde:    |       |                              |       |                                |       |   |   |   |   |   |   |
| Million cubic feet                                |       | 144,539                           |       | 158,286                             |       | 92,336 |   | (9 | )% | 71 | % |
| MMBtu                                             |       | 122,706                           |       | 133,094                             |       | 77,831 |   | (8 | )% | 71 | % |
| Average fee per MMBtu                             |       | $                                 | 0.523      |                                | $          | 0.529 |   | $ | 0.515 |   | (1 | )% | 3 | % |
|                                              |       |                              |       |                                |       |   |   |   |   |   |   |
| Transportation – NGLs:                       |       |                              |       |                                |       |   |   |   |   |   |   |
| Thousand barrels                                  |       | 59,549                            |       | 57,902                              |       | 53,980 |   | 3 | % | 7 | % |
| Average rate per barrel                           |       | $                                 | 0.692      |                                | $          | 0.688 |   | $ | 0.720 |   | 1 | % | (4 | )% |
|                                              |       |                              |       |                                |       |   |   |   |   |   |   |
| Fractionation – NGLs:                        |       |                              |       |                                |       |   |   |   |   |   |   |
| Thousand barrels                                  |       | 4,149                             |       | 4,131                               |       | 4,072 |   | — |   | 1 | % |
| Average rate per barrel                           |       | $                                 | 1.797      |                                | $          | 1.804 |   | $ | 1.824 |   | — |   | (1 | )% |
|                                              |       |                              |       |                                |       |   |   |   |   |   |   |
| Sales – Condensate:                          |       |                              |       |                                |       |   |   |   |   |   |   |
| Thousand barrels                                  |       | 84.4                              |       | 63.3                                |       | 80.0 |   | 33 | % | (21 | )% |
| Average rate per barrel                           |       | $                                 | 37.99      |                                | $          | 30.25 |   | $ | 25.39 |   | 26 | % | 19 | % |

 

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

 

Revenuesfrom the gathering of natural gas increased $5.0 million for the year ended December 31,2004, compared with the year ended December 31, 2003.  Natural gas gathering revenues from the Jonahsystem increased $11.3 million and volumes gathered increased 51.6 Bcf for theyear ended December 31, 2004, due to the expansion of the Jonah systemduring 2003.  The Phase III expansion wassubstantially completed during the fourth quarter of 2003 and increased systemcapacity from 880 MMcf/day to 1,180 MMcf/day. The increase in Jonah’s revenues was also partially due to highergathering rates realized due to lower system pressures resulting from theincreased capacity provided by the Phase III expansion.  Natural gas gathering revenues from the ValVerde system decreased $6.3 million and volumes gathered decreased 13.7 Bcf forthe year ended December 31, 2004, primarily due to the natural decline ofCBM production and slower than anticipated completion and connection of infillwells, partially offset by increased volumes from two new connections made tothe Val Verde system in May and December 2004.  Val Verde’s average natural gas gatheringrate per MMcf decreased due to contracts entered into relating to the newconnections, which have lower rates than the existing Val Verde system’saverage rates.

 

Jonah’sPioneer gas processing plant was completed during the first quarter of 2004, asa part of the Phase III expansion to increase the processing capacity insouthwestern Wyoming.  Pioneer’sprocessing agreements allow the producers to elect annually whether to be chargedunder a fee-based arrangement or a fee plus keep-whole arrangement.  Under the fee-based election, Jonah receivesa fee for its processing services.  Underthe fee plus keep-whole election, Jonah receives a lower fee for its processingservices, retains and sells the NGLs extracted during the process and deliversto the producers residue gas equivalent in energy to the natural gas receivedfrom the producers.  Jonah purchases gasfrom an affiliate of DEFS to replace the equivalent energy removed in theliquids.  Jonah sells the NGLs it retainsto an affiliate of DEFS.  For the yearended December 31, 2004, the sales and purchases under the feearrangements at the Pioneer plant resulted in a margin (sales of petroleumproducts less purchases of petroleum products) of $1.4 million.

 

Revenuesfrom the transportation of NGLs increased $1.4 million for the year ended December 31,2004, compared with the year ended December 31, 2003, primarily due toincreases in volumes transported on the

 

42

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Chaparral and Panola Pipelines,partially offset by decreased volumes on the Dean and Wilcox Pipelines.  Higher average rates per barrel on volumestransported on the Panola and Wilcox Pipelines were offset by lower averagerates per barrel on volumes transported on the Chaparral and Dean Pipelines.

 

Otheroperating revenues increased $7.2 million for the year ended December 31,2004, compared with the year ended December 31, 2003.  Processing fee revenues increased $2.8 millionas a result of Jonah’s Pioneer processing plant, which was constructed as partof the Phase III expansion and placed in service in January 2004.  Jonah’s other operating revenues alsoincreased $0.9 million primarily due to higher condensate sales.  Other operating revenues on Chaparralincreased $1.9 million due to the recognition of deferred revenue related to aninventory settlement.  Val Verde’soperating revenues increased $1.6 million due to revenues generated as a resultof contractual producer minimum fuel levels exceeding actual operating fuelusage during the year ended December 31, 2004.  Val Verde retains a portion of its producers’gas to compensate for fuel used in operations. The actual usage of gas can differ from the amount contractuallyretained from producers.  Value retainedfrom producers or sales generated as a result of efficient fuel usage isrecognized as other operating revenues.

 

Costs andexpenses (excluding purchases of petroleum products) increased $11.7 millionfor the year ended December 31, 2004, compared with the year ended December 31,2003, due to increases in operating, general and administrative expense,operating fuel and power and taxes – other than income taxes, partially offsetby a decrease in depreciation and amortization expense.  Operating, general and administrative expenseincreased due to a $3.8 million increase in gas settlement expenses, a $3.0million increase in general and administrative labor expense, a $1.3 million increasein consulting and contract services related to compliance with theSarbanes-Oxley Act of 2002, a $0.9 million increase related to our integritymanagement program and a $0.9 million increase related to Jonah’s processingplant which began operations in 2004.  Theseincreases are partially offset by a $0.6 million decrease in expense related tothe sale of our Enron Corp. receivable, which had been fully reserved in 2001,and a $0.4 million decrease in maintenance expenditures at Val Verde.  Operating fuel and power increased $2.2 million,primarily due to higher variable power rates and increased NGL volumestransported during times of peak variable power rates.  Depreciation expense increased $3.5 million,primarily as a result of assets placed in service in 2003 related to the expansionof the Jonah system and additional well connections on the Val Verde system in2004.  Taxes – other than income taxesincreased $1.0 million as a result of higher property balances.  Amortization expense decreased $4.7 millionprimarily due to revisions to the estimated life of Jonah’s intangible assetsunder the units-of-production method, partially offset by a $1.7 millionincrease as a result of higher volumes in the 2004 period.  In second quarter 2003, Jonah’s estimatedtotal throughput of the system was adjusted, which resulted in an extension ofthe expected amortization period from 16 years to 25 years.  During the fourth quarter of 2004, additionallimited production forecasts were obtained from some of the producers on theJonah system related to future expansions of the system, and as a result, weagain increased our best estimate of future throughput on the Jonahsystem.  This increase in the estimate offuture throughput extended the amortization period of Jonah’s natural gasgathering contracts by an estimated 10 years, increasing from approximately 25years to approximately 35 years (see Note 3. Goodwill and Other Intangible Assets). Amortization expense on the Val Verde system decreased $2.1 millionprimarily due to lower volumes in the 2004 period, resulting from the naturaldecline in CBM production.

 

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

 

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

 

Revenuesfrom the gathering of natural gas increased $45.1 million for the year ended December 31,2003, compared with the year ended December 31, 2002.  Natural gas gathering revenues from the Jonahsystem increased $14.6 million and volumes gathered increased 54.6 Bcf for the yearended December 31, 2003, due to the expansions of the Jonah system during2002.  The first expansion, which wascompleted in May 2002, increased the capacity of the Jonah system by 62%, fromapproximately 450 MMcf/day to approximately 730 MMcf/day.  In October 2002, additional expansionprojects were completed, which increased the capacity of the Jonah system from730 MMcf/day to approximately 880 MMcf/day. A Phase III expansion was substantially completed during the fourthquarter of 2003 and increased system capacity to 1,180 MMcf/day.  The increase in Jonah’s revenues was alsopartially due to an increase in the average natural gas gathering rate due tocertain volume thresholds being exceeded. Natural gas gathering revenues from the Val Verde system increased $30.5million and volumes gathered increased 65.9 Bcf for the year ended December 31,2003, primarily due to the acquisition of the Val Verde system

 

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on June 30, 2002.  Volumes delivered for the first half of 2003were approximately 82.0 Bcf.  As ValVerde was acquired on June 30, 2002, there were no comparable volumes forthe first half of 2002.  Volumes deliveredduring the second half of 2003 as compared to the second half of 2002 declinedapproximately 16.0 Bcf.  This decrease involumes during the second half of 2003 was due to the natural decline of CBMproduction, which resulted in decreased revenues, partially offset by anincrease in the average natural gas gathering rate due to annual feeescalations in gathering agreements and higher carbon dioxide treating fees asa result of increasing carbon dioxide content in the natural gas.

 

Revenuesfrom the transportation of NGLs increased $1.0 million for the year ended December 31,2003, compared with the year ended December 31, 2002, primarily due to anincrease of $4.4 million related to the acquisition of Chaparral on March 1,2002, $0.7 million due to an increase in volumes transported on Chaparral and$0.2 million due to an increase in volumes transported on the Wilcox Pipeline.  This increase was partially offset by adecrease of $2.4 million due to lower transportation volumes on Panola as a resultof lower NGL volumes available from the connected NGL plants and a decrease of $1.9million on the southern portion of the Dean Pipeline due to decreasedtransportation volumes.  Lowertransportation volumes on the southern portion of the Dean Pipeline resultedfrom the conversion of the northern portion of the pipeline to transport RGPand subsequent classification as a part of the Downstream Segment, effective January 1,2003.  The decrease in the NGLtransportation average rate per barrel resulted from a lower average rate perbarrel on volumes transported on Chaparral.

 

Costs andexpenses increased $26.6 million for the year ended December 31, 2003,compared with the year ended December 31, 2002, due to increased depreciationand amortization expense, increased operating, general and administrativeexpense and increased operating fuel and power, partially offset by decreased taxes– other than income taxes.  Depreciationand amortization expense increased $14.6 million due to the Chaparral and Val Verdeassets acquired on March 1, 2002, and June 30, 2002, respectively,$0.3 million due to assets placed in service in 2002 related primarily to theexpansions of the Jonah system and $2.0 million in amortization expense onJonah’s intangible assets under the units-of-production method, as volumesgathered increased between periods. These increases were partially offset by a decrease of $1.8 million inamortization expense on Val Verde’s intangible assets under theunits-of-production method as volumes gathered decreased between periods.  In addition, amortization expense on Jonahdecreased $2.0 million related to its intangible assets.  In second quarter 2003, Jonah’s estimatedtotal throughput of the system was adjusted, which resulted in an extension ofthe expected amortization period from 16 years to 25 years (see Note 3.  Goodwill and Other Intangible Assets).  Operating, general and administrative expenseincreased $11.0 million from the assets acquired, and $1.1 million primarilydue to higher general and administrative labor and supplies expense andincreased consulting and contracting services. Operating fuel and power costs increased $0.8 million due to the assetsacquired and $0.8 million due to increased volumes transported onChaparral.  Taxes – other than incometaxes decreased $0.2 million due to actual property taxes being lower thanpreviously estimated on Val Verde, Panola and the southern portion of the Dean Pipeline.

 

**Interest Expense and CapitalizedInterest**

 

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

 

Interestexpense decreased $13.3 million for the year ended December 31, 2004,compared with the year ended December 31, 2003, due to a higher percentageof variable interest rate debt during the year ended December 31, 2004,that carried a lower rate of interest as compared to fixed interest ratedebt.  The higher percentage of variableinterest rate debt resulted from the expiration of an interest rate swap in April 2004(see Note 4. Interest Rate Swaps).  Thedecrease was partially offset by higher balances outstanding on our revolvingcredit facility in 2004.

 

Capitalizedinterest decreased $1.1 million for the year ended December 31, 2004,compared with the year ended December 31, 2003, due to interest capitalizedon lower construction work-in-progress balances in 2004.

 

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

* *

Interestexpense increased $19.0 million for the year ended December 31, 2003,compared with the year ended December 31, 2002, primarily due to $12.3million of additional expense related to changes in our fair value

 

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and cash flow hedging activities,$16.1 million of additional expense related to the issuance of our 6.125%Senior Notes in January 2003 and our 7.625% Senior Notes in February 2002and $1.3 million of debt issuance costs written off in June 2003 relatedto the refinancing of our revolving credit facility.  These increases were partially offset by a$10.7 million reduction in interest expense related to decreased borrowingsunder our revolving credit facility.

 

Capitalizedinterest increased $0.9 million for the year ended December 31, 2003,compared with the year ended December 31, 2002, due to increased constructionwork-in-progress balances during 2003, partially offset by interest capitalizedon our investment in Centennial during the first quarter of 2002.

 

****Financial Condition and Liquidity****

 

Cash generated fromoperations, credit facilities and debt and equity offerings are our primarysources of liquidity.  At December 31,2004, and 2003, we had working capital deficits of $37.8 million and $22.8million, respectively.  At December 31,2004, we had approximately $132.0 million in available borrowing capacity underour revolving credit facility to cover any working capital needs.  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        |       | $                                 | 266.2      |   | $ | 239.4 |   | $ | 234.9 |   |
| Investing activities        |       | (189.2                            | )          | (185.3 | ) | (724.7 | ) |
| Financing activities        |       | (90.1                             | )          | (55.6 | ) | 495.3 |   |
|                             |            |                                   |            |  |  |  |  |  |  |  |

 

*OperatingActivities*

 

Net cash from operatingactivities for the years ended December 31, 2004, 2003 and 2002, was comprisedof the following (in millions):

 
| ** **                                           | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                           | ** ** | **2004**                          | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net income                                           |       | $                                 | 142.4      |   | $ | 125.8 |   | $ | 117.9 |   |
| Depreciation and amortization                        |       | 112.9                             |       | 100.7 |   | 86.0 |   |
| Earnings in equity investments                       |       | (26.0                             | )          | (16.9 | ) | (12.0 | ) |
| Distributions from equity investments                |       | 47.2                              |       | 28.0 |   | 30.9 |   |
| Gains on sales of assets                             |       | (1.1                              | )          | (3.9 | ) | — |   |
| Non-cash portion of interest expense                 |       | (0.4                              | )          | 4.8 |   | 4.9 |   |
| Cash provided by (used in) working capital and other |       | (8.8                              | )          | 0.9 |   | 7.2 |   |
|                                                 |       |                              |       |   |   |   |   |
| Net cash from operating  activities                  |       | $                                 | 266.2      |   | $ | 239.4 |   | $ | 234.9 |   |

* *

For a discussion ofchanges in earnings before interest, depreciation and amortization, equityearnings, gain on sales of assets by segment and consolidated interest expense– net, see Results of Operations for the Downstream Segment, Upstream Segmentand Midstream Segment in Item 7. Management’s Discussion and Analysis of Financial Condition and Resultsof Operations.  Cash provided byoperating activities increased $26.8 million for the year ended December 31,2004, compared with the year ended December 31, 2003, primarily due to anincrease of $19.2 million in distributions received from our equity investmentsin Seaway and MB Storage during the year ended December 31, 2004, andhigher net income and depreciation and amortization expense in the 2004 period,partially offset by the timing of cash disbursements and cash receipts forworking capital components.  Cashprovided by operating activities increased $4.5 million for the year ended December 31,2003, compared with the year ended December 31, 2002, primarily due to highernet income and depreciation and amortization expense resulting from our 2002acquisition of Val Verde, partially offset by the $3.9 million non-cash gain onthe sale of assets in 2003. Distributions from equity method investments decreased from 2002 to2003, primarily due to our sharing ratio in Seaway decreasing from 80% to 60%between years, partially offset by a distribution from MB Storage in 2003 of$5.3 million.

 

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We believe that we willcontinue to have adequate liquidity to fund future recurring operating andinvesting activities.  Our primary cashrequirements consist of normal operating expenses, capital expenditures tosustain existing operations and revenue generating expenditures, interestpayments on our Senior Notes and revolving credit facility, distributions toour General Partner and unitholders and acquisitions of new assets orbusinesses.  Short-term cashrequirements, such as operating expenses, capital expenditures to sustainexisting operations and quarterly distributions to our General Partner andunitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions areexpected to be funded by several sources, including cash flows from operatingactivities, borrowings under credit facilities, and the issuance of additionalequity and debt securities.  Our abilityto complete future debt and equity offerings and the timing of any suchofferings will depend on various factors, including prevailing marketconditions, interest rates and our financial condition and our credit rating atthe time.

 

Net cash from operatingactivities for the years ended December 31, 2004, 2003 and 2002, includedinterest payments, net of amounts capitalized, of $77.5 million, $79.9 millionand $48.9 million, respectively. Excluding the effects of hedging activities and interest capitalizedduring the year ended December 31, 2005, we expect interest payments onour fixed rate Senior Notes to be approximately $78.0 million.  We expect to pay our interest payments withcash flows from operating activities.

 

*InvestingActivities*

 

Cash flows used ininvesting activities totaled $189.2 million for the year ended December 31,2004, and were comprised of $164.1 million of capital expenditures, $1.5million of cash contributions for TE Products’ ownership interest inCentennial, $21.4 million of cash contributions for TE Products’ ownershipinterest in MB Storage and $3.4 million for the acquisition of assets acquiredduring the year ended December 31, 2004, partially offset by $1.2 millionin net cash proceeds from the sales of various assets in our Upstream and DownstreamSegments.  Cash flows used in investingactivities totaled $185.3 million for the year ended December 31, 2003,and were comprised of $140.6 million of capital expenditures, $22.0 million forour acquisition of the Genesis assets and other assets, $20.0 million for TEProducts’ acquisition of an additional 16.7% interest in Centennial, $4.0million of cash contributions for TE Products’ ownership interest in Centennialand $2.5 million of cash contributions for TE Products’ ownership interest in MBStorage.  These uses of cash werepartially offset by $3.0 million in net cash proceeds from the Rancho Pipelinetransactions and $0.8 million received on matured cash investments.  Cash flows used in investing activitiestotaled $724.7 million for the year ended December 31, 2002, and werecomprised of $7.3 million for the final purchase price adjustments on theacquisition of Jonah, $133.4 million of capital expenditures, $10.9 million ofcash contributions for TE Products’ ownership interest in Centennial, $132.4million for the purchase of the Chaparral NGL system on March 1, 2002, and$444.2 million for the purchase of Val Verde on June 30, 2002.  These uses of cash were partially offset by$3.5 million in cash proceeds from the sale of assets.

 

*FinancingActivities*

 

Cash flows used infinancing activities totaled $90.1 million for the year ended December 31,2004, and were comprised of $233.1 million of distributions paid tounitholders, partially offset by $143.0 million in borrowings, net of repayments,from our revolving credit facility.  Cashflows used in financing activities totaled $55.6 million for the year ended December 31,2003, and were comprised of $382.0 million in proceeds from revolving creditfacilities; $198.6 million from the issuance in January 2003 of our 6.125%Senior Notes due 2013, partially offset by debt issuance costs of $3.4 million;and $287.5 million from the issuance of 9.2 million Units in April and August 2003.  These sources of cash for the year ended December 31,2003, were partially offset by $604.0 million of repayments on our revolvingcredit facilities, $113.8 million to repurchase and retire all of the 3.9million outstanding Class B Units, and $202.5 million of distributions paid tounitholders.  Cash flows provided byfinancing activities totaled $495.3 million for the year ended December 31,2002, and were comprised of $675.0 million in proceeds from revolving creditfacilities; $497.8 million from the issuance in February 2002 of our7.625% Senior Notes due 2012, partially offset by debt issuance costs of $7.0million; $372.5 million from the issuance of 13.4 million Units during the yearended December 31, 2002, and $7.6 million of General Partnercontributions; and $44.9 million of proceeds from the termination of ourinterest rate swaps on our 7.625% Senior Notes due 2012.  These sources of cash for the year ended December 31,2002, were partially offset by $943.7 million of repayments on our revolvingcredit facilities and $151.8 million of distributions paid to unitholders.

 

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**Centennial entered into credit facilities totaling $150.0million, and as of December 31, 2004, $150.0 million was outstanding underthose credit facilities.  The proceedswere used to fund construction and conversion costs of its pipelinesystem.  TE Products and Marathon haveeach guaranteed one-half of Centennial’s debt, up to a maximum of $75.0 millioneach.**

** **

*UniversalShelf*

** **

**We have filed with the SEC a universal shelf registration statementthat, subject to agreement on terms at the time of use and appropriatesupplementation, allows us to issue, in one or more offerings, up to anaggregate of $2.0 billion of equity securities, debt securities or acombination thereof.  At December 31,2004, we have $2.0 billion available under this shelf registration, subject tocustomary marketing terms and conditions.**

** **

*Credit Facilities and Interest Rate SwapAgreements*

* *

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

 

On June 27,2003, we entered into a $550.0 million revolving credit facility with a threeyear term, including the issuance of letters of credit of up to $20.0 million (“RevolvingCredit Facility”).  The interest rate isbased, at our option, on either the lender’s base rate plus a spread, or LIBORplus a spread in effect at the time of the borrowings.  The credit agreement for the Revolving CreditFacility contains certain restrictive financial covenant ratios.  We borrowed $263.0 million under theRevolving Credit Facility and repaid the outstanding balance of the Three YearFacility.  On October 21, 2004, weamended our Revolving Credit Facility to (i) increase the facility size to$600.0 million, (ii) extend the term to October 21, 2009, (iii) removecertain restrictive covenants, (iv) increase the available amount for theissuance of letters of credit up to $100.0 million and (v) decrease the LIBORrate spread charged at the time of each borrowing.  On December 31, 2004, $353.0 million wasoutstanding under the Revolving Credit Facility at a weighted average interestrate of 3.0%.  At December 31, 2004,we were in compliance with the covenants in this credit agreement.

 

On January 30,2003, we completed the issuance of $200.0 million principal amount of 6.125%Senior Notes due 2013.  The 6.125% SeniorNotes were issued at a discount of $1.4 million and are being accreted to theirface value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce theoutstanding principal on the Three Year Facility to $250.0 million.  The balance of the net proceeds received wasused for general partnership purposes. The Senior Notes may be redeemed at any time at our option with thepayment of accrued interest and a make-whole premium determined by discountingremaining interest and principal payments using a discount rate equal to therate of the United States Treasury securities of comparable remaining maturityplus 35 basis points.  The indenturegoverning our 6.125% Senior Notes contains covenants, including, but notlimited to, covenants limiting the creation of liens securing indebtedness andsale and leaseback transactions. However, the indenture does not limit our ability to incur additionalindebtedness.  As of December 31,2004, we were in compliance with the covenants of these Senior Notes.

 

We haveentered into interest rate swap agreements to hedge our exposure to cash flowsand fair value changes.  These agreementsare more fully described in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

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Thefollowing table summarizes our credit facilities as of December 31, 2004(in millions):

 
| ** **                    | ** ** | **As of December 31, 2004** | ** ** |
|-------------------------------|------------|----------------------------------|------------|
| **Description:**              | ** ** | **Outstanding  Principal**       | ** ** | **Available  Borrowing  Capacity** | ** ** | **Maturity  Date** | ** ** |
| Revolving Credit Facility (1) |       | $                                | 353.0      |   | $ | 247.0 |   | October 2009 |   |
| 6.45% Senior Notes (2)        |       | 180.0                            |       | — |   | January 2008 |   |
| 7.625% Senior Notes (2)       |       | 500.0                            |       | — |   | February 2012 |   |
| 6.125% Senior Notes (2)       |       | 200.0                            |       | — |   | February 2013 |   |
| 7.51% Senior Notes (2)        |       | 210.0                            |       | — |   | January 2028 |   |
| Total                         |       | $                                | 1,443.0    |   | $ | 247.0 |   |   |   |

 

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(1)          Our Revolving Credit Facility contains restrictive covenantsthat require us to maintain certain financial ratios.  Under the most restrictive financialcovenant, approximately $132.0 million was available to be borrowed  for working capital needs at December 31,2004.  Certain of these restrictivecovenants are adjusted in the event of an acquisition by us, which would permitadditional borrowings under the facility.

 

(2)          Our TE Products subsidiary entered into an interest rate swapagreement to hedge its exposure to changes in the fair value of its 7.51%Senior Notes due 2028.  At December 31,2004, the 7.51% Senior Notes include an adjustment to increase the fair valueof the debt by $3.4 million related to this interest rate swap agreement.  We also entered into interest rate swapagreements to hedge our exposure to changes in the fair value of our 7.625%Senior Notes due 2012.  At December 31,2004, the 7.625% Senior Notes include a deferred gain, net of amortization,from previous interest rate swap terminations of $36.6 million.  At December 31, 2004, our 6.45% SeniorNotes, our 7.625% Senior Notes and our 6.125% Senior Notes include $2.8 millionof unamortized debt discounts.  The fairvalue adjustments, the deferred gain adjustment and the unamortized debtdiscounts are excluded from this table.

 

*Distributions andIssuance of Additional Limited Partner Units*

* *

We paid cashdistributions to our limited partners and general partner, including generalpartner incentive distributions, of $233.1 million ($2.6375 per Unit), $202.5million ($2.50 per Unit) and $151.9 million ($2.35 per Unit) during each of theyears ended December 31, 2004, 2003 and 2002, respectively.  Additionally, on January 14, 2005, we declareda cash distribution of $0.6625 per Unit for the quarter ended December 31,2004.  The distribution of $58.7 millionwas paid on February 7, 2005, to unitholders of record on January 31,2005.  See Note 11. Partners’ Capital andDistributions.

 

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

** **

On August 7,2003, we sold in an underwritten public offering 5.0 million Units at $34.68per Unit.  The proceeds from theoffering, net of underwriting discount, totaled approximately $166.0million.  On August 19, 2003,162,900 Units were sold upon exercise of the underwriters’ over-allotmentoption granted in connection with the offering on August 7, 2003.  Proceeds from the over-allotment sale, net ofunderwriting discount, totaled $5.4 million. Approximately $53.0 million of the proceeds were used to repayindebtedness under our revolving credit facility and $21.0 million was used tofund the acquisition of the Genesis assets (see Note 5.  Acquisitions and Dispositions).  The remaining amount was used primarily tofund revenue-generating and system upgrade capital expenditures and for generalpartnership purposes.

 

*General PartnerInterest*

 

As of December 31,2004 and 2003, we had deficit balances of $33.0 million and $7.2 million,respectively, in our General Partner’s equity account. This negative balancedoes not represent an asset to us and does not represent an obligation of theGeneral Partner to contribute cash or other property to us. The General

 

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Partner’s equity account generally consists of itscumulative share of our net income less cash distributions made to it plus capitalcontributions that it has made to us (see our Consolidated Statements ofPartners’ Capital for a detail of the General Partner’s equity account).  For the years ended December 31, 2004and 2003, the General Partner was allocated $41.1 million (representing 28.85%)and $34.8 million (representing 27.65%), respectively, of our net income andreceived $66.9 million and $54.7 million, respectively, in cash distributions.

 

Capital Accounts, asdefined under our Partnership Agreement, are maintained for our General Partnerand our limited partners.  The CapitalAccount provisions of our Partnership Agreement incorporate principlesestablished for U.S. federal income tax purposes and are not comparable to theequity accounts reflected under accounting principles generally accepted in theUnited States in our financial statements. Under our Partnership Agreement, the General Partner is required to makeadditional capital contributions to us upon the issuance of any additional Unitsif necessary to maintain a Capital Account balance equal to 1.999999% of thetotal Capital Accounts of all partners. At December 31, 2004 and 2003, the General Partner’s CapitalAccount balance substantially exceeded this requirement.

 

Net income is allocatedbetween the General Partner and the limited partners in the same proportion asaggregate cash distributions made to the General Partner and the limitedpartners during the period.  This is generallyconsistent with the manner of allocating net income under our PartnershipAgreement.  Net income determined underour Partnership Agreement, however, incorporates principles established forU.S. federal income tax purposes and is not comparable to net income reflectedunder accounting principles generally accepted in the United States in ourfinancial statements.

 

Cash distributions thatwe make during a period may exceed our net income for the period.  We make quarterly cash distributions of allof our Available Cash, generally defined as consolidated cash receipts lessconsolidated cash disbursements and cash reserves established by the GeneralPartner in its sole discretion (see Note 11. Partners’ Capital and Distributions). Cash distributions in excess of net income allocations and capitalcontributions during the years ended December 31, 2004 and 2003, resultedin a deficit in the General Partner’s equity account at December 31, 2004and 2003.  Future cash distributions thatexceed net income will result in an increase in the deficit balance in theGeneral Partner’s equity account.

 

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

 

*Future Capital Needs and Commitments*

* *

We estimate that capitalexpenditures, excluding acquisitions, for 2005 will be approximately $236.0million (which includes $6.0 million of capitalized interest).  We expect to spend approximately $168.0million for revenue generating projects and facility improvements.  Capital spending on revenue generatingprojects and facility improvements will include approximately $23.0 million forthe expansion of our Downstream Segment facilities.  We expect to spend $5.0 million to expand ourUpstream Segment pipelines and facilities in West Texas and Oklahoma andapproximately $140.0 million to expand our Midstream Segment assets, withfurther expansions on our Jonah system. We expect to spend approximately $44.0 million to sustain existingoperations, including life-cycle replacements for equipment at variousfacilities and pipeline and tank replacements among all of our businesssegments.  We expect to spendapproximately $18.0 million to improve operational efficiencies and reducecosts among all of our business segments. We continually review and evaluate potential capital improvements andexpansions that would be complementary to our present business operations.  These expenditures can vary greatly dependingon the magnitude of our transactions.  Wemay finance capital expenditures through internally generated funds, debt or theissuance of additional equity.

 

Our debt repaymentobligations consist of payments for principal and interest on (i) the TEProducts $180.0 million 6.45% Senior Notes due January 15, 2008, (ii)outstanding principal amounts under the Revolving Credit Facility due in October 2009($353.0 million outstanding at December 31, 2004), (iii) our $500.0million 7.625%

 

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Senior Notes due February 15,2012, (iv) our $200.0 million 6.125% Senior Notes due February 1, 2013,and (v) the TE Products $210.0 million 7.51% Senior Notes due January 15,2028.

 

TE Products iscontingently liable as guarantor for the lesser of one-half or $75.0 millionprincipal amount (plus interest) of the borrowings of Centennial.  In January 2003, TE Products enteredinto a pipeline capacity lease agreement with Centennial for a period of fiveyears that contains a minimum throughput requirement.  For the year ended December 31, 2004, TEProducts exceeded the minimum throughput requirements on the leaseagreement.  On February 10, 2003, TEProducts acquired an additional 16.7% ownership interest in Centennial,bringing its ownership percentage to 50%.

 

During the years ended December 31,2004, 2003 and 2002, TE Products contributed $1.5 million, $4.0 million and$10.9 million, respectively, to Centennial to cover operating needs and capitalexpenditures.  During the years ended December 31,2004 and 2003, TE Products 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, TE Products may be required tocontribute cash to Centennial to cover capital expenditures, acquisitions orother operating needs and to MB Storage to cover significant capitalexpenditures or additional acquisitions.

 

*Off-Balance Sheet Arrangements*

 

We do not rely onoff-balance sheet borrowings to fund our acquisitions.  We have no off-balance sheet commitments forindebtedness other than the limited guaranty of Centennial debt and leasescovering assets utilized in several areas of our operations.

 

*Contractual Obligations*

 

The following tablesummarizes our debt repayment obligations and material contractual commitmentsas 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** | ** ** |
| Revolving Credit Facility                  |       | $                                               | 353.0      |   | $ | — |   | $ | — |   | $ | 353.0 |   | $ | — |   |
| 6.45% Senior Notes due 2008 (1) (2)        |       | 180.0                                           |       | — |   | — |   | 180.0 |   | — |   |
| 7.625% Senior Notes due 2012 (2)           |       | 500.0                                           |       | — |   | — |   | — |   | 500.0 |   |
| 6.125% Senior Notes due 2013 (2)           |       | 200.0                                           |       | — |   | — |   | — |   | 200.0 |   |
| 7.51% Senior Notes due 2028 (1) (2)        |       | 210.0                                           |       | — |   | — |   | — |   | 210.0 |   |
| Debt subtotal                              |       | 1,443.0                                         |       | — |   | — |   | 533.0 |   | 910.0 |   |
| Operating leases                           |       | 79.3                                            |       | 18.2 |   | 28.7 |   | 12.9 |   | 19.5 |   |
| Capital expenditure obligations (3)        |       | 10.0                                            |       | 10.0 |   | — |   | — |   | — |   |
| Other liabilities and deferred credits (4) |       | 4.2                                             |       | — |   | 2.4 |   | 0.4 |   | 1.4 |   |
|                                       |       |                                            |       |   |   |   |   |   |   |   |   |
| Total                                      |       | $                                               | 1,536.5    |   | $ | 28.2 |   | $ | 31.1 |   | $ | 546.3 |   | $ | 930.9 |   |

 

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(1)          Obligations of TEProducts.

 

(2)          Our TE Products subsidiary entered into an interest rate swapagreement to hedge its exposure to changes in the fair value of its 7.51%Senior Notes due 2028.  At December 31,2004, the 7.51% Senior Notes include an adjustment to increase the fair valueof the debt by $3.4 million related to this interest rate swap agreement.  We also entered into interest rate swapagreements to hedge our exposure to changes in the fair value of our 7.625%Senior Notes due 2012.  At December 31,2004, the 7.625% Senior Notes include a deferred gain, net of amortization,from previous interest rate swap terminations of $36.6 million.  At December 31, 2004, our 6.45% SeniorNotes, our 7.625% Senior Notes and our 6.125% Senior Notes include $2.8 millionof unamortized debt discounts.  The fairvalue adjustments, the deferred gain adjustment and the unamortized debtdiscounts are excluded from this table.

 

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(3)          Includes accruals for costs incurred but not yet paid relatingto capital projects.

 

(4)          Excludes approximately $9.4 million of long-term deferredrevenue payments, which are being transferred to income over the term of therespective revenue contracts.  The amountof commitment by year is our best estimate of projected payments of these long-termliabilities.

 

We expect to repay thelong-term, senior unsecured obligations and bank debt through the issuance ofadditional long-term senior unsecured debt at the time the 2008, 2012, 2013 and2028 debt matures, issuance of additional equity, with proceeds fromdispositions of assets, cash flow from operations or any combination of theabove items.

 

In addition to the itemsin the table above, we have entered into various operational commitments andagreements related to pipeline operations and to the marketing, transportation,terminaling and storage of crude oil. The majority of contractual commitments for the purchase of crude oilthat are made range in term from a thirty-day evergreen to three years.  A substantial portion of the contracts forthe purchase of crude oil that extend beyond thirty days include cancellationprovisions that allow us to cancel the contract with thirty days writtennotice.  During the year ended December 31,2004, crude oil purchases averaged approximately $448.0 million per month.

 

*Sources of FutureCapital*

* *

Historically, we havefunded our capital commitments from operating cash flow and borrowings underbank credit facilities or bridge loans. We repaid these loans in part by the issuance of long term debt incapital markets and the public offering of Units.  We expect future capital needs would besimilarly funded to the extent not otherwise available from cash flow fromoperations.

 

As of December 31,2004, we had $247.0 million in available borrowing capacity under the RevolvingCredit Facility, subject to compliance with prescribed financial covenants.  We expect that cash flows from operatingactivities will be adequate to fund cash distributions and capital additionsnecessary to sustain existing operations. However, future expansionary capital projects and acquisitions will requirefunding through borrowings under our Revolving Credit Facility or proceeds fromthe sale of additional debt or equity offerings, or any combination thereof.

 

Oursenior unsecured debt is rated BBB by Standard and Poors (“S&P”) and Baa3by Moody’s Investors Service (“Moody’s”). Both ratings are stable.  A ratingreflects only the view of a rating agency and is not a recommendation to buy,sell or hold any indebtedness.  Any ratingcan be revised upward or downward or withdrawn at any time by a rating agencyif it determines that the circumstances warrant such a change.  The senior unsecured debt of our subsidiary,TE Products, is also rated BBB by S&P and Baa3 by Moody’s.  Both ratings are stable.

 

## ****Other Considerations****

 

*Credit Risks*

* *

Risks of non-payment andnonperformance by customers are a major consideration in our businesses.  Our credit procedures and policies do notfully eliminate customer credit risk. During the years ended December 31, 2003 and 2002, some of ourcustomers filed for bankruptcy protection. During the years ended December 31, 2004, 2003 and 2002, we expensedapproximately $0.1 million, $0.8 million and $0.9 million, respectively, ofuncollectible 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 unprecedentedscale.  Since the September 11attacks, the United States government has issued warnings that energy assets,specifically the nation’s pipeline infrastructure, could be a future target ofterrorist organizations.  Thesedevelopments have subjected our operations to increased risks.  Any terrorist attack on our facilities,customers’ facilities and, in some

 

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cases, those ofother pipelines, could have a material adverse effect on our business.  We have increased security initiatives andare working with various governmental agencies to minimize risks associatedwith additional terrorist attacks.

 

*Environmental*

* *

Our operations aresubject to federal, state and local laws and regulations governing thedischarge of materials into the environment. Failure to comply with these lawsand regulations may result in the assessment of administrative, civil andcriminal penalties, imposition of injunctions delaying or prohibiting certainactivities and the need to perform investigatory and remedial activities.  Although we believe our operations are inmaterial compliance with applicable environmental laws and regulations, risksof significant costs and liabilities are inherent in pipeline operations, andwe cannot assure you that significant costs and liabilities will not beincurred.  Moreover, it is possible thatother developments, such as increasingly strict environmental laws andregulations and enforcement policies thereunder, and claims for damages toproperty or persons resulting from our operations, could result in substantialcosts and liabilities to us.  We believethat changes in environmental laws and regulations will not have a materialadverse effect on our financial position, results of operations or cash flowsin the near term.

 

In 1994, the LDEQ issueda compliance order for environmental contamination at our Arcadia, Louisiana,facility.  In 1999, our Arcadia facilityand adjacent terminals were directed by the Remediation Services Division ofthe LDEQ to pursue remediation of this contamination.  At December 31, 2004, we have an accruedliability of $0.2 million for remediation costs at our Arcadia facility.  Effective in March 2004, we executed anaccess agreement with an adjacent industrial landowner who is locatedupgradient of the Arcadia facility.  Thisagreement enables the landowner to proceed with remediation activities at ourArcadia facility for which it has accepted shared responsibility.  We do not expect that the completion of theremediation program proposed to the LDEQ will have a future material adverseeffect on our financial position, results of operations or cash flows.

 

OnMarch 17, 2003, we experienced a release of 511 barrels of jet fuel from astorage tank at our Blue Island terminal located in Cook County, Illinois.  As a result of the release, we have enteredinto an Agreed Order with the State of Illinois, which required us to conductan environmental investigation.  At thistime, we have complied with the terms of the Agreed Order, and the results ofthe environmental investigation indicated there were no soil or groundwaterimpacts from the release.  We are in theprocess of negotiating a final settlement with the State of Illinois, and wedo not expect that compliance with the settlement will have a future materialadverse effect on our financial position, results of operations or cash flows.

 

OnJuly 22, 2004, we experienced a release of approximately 12 barrels of jetfuel from a sump at our Lebanon, Ohio, terminal.  The released jet fuel was contained within astorm water retention pond located on the terminal property.  Six migratory waterfowl were affected by thejet fuel and were subsequently euthanized by or at the request of the USFWS. OnOctober 1, 2004, the USFWS served us with a Notice of Violation, allegingthat we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing]of migratory birds by illegal methods.”  OnFebruary 7, 2005, we entered into a Memorandum of Understanding with theUSFWS, settling all aspects of this matter. The terms of this settlement did not have a material adverse effect onour financial position, results of operations or cash flows.

 

OnJuly 27, 2004, we received notice from the United States DOJ of its intentto 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 diameterpipeline located in Orange County, Texas. The DOJ, at the request of the EPA, is seeking a civil penalty againstus for alleged violations of the CWA arising out of this release.  The maximum statutory penalty calculated forthis alleged violation of the CWA is $2.8 million.  We are in discussions with the DOJ regardingthis matter and have responded to its request for additional information.  We do not expect a civil penalty, if any, tohave a material adverse effect on our financial position, results of operationsor cash flows.

 

At December 31,2004, we have an accrued liability of $5.0 million, related to various TCTM andTE Products sites requiring environmental remediation activities.   At December 31, 2003, we had an accruedliability of $5.9 million related to various TCTM sites requiring environmentalremediation activities.  Under the termsof a 1998 agreement through which we acquired various crude oil assets fromDETTCO, we received a five year contractual indemnity obligation for certainenvironmental liabilities attributable to the operations of the assets prior

 

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to ouracquisition.  Concurrent with theexpiration of this indemnity in 2003, we entered into a Settlement Agreementand Release with DETTCO releasing DETTCO from future obligations pertaining tocertain environmental liabilities, requiring us to share in certain costs forthe remediation of a crude oil site in Oklahoma, and the assumption ofresponsibility by DETTCO for environmental liabilities associated with threesites located in Texas and Oklahoma.  Wedo not expect that the completion of remediation programs associated with TCTMand TE Products activities will have a future material adverse effect on ourfinancial position, results of operations or cash flows.

 

*Recent AccountingPronouncements*

* *

**See discussion ofnew accounting pronouncements in Note 2. Summary of Significant Accounting Policies – New AccountingPronouncements in the accompanying consolidated financial statements.**

** **

*Disclosures About Effectsof Transactions with Related Parties*

 

ThePartnership does not have any employees, and we are managed by the GeneralPartner, an indirect wholly owned subsidiary of DEFS. Duke Energy holds an interestof approximately 70% in DEFS, and ConocoPhillips holds the remaining interestof approximately 30%.  See Item 10. Directorsand Executive Officers of the Registrant and Item 13. Certain Relationships andRelated Transactions for discussion regarding transactions between us and DEFS,Duke Energy and ConocoPhillips.

 

*SubsequentEvent*

 

On February 24, 2005, Texas Eastern Products PipelineCompany, LLC, our General Partner, was acquired by EPCO, Inc. (“EPCO”), aprivately held company controlled by Dan L. Duncan.  The acquisition was valued at $1.1billion.  Additionally, in a separatetransaction, EPCO and its affiliates agreed to purchase 2.5 million of ourUnits, valued at approximately $100.0 million, from Duke Energy.  EPCO and its affiliates own the generalpartner of Enterprise Products Partners L.P. (“Enterprise”) and approximately145 million Enterprise common units. Enterprise is one of the largest publicty traded master limitedpartnerships.  The general partners ofboth TEPPCO Partners, L.P. (“TEPPCO”) and Enterprise will continue to operateindependently and will maintain separate boards of directors, management teamsand offices.

 

***Item 7A***.    Quantitativeand Qualitative Disclosures About Market Risk

*** ***

We may be exposed tomarket risk through changes in crude oil commodity prices and interestrates.  We do not have foreign exchangerisks.  Our Risk Management Committee hasestablished policies to monitor and control these market risks.  The Risk Management Committee is comprised, inpart, of senior executives of the Company.

 

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

 

Occasionally, customersrequire pricing terms which do not allow us to balance our position.  Additionally, certain pricing terms mayexpose us to movements in margin.  On asmall portion of our crude oil marketing business, we enter into derivative contractssuch as physical swaps and other business hedging devices for which we cannottake the normal purchase and normal sale exclusion and for which we do notelect hedge accounting.  The terms ofthese contracts are less than one year. The purpose is to balance our position or lock in a margin and, as such,do not expose us to any additional significant market risk.  We mark these transactions to market and the changesin the fair value are recognized in current earnings.  This could potentially result in somefinancial statement variability during quarterly periods; however, anyunrealized gains and losses reflected in the financial statements related tomarking these transactions to market will be offset by realized gains andlosses in different quarterly periods when the related physical transactionsare settled.

 

At December 31,2004, we had $353.0 million outstanding under our variable interest raterevolving credit facility.  The interestrate is based, at our option, on either the lender’s base rate plus a spread orLIBOR plus a spread in effect at the time of the borrowings and is adjustedmonthly, bimonthly, quarterly or semiannually. Utilizing the balances of our variable interest rate debt outstanding atDecember 31, 2004, and assuming market interest rates increase 100 basispoints, the potential annual increase in interest expense would be $3.5million.

 

At December 31,2004, TE Products had outstanding $180.0 million principal amount of 6.45%Senior Notes due 2008 and $210.0 million principal amount of 7.51% Senior Notesdue 2028 (collectively, the “TE Products Senior Notes”).  At December 31, 2004, the estimated fairvalue of the TE Products Senior Notes was approximately $412.7 million.  At December 31, 2004, we had outstanding$500.0 million principal amount of

 

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7.625% SeniorNotes due 2012 and $200.0 million principal amount of 6.125% Senior Notes due2013.  At December 31, 2004, theestimated fair value of the $500.0 million 7.625% Senior Notes and the $200.0million 6.125% Senior Notes was approximately $569.6 million and $210.2million, respectively.

 

We have utilized andexpect to continue to utilize interest rate swap agreements to hedge a portionof our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floatinginterest rate mix of our total debt portfolio and overall cost ofborrowing.  Interest rate swaps thatmanage our cash flow risk reduce our exposure to increases in the benchmarkinterest rates underlying variable rate debt. Interest rate swaps that manage our fair value risks are intended toreduce our exposure to changes in the fair value of the fixed rate debt.  Interest rate swap agreements involve theperiodic exchange of payments without the exchange of the notional amount uponwhich the payments are based.  Therelated amount payable to or receivable from counterparties is included as anadjustment to accrued interest.

 

In October 2001, TEProducts entered into an interest rate swap agreement to hedge its exposure tochanges in the fair value of its fixed rate 7.51% Senior Notes due 2028. Wedesignated 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 andmaturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interestbased on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives afixed rate of interest of 7.51%.  Duringthe years ended December 31, 2004, 2003 and 2002, we recognized reductionsin interest expense of $9.6 million, $10.0 million and $8.6 million,respectively, related to the difference between the fixed rate and the floatingrate of interest on the interest rate swap. During the quarter ended December 31, 2004, we measured the hedgeeffectiveness of this interest rate swap and noted that no gain or loss fromineffectiveness was required to be recognized. The fair value of this interest rate swap was a gain of approximately $3.4million at December 31, 2004, and a gain of approximately $2.3 million at December 31,2003.  Utilizing the balance of the 7.51%TE Products Senior Notes outstanding at December 31, 2004, and includingthe effects of hedging activities, assuming market interest rates increase 100basis points, the potential annual increase in interest expense is $2.1million.

 

In July 2000, weentered into an interest rate swap agreement to hedge our exposure to increasesin the benchmark interest rate underlying our variable rate revolving creditfacility. This interest rate swap matured in April 2004.  We designated this swap agreement, whichhedged exposure to variability in expected future cash flows attributed tochanges in interest rates, as a cash flow hedge. The swap agreement was basedon a notional amount of $250.0 million. Under the swap agreement, we paid a fixed rate of interest of 6.955% andreceived a floating rate based on a three-month U.S. Dollar LIBOR rate.  Because this swap was designated as a cashflow hedge, the changes in fair value, to the extent the swap was effective,were recognized in other comprehensive income until the hedged interest costswere recognized in earnings.  In June 2003,we repaid the amounts outstanding under our revolving credit facility withborrowings under a new three year revolving credit facility and canceled theold facility (see Note 10.  Debt).  We redesignated this interest rate swap as ahedge of our exposure to increases in the benchmark interest rate underlyingthe new variable rate revolving credit facility.  During the years ended December 31, 2004,2003 and 2002, we recognized increases in interest expense of $2.9 million, $14.4million and $12.9 million, respectively, related to the difference between thefixed rate and the floating rate of interest on the interest rate swap.

 

During2003, we determined that we would repay a portion of the amount outstandingunder the revolving credit facility with proceeds from our Unit offering in August 2003(see Note 11.  Partners’ Capital andDistributions) resulting in a reduction of probable future interest paymentsunder the credit facility.  We reducedthe outstanding balance of the revolving credit facility at December 31,2003, to $210.0 million.  During the yearended December 31, 2003, we recognized a loss of $1.0 million for theportion of the discontinued hedge.  Thetotal fair value of the interest rate swap was a loss of approximately $3.9million at December 31, 2003.  Theremaining $2.9 million of other comprehensive income was transferred toearnings during the period from January 1, 2004, through the maturity ofthe interest rate swap in April 2004.

 

In February 2002,we entered into interest rate swap agreements, designated as fair value hedges,to hedge our exposure to changes in the fair value of our fixed rate 7.625%Senior Notes due 2012.  The swapagreements had a combined notional amount of $500.0 million and matured in 2012to match the principal and maturity of the Senior Notes.  Under the swap agreements, we paid a floatingrate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and receiveda fixed rate of interest of 7.625%.  In July 2002,the swap agreements were terminated

 

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resulting in a gain of approximately$18.0 million.  Concurrent with the swapterminations, we entered into new interest rate swap agreements, with identicalterms as the previous swap agreements; however, the floating rate of interestwas based upon a spread of an additional 50 basis points.  In December 2002, the swap agreementsentered into in July 2002 were terminated, resulting in a gain ofapproximately $26.9 million.  The gainsrealized from the July 2002 and December 2002 swap terminations havebeen deferred as adjustments to the carrying value of the Senior Notes and arebeing amortized using the effective interest method as reductions to futureinterest expense over the remaining term of the Senior Notes.  At December 31, 2004, the unamortizedbalance of the deferred gains was $36.6 million.  In the event of early extinguishment of theSenior Notes, any remaining unamortized gains would be recognized in theconsolidated statement of income at the time of extinguishment.

 

***Item 8.***           Financial Statements and Supplementary Data

 

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

 

***Item 9.***           Changes in and Disagreements with Accountants on Accounting and FinancialDisclosure

*** ***

None.

 

 

***Item 9A***. Controls and Procedures

*** ***

Theprincipal executive officer and principal financial officer of our GeneralPartner, after evaluating the effectiveness of our disclosure controls andprocedures (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 andprocedures are adequate and effective to ensure that material informationrelating to us and our consolidated subsidiaries would be made known to them byothers within those entities.

 

*Management’sAnnual Report on Internal Control over Financial Reporting*

 

Themanagement of Texas Eastern Products Pipeline Company, LLC, (the “GeneralPartner”), the General Partner of TEPPCO Partners, L.P. (the “Partnership”), isresponsible for establishing and maintaining adequate internal control overfinancial reporting as defined in Rules 13a-15(f) and 15d-15(f) under theSecurities Exchange Act of 1934.  ThePartnership’s internal control over financial reporting is designed to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. The Partnership’s internal control over financial reporting includesthose policies and procedures that:

 

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

 

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

 

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

 

Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements.  Also,projections of any evaluation of effectiveness to future periods are subject tothe risk that controls may become inadequate because of changes in conditions,or that the degree of compliance with the policies or procedures maydeteriorate.

 

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Managementassessed the effectiveness of the Partnership’s internal control over financialreporting as of December 31, 2004. In making this assessment, management used the criteria set forth by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework.

 

Based onour assessment and those criteria, management believes that the Partnershipmaintained effective internal control over financial reporting as of December 31,2004.

 

ThePartnership’s independent auditors have issued an attestation report onmanagement’s assessment of the Partnership’s internal control over financialreporting.  That report appears below.

 
| /s/ BARRY R. PEARL                                             |   |
|----------------------------------------------------------------|--------|
| Barry R. Pearl                                                 |
| President and Chief Executive  Officer                         |
| Texas Eastern Products Pipeline Company,  LLC, General Partner |
|                                                           |
| /s/ CHARLES H. LEONARD                                         |   |
| Charles H. Leonard                                             |
| Senior Vice President and Chief  Financial Officer             |
| Texas Eastern Products Pipeline  Company, LLC, General Partner |

 

*Report ofIndependent Registered Public Accounting Firm*

 

To the Partners of

TEPPCO Partners, L.P.:

 

We haveaudited management’s assessment, included in the accompanying report titledManagement’s Annual Report on Internal Control over Financial Reportingincluded in Item 9A, that TEPPCO Partners, L.P. maintained effective internalcontrol over financial reporting as of December 31, 2004, based oncriteria established in *Internal Control –Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commissions (COSO).  TEPPCO Partners, L.P.’s management isresponsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financialreporting.  Our responsibility is toexpress an opinion on management’s assessment and an opinion on theeffectiveness of TEPPCO Partners, L.P.’s internal control over financialreporting based on our audit.

 

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether effective internal control over financialreporting was maintained in all respects. Our audit included obtaining an understanding of internal control overfinancial reporting, evaluating management’s assessment, testing and evaluatingthe design and operating effectiveness of internal control, and performing suchother procedures as we considered necessary in the circumstances.  We believe that our audit provides areasonable basis for our opinion.

 

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

 

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Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements.  Also,projections of any evaluation of effectiveness to future periods are subject tothe risk that controls may become inadequate because of changes in conditions,or that the degree of compliance with the policies or procedures maydeteriorate.

 

In ouropinion, management’s assessment that TEPPCO Partners, L.P. maintainedeffective internal control over financial reporting as of December 31,2004, is fairly stated, in all material respects, based on criteria establishedin *Internal Control – Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission(COSO).  Also, in our opinion, TEPPCOPartners, L.P. maintained, in all material respects, effective internal controlover financial reporting as of December 31, 2004, based on criteriaestablished in *Internal Control – Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

We also haveaudited, in accordance with the standards of the Public Company AccountingOversight Board (United States), the consolidated balance sheets of TEPPCOPartners, L.P. as of December 31, 2004 and 2003, and the relatedconsolidated statements of income, partners’ capital and cash flows for each ofthe years in the three-year period ended December 31, 2004, and our reportdated February 24, 2005, expressed an unqualified opinion on those consolidatedfinancial statements.

 

KPMG LLP

 

Houston, Texas

February 24, 2005

 

*Changes inInternal Control over Financial Reporting*

 

There hasbeen no change in our internal control over financial reporting during thefourth quarter of 2004 that has materially affected, or is reasonably likely tomaterially affect, our internal control over financial reporting.  As a result, no corrective actions wererequired or undertaken.

 

 

***Item 9B. ***Other Information

 

None.

 

**PART III**

** **

** **

***Item 10.***      Directors and Executive Officers of the Registrant

 

**PartnershipManagement**

 

We do not directly havedirectors or officers, as is commonly the case with publicly tradedpartnerships. Our operations and activities are managed by the General Partner,which employs our management and operational personnel.  The officers and directors of the GeneralPartner are responsible for managing us. All directors of the General Partner are elected annually by DEFS.  All officers serve at the discretion of thedirectors.  None of the officers of theGeneral Partner serve as officers or employees of DEFS or any otherparent-affiliated company.

 

Because we are a limitedpartnership, we meet the definition of a “controlled company” under the listingstandards of the New York Stock Exchange. Accordingly, we and our General Partner are not required to have amajority of independent directors or a nominating or compensation committee ofthe General Partner’s board of directors.

 

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**Committ**e**es of theBoard of Directors**

 

*Audit Committee*

 

Our General Partner has anaudit committee (the “Audit Committee”) comprised of three board members whoare “independent” as that term is defined in Rule 10A-3 of the Exchange Act andas that term is used in applicable listing standards of the New York StockExchange.  The members of the AuditCommittee are Paul F. Ferguson, Jr. (Chairman), John P. DesBarres and MiltonCarroll.  The members of the AuditCommittee are non-employee directors of the General Partner and are notofficers, directors or otherwise affiliated with DEFS or its parent companies,ConocoPhillips or Duke Energy.  No memberof the Audit Committee of our General Partner serves on the audit committees ofmore than three public companies.  OurBoard of Directors has determined that no Audit Committee member has a materialrelationship with the Company.  Our Boardof Directors has also determined that Mr. Ferguson qualifies as an auditcommittee financial expert as defined in Item 401(h) of Regulation S-K.

 

The Audit Committeeprovides independent oversight with respect to our internal controls,accounting policies, financial reporting, internal audit function and theindependent auditors.  The AuditCommittee also reviews the scope and quality, including the independence andobjectivity of the independent and internal auditors.  The Audit Committee has sole authority as tothe retention, evaluation, compensation and oversight of the work of theindependent auditors.  The independentauditors report directly to the Audit Committee.  The Audit Committee also has sole authorityto approve all audit and non-audit services provided by the independentauditors and shall ensure that the independent auditors are not engaged toperform specific non-audit services prohibited by law or regulation.  The charter of the Audit Committee is filedas an exhibit to this Annual Report on Form 10-K and is available on ourwebsite at www.teppco.com.

 

Our Audit Committee hasestablished procedures for the receipt, retention and treatment of complaintswe receive regarding accounting, internal accounting controls or auditingmatters and the confidential, anonymous submission by our employees of concernsregarding questionable accounting or auditing matters.  Persons wishing to communicate with our AuditCommittee may do so by calling 1-800-799-4607.

 

*Special Committee*

* *

The Special Committee isa standing committee of the Board of Directors of the General Partner and iscomposed of three independent directors, John P. DesBarres (Chairman), MiltonCarroll and Paul F. Ferguson, Jr.  Themembers of the Special Committee are non-employee directors of the GeneralPartner and are not officers, directors or otherwise affiliated with DEFS orits parent companies, ConocoPhillips or Duke Energy.  The Special Committee is responsible for theindependent evaluation of the fairness and reasonableness of affiliatetransactions and the approval or rejection of those transactions that wouldordinarily require board approval involving the General Partner, DEFS or anaffiliate of either, and us.  Suchtransactions include related party asset sales and operating agreements.  The Special Committee is also responsible forthe evaluation of the fairness and approval or rejection of the issuance andpricing of additional Units and debt.

 

*CompensationCommittee*

 

The CompensationCommittee is a standing committee of the Board of Directors of the GeneralPartner and is composed of five directors, Jim W. Mogg (Chairman), MiltonCarroll, Derrill Cody, John P. DesBarres and Paul F. Ferguson, Jr.  The Compensation Committee establishes andmaintains competitive and equitable compensation and employment policies toretain the management required to carry out our business, to stimulate theiruseful and profitable efforts on our behalf and to attract necessary additionsto management with appropriate qualifications. The Compensation Committee also recommends to the Board of Directors theelection of officers and reviews the management succession plans for seniorofficer positions.

 

**Code ofEthics, Corporate Governance Guidelines and Charter of the Audit Committee**

 

We have adopted a Code ofEthics applicable to all employees, including the principal executive officer, principalfinancial officer and directors of the General Partner.  A copy of the Code of Ethics is available onour

 

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website at www.teppco.comunder Corporate Governance.  We intend topost on our website any amendments to, or waivers from, our Code of Ethicsapplicable to our senior officers.

 

Our Corporate Governance Guidelines address directorqualification standards; director access to management, and as necessary andappropriate, independent advisors; director compensation; director orientationand continuing education; management succession and annual performanceevaluation of the board.  The Charter of ourAudit Committee and our Corporate Governance Guidelines are currently availableon our website at www.teppco.com under Corporate Governance.  Additionally, the Code of Ethics, ourCorporate Governance Guidelines and the Charter of the Audit Committee areavailable in print to any person who requests the information.  Persons wishing to obtain this printedmaterial should submit a request in care of Secretary, TEPPCO Partners, L.P.,2929 Allen Parkway, P.O. Box 2521, Houston, Texas 77252-2521.

 

**NYSE Corporate Governance ListingStandards**

 

*Annual CEO Certification*

 

As the Chief Executive Officer of Texas EasternProducts Pipeline Company, LLC, as General Partner of TEPPCO Partners, L.P.,and as required by Section 303A.12(a) of the New York Stock Exchange ListedCompany Manual, I hereby certify that as of the date hereof I am not aware ofany violation of the Company of NYSE’s Corporate Governance listing standards,other than has been notified to the Exchange pursuant to Section 303A.12(b) anddisclosed as an attachment hereto.

 
| /s/ BARRY R. PEARL                           |   |
|----------------------------------------------|--------|
| Barry R. Pearl                               |
| Chief Executive Officer and President        |
| Texas Eastern Products Pipeline Company, LLC |
| October 28, 2004                             |

 

**Executive Sessions ofNon-Management Directors**

 

Mark A. Borer, Michael J. Bradley, Milton Carroll, DerrillCody, John P. DesBarres, William H. Easter III, Paul F. Ferguson, Jr. and JimW. Mogg, who are non-management directors of our General Partner, meet atregularly scheduled executive sessions without management.  Mr. Mogg serves as the presiding director atthose executive sessions.  Personswishing to communicate with the Company’s non-management directors may do so bycalling 1-800-799-4607.

 

Milton Carroll, John P. DesBarres and Paul F.Ferguson, Jr., who are independent non-management directors of our GeneralPartner, meet at least annually in executive session without management and theother directors.  The chairs of the AuditCommittee and the Special Committee of the Board of Directors rotate on anannual basis as the chair of the independent non-management directors.  The chair for 2005 is Paul F. Ferguson,Jr.  Persons wishing to communicate withthe Company’s independent non-management directors may do so by calling1-800-799-4607.

 

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**Directors and Executive Officers**

 

The following table sets forth certain informationwith respect to the directors and executive officers of the GeneralPartner.  

 
| **Name**              | ** ** | **Age** | ** ** | **Position  with Our General Partner**                                     |
|-----------------------|------------|---------|------------|----------------------------------------------------------------------------|
|                  |       |    |       |                                                                       |
| Jim W. Mogg           |       | 56      |       | Chairman of the Board,  Member of the Compensation* Committee and Director |
| Mark A. Borer         |       | 50      |       | Director                                                                   |
| Michael J. Bradley    |       | 50      |       | Director                                                                   |
| Milton Carroll        |       | 54      |       | Director and Member of  the Compensation, Special and Audit Committees     |
| Derrill Cody          |       | 66      |       | Director and Member of  the Compensation Committee                         |
| John P. DesBarres     |       | 65      |       | Director and Member of  the Compensation, Special* and Audit Committees    |
| William H. Easter III |       | 55      |       | Director                                                                   |
| Paul F. Ferguson, Jr. |       | 55      |       | Director and Member of  the Compensation, Special and Audit* Committees    |
| Barry R. Pearl+       |       | 55      |       | President, Chief  Executive Officer and Director                           |
| Charles H. Leonard+   |       | 56      |       | Senior Vice President  and Chief Financial Officer                         |
| J. Michael Cockrell+  |       | 58      |       | Senior Vice President  of Commercial Upstream                              |
| Thomas R. Harper+     |       | 64      |       | Senior Vice President  of Commercial Downstream                            |
| Leonard W. Mallett+   |       | 48      |       | Senior Vice President  of Operations                                       |
| James C. Ruth+        |       | 57      |       | Senior Vice President,  General Counsel and Secretary                      |
| Barbara A. Carroll+   |       | 50      |       | Vice President of  Environmental, Health and Safety                        |
| John N. Goodpasture+  |       | 56      |       | Vice President of  Corporate Development                                   |
| Stephen W. Russell+   |       | 53      |       | Vice President of  Support Services                                        |
| C. Bruce Shaffer+     |       | 46      |       | Vice President of Human  Resources and Ethics and Compliance Officer       |

 

----

* Indicates Chairman ofcommittee

+Indicates employment contract with the General Partner (see ExecutiveEmployment Contracts and Termination of

   Employment Arrangements)

 

*Jim W. Mogg* was elected adirector of the General Partner in October 1997, Chairman of the CompensationCommittee in April 2000 and Chairman of the Board in May 2002.  Mr. Mogg succeeded William L. Thacker asChairman of the Board in May 2002, when Mr. Thacker retired as Chairman.  Prior to being elected Chairman of the Boardin 2002, Mr. Mogg served as Vice Chairman of the Board from April 2000 to April2002.  Mr. Mogg was named group vicepresident and chief development officer of Duke Energy, effective January 1,2004.  He served as chairman, presidentand chief executive officer of DEFS from December 1999 to December 2003. Mr.Mogg was previously president of Centana Energy Corporation, a subsidiary of apredecessor of Duke Energy, from 1992 to 1999. He joined Duke Energy in 1973 inthe gas supply department of Panhandle Eastern Pipe Line Company.

 

*Mark A. Borer* was elected adirector of the General Partner in April 2000. Mr. Borer is group vice president, marketing and corporate developmentof DEFS, having been elected to that position in December 2004.  He was previously executive vice president ofmarketing and corporate development of DEFS from April 2002 to December 2004.  Mr. Borer previously served as senior vicepresident, Southern Division, having been elected to that position in 1999 whenUnion Pacific Fuels, Inc. was acquired by DEFS. Before joining DEFS, he was vice president of natural gas marketing forUnion Pacific Fuels, Inc. from 1992 until 1999.

 

*Michael J. Bradley* was elected adirector of the General Partner in February 2003.  Mr. Bradley is group vice president,gathering and processing of DEFS, having been elected to that position inDecember 2004.  He was previously executivevice president, gathering and processing of DEFS, from April 2002 untilDecember 2004.  Mr. Bradley previouslyserved as senior vice president, Northern Division, for DEFS, having beenelected to that position in 1999.  Mr.Bradley joined DEFS in 1979 and served in a variety of positions in marketing,business development and operations.

 

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*Milton Carroll* was elected adirector of the General Partner in November 1997 and is a member of theCompensation Committee, Special Committee and the Audit Committee.  He served as Chairman of the Audit Committee fromApril 2000 until January 16, 2003.  Mr.Carroll is the chairman of CenterPoint Energy, Inc., having been elected inSeptember 2002.  Mr. Carroll is thefounder and chairman of Instrument Products, Inc., a manufacturer of oil fieldequipment since 1977.  Mr. Carroll is adirector of Devon Energy Corporation, Eagle Global Logistics and Chairman of theBoard of Health Care Service Corporation.

 

*Derrill Cody* was elected adirector of the General Partner in 1989. He is a member of the CompensationCommittee and was Chairman of the Audit Committee from April 1990 until April2000. Mr. Cody is currently of counsel to McKinney and Stringer, P. C., whichrepresents Duke Energy, DEFS and us in certain matters.  Mr. Cody served as chief executive officer ofTexas Eastern Gas Pipeline Company from 1987 to 1990.  Prior to that, he was executive vicepresident of Kerr McGee Corporation.  Mr.Cody is a director of CenterPoint Energy, Inc.

* *

*John P. DesBarres* was elected adirector of the General Partner in May 1995. He is a member of the Compensation and Audit Committees and serves asChairman of the Special Committee.  Mr.DesBarres was formerly chairman, president and chief executive officer ofTransco Energy Company from 1992 to 1995. He joined Transco in 1991 as president and chief executive officer.  Prior to joining Transco, Mr. DesBarresserved as chairman, president and chief executive officer for Santa Fe PacificPipelines, Inc. from 1988 to 1991. Mr. DesBarres is a director of AmericanElectric Power and Penn Virginia G.P., LLC, an indirect wholly owned subsidiaryof Penn Virginia Corporation, which is the general partner of Penn VirginiaResource Partners, L.P.

 

*William H. Easter III* was electeda director of the General Partner in February 2004.  Mr. Easter is chairman, president and chiefexecutive officer of DEFS, having been elected to that position in January2004.  Mr. Easter joined ConocoPhillips(formerly Conoco Inc.) in 1971 and served in a variety of positions, mostrecently as general manager of Gulf Coast businesses unit in Lake Charles,Louisiana, from 1998 until 2002 and vice president of state government affairsfor ConocoPhillips from 2002 until December 2003.

 

*Paul F. Ferguson, Jr.*was electeddirector of the General Partner in October 2004, and is a member of theCompensation, Audit and Special Committees. He was elected Chairman of the Audit Committee in October 2004.  Mr. Ferguson served as senior vice presidentand treasurer of Duke Energy from June 1997 to June 1998, when he retired.  Mr. Ferguson served as senior vice presidentand chief financial officer of PanEnergy Corp. from September 1995 to June 1997.  He held various other financial positionswith PanEnergy Corp. from 1988 to 1995, and served as treasurer of TexasEastern Corporation from 1988 to 1989.

 

*Barry R. Pearl* was electedPresident of the General Partner in February 2001 and Chief Executive Officerand director in May 2002.  He succeededWilliam L. Thacker as Chief Executive Officer in May 2002, when Mr. Thackerretired as Chief Executive Officer.  Mr.Pearl was previously Chief Operating Officer from February 2001 until May 2002.  Prior tojoining the Company, Mr. Pearl was vice president – finance and administration,treasurer, secretary and chief financial officer of Maverick Tube Corporation fromJune 1998.  Mr. Pearl was seniorvice president and chief financial officerof Santa Fe Pacific Pipeline Partners, L.P. from 1995 until 1998, and seniorvice president, business development from 1992 to 1995.

 

*Charles H. Leonard* is Senior VicePresident and Chief Financial Officer of the General Partner. Mr. Leonardjoined the Company in 1988 as Vice President and Controller. In November 1989,he was elected Vice President and Chief Financial Officer.  He was elected Senior Vice President in March1990, and was Treasurer from October 1996 until May 2002.

 

*J. Michael Cockrell* is SeniorVice President, Commercial Upstream of the General Partner, having been electedin February 2003.  Mr. Cockrell waspreviously Vice President, Commercial Upstream from September 2000 untilFebruary 2003.  He was elected VicePresident of the General Partner in January 1999 and also serves as Presidentof TEPPCO Crude GP, LLC.  He joinedPanEnergy in 1987 and served in a variety of positions in supply anddevelopment, including president of DETTCO.

 

*Thomas R. Harper* is Senior VicePresident, Commercial Downstream of the General Partner, having been elected inFebruary 2003.  Mr. Harper was previouslyVice President, Commercial Downstream from September

 

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2000 until February 2003 and Vice President, ProductTransportation and Refined Products Marketing from 1988 until September2000.  Mr. Harper joined the Company in1987 as Director of Product Transportation.

 

*Leonard W. Mallett* is Senior VicePresident, Operations of the General Partner, having been elected in February2005.  He was previously Vice President,Operations from September 2000 until February 2005.  Mr. Mallett was previously Region Manager ofthe Southwest Region of the Company from 1994 until 1999 and Director ofEngineering, from 1992 until 1994.  Mr.Mallett joined the Company in 1979 as an engineer.

 

*James C. Ruth* is Senior VicePresident, General Counsel and Secretary of the General Partner, having beenelected in February 2001. Mr. Ruth was previously Vice President and GeneralCounsel and Secretary from 1998 until February 2001, and Vice President,General Counsel from 1991 until 1998. Mr. Ruth joined the Company in 1970.

 

*Barbara A. Carroll* is VicePresident, Environmental, Health and Safety, having been elected in February2002.  Ms. Carroll joined ExxonMobil in1990 and served in a variety of management positions, including ProcurementServices Manager, Materials and Service Manager and Baytown Area Public AffairsManager until she joined the Company in February 2002.  Prior to ExxonMobil, Ms. Carroll was GeneralManager, Corporate Environmental Protection and Compliance with PanhandleEastern Corporation.  Ms. Carroll is notrelated to Milton Carroll.

 

*John N. Goodpasture* is VicePresident, Corporate Development of the General Partner, having joined theCompany in November 2001.  Mr.Goodpasture was previously Vice President of Business Development for EnronTransportation Services from June 1999 until he joined the Company. Prior tohis employment at Enron Transportation Services, Mr. Goodpasture spent 19 yearsin various executive positions at Seagull Energy Corporation (now Devon EnergyCorporation), a large independent oil and gas company.  At Seagull Energy, Mr. Goodpasture had mostrecently served for over ten years as Senior Vice President, Pipelines andMarketing.

* *

*Stephen W. Russell* is VicePresident, Support Services of the General Partner, having been elected inSeptember 2000.  Mr. Russell waspreviously Region Manager of the Southwest Region from July 1999 untilSeptember 2000, and Technical Operations Superintendent of the Southwest Regionfrom 1994 until 1999.  Mr. Russell joinedthe Company in 1988 as Project Manager in Engineering.

 

*C. Bruce Shaffer*is VicePresident, Human Resources and Ethics and Compliance Officer of the GeneralPartner, having been elected in February 2005. Mr. Shaffer joined the Company in August 2004 supporting Human Resources.  He was previously Vice President of Human ResourcesServices for Duke Energy Gas Transmission and Duke Energy Americas from January2004 until July 2004 and Vice President of Human Resources for Duke EnergyNorth America from June 2003 until July 2004. Mr. Shaffer joined Duke Energy in January 2000 as Managing Director of HumanResources for Duke Energy North America and Duke Energy International.

 

In addition to our Executive Officers, Mark G.Stockard serves as Treasurer, having been elected in May 2002.  Mr. Stockard was Assistant Treasurer of theGeneral Partner from July 2001 until May 2002. He was previously Controller from October 1996 until May 2002.  Mr. Stockard joined the Company in October1990.

 

**Section 16(a) BeneficialOwnership Reporting Compliance**

 

Section 16(a) of the Securities Exchange Act of 1934requires directors, officers and persons who beneficially own more than tenpercent of a registered class of our equity securities to file with the SEC andthe New York Stock Exchange initial reports of ownership and reports of changesin ownership of such equity securities.  Basedon information furnished to the Company and written representation that noother reports were required, to the Company’s knowledge, all applicable Section16(a) filing requirements were complied with during the year ended December 31,2004, except for a report covering a transaction that was filed late by Mr.Mallett.

 

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***Item 11. ***Executive Compensation

 

**Summary Compensation Table**

 

The officers of the General Partner manage and operateour business.  We do not directly employany of the persons responsible for managing or operating our operations, butinstead reimburse the General Partner for the services of these persons (seeNote 7.  Related Party Transactions).  The following table reflects cashcompensation paid or accrued by the General Partner for the years endedDecember 31, 2004, 2003 and 2002, with respect to its Chief Executive Officerand the four other most highly compensated executive officers in 2004(collectively, the “Named Executive Officers”).

 

**SUMMARYCOMPENSATION TABLE**

 
| **Name and**               | ** ** | ** ** | ** ** | ** **      | ** ** | **Other  Annual  Compensation** | ** ** | **Long  Term  Compensation  Payouts** | ** ** | **All  Other  Compensation** | ** ** |
|----------------------------|------------|------------|------------|-----------------|------------|---------------------------------|------------|---------------------------------------|------------|------------------------------|------------|
| **Annual  Compensation**   |
| ** **                 | ** ** | ** ** | **Bonus**  |
| **Principal  Position**    | ** ** | **Year**   | ** ** | **Salary  ($)** | ** ** | **($) (2)**                     | ** ** | **($) (3)**                           | ** ** | **($) (4)**                  | ** ** | **($) (5)** | ** ** |
|                       |       |       |       |            |       |                            |       |                                  |       |                         |       |   |   |
| Barry R. Pearl (1)         |       | 2004       |       | 291,738         |       | 157,242                         |       | 59,431                                |       | 291,910                      |       | 31,321 |   |
| President and  Chief       |       | 2003       |       | 283,500         |       | 196,465                         |       | 52,000                                |       | —                       |       | 27,608 |   |
| Executive  Officer         |       | 2002       |       | 252,308         |       | 142,000                         |       | 24,160                                |       | —                       |       | 24,310 |   |
|                       |       |       |       |            |       |                            |       |                                  |       |                         |       |   |   |
| J. Michael  Cockrell       |       | 2004       |       | 209,654         |       | 91,451                          |       | 12,021                                |       | —                       |       | 32,714 |   |
| Senior Vice President,     |       | 2003       |       | 202,846         |       | 114,364                         |       | 7,250                                 |       | 108,225                      |       | 69,078 |   |
| Commercial  Upstream       |       | 2002       |       | 195,462         |       | 86,600                          |       | 21,750                                |       | 358,200                      |       | 27,034 |   |
|                       |       |       |       |            |       |                            |       |                                  |       |                         |       |   |   |
| James C. Ruth              |       | 2004       |       | 208,308         |       | 88,218                          |       | 14,906                                |       | 183,106                      |       | 34,069 |   |
| Senior Vice  President and |       | 2003       |       | 195,654         |       | 108,333                         |       | 20,250                                |       | 456,084                      |       | 864,675 |   |
| General Counsel            |       | 2002       |       | 182,342         |       | 86,300                          |       | 18,095                                |       | 55,368                       |       | 29,024 |   |
|                       |       |       |       |            |       |                            |       |                                  |       |                         |       |   |   |
| Charles H.  Leonard        |       | 2004       |       | 202,654         |       | 86,391                          |       | 14,906                                |       | 183,106                      |       | 325,281 |   |
| Senior Vice  President and |       | 2003       |       | 195,654         |       | 108,800                         |       | 20,250                                |       | 271,523                      |       | 22,007 |   |
| Chief Financial  Officer   |       | 2002       |       | 182,342         |       | 88,200                          |       | 18,095                                |       | 32,062                       |       | 23,991 |   |
|                       |       |       |       |            |       |                            |       |                                  |       |                         |       |   |   |
| Thomas R. Harper           |       | 2004       |       | 197,115         |       | 84,365                          |       | 12,322                                |       | 139,300                      |       | 29,646 |   |
| Senior Vice  President,    |       | 2003       |       | 181,154         |       | 102,135                         |       | 15,500                                |       | 493,052                      |       | 25,334 |   |
| Commercial  Downstream     |       | 2002       |       | 161,488         |       | 79,500                          |       | 14,805                                |       | 37,460                       |       | 23,622 |   |

 

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(1)          Mr. Pearl was elected as ChiefExecutive Officer and director effective May 1, 2002.

 

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

 

(3)          Amounts represent quarterlydistribution equivalents under the terms of the Company’s 2000 Long TermIncentive Plan (“2000 LTIP”) and Phantom Unit Retention Plan (“PURP”).

 

(4)          Amounts represent creditsearned to Performance Unit accounts and payouts under the 2000 LTIP.

 

(5)          Includes (i) Company matchingcontributions under funded, qualified, defined contribution retirement plans;(ii) Company matching contribution credits under unfunded, non qualified plans;(iii) the imputed value of premiums paid by the Company for insurance on the NamedExecutive Officers’ lives; and (iv) payments received under the Duke EnergyRetirement Cash Balance Plan.

 

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## **Executive Employment Contracts and Termination ofEmployment Arrangements**

 

On February 12, 2001, Barry R. Pearl and the Companyentered into an employment agreement, which set a minimum base salary of $220,000per year. The Company may terminate the employment agreement for cause, deathor disability. In addition, the Company or Mr. Pearl may terminate theagreement upon written notice.  Mr. Pearlparticipates in other Company sponsored benefit plans on the same basis asother senior executives of the Company. In the event Mr. Pearl is terminated due to death or disability or bythe Company for cause, Mr. Pearl is entitled only to base salary earned throughthe date of termination.  In the event oftermination for any other reason, Mr. Pearl is entitled to base salary earnedthrough the date of termination plus a lump sum severance payment equal to twotimes his base annual salary and two times the current target bonus approvedunder the MICP by the Compensation Committee. In the event Mr. Pearl isinvoluntarily terminated following a change in control, he is entitled to alump sum severance payment equal to two times his base annual salary plus twotimes his current target bonus.

 

The Company has entered into employment agreementswith its executive officers identified in Item 10.  Directors and Executive Officers of theRegistrant.  The agreements may beterminated for death, disability or by the Company with or without cause.  In the event one of the named executives’employment is terminated due to death or disability or by the Company forcause, the executive is entitled only to base salary earned through the date oftermination.  In the event of terminationfor any other reason, the executive is entitled to base salary earned throughthe date of termination plus a lump sum severance payment equal to two timessuch executive’s base annual salary and two times the current target bonusapproved under the MICP by the Compensation Committee.  In the event that an executive isinvoluntarily terminated following a change in control, the executive isentitled to a lump sum severance payment equal to two times his base annualsalary plus two times his current target bonus.

 

## **Compensation Committee Interlocks and InsiderParticipation**

 

During 2004, Jim W. Mogg, a director of the GeneralPartner and group vice president and chief development officer of Duke Energy,was chairman of the Compensation Committee of the General Partner andparticipated in deliberations concerning the General Partner’s executiveofficer compensation.  The other fourmembers of the Compensation Committee of the General Partner, Milton Carroll,Derrill Cody, John P. DesBarres and Paul F. Ferguson, Jr., are non-employeedirectors of the General Partner and are not officers or directors of DEFS orits parent companies, ConocoPhillips or Duke Energy.

 

## ****Compensation Pursuant to General Partner Plans****

 

*Management IncentiveCompensation Plan*

* *

The General Partner has established the MICP, whichprovides for the payment of additional cash compensation to participants ifcertain Partnership performance objectives and personal objectives are met eachyear.  The Compensation Committee of theBoard of Directors of the General Partner determines at the beginning of eachyear which employees are eligible to become participants in the MICP.  Additional participants may be added to theplan during the year by the Chief Executive Officer.  Each participant is assigned a target award,determined as a percentage of total annual eligible earnings for the plan yearless any incentive compensation payments during the plan year, by the CompensationCommittee. Such target award determines the additional compensation to be paidif certain performance objectives and personal objectives are met. The amountof the target awards may range from 10% to 55% of a participant’s basesalary.  Maximum payout under the MICP is144% of a participant’s target award. Awards are paid as soon as practicable following approval by the CompensationCommittee after the close of a year.

 

*1994 Long Term IncentivePlan*

* *

During 1994, the Company adopted the Texas EasternProducts Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”).  The 1994 LTIP provides certain key employeeswith an incentive award whereby a participant is granted an option to purchaseUnits.  These same employees are alsogranted a stipulated number of Performance Units, the cash value of which maybe used to pay for the exercise of the respective Unit options awarded.  Under the provisions of the 1994 LTIP, nomore than one million options and two million Performance

 

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Units may be granted. No awards have been made under the 1994 LTIP since 1999, and none areexpected to be made in the future.

 

There were no Aggregated Option Exercises during theyear ended December 31, 2004, under the 1994 LTIP by the Named ExecutiveOfficers, and there were no unexercised outstanding Unit options under the 1994LTIP to the Named Executive Officers as of December 31, 2004.

 

*2000 Long Term IncentivePlan*

* *

Effective January 1, 2000, the General Partnerestablished the Texas Eastern Products Pipeline Company, LLC 2000 Long TermIncentive Plan (“2000 LTIP”) to provide key employees incentives to achieveimprovements in our financial performance. Generally, upon the close of a three-year performance period, if theparticipant is then still an employee of the General Partner, the participantwill receive a cash payment in an amount equal to (1) the applicableperformance percentage specified in the award multiplied by (2) the number ofphantom units granted under the award multiplied by (3) the average of theclosing prices of a Unit over the ten consecutive trading days immediatelypreceding the last day of the performance period.  Generally, a participant’s performancepercentage is based upon the improvement of our Economic Value Added (asdefined below) during a three-year performance period over the Economic Value Addedduring the three-year period immediately preceding the performance period.  If a participant incurs a separation fromservice during the performance period due to death, disability or retirement(as such terms are defined in the 2000 LTIP), the participant will be entitled toreceive a cash payment in an amount equal to the amount computed as describedabove multiplied by a fraction, the numerator of which is the number of daysthat have elapsed during the performance period prior to the participant’sseparation from service and the denominator of which is the number of days inthe performance period.

 

The performance period applicable to awards granted in2004 is the three-year period that commenced on January 1, 2004, and ends onDecember 31, 2006.  Each participant’sperformance percentage is the result of 100% +/- [(A) minus (C)] divided by [(C)minus (B)] where (A) is the actual Economic Value Added for the performanceperiod, (B) is $67.6 million (which represents the actual Economic Value Addedfor the three-year period immediately preceding the performance period) and (C)is $103.3 million (which represents the Target Economic Value Added during thethree-year performance period).  Noamounts will be payable under the awards granted in 2004 for the 2000 LTIPunless Economic Value Added for the three year performance period exceeds $67.6million.  The performance percentage maynot exceed 150%.

 

Economic Value Added means our average annual EBITDA forthe performance period minus the product of our average asset base and our costof capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDAmeans our earnings before net interest expense, depreciation and amortizationand our proportional interest in EBITDA of our joint ventures as presented in ourconsolidated financial statements prepared in accordance with generallyaccepted accounting principles, except that in its discretion the CompensationCommittee of the General Partner may exclude gains or losses fromextraordinary, unusual or non-recurring items. For the years ended December 31, 2004 and 2003, EBITDA means, inaddition to the above, earnings before other income – net.  Average asset base means the quarterlyaverage, during the performance period, of our gross value of property, plantand equipment, *plus* products and crude oil operatingoil supply and the gross value of intangibles and equity investments.  Our cost of capital is approved by theCompensation Committee at the date of award grant.

 

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

 

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The following table provides information concerningawards under the 2000 LTIP to each of the Named Executive Officers during 2004.

 
| ** **   | ** ** | **Number**         | ** ** | ** **              | ** ** | ** **                        | ** ** | ** **          | ** ** | ** **           | ** ** |
|--------------|------------|--------------------|------------|-------------------------|------------|-----------------------------------|------------|---------------------|------------|----------------------|------------|
| ** **   | ** ** | **of**             | ** ** | ** **              | ** ** | **Estimated  Future Payouts (1)** |
| **Name**     | ** ** | **Phantom  Units** | ** ** | **Performance  Period** | ** ** | **Threshold  (#)  (2)**           | ** ** | **Target  (#) (3)** | ** ** | **Maximum  (#) (4)** |
| ** **   | ** ** | ** **         | ** ** | ** **              | ** ** | ** **                        | ** ** | ** **          | ** ** | ** **           | ** ** |
| Mr. Pearl    |       | 7,100              |       | 3 years                 |       | —                            |       | 7,100               |       | 10,650               |       |
| Mr. Leonard  |       | 2,200              |       | 3 years                 |       | —                            |       | 2,200               |       | 3,300                |       |
| Mr. Ruth     |       | 2,200              |       | 3 years                 |       | —                            |       | 2,200               |       | 3,300                |       |
| Mr. Cockrell |       | 2,200              |       | 3 years                 |       | —                            |       | 2,200               |       | 3,300                |       |
| Mr. Harper   |       | 2,100              |       | 3 years                 |       | —                            |       | 2,100               |       | 3,150                |       |

----

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

 

(2)          No amounts will be payable forawards granted in 2004 unless Economic Value Added for the three year performanceperiod exceeds $67.6 million.

 

(3)          In number of phantomunits.  Pursuant to Instruction 5 toRegulation 402(e) of the Securities and Exchange Commission, these amountsassume that the 13% increase in Economic Value Added for 2004 as compared with2003 is maintained for each of the three years in the performance period.  There can be no assurance that any specificamount of Economic Value Added will be attained for such period.

 

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

 

## **Pension Plan**

## ** **

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

 

Benefits under the Duke Energy Retirement Cash BalancePlan and the Duke Energy Executive Cash Balance Plan were based on eligiblepay, generally consisting of base pay, short term incentive pay and lump-summerit increases.  The Duke EnergyRetirement Cash Balance Plan excludes deferred compensation, other thandeferrals pursuant to Sections 401(k) and 125 of the Internal Revenue Code.  All benefits owed to the Named Executive Officersunder the Duke Energy Retirement Cash Balance Plan have been paid.  As part of the change in ownership on March31, 2000, the Company is no longer responsible for the funding of theliabilities associated with the Duke Energy Executive Cash Balance Plan.

 

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

 

Under the cash balance benefit accrual formula thatapplies in determining benefits under the TEPPCO RCBP, an eligible employee’splan account receives a pay credit at the end of each month in which theemployee remains eligible and receives eligible pay for services.  The monthly pay credit is equal to apercentage of the employee’s monthly eligible pay.  The percentage depends on age added to completedyears of services at the beginning of the year, as shown below:

 

66

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

 

The above monthly pay credit is increased by anadditional 4% of any portion of eligible pay above the Social Security taxablewage base ($87,900 for 2004). Employee accounts also receive monthly interestcredits on their balances.  The rate ofthe interest credit is adjusted quarterly and is derived from the averageannual yield on 30-year U.S. Treasury Bonds during the third week of the lastmonth of the previous quarter, subject to a minimum rate of 4% per year and amaximum rate of 9% per year.

 

Assuming that the Named Executive Officers continue intheir present positions at their present salaries until retirement at age 65,their estimated annual pensions in a single life annuity form under theapplicable pension plan(s) (including the Duke Energy Executive Cash BalancePlan, the TEPPCO RCBP and the TEPPCO SBP) attributable to such salaries wouldbe as follows: Barry R. Pearl, $73,596; J. Michael Cockrell, $40,571; James C.Ruth, $61,862; Charles H. Leonard, $72,531; and Thomas R. Harper, $15,191.  Such estimates were calculated assuminginterest credits at a rate of 6% per annum and using a future Social Securitytaxable wage base equal to $90,000.

 

**Compensation of Directors**

 

Directors of the General Partner who are neitherofficers nor employees of either the Company or DEFS receive a stipend,effective January 1, 2005, of $35,000 per annum, $1,000 for attendance at eachmeeting of the Board of Directors, $1,000 for attendance at each meeting of acommittee of the Board of Directors, except for attendance of the Audit Committee,for which the amount is $2,000 for each meeting, and reimbursement of expensesincurred in connection with attendance at a meeting of the Board of Directorsor a committee of the Board of Directors. Each non-employee director who serves as chairman of a committee of theBoard of Directors receives an additional stipend of $8,000 per annum, exceptfor the chairman of the Audit Committee, who receives an additional stipend of$20,000 per annum.  Effective September1, 1999, non-employee directors may elect to defer payment of retainer andattendance fees until termination of service on the Board of Directors.  Such deferral may be either 50% or 100% ineither a fixed income investment account that is credited with annual interest(currently 7%) or an investment account based upon the market value of Units.

 

Effective January 1, 2004, each quarter that anon-employee director continues to serve on the Board of Directors, suchdirector will be credited with an amount equal to the then current market valueof 100 Units and distribution equivalents on previously awarded amounts. Ingeneral, such amounts will not become distributable until the non-employeedirector terminates service on the Board of Directors. When a non-employeedirector terminates service on the Board of Directors, payment will bedistributed in cash to the director according to the distribution schedulechosen by such director.

 

Messrs. Mogg, Pearl, Borer, Bradley and Easter are notcompensated for their services as directors, and it is not anticipated that anycompensation for service as a director will be paid in the future to directorswho are either officers or full-time employees of Duke Energy, DEFS, theGeneral Partner or any of their affiliates.

 

***Item 12. ***Security Ownership of Certain Beneficial Ownersand Management

 

*Equity Compensation PlanInformation*

* *

At December 31, 2004, we had no Equity CompensationPlans approved or unapproved by security holders as none of our compensationplans require the issuance of securities or options.  During the year ended December 31, 2003, allof the remaining outstanding Unit options under the 1994 LTIP were exercised(see Compensation Pursuant to General Partner Plans).  We have no other compensation plans thatwould result in the issuance of Units.

 

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* *

*Security Ownership ofCertain Beneficial Owners*

* *

As of February 23, 2005, Duke Energy, through itsownership of the Company and other subsidiaries, owns 2,500,000 Units,representing 4.0% of the 63.0 million Units outstanding.  No other person is known by us to own morethan 5% of our outstanding Units.  OnFebruary 24, 2005, our General Partner was acquired by EPCO, a privately heldcompany controlled by Dan L. Duncan. Additionally, in a separate transaction, EPCO and its affiliates haveagreed to purchase the 2.5 million Units from Duke Energy, valued atapproximately $100.0 million (see Note 21. Subsequent Event).

 

*Security Ownership ofManagement*

* *

The following table sets forth certain information, asof February 25, 2005, concerning the beneficial ownership of Units by eachdirector and Named Executive Officer of the General Partner and by alldirectors and officers of the General Partner as a group.  This information is based on data furnished bythe persons named. Based on information furnished to the General Partner by thesepersons, no director or officer of the General Partner owned beneficially, asof February 25, 2005, more than 1% of the 63.0 million Units outstanding atthat date.

 
| **Name**                                                                           | ** ** | **Number of  Units (1)** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------|------------|
| ** **                                                                         | ** ** | ** **               | ** ** |
| Jim W. Mogg (2)                                                                    |       | 4,427                    |       |
| Mark A. Borer                                                                      |       | 1,000                    |       |
| Michael J.  Bradley                                                                |       | 1,150                    |       |
| Derrill Cody                                                                       |       | 13,000                   |       |
| John P.  DesBarres (3)                                                             |       | 20,000                   |       |
| Paul F.  Ferguson, Jr.                                                             |       | 200                      |       |
| Barry R. Pearl                                                                     |       | 10,000                   |       |
| J. Michael  Cockrell                                                               |       | 5,000                    |       |
| Thomas R. Harper                                                                   |       | 10,000                   |       |
| James C. Ruth                                                                      |       | 5,000                    |       |
| Charles H.  Leonard                                                                |       | 1,124                    |       |
| All directors  and officers (consisting of 18 people, including those named above) |       | 72,737                   |       |

 

----

(1)          Unless otherwise indicated,the persons named above have sole voting and investment power over the Unitsreported. Includes Units that the named person has the right to acquire within60 days.

 

(2)          Includes 2,227 Units owned by daughters.

 

(3)          Units are held jointly withspouse with right of survivorship.

 

***Item 13. ***Certain Relationships and Related Transactions

 

## **Our Management**

## ** **

We have no employees and are managed by the Company, anindirect wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, andConocoPhillips holds the remaining interest of approximately 30%.  According to the Partnership Agreements, theCompany is entitled to reimbursement of all direct and indirect expensesrelated to our business activities (see Note 1. Partnership Organization).

 

For the years ended December 31, 2004, 2003, and 2002,we incurred direct expenses of $83.6 million, $78.0 million and $66.7 million,respectively, which were charged to us by DEFS. Substantially all of these costs were related to payroll and payrollrelated expenses.  For the years endedDecember 31, 2004, 2003, and 2002, expenses for administrative services andoverhead allocated to us by Duke Energy and its affiliates were $1.2 million, $1.1million and $0.8 million, respectively.

 

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## **Transactions with DEFS and its affiliates**

 

TCO purchases condensate from DEFS and itsaffiliates.  For the years ended December31, 2004, 2003, and 2002, TCO’s purchases from DEFS and its affiliates were $141.3million, $110.7 million and $80.5 million, respectively.

 

LSI sells lubrication oils and specialty chemicals toDEFS.  For the years ended December 31,2004, 2003, and 2002, revenues recognized by LSI included $16.1 million, $15.2million and $14.6 million, respectively, for the sale of lubrication oils andspecialty chemicals to DEFS.

 

Effective with the purchase of fractionationfacilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-yearFractionation Agreement, under which TEPPCO Colorado receives a variable feefor all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $7.5million, $7.4 million and $7.4 million for the years ended December 31, 2004,2003 and 2002, respectively.  TEPPCOColorado and DEFS also entered into an Operation and Maintenance Agreement,whereby DEFS operates and maintains the fractionation facilities for TEPPCOColorado.  For these services, TEPPCOColorado pays DEFS a set volumetric rate for all fractionated volumes deliveredto DEFS.  Expenses related to the Operationand Maintenance Agreement totaled $0.9 million for each of the years endedDecember 31, 2004, 2003 and 2002.

 

The Dean Pipeline and the Wilcox Pipeline wereincluded with the crude oil assets purchased from DEFS effective November 1,1998.  The southern portion of the DeanPipeline originates in South Texas and transports NGLs for DEFS into itspipeline in Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation totaled $0.2million, $1.0 million and $2.9 million for the years ended December 31, 2004,2003 and 2002, respectively.  The WilcoxPipeline, which is located along the Texas Gulf Coast, transports NGLs for DEFSfrom two of its natural gas processing plants and is currently supported by athroughput agreement with DEFS through November 2005.  The fees paid to us by DEFS under theagreement were $1.4 million, $1.5 million and $1.2 million for the years endedDecember 31, 2004, 2003 and 2002, respectively.

 

The Panola Pipeline and San Jacinto Pipeline werepurchased on December 31, 2000, from DEFS for $91.7 million.  These pipelines originate at DEFS’ East TexasPlant Complex in Panola County, Texas, and transport NGLs for DEFS and othermajor integrated oil and gas companies. Revenues recognized from an affiliate of DEFS for NGL transportationtotaled $11.3 million, $9.2 million and $12.0 million for the years endedDecember 31, 2004, 2003 and 2002, respectively.

 

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

 

On September 30, 2001, we purchased Jonah (see Note5.  Acquisitions and Dispositions).  The Jonah assets are managed and operated byemployees of DEFS under a contractual agreement under which DEFS is reimbursedfor its actual costs.  During the yearsended December 31, 2004, 2003 and 2002, we recognized $4.1 million, $3.7million and $3.3 million, respectively, of expenses related to the operationand management of the Jonah assets by DEFS. Jonah provides gas gathering services to an affiliate of DEFS.  The gathering fees paid to us by an affiliateof DEFS totaled $3.3 million, $2.0 million and $1.2 million for the years endedDecember 31, 2004, 2003 and 2002, respectively. In connection with Jonah’s Pioneer processing plant operations, which wasconstructed during the Phase III expansion and began operating in 2004, Jonah sellsNGLs to, and purchases gas from, an affiliate of DEFS.  For the year ended December 31, 2004, Jonah’ssales to DEFS and its affiliates were $7.1 million, and purchases from DEFS andits affiliates were $5.1 million.  Inaddition, processing fees we received from an affiliate of DEFS for gasprocessing services at the Pioneer plant totaled $0.6 million for the yearended December 31, 2004.

 

On March 1, 2002, we purchased the Chaparral NGLsystem (see Note 5.  Acquisitions andDispositions).  The Chaparral assets aremanaged and operated by employees of DEFS under a contractual agreement under whichDEFS is reimbursed for its actual costs. During the years ended December 31, 2004, 2003, and 2002, we recognized

 

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$2.3 million, $2.1 million and $1.7 million,respectively, of expenses related to the operation and management of theChaparral assets by DEFS.  An affiliateof DEFS transports NGLs on the Chaparral NGL system.  The fees paid to us by an affiliate of DEFSfor NGL transportation on the Chaparral NGL system totaled $3.8 million, $5.5million and $4.5 million for the years ended December 31, 2004, 2003 and 2002,respectively.

 

On June 30, 2002, we purchased Val Verde (see Note 5.  Acquisitions and Dispositions).  The Val Verde assets are managed and operatedby employees of DEFS under a contractual agreement under which DEFS isreimbursed for its actual costs.  Duringthe years ended December 31, 2004, 2003, and 2002, we recognized $3.8 million, $3.0million and $1.2 million, respectively, of expenses related to the operationand management of the Val Verde assets by DEFS.

 

At December 31, 2004 and 2003, we had a receivablefrom DEFS of $10.5 million and $1.8 million, respectively, related to sales andtransportation services provided to DEFS. Included in this receivable balance from DEFS at December 31, 2004, is agas imbalance receivable of $0.9 million. At December 31, 2004 and 2003, we had a payable to DEFS of $22.4 millionand $15.0 million, respectively, related to direct payroll, payroll relatedcosts, management fees, and other operational related charges, including thosefor Jonah, Chaparral and Val Verde as described above.  Included in this payable balance at December31, 2004 and 2003, is a gas imbalance payable to DEFS of $3.2 million and $1.5million, respectively.

 

On April 2, 2003, we sold in an underwritten publicoffering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaledapproximately $114.5 million, of which approximately $113.8 million was used torepurchase and retire all of the 3.9 million previously outstanding Class BUnits held by DETTCO (see Note 11. Partners’ Capital and Distributions).

 

We contract with Bison Insurance Company Limited (“Bison”),a wholly owned subsidiary of Duke Energy, for a majority of our insurancecoverage, including property, liability, auto and directors and officersinsurance coverage.  For the years endedDecember 31, 2004, 2003 and 2002, we incurred insurance expense related topremiums paid to Bison of $6.5 million, $5.9 million and $3.8 million,respectively.  At December 31, 2004 and2003, we had insurance reimbursement receivables due from Bison of $5.2 millionand $4.2 million, respectively.

 

**Interest of the General Partnerin the Partnership**

 

We make quarterly cash distributions of all of ourAvailable Cash, generally defined as consolidated cash receipts lessconsolidated cash disbursements and cash reserves established by the GeneralPartner in its sole discretion. According to the Partnership Agreement, theCompany receives incremental incentive cash distributions when cashdistributions exceed certain target thresholds as follows:

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

 

During the year ended December 31, 2004, distributionspaid to the General Partner totaled $66.9 million, including incentivedistributions of $63.5 million.

 

## **Interests of Duke Energy in the Partnership**

 

In connection with our formation, the Company received2,500,000 Deferred Participation Interests (“DPIs”).  Effective April 1, 1994, the DPIs beganparticipating in distributions of cash and allocations of profit and loss in amanner identical to our Units and are treated as Units for purposes of thisReport.  These Units were assigned toDuke Energy when ownership of the Company was transferred from Duke Energy toDEFS in 2000.  Pursuant to ourPartnership Agreement, we have registered the resale by Duke Energy of theseUnits with the SEC.  As of December 31,2004, none of these Units had been sold by Duke Energy.

 

On February 24, 2005, our General Partner was acquired by EPCO, aprivately held company controlled by Dan L. Duncan.  Additionally, in a separate transaction, EPCOand its affiliates have agreed to purchase the 2.5 million Units from Duke Energy,valued at approximately $100.0 million (see Note 21. Subsequent Event).

 

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***Item 14. ***Principal Accounting Fees and Services

 

The following table describes fees for professionalaudit services rendered by KPMG, our principal accountant, for the audit of ourfinancial statements for the years ended December 31, 2004 and 2003, and forfees billed for other services rendered by KPMG during those periods (inthousands):  

 
| ** **              | ** ** | **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 forthe audits of the consolidated financial statements as well as for the audit ofinternal control over financial reporting.

 

(2)          Audit related fees consistprincipally of fees for audits of financial statements of certain employeebenefit plans and certain internal control documentation assistance.

 

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

 

(4)          All Other Fees include theaggregate fees we paid during the year ended December 31, 2003, for productsand services provided by KPMG, other than the services reported above.  The majority of the other fees in 2003 arefees for litigation support services related to the D.R.D. legal proceedingswhich was settled on July 16, 2003 (see Note 16.  Commitments and Contingencies).

 

## **Procedures for Audit Committee Pre-Approval of Auditand Permissible Non-Audit Services of Independent Registered Public Accountant**

 

Pursuant to its charter, the Audit Committee of ourBoard of Directors is responsible for reviewing and approving, in advance, anyaudit and any permissible non-audit engagement or relationship between us andour independent registered public accountants. KPMG’s engagement to conduct our audit was approved by the AuditCommittee on April 26, 2004.  Additionally,all permissible non-audit engagements with KPMG have been reviewed and approvedby the Audit Committee, pursuant to pre-approval policies and proceduresestablished by the Audit Committee.

 

 

**PARTIV**

** **

** **

***Item 15. ***Exhibits, Financial Statement Schedules.

 

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

 

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

 

(2)                                  Financial Statement Schedules:   None.

 

(3)                                  Exhibits.

 
| **Exhibit  Number** | ** ** | **Description**                                                                                                                                                                                                   |
|---------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |       |                                                                                                                                                                                                              |
| 3.1                 |       | Certificate of Limited Partnership of TEPPCO  Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO  Partners, L.P. (Commission File No. 33-32203) and incorporated herein by  reference). |

 

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

 

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|   |   | L.P. (Commission File No. 1-10403) for the quarter  ended June 30, 1999 and incorporated herein by reference).                                                                                                                                                                                                                                                                                                |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.6+  |   | Form of Employment Agreement between the Company and  Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture,  Leonard W. Mallett, Stephen W. Russell, C. Bruce Shaffer, and Barbara A. Carroll  (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission  File No. 1-10403) for the year ended December 31, 1998 and incorporated  herein by reference).                  |
| 10.7   |   | Services and Transportation Agreement between TE  Products Pipeline Company, Limited Partnership and Fina Oil and Chemical  Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership,  dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO  Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31,  1999 and incorporated herein by reference).      |
| 10.8   |   | Call Option Agreement, dated February 9, 1999 (Filed  as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the quarter ended March 31, 1999 and incorporated herein by  reference).                                                                                                                                                                                      |
| 10.9+  |   | Form of Employment and Non-Compete Agreement between  the Company and J. Michael Cockrell effective January 1, 1999 (Filed as  Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the quarter ended September 30, 1999 and incorporated herein by  reference).                                                                                                            |
| 10.10+ |   | Texas Eastern Products Pipeline Company Non-employee  Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit  10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for  the quarter ended September 30, 1999 and incorporated herein by reference).                                                                                                                 |
| 10.11+ |   | Texas Eastern Products Pipeline Company Non-employee  Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as  Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the quarter ended September 30, 1999 and incorporated herein by  reference).                                                                                                         |
| 10.12+ |   | Texas Eastern Products Pipeline Company Phantom Unit  Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form  10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter  ended September 30, 1999 and incorporated herein by reference).                                                                                                                                 |
| 10.13+ |   | Texas Eastern Products Pipeline Company, LLC 2000  Long Term Incentive Plan, Amendment and Restatement, effective January 1,  2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P.  (Commission File No. 1-10403) for the year ended December 31, 2000 and  incorporated herein by reference).                                                                                                  |
| 10.14+ |   | TEPPCO Supplemental Benefit Plan, effective April 1,  2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P.  (Commission File No. 1-10403) for the year ended December 31, 2000 and  incorporated herein by reference).                                                                                                                                                                          |
| 10.15+ |   | Employment Agreement with Barry R. Pearl (Filed as  Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the quarter ended March 31, 2001 and incorporated herein by  reference).                                                                                                                                                                                           |
| 10.16  |   | Second Amended and Restated Agreement of Limited  Partnership of TE Products Pipeline Company, Limited Partnership, dated  September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners,  L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001  and incorporated herein by reference).                                                                                     |
| 10.17  |   | Amended and Restated Agreement of Limited Partnership  of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of  TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended  September 30, 2001 and incorporated herein by reference).                                                                                                                                    |
| 10.18  |   | Contribution, Assignment and Amendment Agreement  among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited  Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and  TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of  TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended  June 30, 2001 and incorporated herein by reference). |

 

73

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| 10.19  |   | Certificate of Formation of TEPPCO Colorado, LLC  (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File  No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by  reference).                                                                                                                                                                                                   |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.20  |   | Agreement of Limited Partnership of TEPPCO Midstream  Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q  of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended  September 30, 2001 and incorporated herein by reference).                                                                                                                                                |
| 10.21  |   | Agreement of Partnership of Jonah Gas Gathering  Company dated June 20, 1996 as amended by that certain Assignment of  Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to  Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year  ended December 31, 2001 and incorporated herein by reference).                                                                             |
| 10.22  |   | Unanimous Written Consent of the Board of Directors  of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form  10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year  ended December 31, 2001 and incorporated herein by reference).                                                                                                                                                   |
| 10.23  |   | Amended and Restated Credit Agreement among TEPPCO  Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC  Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002  ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of  TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months  ended March 31, 2002 and incorporated herein by reference).    |
| 10.24  |   | Purchase and Sale Agreement between Burlington  Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated  May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P.  (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated  herein by reference).                                                                                                                     |
| 10.25  |   | Amendment, dated as of June 27, 2002 to the Amended  and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower,  SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of  March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit  99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated  as of July 2, 2002 and incorporated herein by reference). |
| 10.26  |   | Agreement of Limited Partnership of Val Verde Gas  Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form  10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter  ended June 30, 2002 and incorporated herein by reference).                                                                                                                                                     |
| 10.27+ |   | Texas Eastern Products Pipeline Company, LLC 2002  Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43  to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the  quarter ended June 30, 2002 and incorporated herein by reference).                                                                                                                                             |
| 10.28+ |   | Amended and Restated TEPPCO Supplemental Benefit  Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of  TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended  December 31, 2002 and incorporated herein by reference).                                                                                                                                                                |
| 10.29+ |   | Texas Eastern Products Pipeline Company, LLC 2000  Long Term Incentive Plan, Second Amendment and Restatement, effective January  1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P.  (Commission File No. 1-10403) for the year ended December 31, 2002 and  incorporated herein by reference).                                                                                                         |
| 10.30+ |   | Amended and Restated Texas Eastern Products Pipeline  Company, LLC Management Incentive Compensation Plan, effective January 1,  2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P.  (Commission File No. 1-10403) for the year ended December 31, 2002 and  incorporated herein by reference).                                                                                                             |
| 10.31+ |   | Amended and Restated TEPPCO Retirement Cash Balance  Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of  TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended  December 31, 2002 and incorporated herein by reference).                                                                                                                                                              |
| 10.32  |   | Formation Agreement between Panhandle Eastern Pipe  Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline  Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit  10.48 to Form 10-K of TEPPCO Partners, L.P.                                                                                                                                                                      |

 

74

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|    |   | (Commission File No. 1-10403) for the year ended  December 31, 2002 and incorporated herein by reference).                                                                                                                                                                                                                                                                                                            |
|---------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.33   |   | Amended and Restated Limited Liability Company  Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as  Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the year ended December 31, 2002 and incorporated herein by  reference).                                                                                                                           |
| 10.34   |   | Guaranty Agreement, dated as of September 27, 2002,  between TE Products Pipeline Company, Limited Partnership and Marathon  Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed  as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No.  1-10403) for the year ended December 31, 2002 and incorporated herein by  reference).                                          |
| 10.35   |   | LLC Membership Interest Purchase Agreement By and  Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum  LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers,  dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO  Partners, L.P. (Commission File No. 1-10403) for the year ended December 31,  2002 and incorporated herein by reference).  |
| 10.36   |   | Joint Development Agreement between TE Products Pipeline  Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated  February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners,  L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and  incorporated herein by reference).                                                                                      |
| 10.37   |   | Credit Agreement among TEPPCO Partners, L.P. as  Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The  Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000  Revolving Facility) (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners,  L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2003 and  incorporated herein by reference).                 |
| 10.38   |   | Agreement of Limited Partnership of Mont Belvieu  Storage Partners, L.P. dated effective January 21, 2003 (Filed as Exhibit  10.53 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for  the quarter ended September 30, 2003 and incorporated herein by reference).                                                                                                                               |
| 10.39   |   | Letter of Agreement Clarifying Rights and Obligations  of the Parties Under the Mont Belvieu Storage Partners, L.P., Partnership  Agreement and the Mont Belvieu Venture, LLC, LLC Agreement, dated October 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).                   |
| 10.40   |   | Amended and Restated Credit Agreement among TEPPCO  Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and LC  Issuing Bank and The Lenders Party Hereto, as Lenders dated as of October 21,  2004 ($600,000,000 Revolving Facility) (Filed as Exhibit 99.1 to Form 8-K of  TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of October 21,  2004 and incorporated herein by reference). |
| 10.41+* |   | Texas Eastern Products Pipeline Company Amended and  Restated Non-employee Directors Deferred Compensation Plan, effective April  1, 2002.                                                                                                                                                                                                                                                                            |
| 10.42+* |   | Texas Eastern Products Pipeline Company Second  Amended and Restated Non-employee Directors Unit Accumulation Plan, effective  January 1, 2004.                                                                                                                                                                                                                                                                       |
| 12.1*   |   | Statement of Computation of Ratio of Earnings to  Fixed Charges.                                                                                                                                                                                                                                                                                                                                                      |
| 21      |   | Subsidiaries of the Partnership (Filed as Exhibit 21  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).                                                                                                                                                                                                                 |
| 23*     |   | Consent of KPMG LLP.                                                                                                                                                                                                                                                                                                                                                                                                  |
| 24*     |   | Powers of Attorney.                                                                                                                                                                                                                                                                                                                                                                                                   |
| 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.                                                                                                                                                                                                                                                                                                                  |

 

75

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

 
|   | TEPPCO  Partners, L.P.           |   |
|--------|----------------------------------|--------|
|   | (Registrant)                     |   |
|   | (A Delaware Limited Partnership) |   |
|        |                                  |        |  |  |

 
|   | By: Texas  Eastern Products Pipeline  Company, LLC, as General Partner |
|--------|------------------------------------------------------------------------|
|   |                                                                   |

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

 

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

 

Dated: March 1, 2005

 

76

----

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, this Report has been signed below by the followingpersons on behalf of the Registrant and in the capacities and on the datesindicated.

 
| **Signature**           | ** ** | **Title**                                          | ** **                                    | **Date**            |
|-------------------------|------------|----------------------------------------------------|-----------------------------------------------|---------------------|
|                    |       |                                               |                                          |                |
| BARRY  R. PEARL*        |       | President  and Chief Executive Officer             |                                          | March 1,  2005 |
| Barry R. Pearl          |       | of Texas Eastern  Products Pipeline Company, LLC   |                                          |                |
|                    |       |                                               |                                          |                |   |
| CHARLES  H. LEONARD     |       | Senior  Vice President and Chief Financial Officer |                                          | March 1,  2005 |
| Charles H.  Leonard     |       | of Texas Eastern  Products Pipeline Company, LLC   |                                          |                |
|                    |       |                                               | (Principal  Accounting and Financial Officer) |                |   |
|                    |       |                                               |                                          |                |   |
| JIM  W. MOGG*           |       | Chairman  of the Board of Texas                    |                                          | March 1,  2005 |
| Jim W. Mogg             |       | Eastern Products  Pipeline Company, LLC            |                                          |                |
|                    |       |                                               |                                          |                |   |
| MARK  A. BORER *        |       | Director  of Texas Eastern                         |                                          | March 1,  2005 |
| Mark A. Borer           |       | Products  Pipeline Company, LLC                    |                                          |                |
|                    |       |                                               |                                          |                |   |
| MICHAEL  J. BRADLEY*    |       | Director  of Texas Eastern                         |                                          | March 1,  2005 |
| Michael J.  Bradley     |       | Products  Pipeline Company, LLC                    |                                          |                |
|                    |       |                                               |                                          |                |   |
| MILTON  CARROLL*        |       | Director  of Texas Eastern                         |                                          | March 1,  2005 |
| Milton Carroll          |       | Products  Pipeline Company, LLC                    |                                          |                |
|                    |       |                                               |                                          |                |   |
| DERRILL  CODY*          |       | Director  of Texas Eastern                         |                                          | March 1,  2005 |
| Derrill Cody            |       | Products  Pipeline Company, LLC                    |                                          |                |
|                    |       |                                               |                                          |                |   |
| JOHN  P. DESBARRES*     |       | Director  of Texas Eastern                         |                                          | March 1,  2005 |
| John P.  DesBarres      |       | Products  Pipeline Company, LLC                    |                                          |                |
|                    |       |                                               |                                          |                |   |
| WILLIAM  H. EASTER III* |       | Director  of Texas Eastern                         |                                          | March 1,  2005 |
| William H.  Easter III  |       | Products  Pipeline Company, LLC                    |                                          |                |
|                    |       |                                               |                                          |                |   |
| PAUL  F. FERGUSON, JR.* |       | Director  of Texas Eastern                         |                                          | March 1,  2005 |
| Paul F.  Ferguson, Jr.  |       | Products  Pipeline Company, LLC                    |                                          |                |

 

----

* Signed on behalf of the Registrant and each of thesepersons:

 

 
| By:    |   /s/  CHARLES H. LEONARD     |   |
|--------|-----------------------------------------|--------|
|   | (Charles  H. Leonard, Attorney-in-Fact) |

 

77

----

 

**CONSOLIDATEDFINANCIAL STATEMENTS**

**OF TEPPCO PARTNERS, L.P.**

 

**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

TEPPCO Partners, L.P.:

 

We have audited the accompanying consolidated balancesheets of TEPPCO Partners, L.P. as of December 31, 2004 and 2003, and therelated consolidated statements of income, partners’ capital, and cash flowsfor each of the years in the three-year period ended December 31, 2004. Theseconsolidated financial statements are the responsibility of the Partnership’smanagement. Our responsibility is to express an opinion on these consolidatedfinancial statements based on our audits.

 

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, 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 statementsreferred to above present fairly, in all material respects, the financialposition of TEPPCO Partners, L.P. as of December 31, 2004 and 2003, and theresults of their operations and their cash flows for each of the years in thethree-year period ended December 31, 2004, in conformity with U.S. generallyaccepted accounting principles.

 

We have also audited, in accordance with the standardsof the Public Company Accounting Oversight Board (United States), theeffectiveness of TEPPCO Partners, L.P.’s internal control over financialreporting as of December 31, 2004, based on criteria established in *Internal Control – Integrated Framework*issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO), andour report dated February 24, 2005, expressed an unqualified opinion onmanagement’s assessment of, and the effective operation of, internal controlover financial reporting.

 

 
|              | KPMG LLP |
|-------------------|----------|
|              |     |
|              |     |
| Houston, Texas    |     |
| February 24, 2005 |     |

 

F-2

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATEDBALANCE SHEETS**

**(in thousands)**

 
| ** **                                                                                                           | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                                           | ** ** | **2004**         | ** ** | **2003** | ** ** |
| ** **                                                                                                           | ** ** | ** **       | ** ** | ** ** | ** ** |
| **ASSETS**                                                                                                           |       |             |       |   |   |
| Current assets:                                                                                                      |       |             |       |   |   |
| Cash and cash  equivalents                                                                                           |       | $                | 16,422     |   | $ | 29,469 |   |
| Accounts  receivable, trade (net of allowance for doubtful accounts of $112 and $4,700)                              |       | 553,628          |       | 371,938 |   |
| Accounts  receivable, related parties                                                                                |       | 12,921           |       | 3,143 |   |
| Inventories                                                                                                          |       | 19,521           |       | 16,060 |   |
| Other                                                                                                                |       | 42,138           |       | 32,208 |   |
| Total current  assets                                                                                                |       | 644,630          |       | 452,818 |   |
| Property, plant  and equipment, at cost (net of accumulated depreciation and amortization of  $407,670 and $345,357) |       | 1,703,702        |       | 1,619,163 |   |
| Equity  investments                                                                                                  |       | 373,652          |       | 365,286 |   |
| Intangible  assets                                                                                                   |       | 407,358          |       | 438,565 |   |
| Goodwill                                                                                                             |       | 16,944           |       | 16,944 |   |
| Other assets                                                                                                         |       | 51,419           |       | 48,216 |   |
| Total assets                                                                                                         |       | $                | 3,197,705  |   | $ | 2,940,992 |   |
|                                                                                                                 |       |             |       |   |   |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                                           |       |             |       |   |   |
|                                                                                                                 |       |             |       |   |   |
| Current  liabilities:                                                                                                |       |             |       |   |   |
| Accounts payable  and accrued liabilities                                                                            |       | $                | 564,464    |   | $ | 357,852 |   |
| Accounts  payable, related parties                                                                                   |       | 25,730           |       | 21,486 |   |
| Accrued interest                                                                                                     |       | 32,292           |       | 35,111 |   |
| Other accrued  taxes                                                                                                 |       | 13,309           |       | 9,941 |   |
| Other                                                                                                                |       | 46,593           |       | 51,201 |   |
| Total current  liabilities                                                                                           |       | 682,388          |       | 475,591 |   |
| Senior Notes                                                                                                         |       | 1,127,226        |       | 1,129,650 |   |
| Other long-term  debt                                                                                                |       | 353,000          |       | 210,000 |   |
| Other  liabilities and deferred credits                                                                              |       | 13,643           |       | 16,430 |   |
| Commitments and  contingencies                                                                                       |       |             |       |   |   |
| Partners’  capital:                                                                                             |       |             |       |   |   |
| Accumulated  other comprehensive loss                                                                                |       | —           |       | (2,902 | ) |
| General  partner’s interest                                                                                     |       | (33,006          | )          | (7,181 | ) |
| Limited  partners’ interests                                                                                    |       | 1,054,454        |       | 1,119,404 |   |
| Total partners’  capital                                                                                        |       | 1,021,448        |       | 1,109,321 |   |
| Total  liabilities and partners’ capital                                                                        |       | $                | 3,197,705  |   | $ | 2,940,992 |   |

 

Seeaccompanying Notes to Consolidated Financial Statements.

 

F-3

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATED STATEMENTS OF INCOME**

**(in thousands, except per Unit amounts)**

 
| ** **                                                         | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------------------------------|------------|------------------------------|------------|
| ** **                                                         | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                         | ** ** | ** **                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  revenues:                                               |       |                         |       |   |   |   |   |
| Sales of  petroleum products                                       |       | $                            | 5,434,127  |   | $ | 3,766,651 |   | $ | 2,823,800 |   |
| Transportation –  Refined products                            |       | 148,166                      |       | 138,926 |   | 123,476 |   |
| Transportation –  LPGs                                        |       | 87,050                       |       | 91,787 |   | 74,577 |   |
| Transportation –  Crude oil                                   |       | 37,177                       |       | 29,057 |   | 27,414 |   |
| Transportation –  NGLs                                        |       | 41,204                       |       | 39,837 |   | 38,870 |   |
| Gathering –  Natural gas                                      |       | 140,122                      |       | 135,144 |   | 90,053 |   |
| Mont Belvieu  operations                                           |       | —                       |       | — |   | 15,238 |   |
| Other                                                              |       | 70,346                       |       | 54,430 |   | 48,735 |   |
| Total operating  revenues                                          |       | 5,958,192                    |       | 4,255,832 |   | 3,242,163 |   |
|                                                               |       |                         |       |   |   |   |   |
| Costs and  expenses:                                               |       |                         |       |   |   |   |   |
| Purchases of  petroleum products                                   |       | 5,372,971                    |       | 3,711,207 |   | 2,772,328 |   |
| Operating,  general and administrative                             |       | 223,382                      |       | 201,329 |   | 158,753 |   |
| Operating fuel  and power                                          |       | 45,404                       |       | 38,511 |   | 36,814 |   |
| Depreciation and  amortization                                     |       | 112,894                      |       | 100,728 |   | 86,032 |   |
| Taxes – other  than income taxes                              |       | 17,461                       |       | 15,597 |   | 17,989 |   |
| Gains on sales  of assets                                          |       | (1,053                       | )          | (3,948 | ) | — |   |
| Total costs and  expenses                                          |       | 5,771,059                    |       | 4,063,424 |   | 3,071,916 |   |
|                                                               |       |                         |       |   |   |   |   |
| Operating income                                                   |       | 187,133                      |       | 192,408 |   | 170,247 |   |
|                                                               |       |                         |       |   |   |   |   |
| Interest expense  – net                                       |       | (72,053                      | )          | (84,250 | ) | (66,192 | ) |
| Equity earnings                                                    |       | 25,981                       |       | 16,863 |   | 11,980 |   |
| Other income –  net                                           |       | 1,320                        |       | 748 |   | 1,827 |   |
|                                                               |       |                         |       |   |   |   |   |
| Net income                                                         |       | $                            | 142,381    |   | $ | 125,769 |   | $ | 117,862 |   |
|                                                               |       |                         |       |   |   |   |   |
| Net Income  Allocation:                                            |       |                         |       |   |   |   |   |
| Limited Partner  Unitholders                                       |       | $                            | 101,307    |   | $ | 89,191 |   | $ | 81,238 |   |
| Class B  Unitholder                                                |       | —                       |       | 1,806 |   | 6,943 |   |
| General Partner                                                    |       | 41,074                       |       | 34,772 |   | 29,681 |   |
| Total net income  allocated                                        |       | $                            | 142,381    |   | $ | 125,769 |   | $ | 117,862 |   |
|                                                               |       |                         |       |   |   |   |   |
| Basic and  diluted net income per Limited Partner and Class B Unit |       | $                            | 1.61       |   | $ | 1.52 |   | $ | 1.79 |   |
|                                                               |       |                         |       |   |   |   |   |
| Weighted average  Limited Partner and Class B Units outstanding    |       | 62,999                       |       | 59,765 |   | 49,202 |   |

 

Seeaccompanying Notes to Consolidated Financial Statements.

 

F-4

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(in thousands)**

 
| ** **                                                                     | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------|------------|------------------------------|------------|
| ** **                                                                     | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| Cash flows from  operating activities:                                         |       |                         |       |   |   |   |   |
| Net income                                                                     |       | $                            | 142,381    |   | $ | 125,769 |   | $ | 117,862 |   |
| Adjustments to  reconcile net income to cash provided by operating activities: |       |                         |       |   |   |   |   |
| Depreciation and  amortization                                                 |       | 112,894                      |       | 100,728 |   | 86,032 |   |
| Earnings in  equity investments, net of distributions                          |       | 21,232                       |       | 11,140 |   | 18,401 |   |
| Gains on sales of  assets                                                      |       | (1,053                       | )          | (3,948 | ) | — |   |
| Non-cash portion  of interest expense                                          |       | (391                         | )          | 4,793 |   | 4,916 |   |
| Increase in  accounts receivable                                               |       | (181,690                     | )          | (100,085 | ) | (50,313 | ) |
| Decrease  (increase) in inventories                                            |       | (3,461                       | )          | (956 | ) | 2,139 |   |
| Increase in  other current assets                                              |       | (9,926                       | )          | (953 | ) | (16,263 | ) |
| Increase in  accounts payable and accrued expenses                             |       | 186,942                      |       | 95,540 |   | 68,805 |   |
| Other                                                                          |       | (718                         | )          | 7,326 |   | 3,338 |   |
| Net cash  provided by operating activities                                     |       | 266,210                      |       | 239,354 |   | 234,917 |   |
|                                                                           |       |                         |       |   |   |   |   |
| Cash flows from  investing activities:                                         |       |                         |       |   |   |   |   |
| Proceeds from  sales of assets                                                 |       | 1,226                        |       | 8,531 |   | 3,380 |   |
| Proceeds from  cash investments                                                |       | —                       |       | 750 |   | — |   |
| Purchase of  assets                                                            |       | (3,421                       | )          | (27,469 | ) | — |   |
| Purchase of Val  Verde Gathering System                                        |       | —                       |       | — |   | (444,150 | ) |
| Purchase of  Jonah Gas Gathering Company                                       |       | —                       |       | — |   | (7,319 | ) |
| Purchase of  Chaparral NGL System                                              |       | —                       |       | — |   | (132,372 | ) |
| Investment in  Mont Belvieu Storage Partners, L.P.                             |       | (21,358                      | )          | (2,533 | ) | — |   |
| Investment in  Centennial Pipeline LLC                                         |       | (1,500                       | )          | (4,000 | ) | (10,882 | ) |
| Acquisition of  additional interest in Centennial Pipeline LLC                 |       | —                       |       | (20,000 | ) | — |   |
| Capital  expenditures                                                          |       | (164,147                     | )          | (140,517 | ) | (133,372 | ) |
| Net cash used in  investing activities                                         |       | (189,200                     | )          | (185,238 | ) | (724,715 | ) |
|                                                                           |       |                         |       |   |   |   |   |
| Cash flows from  financing activities:                                         |       |                         |       |   |   |   |   |
| Proceeds from  revolving credit facilities                                     |       | 324,200                      |       | 382,000 |   | 675,000 |   |
| Issuance of  Limited Partner Units, net                                        |       | —                       |       | 287,506 |   | 372,506 |   |
| Issuance of  Senior Notes                                                      |       | —                       |       | 198,570 |   | 497,805 |   |
| Proceeds from  termination of interest rate swaps                              |       | —                       |       | — |   | 44,896 |   |
| Repayments on  revolving credit facilities                                     |       | (181,200                     | )          | (604,000 | ) | (943,659 | ) |
| Repurchase and  retirement of Class B Units                                    |       | —                       |       | (113,814) |   | — |   |
| Debt issuance  costs                                                           |       | —                       |       | (3,381 | ) | (7,025 | ) |
| General  Partner’s contributions                                          |       | —                       |       | 2 |   | 7,617 |   |
| Distributions  paid                                                            |       | (233,057                     | )          | (202,498 | ) | (151,853 | ) |
| Net cash (used  in) provided by financing activities                           |       | (90,057                      | )          | (55,615 | ) | 495,287 |   |
| Net increase  (decrease) in cash and cash equivalents                          |       | (13,047                      | )          | (1,499 | ) | 5,489 |   |
| Cash and cash  equivalents at beginning of period                              |       | 29,469                       |       | 30,968 |   | 25,479 |   |
| Cash and cash  equivalents at end of period                                    |       | $                            | 16,422     |   | $ | 29,469 |   | $ | 30,968 |   |
|                                                                           |       |                         |       |   |   |   |   |
| **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)                           |       | $                            | 77,510     |   | $ | 79,930 |   | $ | 48,908 |   |

 

Seeaccompanying Notes to Consolidated Financial Statements.

 

F-5

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL**

**(in thousands, except Unit amounts)**

 
| ** **                                                       | ** ** | **Outstanding  Limited  Partner  Units** | ** ** | **General  Partner’s  Interest** | ** ** | **Limited  Partners’  Interests** | ** ** | **Accumulated  Other  Comprehensive  Loss** | ** ** | **Total** | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------|------------|---------------------------------------|------------|----------------------------------------|------------|---------------------------------------------|------------|-----------|------------|
| Partners’  capital at December 31, 2001                     |       | 40,450,000                               |       | $                                     | 13,190     |                                   | $          | 550,315                                     |       | $         | (20,324    | ) | $ | 543,181 |   |
| Capital  contributions                                           |       | —                                   |       | 7,568                                 |       | —                                 |       | —                                      |       | 7,568     |       |
| Issuance of  Limited Partner Units, net                          |       | 13,260,000                               |       | —                                |       | 370,108                                |       | —                                      |       | 370,108   |       |
| Net income on  cash flow hedge                                   |       | —                                   |       | —                                |       | —                                 |       | 269                                         |       | 269       |       |
| 2002 net income  allocation                                      |       | —                                   |       | 29,681                                |       | 81,238                                 |       | —                                      |       | 110,919   |       |
| 2002 cash  distributions                                         |       | —                                   |       | (37,718                               | )          | (104,932                               | )          | —                                      |       | (142,650  | )          |
| Issuance of  Limited Partners Units upon exercise of options     |       | 99,597                                   |       | 49                                    |       | 2,398                                  |       | —                                      |       | 2,447     |       |
| Partners’  capital at December 31, 2002                     |       | 53,809,597                               |       | 12,770                                |       | 899,127                                |       | (20,055                                     | )          | 891,842   |       |
| Issuance of  Limited Partner Units, net                          |       | 9,101,650                                |       | —                                |       | 285,461                                |       | —                                      |       | 285,461   |       |
| Retirement of  Class B units                                     |       | —                                   |       | —                                |       | (10,993                                | )          | —                                      |       | (10,993   | )          |
| Net income on  cash flow hedge                                   |       | —                                   |       | —                                |       | —                                 |       | 16,164                                      |       | 16,164    |       |
| Reclassification  due to discontinued portion of cash flow hedge |       | —                                   |       | —                                |       | —                                 |       | 989                                         |       | 989       |       |
| 2003 net income  allocation                                      |       | —                                   |       | 34,772                                |       | 89,191                                 |       | —                                      |       | 123,963   |       |
| 2003 cash  distributions                                         |       | —                                   |       | (54,725                               | )          | (145,427                               | )          | —                                      |       | (200,152  | )          |
| Issuance of  Limited Partner Units upon exercise of options      |       | 87,307                                   |       | 2                                     |       | 2,045                                  |       | —                                      |       | 2,047     |       |
| Partners’  capital at December 31, 2003                     |       | 62,998,554                               |       | (7,181                                | )          | 1,119,404                              |       | (2,902                                      | )          | 1,109,321 |       |
| Adjustments to  issuance of Limited Partner Units, net           |       | —                                   |       | —                                |       | (99                                    | )          | —                                      |       | (99       | )          |
| Net income on  cash flow hedge                                   |       | —                                   |       | —                                |       | —                                 |       | 2,902                                       |       | 2,902     |       |
| 2004 net income  allocation                                      |       | —                                   |       | 41,074                                |       | 101,307                                |       | —                                      |       | 142,381   |       |
| 2004 cash  distributions                                         |       | —                                   |       | (66,899                               | )          | (166,158                               | )          | —                                      |       | (233,057  | )          |
|                                                             |       |                                     |       |                                  |       |                                   |       |                                        |       |      |       |
| Partners’  capital at December 31, 2004                     |       | 62,998,554                               |       | $                                     | (33,006    | )                                      | $          | 1,054,454                                   |       | $         | —     |   | $ | 1,021,448 |   |

 

Seeaccompanying Notes to Consolidated Financial Statements.

 

F-6

----

 

**TEPPCO PARTNERS, L.P.**

** **

**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS**

** **

**NOTE 1.     PARTNERSHIP ORGANIZATION**

** **

TEPPCO Partners, L.P. (the “Partnership”), a Delawarelimited partnership, is a master limited partnership formed in March 1990.  We operate through TE Products PipelineCompany, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCOMidstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to asthe “Operating Partnerships.”  TexasEastern Products Pipeline Company, LLC (the “Company” or “General Partner”), aDelaware limited liability company, serves as our general partner and owns a 2%general partner interest in us.  TheGeneral Partner is an indirect wholly owned subsidiary of Duke Energy FieldServices, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”)and ConocoPhillips.  Duke Energy holds aninterest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interestof approximately 30%.  The Company, asgeneral partner, performs all management and operating functions required for us,except for the management and operations of certain of the TEPPCO Midstreamassets that are managed by DEFS on our behalf. We reimburse the General Partner for all reasonable direct and indirectexpenses incurred in managing us.

 

As used in this Report, “we,” “us,” “our,” and the “Partnership”means TEPPCO Partners, L.P. and, where the context requires, includes oursubsidiaries.

 

On July 26, 2001, the Company restructured its generalpartner ownership of the Operating Partnerships to cause them to be indirectlywholly owned by us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeededthe Company as general partner of the Operating Partnerships. All remainingpartner interests in the Operating Partnerships not already owned by us weretransferred to us.  In exchange for thiscontribution, the Company’s interest as our general partner was increased to2%.  The increased percentage is theeconomic equivalent of the aggregate interest that the Company had prior to therestructuring through its combined interests in us and the OperatingPartnerships.  As a result, we hold a99.999% limited partner interest in the Operating Partnerships and TEPPCO GPholds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reportingby the Operating Partnerships when the Operating Partnerships issue guaranteesof our debt.

 

At formation in 1990, we completed an initial publicoffering of 26,500,000 Units representing Limited Partner Interests (“LimitedPartner Units”) at $10.00 per Unit.  Inconnection with our formation, the Company received 2,500,000 Deferred ParticipationInterests (“DPIs”).  Effective April 1,1994, the DPIs began participating in distributions of cash and allocations ofprofit and loss in a manner identical to Limited Partner Units and are treatedas Limited Partner Units for purposes of this Report.  These Limited Partner Units were assigned toDuke Energy when ownership of the Company was transferred from Duke Energy toDEFS in 2000.  Pursuant to our PartnershipAgreement, we have registered the resale by Duke Energy of such Limited PartnerUnits with the Securities and Exchange Commission.  As of December 31, 2004, none of these LimitedPartner Units had been sold by Duke Energy.

 

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

 

F-7

----

 

**NOTE 2.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

** **

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

 

## **Basis of Presentation and Principles of Consolidation**

## ** **

The financial statements include our accounts on aconsolidated basis.  We have eliminatedall significant intercompany items in consolidation.  We have reclassified certain amounts fromprior periods to conform with the current presentation.

 

## **Use of Estimates**

## ** **

The preparation of financial statements in conformitywith generally accepted accounting principles in the United States requires ourmanagement to make estimates and assumptions that affect the reported amountsof assets and liabilities and disclosure of contingent assets and liabilitiesat the date of the financial statements and the reported amounts of revenues andexpenses during the reporting periods. Although we believe these estimates are reasonable, actual results coulddiffer from those estimates.

 

## **Business Segments**

## ** **

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

 

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

 

## **Revenue Recognition**

## ** **

Our Downstream Segment revenues are earned fromtransportation and storage of refined products and LPGs, intrastatetransportation of petrochemicals, sale of product inventory and other ancillaryservices.  Transportation revenues arerecognized as products are delivered to customers.  Storage revenues are recognized upon receiptof products into storage and upon performance of storage services. Terminalingrevenues are recognized as products are out-loaded.  Revenues from the sale of product inventoryare recognized when the products are sold.

 

Our Upstream Segment revenues are earned fromgathering, transportation, marketing and storage of crude oil, and distributionof lubrication oils and specialty chemicals principally in Oklahoma, Texas, NewMexico and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpoverservices, primarily at Cushing, Oklahoma, and Midland, Texas.  Revenues are accrued at the time title to theproduct sold transfers to the purchaser, which typically occurs upon receipt ofthe product by the purchaser, and purchases are accrued at the time title tothe product purchased transfers to our crude oil marketing company, TEPPCOCrude Oil, L.P. (“TCO”), which typically occurs upon our receipt of theproduct.  Revenues related to tradedocumentation and pumpover fees are recognized as services are completed.

 

F-8

----

 

Except for crude oil purchased from time to time asinventory, our policy is to purchase only crude oil for which we have a marketto sell and to structure sales contracts so that crude oil price fluctuationsdo not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil forphysical delivery to third party users or by entering into a future deliveryobligation.  Through these transactions, weseek to maintain a position that is balanced between crude oil purchases andsales and future delivery obligations.  However,certain basis risks (the risk that price relationships between delivery points,classes of products or delivery periods will change) cannot be completelyhedged.

 

Our Midstream Segment revenues are earned from the gatheringof natural gas, fractionation of NGLs and transportation of NGLs.  Gathering and transportation revenues arerecognized as natural gas or NGLs are delivered to customers.  Revenues are also earned from the sale of condensateliquid extracted from the natural gas stream to an Upstream Segment marketingaffiliate.  Fractionation revenues arerecognized ratably over the contract year as products are delivered toDEFS.  We generally do not take title tothe natural gas gathered, NGLs transported or NGLs fractionated, with theexception of inventory imbalances discussed in “Natural Gas Imbalances.”  Therefore, the results of our MidstreamSegment are not directly affected by changes in the prices of natural gas orNGLs.

 

## **Cash and Cash Equivalents**

## ** **

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

 

**Allowance for Doubtful Accounts**

 

We establish provisions for losses on accountsreceivable if we determine that we will not collect all or part of theoutstanding balance.  Collectibility isreviewed 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 doubtfulaccounts for the years ended December 31, 2004, 2003 and 2002 (in thousands):

 
| ** **                      | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------|------------|------------------------------|------------|
| ** **                      | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                      | ** ** | ** **                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Balance at  beginning of period |       | $                            | 4,700      |   | $ | 4,608 |   | $ | 4,422 |   |
| Charges to  expense             |       | 536                          |       | 793 |   | 325 |   |
| Deductions and  other           |       | (5,124                       | )          | (701 | ) | (139 | ) |
| Balance at end  of period       |       | $                            | 112        |   | $ | 4,700 |   | $ | 4,608 |   |

 

## **Inventories**

## ** **

Inventories consist primarily of petroleum productsand crude oil, which are valued at the lower of cost (weighted average costmethod) or market.  Our DownstreamSegment acquires and disposes of various products under exchange agreements.  Receivables and payables arising from thesetransactions are usually satisfied with products rather than cash.  The net balances of exchange receivables andpayables 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 itsacquisition cost.  Additions to property,plant and equipment, including major replacements or betterments, are recordedat cost.  We charge replacements andrenewals of minor items of property that do not materially increase values orextend useful lives to maintenance 

 

F-9

----

 

expense.  Depreciation expense is computed on thestraight-line method using rates based upon expected useful lives of variousclasses of assets (ranging from 2% to 20% per annum).

 

We evaluate impairment of long-lived assets inaccordance 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 impairmentwhenever events or changes in circumstances indicate that the carrying amountof an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used ismeasured by a comparison of the carrying amount of the asset to future net cashflows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to berecognized is measured by the amount by which the carrying amount of the assetsexceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carryingamount or fair value less costs to sell.

 

## **Asset Retirement Obligations**

## ** **

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

 

The Downstream Segment assets consist primarily of aninterstate trunk pipeline system and a series of storage facilities thatoriginate along the upper Texas Gulf Coast and extend through the Midwest andnortheastern United States.  We transportrefined products, LPGs and petrochemicals through the pipeline system.  These products are primarily received in thesouth end of the system and stored and/or transported to various points alongthe system per customer nominations.  TheUpstream Segment’s operations include purchasing crude oil from producers atthe wellhead and providing delivery, storage and other services to itscustomers.  The properties in theUpstream Segment consist of interstate trunk pipelines, pump stations, truckingfacilities, storage tanks and various gathering systems primarily in Texas andOklahoma.  The Midstream Segment gathersnatural gas from wells owned by producers and transports natural gas and NGLson its pipeline systems, primarily in Texas, Wyoming, New Mexico andColorado.  The Midstream Segment alsoowns and operates two NGL fractionator facilities in Colorado.

 

We have completed our assessment of SFAS 143, and wehave determined that we are obligated by contractual or regulatory requirementsto remove certain facilities or perform other remediation upon retirement ofour assets.  However, we are not able toreasonably determine the fair value of the asset retirement obligations for ourtrunk, interstate and gathering pipelines and our surface facilities, sincefuture dismantlement and removal dates are indeterminate.

 

In order to determine a removal date for our gatheringlines and related surface assets, reserve information regarding the productionlife of the specific field is required. As a transporter and gatherer of crude oil and natural gas, we are not aproducer of the field reserves, and we therefore do not have access to adequateforecasts that predict the timing of expected production for existing reserveson those fields in which we gather crude oil and natural gas.  In the absence of such information, we arenot able to make a reasonable estimate of when future dismantlement and removaldates of our gathering assets will occur. With regard to our trunk and interstate pipelines and their relatedsurface assets, it is impossible to predict when demand for transportation ofthe related products will cease.  Ourright-of-way agreements allow us to maintain the right-of-way rather thanremove the pipe.  In addition, we canevaluate our trunk pipelines for alternative uses, which can be and have beenfound.

 

F-10

----

 

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

 

## **Capitalization of Interest**

## ** **

We capitalize interest on borrowed funds related tocapital projects only for periods that activities are in progress to bringthese projects to their intended use. The weighted average rate used tocapitalize interest on borrowed funds was 5.74%, 6.50% and 5.11% for the yearsended December 31, 2004, 2003 and 2002, respectively.  During the years ended December 31, 2004, 2003and 2002, the amount of interest capitalized was $4.2 million, $5.3 million and$4.3 million, respectively.

 

**Intangible Assets**

 

Intangible assets at December 31, 2004, consistprimarily of gathering contracts assumed in the acquisition of Jonah GasGathering System (“Jonah”) on September 30, 2001, and the acquisition of ValVerde Gathering System (“Val Verde”) on June 30, 2002, the fractionationagreement with DEFS and other intangible assets (see Note 3.  Goodwill and Other Intangible Assets).

 

In connection with the acquisitions of Jonah and ValVerde, we assumed contracts that dedicate future production from natural gaswells in the Green River Basin in Wyoming, and we assumed fixed-term contractswith customers that gather coal bed methane (“CBM”) from the San Juan Basin inNew Mexico and Colorado, respectively (see Note 5. Acquisitions andDispositions).  The value assigned to theseintangible assets relates to contracts with customers that are for either afixed term or which dedicate total future lease production to the gatheringsystem.  These intangible assets areamortized on a unit-of-production basis, based upon the actual throughput ofthe system over the expected total throughput for the lives of the contracts.  Revisions to the unit-of-production estimatesmay occur as additional production information is made available to us (seeNote 3.  Goodwill and Other IntangibleAssets).

 

In connection with the purchase of the fractionationfacilities in 1998, we entered into a fractionation agreement with DEFS.  The fractionation agreement is beingamortized over a period of 20 years, which is the term of the agreement withDEFS (see Note 7. Related Party Transactions).

 

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

 

We have $33.4 million of excessinvestment in our equity investment in Centennial Pipeline LLC, which wascreated upon formation of the company. The excess investment is included in our equity investments account.  This excess investment is accounted for as anintangible asset with an indefinite life. We assess the intangible asset for impairment on an annual basis (seeNote 3.  Goodwill and Other IntangibleAssets).

 

**Goodwill**

 

## **Goodwill represents the excess of purchase price over fairvalue of net assets acquired and is presented on the consolidated balancesheets net of accumulated amortization. We account for goodwill under SFAS No. 142, *Goodwill andOther Intangible Assets*, which was issued by the FASB in July 2001(see Note 3.  Goodwill and OtherIntangible Assets).  SFAS 142 prohibitsamortization of goodwill and intangible assets with indefinite useful lives,but instead requires testing for impairment at least annually.  SFAS 142 requires that intangible assets withdefinite useful lives be amortized over their respective estimated usefullives.  Beginning January 1, 2002,effective with the adoption of SFAS 142, we no longer record amortizationexpense related to goodwill or amortization**

 

F-11

----

 

## **expenserelated to the excess investment on our equity investment in Seaway CrudePipeline Company (equity method goodwill).**

 

## **Environmental Expenditures**

## ** **

We accrue for environmental costs that relate toexisting conditions caused by past operations. Environmental costs include initial site surveys and environmentalstudies of potentially contaminated sites, costs for remediation andrestoration of sites determined to be contaminated and ongoing monitoringcosts, as well as damages and other costs, when estimable.  We monitor the balance of accruedundiscounted environmental liabilities on a regular basis.  We record liabilities for environmental costsat a specific site when our liability for such costs is probable and areasonable estimate of the associated costs can be made.  Adjustments to initial estimates arerecorded, from time to time, to reflect changing circumstances and estimatesbased upon additional information developed in subsequent periods.  Estimates of our ultimate liabilitiesassociated with environmental costs are particularly difficult to make withcertainty due to the number of variables involved, including the early stage ofinvestigation at certain sites, the lengthy time frames required to completeremediation alternatives available and the evolving nature of environmentallaws and regulations.

 

The following table presents the activity of ourenvironmental reserve for the years ended December 31, 2004, 2003 and 2002 (inthousands):

 
| ** **                      | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------|------------|------------------------------|------------|
| ** **                      | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                      | ** ** | ** **                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Balance at  beginning of period |       | $                            | 7,639      |   | $ | 7,693 |   | $ | 6,434 |   |
| Charges to  expense             |       | 5,178                        |       | 6,824 |   | 5,785 |   |
| Deductions and  other           |       | (7,780                       | )          | (6,878 | ) | (4,526 | ) |
| Balance at end  of period       |       | $                            | 5,037      |   | $ | 7,639 |   | $ | 7,693 |   |

 

## **Natural Gas Imbalances**

## ** **

Gas imbalances occur when gas producers (customers)deliver more or less actual natural gas gathering volumes to our gatheringsystems than they originally nominated. Actual deliveries are different from nominated volumes due tofluctuations in gas production at the wellhead. If the customers supply more natural gas gathering volumes than theynominated, Val Verde and Jonah record a payable for the amount due to customersand also record a receivable for the same amount due from connecting pipelinetransporters or shippers.  If thecustomers supply less natural gas gathering volumes than they nominated, ValVerde and Jonah record a receivable reflecting the amount due from customersand a payable for the same amount due to connecting pipeline transporters orshippers.  We record natural gasimbalances using a mark-to-market approach.

 

## **Income Taxes**

## ** **

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

 

F-12

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## **Use of Derivatives**

## ** **

We account for derivative financial instruments inaccordance with SFAS No. 133, *Accounting for DerivativeInstruments and Hedging Activities,*and SFAS No. 138, *Accounting for Certain Derivative Instruments and Certain HedgingActivities, an amendment of FASB Statement No. 133. *These statements establishaccounting and reporting standards requiring that derivative instruments(including certain derivative instruments embedded in other contracts) berecorded on the balance sheet at fair value as either assets orliabilities.  The accounting for changesin the fair value of a derivative instrument depends on the intended use of thederivative and the resulting designation, which is established at the inceptionof a derivative.

 

Our derivative instruments consist primarily ofinterest rate swaps and contracts for the purchase and sale of petroleumproducts in connection with our crude oil marketing activities.  Substantially all derivative instrumentsrelated to our crude oil marketing activities meet the normal purchases andsales criteria of SFAS 133, as amended, and as such, changes in the fair valueof petroleum product purchase and sales agreements are reported on the accrualbasis of accounting.  SFAS 133 describesnormal purchases and sales as contracts that provide for the purchase or saleof something other than a financial instrument or derivative instrument thatwill be delivered in quantities expected to be used or sold by the reportingentity over a reasonable period in the normal course of business.

 

For all hedging relationships, we formally document atinception the hedging relationship and its risk-management objective andstrategy for undertaking the hedge, the hedging instrument, the item, thenature of the risk being hedged, how the hedging instrument’s effectiveness inoffsetting the hedged risk will be assessed and a description of the method ofmeasuring ineffectiveness.  This processincludes linking all derivatives that are designated as fair value or cash flowto specific assets and liabilities on the balance sheet or to specific firmcommitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoingbasis, whether the derivatives that are used in hedging transactions are highlyeffective in offsetting changes in fair values or cash flows of hedged items.  If it is determined that a derivative is nothighly effective as a hedge or that it has ceased to be a highly effectivehedge, we discontinue hedge accounting prospectively.

 

For derivative instruments designated as fair valuehedges, gains and losses on the derivative instrument are offset against relatedresults on the hedged item in the statement of income.  Changes in the fair value of a derivativethat is highly effective and that is designated and qualifies as a fair valuehedge, along with the loss or gain on the hedged asset or liability or unrecognizedfirm commitment of the hedged item that is attributable to the hedged risk, arerecorded in earnings.  Changes in thefair value of a derivative that is highly effective and that is designated andqualifies as a cash flow hedge are recorded in other comprehensive income tothe extent that the derivative is effective as a hedge, until earnings areaffected by the variability in cash flows of the designated hedged item. Hedgeeffectiveness is measured at least quarterly based on the relative cumulativechanges in fair value between the derivative contract and the hedged item overtime.  The ineffective portion of thechange in fair value of a derivative instrument that qualifies as either a fairvalue hedge or a cash flow hedge is reported immediately in earnings.

 

According to SFAS 133, as amended, we are required to discontinuehedge accounting prospectively when it is determined that the derivative is nolonger effective in offsetting changes in the fair value or cash flows of thehedged item, the derivative expires or is sold, terminated, or exercised, thederivative is de-designated as a hedging instrument, because it is unlikelythat a forecasted transaction will occur, a hedged firm commitment no longermeets the definition of a firm commitment, or management determines thatdesignation of the derivative as a hedging instrument is no longer appropriate.

 

When hedge accounting is discontinued because it isdetermined that the derivative no longer qualifies as an effective fair valuehedge, we continue to carry the derivative on the balance sheet at its fairvalue and no longer adjust the hedged asset or liability for changes in fairvalue.  The adjustment of the carryingamount of the hedged asset or liability is accounted for in the same manner asother components of the carrying amount of that asset or 

 

F-13

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liability.  When hedge accounting is discontinued becausethe hedged item no longer meets the definition of a firm commitment, wecontinue to carry the derivative on the balance sheet at its fair value, removeany asset or liability that was recorded pursuant to recognition of the firmcommitment from the balance sheet, and recognize any gain or loss inearnings.  When hedge accounting isdiscontinued because it is probable that a forecasted transaction will notoccur, we continue to carry the derivative on the balance sheet at its fairvalue with subsequent changes in fair value included in earnings, and gains andlosses that were accumulated in other comprehensive income are recognizedimmediately in earnings.  In all othersituations in which hedge accounting is discontinued, we continue to carry thederivative at its fair value on the balance sheet and recognize any subsequentchanges in its fair value in earnings.

 

**Fair Value of FinancialInstruments**

 

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

 

**Net Income Per Unit**

 

Basic net income per Unit is computed by dividing netincome, after deduction of the General Partner’s interest, by the weightedaverage number of Units outstanding (a total of 63.0 million Units, 59.8 millionUnits and 49.2 million Units for the years ended December 31, 2004, 2003 and 2002,respectively). The General Partner’s percentage interest in our net income isbased on its percentage of cash distributions from Available Cash for each year(see Note 11. Partner’s Capital and Distributions). The General Partner wasallocated $41.1 million (representing 28.85%) of net income for the year endedDecember 31, 2004, $34.8 million (representing 27.65%) of net income for theyear ended December 31, 2003, and $29.7 million (representing 25.18%) of netincome for the year ended December 31, 2002. The General Partner’s percentage interest in our net income increases ascash distributions paid per Unit increase, in accordance with our Limited PartnershipAgreement.

 

Diluted net income per Unit is similar to thecomputation of basic net income per Unit discussed above, except that thedenominator is increased to include the dilutive effect of outstanding Unitoptions by application of the treasury stock method.  For the years ended December 31, 2003 and 2002,the denominator was increased by 11,878 Units and 32,053 Units, respectively.  For the year ended December 31, 2004, dilutednet income per Unit equaled basic net income per Unit as the denominator wasnot changed because all remaining outstanding Unit options were exercised duringthe third quarter of 2003 (see Note 13. Unit-Based Compensation).

 

## **Unit Option Plan**

## ** **

We have not granted options for any periodspresented.  For options outstanding underthe 1994 Long Term Incentive Plan (see Note 13. Unit-Based Compensation), we followed the intrinsic value method of accountingfor recognizing stock-based compensation expense.  Under this method, we record no compensationexpense for Unit options granted when the exercise price of the options grantedis equal to, or greater than, the market price of our Units on the date of thegrant.  During the year ended December31, 2003, all remaining outstanding Unit options were exercised.

 

In December 2002, SFAS No. 148, *Accountingfor Stock-Based Compensation – Transition and Disclosure* was issued.  SFAS 148 amends SFAS No. 123, *Accounting for Stock-Based Compensation*, and providesalternative methods of transition for a voluntary change to the fair valuebased method of accounting for stock-based employee compensation.  In addition, SFAS 148 amends the disclosurerequirements of SFAS 123 to require prominent disclosure in both annual and interimfinancial statements about the method of accounting for stock-based employeecompensation and the effect of the method used on reported results.  Certain of the disclosure modifications arerequired for fiscal years ending after December 15, 2002, and are included in Note13.  Unit-Based Compensation.

 

F-14

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Assuming we had used the fair value method ofaccounting for our Unit option plan, pro forma net income for the year endedDecember 31, 2002, would be lower than reported net income by an immaterialamount.  Pro forma net income would equalreported net income for the years ended December 31, 2004 and 2003.  Pro forma net income per Unit would equalreported net income per Unit for the periods presented.  The adoption of SFAS 148 did not have aneffect on our financial position, results of operations or cash flows.

 

## **New Accounting Pronouncements**

## ** **

**In December 2003,the FASB revised FASB Interpretation No. 46, *Consolidationof Variable Interest Entities, an interpretation of ARB No. 51* (“FIN46”).  FIN 46, issued by the FASB inJanuary 2003, requires certain variable interest entities to be consolidated bythe primary beneficiary of the entity if the equity investors in the entity donot have the characteristics of a controlling financial interest or do not havesufficient equity at risk for the entity to finance its activities withoutadditional subordinated financial support from other parties.  The revised statement, FASB InterpretationNo. 46(R), *Consolidation of Variable Interest Entities, aninterpretation of ARB No. 51* (“FIN 46(R)”), clarifies some of therequirements of FIN 46, eases some implementation problems that companiesexperienced implementing FIN 46, adds new scope exceptions and makes the probabilitymore likely for many companies that potential variable interest entities willbe identified and consolidated.  Weadopted 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, Seaway Crude PipelineCompany and Mont Belvieu Storage Partners, L.P. and determined that theseentities are not materially affected by our adoption of FIN 46(R), and thus wehave accounted for them as equity method investments (see Note 6. EquityInvestments).  Our adoption of FIN 46(R)did not have an effect on our financial position, results of operations or cashflows.**

** **

**On December 8,2003, President Bush signed into law a bill that expands Medicare, primarilyadding a prescription drug benefit for Medicare-eligible retirees starting in2006.  We anticipate that the benefits wepay 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 notreflect any changes as a result of this legislation.  Deferring the recognition of the new Medicareprovisions’ impact was permitted by FASB Staff Position (“FSP”) Nos. 106-1 and106-2, *Accounting and Disclosure Requirements Related tothe Medicare Prescription Drug, Improvement and Modernization Act of 2003*,due to open questions about some of the new Medicare provisions and a lack ofauthoritative accounting guidance about certain matters.  The final accounting guidance could requirechanges to previously reported information. We adopted the provisions of these FSPs in the quarter ended September30, 2004.  This regulation did not have amaterial adverse effect on our financial position, results of operations orcash flows.**

** **

**In December 2003, the FASB issued a revision SFAS No. 132, *Employers’ Disclosures about Pensions and OtherPost-Retirement Benefits*. This revision required that companies provide more details about theirplan assets, benefit obligations, cash flows, benefit costs and other relevantinformation.  A description of investmentpolicies 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 futurebenefit payments and an estimate of contributions to be made in the next yearto 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 otherpostretirement benefit costs on a quarterly basis.  The guidance is effective for fiscal yearsending after December 15, 2003, and for quarters beginning after December 15,2003.  We adopted the provisions of therevised SFAS 132 effective December 31, 2003, and certain provisions regardingdisclosure of information about estimated future benefit payments in the firstquarter of 2004.**

** **

**In April 2004, the Emerging Issues Task Force (“EITF”) reachedconsensus in EITF 03-06, *ParticipatingSecurities and the Two-Class Method under FASB Statement No. 128*, toclarify what is meant by a participating security as described in SFAS No. 128,*Earnings Per Share. *The consensus also providesguidance on applying the two-class method for computing earnings per share.  The two-class method is an earningsallocation formula for computing earnings per share and is the required methodprescribed by SFAS 128 for companies with participating**

 

F-15

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**securities ormore than one class of common stock.  Theconsensus primarily affects companies that issue securities that are entitledto participate in dividends with common shares and would cause affectedcompanies to report lower earnings per share amounts.  The consensus is to be applied retroactivelyfor periods beginning after March 31, 2004. The adoption of EITF 03-06 did not have an effect on our financialposition, results of operations or cash flows.**

** **

**In July 2004, the EITF reachedconsensus in EITF 02-14, *Whether an InvestorShould Apply the Equity Method of Accounting to Investments Other Than CommonStock*, to clarify whether Accounting Principles Board (“APB”)Opinion No. 18, *The Equity Method ofAccounting for Investments in Common Stock* applies to joint ventureswith ownership not represented by common stock. APB Opinion No. 18 scopes out investments with ownership not representedby common stock.  EITF 02-14 clarifiesthat joint ventures with ownership represented by in-substance common stock, asdefined by EITF 02-14, are subject to the requirements of APB Opinion No.18.  We do not have common stockownership in our three joint ventures, Centennial Pipeline LLC, Seaway CrudePipeline Company and Mont Belvieu Storage Partners, L.P.  We have assessed the impact of EITF 02-14 onthese three joint ventures and have determined that we have in-substance commonstock ownership for all of these ventures. However, similar to other companies with ownership structures in jointventures not represented by common stock, we have historically accounted forthese joint ventures under the guidance of APB Opinion No. 18 due to a lack ofother authoritative guidance.  Theconsensuses in this EITF should be applied in reporting periods beginning afterSeptember 15, 2004.  The adoption of EITF02-14 did not have an effect on our financial position, results of operationsor cash flows.**

** **

**In December 2004, the FASB issuedSFAS No. 123(R), *Share-Based Payment*.  SFAS 123(R) requires compensation costsrelated to share-based payment transactions to be recognized in the financialstatements.  With limited exceptions, theamount of the compensation cost is to be measured based on the grant-date fairvalue of the equity or liability instruments issued.  In addition, liability awards are to be re-measuredeach reporting period.  Compensation costwill be recognized over the period that an employee provides service inexchange for the award. SFAS 123(R) is a revision of SFAS 123, *Accounting for Stock-Based Compensation*, as amended by SFASNo. 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 companiesas of the beginning of the first interim or annual reporting period that beginsafter June 15, 2005.  All publiccompanies that adopted the fair-value-based method of accounting must use themodified prospective transition method and may elect to use the modifiedretrospective transition method.  We donot believe that the adoption of SFAS 123(R) will have a material effect on ourfinancial position, results of operations, or cash flows.**

** **

**NOTE 3.     GOODWILL AND OTHER INTANGIBLE ASSETS**

** **

**Goodwill**

** **

Goodwill represents the excess of purchase price overfair value of net assets acquired and is presented on the consolidated balancesheets net of accumulated amortization. We account for goodwill under SFAS No. 142, *Goodwill andOther Intangible Assets,*which was issued by the FASB in July2001.  SFAS 142 prohibits amortization ofgoodwill and intangible assets with indefinite useful lives, but insteadrequires testing for impairment at least annually.

 

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

 

F-16

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At December 31, 2004 and 2003, we have$16.9 million of unamortized goodwill and $25.5 million of excess investment inour equity investment in Seaway Crude Pipeline Company (equity methodgoodwill).  The excess investment isincluded in our equity investments account at December 31, 2004.  The following table presents the carryingamount of goodwill and equity method goodwill at December 31, 2004 and 2003, bybusiness segment (in thousands):

 
| ** **              | ** ** | **Downstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Upstream  Segment** | ** ** | **Segments  Total** | ** ** |
|-------------------------|------------|-------------------------|------------|------------------------|------------|-----------------------|------------|---------------------|------------|
| Goodwill                |       | $                       | —     |                   | $          | 2,777                 |       | $                   | 14,167     |   | $ | 16,944 |   |
| Equity method  goodwill |       | —                  |       | —                 |       | 25,502                |       | 25,502              |       |
|                         |            |                         |            |                        |            |                       |            |                     |            |  |  |  |  |

 

**Other Intangible Assets**

 

The following table reflects thecomponents of intangible assets being amortized 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:      |       |                       |       |                          |       |   |   |   |   |
| Gathering and  transportation agreements |       | $                          | 464,337    |                          | $          | (91,262 | ) | $ | 464,337 |   | $ | (62,436 | ) |
| Fractionation  agreement                 |       | 38,000                     |       | (12,825                       | )          | 38,000 |   | (10,925 | ) |
| Other                                    |       | 12,262                     |       | (3,154                        | )          | 11,270 |   | (1,681 | ) |
| Total                                    |       | $                          | 514,599    |                          | $          | (107,241 | ) | $ | 513,607 |   | $ | (75,042 | ) |

 

SFAS 142 requires that intangibleassets with finite useful lives be amortized over their respective estimateduseful lives.  If an intangible asset hasa finite useful life, but the precise length of that life is not known, thatintangible asset shall be amortized over the best estimate of its usefullife.  At a minimum, we will assess theuseful lives and residual values of all intangible assets on an annual basis todetermine if adjustments are required. Amortization expense on intangible assets was $32.2 million, $36.2 millionand $27.9 million for the years ended December 31, 2004, 2003 and 2002,respectively.

 

The value assigned to our intangibleassets for natural gas gathering contracts is amortized on a unit-of-productionbasis, based upon the actual throughput of the system over the expected totalthroughput for the lives of the contracts. We update throughput estimates and evaluate the remaining expecteduseful lives of the contract assets on a quarterly basis based on the bestavailable information.  Due to expansionson the gathering systems at Jonah and because of certain limited productionforecasts obtained from some of the producers on the Jonah system related tothe expansions, in the second quarter of 2003 we increased our best estimate offuture throughput on the Jonah system. This increase in the estimate of future throughput extended theamortization period of Jonah’s natural gas gathering contracts by an estimated9 years, increasing from approximately 16 years to approximately 25 years.  During the fourth quarter of 2004, additionallimited production forecasts were obtained from some of the producers on theJonah system related to future expansions of the system, and as a result, weagain increased our best estimate of future throughput on the Jonah system.  This increase in the estimate of futurethroughput extended the amortization period of Jonah’s natural gas gatheringcontracts by an estimated 10 years, increasing from approximately 25 years toapproximately 35 years.  Revisions tothese estimates may occur as additional production information is madeavailable to us.

 

The amortization of the contractsrelated to the Val Verde assets is also amortized on a unit-of-productionbasis.  During the fourth quarter of2004, certain limited production forecasts were obtained from some of the producerson the Val Verde system, and as a result, the amortization period of Val Verde’snatural gas gathering contracts was extended by approximately 10 years, fromapproximately 20 years to approximately 30 years.  Revisions to these estimates may occur asadditional production information is made available to us.

 

F-17

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The values assigned to ourfractionation agreement and other intangible assets are generally amortized ona straight-line basis.  Our fractionationagreement with DEFS is being amortized over its contract period of 20years.  The amortization periods for ourother intangible assets, which include non-compete and other agreements, rangefrom 3 years to 15 years.  In connectionwith the acquisition of crude supply and transportation assets in November2003, we acquired intangible customer contracts for $8.7 million, which arebeing amortized on a unit-of-production basis (see Note 5.  Acquisitions and Dispositions).

 

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

 

The following table sets forth theestimated amortization expense of intangible assets for the years endingDecember 31 (in thousands):

 
| 2005 |   | $      | 29,679 |   |
|------|--------|--------|--------|--------|
| 2006 |   | 31,952 |   |
| 2007 |   | 32,305 |   |
| 2008 |   | 31,144 |   |
| 2009 |   | 29,091 |   |

 

**NOTE 4.     INTEREST RATE SWAPS**

** **

In July 2000, we entered into an interest rate swapagreement to hedge our exposure to increases in the benchmark interest rateunderlying our variable rate revolving credit facility.  This interest rate swap matured in April2004.  We designated this swap agreement,which hedged exposure to variability in expected future cash flows attributedto changes in interest rates, as a cash flow hedge. The swap agreement wasbased on a notional amount of $250.0 million. Under the swap agreement, we paid a fixed rate of interest of 6.955% andreceived a floating rate based on a three-month U.S. Dollar LIBOR rate.  Because this swap was designated as a cashflow hedge, the changes in fair value, to the extent the swap was effective, wererecognized in other comprehensive income until the hedged interest costs wererecognized in earnings.  In June 2003, werepaid the amounts outstanding under our revolving credit facility withborrowings under a new three year revolving credit facility and canceled theold facility (see Note 10.  Debt).  We redesignated this interest rate swap as ahedge of our exposure to increases in the benchmark interest rate underlyingthe new variable rate revolving credit facility.  During the years ended December 31, 2004, 2003and 2002, we recognized increases in interest expense of $2.9 million, $14.4million and $12.9 million, respectively, related to the difference between thefixed rate and the floating rate of interest on the interest rate swap.

 

During 2003, we determined that we would repay aportion of the amount outstanding under the revolving credit facility withproceeds from our Unit offering in August 2003 (see Note 11.  Partners’ Capital and Distributions)resulting in a reduction of probable future interest payments under the creditfacility.  We reduced the outstandingbalance of the revolving credit facility at December 31, 2003, to $210.0million.  During the year ended December31, 2003, we recognized a loss of $1.0 million for the portion of thediscontinued hedge.  The total fair valueof the interest rate swap was a loss of approximately $3.9 million at December31, 2003.  The remaining $2.9 million ofother comprehensive income was transferred to earnings during the period fromJanuary 1, 2004, through the maturity of the interest rate swap in April 2004.

 

In October 2001, TE Products entered into an interestrate swap agreement to hedge its exposure to changes in the fair value of itsfixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as afair value hedge.  The swap agreement hasa notional amount of $210.0 million and matures in January 2028 to match the 

 

F-18

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principal and maturity ofthe TE Products Senior Notes.  Under theswap agreement, TE Products pays a floating rate of interest based on athree-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate ofinterest of 7.51%.  During the yearsended December 31, 2004, 2003 and 2002, we recognized reductions in interestexpense of $9.6 million, $10.0 million and $8.6 million, respectively, relatedto the difference between the fixed rate and the floating rate of interest onthe interest rate swap. During the quarter ended December 31, 2004, we measuredthe hedge effectiveness of this interest rate swap and noted that no gain orloss from ineffectiveness was required to be recognized.  The fair value of this interest rate swap wasa gain of approximately $3.4 million at December 31, 2004, and a gain ofapproximately $2.3 million at December 31, 2003.

 

In February 2002, we entered into interest rate swapagreements, designated as fair value hedges, to hedge our exposure to changesin the fair value of our fixed rate 7.625% Senior Notes due 2012.  The swap agreements had a combined notionalamount of $500.0 million and matured in 2012 to match the principal andmaturity of the Senior Notes.  Under theswap agreements, we paid a floating rate of interest based on a U.S. DollarLIBOR rate, plus a spread, and received a fixed rate of interest of7.625%.  In July 2002, the swapagreements were terminated resulting in a gain of approximately $18.0million.  Concurrent with the swapterminations, we entered into new interest rate swap agreements, with identicalterms as the previous swap agreements; however, the floating rate of interestwas based upon a spread of an additional 50 basis points.  In December 2002, the swap agreements enteredinto in July 2002 were terminated, resulting in a gain of approximately $26.9million.  The gains realized from theJuly 2002 and December 2002 swap terminations have been deferred as adjustmentsto the carrying value of the Senior Notes and are being amortized using theeffective interest method as reductions to future interest expense over theremaining term of the Senior Notes.  AtDecember 31, 2004, the unamortized balance of the deferred gains was $36.6 million.  In the event of early extinguishment of theSenior Notes, any remaining unamortized gains would be recognized in theconsolidated statement of income at the time of extinguishment.

 

**NOTE 5.     ACQUISITIONS AND DISPOSITIONS**

** **

**Jonah Gas Gathering Company**

 

On September 30, 2001, we purchased Jonah from AlbertaEnergy Company for $359.8 million, with an additional payment of $7.3 millionmade on February 4, 2002, for final purchase adjustments related primarily toconstruction projects in progress at the time of closing.  The acquisition served as our entry into thenatural gas gathering industry.  Wefunded the acquisition through a borrowing under a bank credit facility.  We allocated the purchase price, net ofliabilities assumed, primarily to property, plant and equipment and intangibleassets for gas gathering contracts.  Wealso recognized goodwill on the purchase of approximately $2.8 million.  We accounted for the acquisition under thepurchase method of accounting. Accordingly, the results of operations of the acquisition have beenincluded in our consolidated financial statements from September 30, 2001.  Under a contractual agreement, DEFS managesand operates Jonah on our behalf.

 

The following table allocates the estimated fair valueof Jonah assets acquired on September 30, 2001, and includes the additionalpurchase adjustment paid on February 4, 2002 (in thousands):

 
| Property, plant  and equipment                         |   | $       | 141,835 |   |
|--------------------------------------------------------|--------|---------|---------|--------|
| Intangible  assets (primarily gas gathering contracts) |   | 222,800 |    |
| Goodwill                                               |   | 2,777   |    |
| Other                                                  |   | 147     |    |
| Total assets                                           |   | 367,559 |    |
|                                                   |   |    |    |
| Total  liabilities assumed                             |   | (489    | )       |
| Net assets  acquired                                   |   | $       | 367,070 |   |

 

F-19

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The value assigned to intangible assets relates tocontracts with customers that are for either a fixed term or which dedicatetotal future lease production.  We areamortizing the value assigned to intangible assets on a unit-of-productionbasis, based upon the actual throughput of the system over the expected totalthroughput for the contracts (averaging approximately 35 years) (see Note3.  Goodwill and Other Intangible Assets).

 

**Chaparral NGL System**

 

On March 1, 2002, we purchased the Chaparral NGLsystem (“Chaparral”) for $132.4 million from Diamond-Koch II, L.P. andDiamond-Koch III, L.P., including acquisition related costs of approximately$0.4 million.  The Chaparral NGL systemextends from West Texas and New Mexico to Mont Belvieu.  The pipeline delivers NGLs to fractionatorsand to our existing storage facilities in Mont Belvieu.  We funded the purchase through borrowingsunder a bank credit facility.  Weallocated the purchase price to property, plant and equipment, and we accountedfor the acquisition of these assets under the purchase method ofaccounting.  Accordingly, the results ofthe acquisition have been included in our consolidated financial statementsfrom March 1, 2002.  Under a contractualagreement, DEFS manages and operates Chaparral on our behalf.

 

**Val Verde Gas Gathering Company**

 

On June 30, 2002, we purchased Val Verde for $444.2million from Burlington Resources Gathering Inc., a subsidiary of BurlingtonResources Inc., including acquisition related costs of approximately $1.2million.  The Val Verde system gathersCBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico andColorado.  The system is one of thelargest CBM gathering and treating facilities in the United States.  The purchase was primarily funded throughborrowings under bank credit facilities. We allocated the purchase price, net of liabilities assumed, primarilyto property, plant and equipment and intangible assets for gas gatheringcontracts.  We accounted for theacquisition of these assets under the purchase method of accounting.  Accordingly, the results of the acquisition havebeen included in our consolidated financial statements from June 30, 2002.  Under a contractual agreement, DEFS managesand operates Val Verde on our behalf.

 

The following table allocates the estimated fair valueof the Val Verde assets acquired on June 30, 2002 (in thousands):

 
| Property, plant  and equipment                         |   | $       | 205,146 |   |
|--------------------------------------------------------|--------|---------|---------|--------|
| Intangible  assets (primarily gas gathering contracts) |   | 239,649 |    |
| Total assets                                           |   | 444,795 |    |
|                                                   |   |    |    |
| Total  liabilities assumed                             |   | (645    | )       |
| Net assets  acquired                                   |   | $       | 444,150 |   |

 

The value assigned to intangible assets relates tofixed-term contracts with customers.  We areamortizing the value assigned to intangible assets on a unit-of-productionbasis, based upon the actual throughput of the system over the expected totalthroughput for the contracts.  The periodof amortization is expected to be approximately 30 years from the date ofacquisition.

 

The following table presents our unaudited pro formaresults as though the acquisition of Val Verde occurred at the beginning of2002 (in thousands, except per Unit amounts). The unaudited pro forma results give effect to certain pro formaadjustments including depreciation and amortization expense adjustments ofproperty, plant and equipment and intangible assets based upon the purchaseprice allocations, interest expense related to financing the acquisition,amortization expense of debt issue costs and the removal of income tax effectsin historical results of operations.  Thepro forma results do not include operating efficiencies or revenue growth fromhistorical results.

 

F-20

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| ** **                             | ** ** | **Year Ended  December 31, 2002** | ** ** |
|----------------------------------------|------------|-----------------------------------|------------|
| Revenues                               |       | $                                 | 3,279,948  |   |
| Operating income                       |       | 181,717                           |       |
| Net income                             |       | 130,335                           |       |
| Basic and  diluted net income per Unit |       | $                                 | 1.70       |   |

 

The summarized pro forma information has been preparedfor comparative purposes only.  It is notintended to be indicative of the actual operating results that would haveoccurred had the acquisition been consummated at the beginning of 2002, or theresults which may be attained in the future.

 

**Rancho Pipeline**

 

In connection with our acquisition of crude oil assetsin 2000, we acquired an approximate 23.5% undivided joint interest in theRancho Pipeline, which was a crude oil pipeline system from West Texas toHouston, Texas.  In March 2003, theRancho Pipeline ceased operations, and segments of the pipeline were sold tocertain of the owners that previously held undivided interests in thepipeline.  We acquired 241 miles of thepipeline in exchange for cash of $5.5 million and our interests in otherportions of the Rancho Pipeline.  We sold183 miles of the segment we acquired to other entities for cash and assetsvalued at approximately $8.5 million.  Werecorded a net gain of $3.9 million on the transactions in the second quarterof 2003.  During the third quarter of2004, we sold our remaining interest in the original Rancho Pipeline system fora net gain of $0.4 million. These gains are included in the gains on sales ofassets in our consolidated statements of income.

 

**Genesis Pipeline**

 

On November 1, 2003, we  purchased crude supply and transportationassets along the upper Texas Gulf Coast for $21.0 million from Genesis CrudeOil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”).  Thetransaction was funded with proceeds from our August 2003 equity offering (seeNote 11.  Partners’ Capital andDistributions).  We allocated thepurchase price, net of liabilities assumed, primarily to property, plant andequipment and intangible assets.  Theassets acquired included approximately 150 miles of small diameter trunk lines,26,000 barrels per day of throughput and 12,000 barrels per day of leasemarketing and supply business.  We haveintegrated these assets into our South Texas pipeline system, which has allowedus to consolidate gathering and marketing assets in key operating areas in acost effective manner and will provide future growth opportunities.  Accordingly, the results of the acquisitionare included in the consolidated financial statements from November 1, 2003.

 

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

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

 

**NOTE 6.    EQUITY INVESTMENTS**

** **

Through one of our indirect wholly owned subsidiaries,we own a 50% ownership interest in Seaway Crude Pipeline Company (“Seaway”).  The remaining 50% interest is owned byConocoPhillips.  Seaway owns a pipeline 

 

F-21

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that carries mostlyimported crude oil from a marine terminal at Freeport, Texas, to Cushing,Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in theTexas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides forvarying participation ratios throughout the life of the Seaway partnership.  From June 2002 through May 2006, we receive60% of revenue and expense of Seaway. Thereafter, we will receive 40% of revenue and expense of Seaway.  During the years ended December 31, 2004 and2003, we received distributions from Seaway of $36.9 million and $22.7 million,respectively.

 

In August 2000, TE Products entered into agreementswith Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMSEnergy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to formCentennial Pipeline LLC (“Centennial”). Centennial owns an interstate refined petroleum products pipelineextending from the upper Texas Gulf Coast to central Illinois.  Through February 9, 2003, each participantowned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired anadditional 16.7% interest in Centennial from PEPL for $20.0 million each,increasing their ownership percentages in Centennial to 50% each.  During the years ended December 31, 2004 and2003, TE Products invested an additional $1.5 million and $24.0 million,respectively, in Centennial, which is included in the equity investment balanceat December 31, 2004.  The 2003 amountincludes the $20.0 million paid for the acquisition of the additional ownershipinterest in Centennial.  TE Products has not received any distributions fromCentennial since its formation.

 

On January 1, 2003, TE Products and Louis DreyfusEnergy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners,L.P. (“MB Storage”).  TE Products andLouis Dreyfus each own a 50% ownership interest in MB Storage.  The purpose of MB Storage is to expandservices to the upper Texas Gulf Coast energy marketplace by increasingpipeline throughput and the mix of products handled through the existing systemand establishing new receipt and delivery connections.  MB Storage is a service-oriented, fee-basedventure with no commodity trading activity. TE Products operates the facilities for MB Storage.  Effective January 1, 2003, TE Productscontributed property and equipment with a net book value of $67.1 million to MBStorage.  Additionally, as of thecontribution date, Louis Dreyfus had invested $6.1 million for expansionprojects for MB Storage that TE Products was required to reimburse if theoriginal joint development and marketing agreement was terminated by eitherparty.  This deferred liability was alsocontributed and credited to the capital account of Louis Dreyfus in MB Storage.

 

TE Products receives the first $1.8 million perquarter (or $7.15 million on an annual basis) of MB Storage’s income beforedepreciation expense, as defined in the operating agreement.  Any amount of MB Storage’s annual incomebefore depreciation expense in excess of $7.15 million is allocated evenlybetween TE Products and Louis Dreyfus. Depreciation expense on assets each originally contributed to MB Storageis allocated between TE Products and Louis Dreyfus based on the net book valueof the assets contributed.  Depreciationexpense on assets constructed or acquired by MB Storage subsequent to formationis allocated evenly between TE Products and Louis Dreyfus. For the years ended December31, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage wasapproximately 69.4% and 70.4%, respectively. For the years ended December 31, 2004 and 2003, excluding the contributionof property and equipment upon formation of the partnership, TE Products has 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 forcapital expenditures in both periods.  Duringthe years ended December 31, 2004 and 2003, TE Products received distributions of$10.3 million and $5.3 million, respectively, from MB Storage.

 

We use the equity method of accounting to account forour investments in Seaway, Centennial and MB Storage.  Summarized combined financial information forSeaway, Centennial and MB Storage for the years ended December 31, 2004 and 2003,is presented below (in thousands):

 

F-22

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| ** ** | ** ** | **Years Ended  December 31,** | ** ** |
|------------|------------|-------------------------------|------------|
| ** ** | ** ** | **2004**                      | ** ** | **2003** | ** ** |
| Revenues   |       | $                             | 149,843    |   | $ | 125,521 |   |
| Net income |       | 52,059                        |       | 30,034 |   |
|            |            |                               |            |  |  |  |  |

 

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

 
| ** **              | ** ** | **December 31,** | ** ** |
|-------------------------|------------|------------------|------------|
| ** **              | ** ** | **2004**         | ** ** | **2003** | ** ** |
| Current assets          |       | $                | 59,314     |   | $ | 56,243 |   |
| Noncurrent  assets      |       | 633,222          |       | 609,215 |   |
| Current  liabilities    |       | 41,209           |       | 43,177 |   |
| Long-term debt          |       | 140,000          |       | 140,000 |   |
| Noncurrent  liabilities |       | 20,440           |       | 13,182 |   |
| Partners’  capital |       | 490,887          |       | 469,099 |   |
|                         |            |                  |            |  |  |  |  |

 

**NOTE 7.**     RELATED PARTY TRANSACTIONS

** **

## **Duke Energy, DEFS and Affiliates**

## ** **

We have no employees and are managed by the Company, anindirect wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, andConocoPhillips holds the remaining interest of approximately 30%.  According to the Partnership Agreements, theCompany is entitled to reimbursement of all direct and indirect expensesrelated to our business activities (see Note 1. Partnership Organization).

 

For the years ended December 31, 2004, 2003, and 2002,we incurred direct expenses of $83.6 million, $78.0 million and $66.7 million, respectively,which were charged to us by DEFS. Substantially all of these costs were related to payroll and payrollrelated expenses.  For the years endedDecember 31, 2004, 2003, and 2002, expenses for administrative services andoverhead allocated to us by Duke Energy and its affiliates were $1.2 million, $1.1million and $0.8 million, respectively.

 

TCO purchases condensate from DEFS and itsaffiliates.  For the years ended December31, 2004, 2003, and 2002, TCO’s purchases from DEFS and its affiliates were $141.3million, $110.7 million and $80.5 million, respectively.

 

Lubrication Services, L.P. (“LSI”) sells lubricationoils and specialty chemicals to DEFS. For the years ended December 31, 2004, 2003, and 2002, revenuesrecognized by LSI included $16.1 million, $15.2 million and $14.6 million,respectively, for the sale of lubrication oils and specialty chemicals to DEFS.

 

Effective with the purchase of the fractionationfacilities on March 31, 1998, TEPPCO Colorado, LLC (“TEPPCO Colorado”) and DEFSentered into a 20-year Fractionation Agreement, under which TEPPCO Coloradoreceives a variable fee for all fractionated volumes delivered to DEFS.  Revenues recognized from the fractionationfacilities totaled $7.5 million, $7.4 million and $7.4 million for the yearsended December 31, 2004, 2003 and 2002, respectively.  TEPPCO Colorado and DEFS also entered into anOperation and Maintenance Agreement, whereby DEFS operates and maintains thefractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado pays DEFS a set volumetric rate forall fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.9million for each of the years ended December 31, 2004, 2003 and 2002.

 

F-23

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The Dean Pipeline and the Wilcox Pipeline wereincluded with the crude oil assets purchased from DEFS effective November 1,1998.  The southern portion of the DeanPipeline originates in South Texas and transports NGLs for DEFS into itspipeline in Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation totaled $0.2million, $1.0 million and $2.9 million for the years ended December 31, 2004,2003 and 2002, respectively.  The WilcoxPipeline, which is located along the Texas Gulf Coast, transports NGLs for DEFSfrom two of its processing plants and is currently supported by a throughputagreement with DEFS through November 2005. The fees paid to us by DEFS under the agreement were $1.4 million, $1.5million and $1.2 million for the years ended December 31, 2004, 2003 and 2002,respectively.

 

The Panola Pipeline and San Jacinto Pipeline werepurchased on December 31, 2000, from DEFS for $91.7 million.  These pipelines originate at DEFS’ East TexasPlant Complex in Panola County, Texas, and transport NGLs for DEFS and othermajor integrated oil and gas companies.  Revenuesrecognized from an affiliate of DEFS for NGL transportation totaled $11.3million, $9.2 million and $12.0 million for the years ended December 31, 2004,2003 and 2002, respectively.

 

Effective May 2001, we entered into an agreement with anaffiliate of DEFS to commit to it sole utilization of our Providenceterminal.  We operate the terminal andprovide propane loading services to an affiliate of DEFS.  The agreement was renegotiated in May2004.  During the years ended December31, 2004, 2003 and 2002, revenues of $4.3 million, $3.2 million and $2.3million, respectively, from an affiliate of DEFS were recognized pursuant tothis agreement.

 

On September 30, 2001, we purchased Jonah (see Note 5.  Acquisitions and Dispositions).  The Jonah assets are managed and operated byemployees of DEFS under a contractual agreement under which DEFS is reimbursedfor its actual costs.  During the yearsended December 31, 2004, 2003 and 2002, we recognized $4.1 million, $3.7million and $3.3 million, respectively, of expenses related to the operationand management of the Jonah assets by DEFS. Jonah provides gas gathering services to an affiliate of DEFS.  The gathering fees paid to us by an affiliateof DEFS totaled $3.3 million, $2.0 million and $1.2 million for the years endedDecember 31, 2004, 2003 and 2002, respectively. In connection with Jonah’s Pioneer processing plant operations, which wasconstructed during the Phase III expansion and began operating in 2004, Jonah sellsNGLs to, and purchases gas from, an affiliate of DEFS.  For the year ended December 31, 2004, Jonah’ssales to DEFS and its affiliates were $7.1 million, and purchases from DEFS andits affiliates were $5.1 million.  Inaddition, processing fees we received from an affiliate of DEFS for gasprocessing services at the Pioneer plant totaled $0.6 million for the yearended December 31, 2004.

 

On March 1, 2002, we purchased the Chaparral NGLsystem (see Note 5. Acquisitions and Dispositions).  The Chaparral assets are managed and operatedby employees of DEFS under a contractual agreement under which DEFS isreimbursed for its actual costs.  Duringthe years ended December 31, 2004, 2003, and 2002, we recognized $2.3 million, $2.1million and $1.7 million, respectively, of expenses related to the operationand management of the Chaparral assets by DEFS. An affiliate of DEFS transports NGLs on the Chaparral NGL system.  The fees paid to us by an affiliate of DEFSfor NGL transportation on the Chaparral NGL system totaled $3.8 million, $5.5million and $4.5 million for the years ended December 31, 2004, 2003 and 2002,respectively.

 

On June 30, 2002, we purchased Val Verde (see Note 5.  Acquisitions and Dispositions).  The Val Verde assets are managed and operatedby employees of DEFS under a contractual agreement under which DEFS isreimbursed for its actual costs.  Duringthe years ended December 31, 2004, 2003 and 2002, we recognized $3.8 million, $3.0million and $1.2 million, respectively, of expenses related to the operationand management of the Val Verde assets by DEFS.

 

At December 31, 2004 and 2003, we had a receivablefrom DEFS of $10.5 million and $1.8 million, respectively, related to sales andtransportation services provided to DEFS. Included in this receivable balance from DEFS at December 31, 2004, is agas imbalance receivable of $0.9 million. At December 31, 2004 and 2003, we

 

F-24

----

 

had a payable to DEFS of$22.4 million and $15.0 million, respectively, related to direct payroll,payroll related costs, management fees, and other operational related charges,including those for Jonah, Chaparral and Val Verde as described above.  Included in this payable balance at December31, 2004 and 2003, is a gas imbalance payable to DEFS of $3.2 million and $1.5million, respectively.

 

On April 2, 2003, we sold in an underwritten publicoffering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaledapproximately $114.5 million, of which approximately $113.8 million was used torepurchase and retire all of the 3.9 million previously outstanding Class BUnits held by DETTCO (see Note 11. Partners’ Capital and Distributions).

 

We contract with Bison Insurance Company Limited (“Bison”),a wholly owned subsidiary of Duke Energy, for a majority of our insurancecoverage, including property, liability, auto and directors and officersinsurance coverage.  For the years endedDecember 31, 2004, 2003 and 2002, we incurred insurance expense related topremiums paid to Bison of $6.5 million, $5.9 million and $3.8 million,respectively.  At December 31, 2004 and2003, we had insurance reimbursement receivables due from Bison of $5.2 millionand $4.2 million, respectively.

 

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

 

## **Seaway**

## ** **

We own a 50% ownership interest in Seaway, and theremaining 50% interest is owned by ConocoPhillips (see Note 6.  Equity Investments).  We are the operator of Seaway.  During the years ended December 31, 2004, 2003and 2002, we billed Seaway $7.6 million, $7.4 million and $7.1 million,respectively, for direct payroll and payroll related expenses for operatingSeaway.  Additionally, for each of theyears ended December 31, 2004, 2003 and 2002, we billed Seaway $2.1 million forindirect management fees for operating Seaway. At December 31, 2004 and 2003, we had a payable balance to Seaway of $0.5million and $4.0 million, respectively, for advances Seaway paid to us asoperator for operating costs, including payroll and related expenses andmanagement fees.

 

## **Centennial**

## ** **

In August 2000, TE Products entered into agreementswith PEPL and Marathon to form Centennial (see Note 6.  Equity Investments).  At December 31, 2004, TE Products had a 50%ownership interest in Centennial.  TEProducts has entered into a management agreement with Centennial to operateCentennial’s terminal at Creal Springs, Illinois, and pipeline connection inBeaumont, Texas.  For each of the yearsended December 31, 2004, 2003 and 2002, we recognized management fees of $0.2million from Centennial, and actual operating expenses billed to Centennialwere $6.9 million, $4.4 million and $4.0 million, respectively.

 

TE Products also has a joint tariff with Centennial todeliver products at TE Products’ locations using Centennial’s pipeline as partof the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for theentire delivery rate, records only the net rate attributable to it astransportation revenues and records a liability for the amounts due toCentennial for its share of the tariff. At December 31, 2004 and 2003, we had payable balances of $2.8 millionand $2.3 million, respectively, to Centennial for its share of the joint tariffdeliveries and other operational related charges.  In addition, TE Products performs ongoingconstruction services for Centennial and bills Centennial for labor and othercosts to perform the construction.  AtDecember 31, 2004 and 2003, TE Products had receivable balances of $1.1 millionand $1.3 million, respectively, due from Centennial for reimbursement ofconstruction services provided to Centennial.

 

F-25

----

 

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

 

## **MB Storage**

## ** **

Effective January 1, 2003, TE Products entered intoagreements with Louis Dreyfus to form MB Storage (see Note 6.  Equity Investments).  TE Products operates the facilities for MBStorage.  TE Products and MB Storage haveentered into a pipeline capacity lease agreement, and for each of the yearsended December 31, 2004 and 2003, TE Products recognized $0.1 million in rentalrevenue related to this lease agreement. During the years ended December 31, 2004 and 2003, TE Products alsobilled MB Storage $3.2 million and $2.5 million, respectively, for directpayroll and payroll related expenses for operating MB Storage.  At December 31, 2004, TE Products had a netreceivable balance from MB Storage of $1.3 million for operating costs,including payroll and related expenses for operating MB Storage.  At December 31, 2003, TE Products had a netpayable balance to MB Storage of $0.2 million for advances MB Storage paid foroperating costs.

 

**NOTE 8.                INVENTORIES**

** **

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

 
| ** **                                | ** ** | **December 31,** | ** ** |
|-------------------------------------------|------------|------------------|------------|
| ** **                                | ** ** | **2004**         | ** ** | **2003** | ** ** |
| Crude oil                                 |       | $                | 3,690      |   | $ | 1,303 |   |
| Refined products                          |       | 5,665            |       | 6,632 |   |
| LPGs                                      |       | —           |       | 517 |   |
| Lubrication oils  and specialty chemicals |       | 4,002            |       | 3,080 |   |
| Materials and  supplies                   |       | 6,135            |       | 4,528 |   |
| Other                                     |       | 29               |       | — |   |
| Total                                     |       | $                | 19,521     |   | $ | 16,060 |   |

 

**NOTE 9.                PROPERTY, PLANT AND EQUIPMENT**

** **

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

 
| ** **                                      | ** ** | **December 31,** | ** ** |
|-------------------------------------------------|------------|------------------|------------|
| ** **                                      | ** ** | **2004**         | ** ** | **2003** | ** ** |
| Land and right  of way                          |       | $                | 135,984    |   | $ | 130,775 |   |
| Line pipe and  fittings                         |       | 1,344,193        |       | 1,256,393 |   |
| Storage tanks                                   |       | 140,690          |       | 135,938 |   |
| Buildings and  improvements                     |       | 41,205           |       | 35,648 |   |
| Machinery and  equipment                        |       | 333,363          |       | 292,949 |   |
| Construction  work in progress                  |       | 115,937          |       | 112,817 |   |
| Total property,  plant and equipment            |       | $                | 2,111,372  |   | $ | 1,964,520 |   |
| Less accumulated  depreciation and amortization |       | 407,670          |       | 345,357 |   |
| Net property,  plant and equipment              |       | $                | 1,703,702  |   | $ | 1,619,163 |   |

 

F-26

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Depreciation expense on property, plant and equipmentwas $80.7 million, $64.5 million and $56.0 million for the years ended December31, 2004, 2003 and 2002, respectively.  During the fourth quarter of 2004, we wrote offapproximately $2.1 million in assets taken out of service to depreciationexpense.

 

We evaluate impairment of long-livedassets in accordance with SFAS No. 144, *Accounting for theImpairment or Disposal of Long-Lived Assets*.  During the third quarter of 2004, wecompleted an evaluation of our marine terminal facility in the Beaumont, Texas,area.  The facility consists primarily ofa barge dock, a ship dock, four storage tanks and various segments ofconnecting pipelines and is included in our Downstream Segment.  The evaluation indicated that the docks andother assets at the facility needed extensive work to continue to becommercially 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 andamortization expense in our consolidated statements of income, for the excesscarrying value over the fair value of the facility.

 

**NOTE 10.    DEBT**

** **

## **Senior Notes**

## ** **

On January 27, 1998, TE Products completed theissuance 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 (collectivelythe “TE Products Senior Notes”).  The6.45% TE Products Senior Notes were issued at a discount of $0.3 million andare being accreted to their face value over the term of the notes.  The 6.45% TE Products Senior Notes due 2008are not subject to redemption prior to January 15, 2008.  The 7.51% TE Products Senior Notes due 2028,issued at par, may be redeemed at any time after January 15, 2008, at theoption of TE Products, in whole or in part, at a premium.

 

The TE Products Senior Notes do not have sinking fundrequirements.  Interest on the TEProducts Senior Notes is payable semiannually in arrears on January 15 and July15 of each year.  The TE Products SeniorNotes are unsecured obligations of TE Products and rank on a parity with allother unsecured and unsubordinated indebtedness of TE Products.  The indenture governing the TE ProductsSenior Notes contains covenants, including, but not limited to, covenantslimiting the creation of liens securing indebtedness and sale and leasebacktransactions.  However, the indenturedoes not limit our ability to incur additional indebtedness.  As of December 31, 2004, TE Products was incompliance with the covenants of the TE Products Senior Notes.

 

On February 20, 2002, we completed the issuance of$500.0 million principal amount of 7.625% Senior Notes due 2012.  The 7.625% Senior Notes were issued at adiscount of $2.2 million and are being accreted to their face value over theterm of the notes.  The Senior Notes maybe redeemed at any time at our option with the payment of accrued interest anda make-whole premium determined by discounting remaining interest and principalpayments using a discount rate equal to the rate of the United States Treasurysecurities of comparable remaining maturity plus 35 basis points.  The indenture governing our 7.625% SeniorNotes contains covenants, including, but not limited to, covenants limiting thecreation of liens securing indebtedness and sale and leasebacktransactions.  However, the indenturedoes not limit our ability to incur additional indebtedness.  As of December 31, 2004, we were incompliance with the covenants of these Senior Notes.

 

On January 30, 2003, we completed the issuance of$200.0 million principal amount of 6.125% Senior Notes due 2013.  The 6.125% Senior Notes were issued at adiscount of $1.4 million and are being accreted to their face value over theterm of the notes.  We used $182.0million of the proceeds from the offering to reduce the outstanding principalon our $500.0 million revolving credit facility to $250.0 million.  The balance of the net proceeds received wasused for general partnership purposes. The Senior Notes may be redeemed at any time at our option with thepayment of accrued interest and a make-whole premium determined by discountingremaining interest and principal payments using a discount rate equal to therate of the United States Treasury securities of comparable remaining maturityplus 35 basis points.  The indenturegoverning our 6.125% Senior Notes contains covenants, including, but notlimited to, covenants limiting the creation of liens securing indebtedness andsale and 

 

F-27

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leasebacktransactions.  However, the indenturedoes not limit our ability to incur additional indebtedness.  As of December 31, 2004, we were incompliance with the covenants of these Senior Notes.

 

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

 
| ** **                                        | ** ** | ** ** | ** ** | **Fair Value**   | ** ** |
|---------------------------------------------------|------------|------------|------------|------------------|------------|
| ** **                                        | ** ** | **Face**   | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **Value**  | ** ** | **2004**         | ** ** | **2003** | ** ** |
| 6.45% TE  Products Senior Notes, due January 2008 |       | $          | 180.0      |             | $          | 187.1 |   | $ | 190.1 |   |
| 7.625% Senior  Notes, due February 2012           |       | 500.0      |       | 569.6            |       | 566.3 |   |
| 6.125% Senior  Notes, due February 2013           |       | 200.0      |       | 210.2            |       | 206.1 |   |
| 7.51% TE  Products Senior Notes, due January 2028 |       | 210.0      |       | 225.6            |       | 222.4 |   |
|                                                   |            |            |            |                  |            |  |  |  |  |  |

 

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

 

## **Other Long Term Debt and Credit Facilities**

## ** **

On April 6, 2001, we entered into a $500.0 millionrevolving credit facility including the issuance of letters of credit of up to$20.0 million (“Three Year Facility”). The interest rate was based, at our option, on either the lender’s baserate plus a spread, or LIBOR plus a spread in effect at the time of theborrowings.  The credit agreement for theThree Year Facility contained certain restrictive financial covenantratios.  During the first quarter of2003, we repaid $182.0 million of the outstanding balance of the Three YearFacility with proceeds from the issuance of our 6.125% Senior Notes on January30, 2003.  On June 27, 2003, we repaidthe outstanding balance under the Three Year Facility with borrowings under anew credit facility, and canceled the Three Year Facility.

 

On June 27, 2003, we entered into a $550.0 millionrevolving credit facility with a three year term, including the issuance ofletters of credit of up to $20.0 million (“Revolving Credit Facility”).  The interest rate is based, at our option, oneither the lender’s base rate plus a spread, or LIBOR plus a spread in effectat the time of the borrowings.  Thecredit agreement for the Revolving Credit Facility contains certain restrictivefinancial covenant ratios.  We borrowed$263.0 million under the Revolving Credit Facility and repaid the outstandingbalance of the Three Year Facility.  OnOctober 21, 2004, we amended our Revolving Credit Facility to (i) increase thefacility size to $600.0 million, (ii) extend the term to October 21, 2009,(iii) remove certain restrictive covenants, (iv) increase the available amountfor the issuance of letters of credit up to $100.0 million and (v) decrease theLIBOR rate spread charged at the time of each borrowing.  On December 31, 2004, $353.0 million wasoutstanding under the Revolving Credit Facility at a weighted average interestrate of 3.0%.  At December 31, 2004, wewere in compliance with the covenants of this credit agreement.

 

F-28

----

 

The following table summarizes the principal amountsoutstanding under all of our credit facilities as of December 31, 2004 and 2003(in thousands):

 
| ** **                                                         | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                         | ** ** | **2004**         | ** ** | **2003** | ** ** |
| Credit  Facilities:                                                |       |             |       |   |   |
| Revolving Credit  Facility, due October 2009                       |       | $                | 353,000    |   | $ | 210,000 |   |
| 6.45% TE  Products Senior Notes, due January 2008                  |       | 179,906          |       | 179,876 |   |
| 7.625% Senior  Notes, due February 2012                            |       | 498,438          |       | 498,216 |   |
| 6.125% Senior  Notes, due February 2013                            |       | 198,845          |       | 198,702 |   |
| 7.51% TE  Products Senior Notes, due January 2028                  |       | 210,000          |       | 210,000 |   |
| Total borrowings                                                   |       | 1,440,189        |       | 1,296,794 |   |
| Adjustment to  carrying value associated with hedges of fair value |       | 40,037           |       | 42,856 |   |
| Total Credit  Facilities                                           |       | $                | 1,480,226  |   | $ | 1,339,650 |   |

 

**NOTE 11.              PARTNERS’ CAPITAL AND DISTRIBUTIONS**

** **

## **Equity Offerings**

## ** **

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

 

On August 7, 2003, we sold in anunderwritten public offering 5.0 million Units at $34.68 per Unit.  The proceeds from the offering, net ofunderwriting discount, totaled approximately $166.0 million.  On August 19, 2003, 162,900 Units were soldupon exercise of the underwriters’ over-allotment option granted in connectionwith the offering on August 7, 2003. Proceeds from the over-allotment sale, net of underwriting discount,totaled $5.4 million.  Approximately $53.0million of the proceeds were used to repay indebtedness under our revolvingcredit facility and $21.0 million was used to fund the acquisition of the Genesisassets (see Note 5.  Acquisitions andDispositions).  The remaining amount wasused primarily to fund revenue-generating and system upgrade capitalexpenditures and for general partnership purposes.

 

## **Quarterly Distributions of Available Cash**

## ** **

We make quarterly cash distributions of all of ourAvailable Cash, generally defined as consolidated cash receipts lessconsolidated cash disbursements and cash reserves established by the GeneralPartner in its sole discretion.  Pursuantto the Partnership Agreement, the Company receives incremental incentive cashdistributions when cash distributions exceed certain target thresholds asfollows:

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

 

F-29

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The following table reflects the allocation of totaldistributions paid during the years ended December 31, 2004, 2003 and 2002 (inthousands, except per Unit amounts):

 
| ** **                                       | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------------|------------|------------------------------|------------|
| ** **                                       | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| Limited Partner  Units                           |       | $                            | 166,158    |   | $ | 145,427 |   | $ | 104,932 |   |
| General Partner  Ownership Interest              |       | 3,391                        |       | 3,016 |   | 2,329 |   |
| General Partner  Incentive                       |       | 63,508                       |       | 51,709 |   | 35,389 |   |
| Total Partners’  Capital Cash Distributions |       | 233,057                      |       | 200,152 |   | 142,650 |   |
| Class B Units                                    |       | —                       |       | 2,346 |   | 9,203 |   |
| Total Cash  Distributions Paid                   |       | $                            | 233,057    |   | $ | 202,498 |   | $ | 151,853 |   |
| Total Cash  Distributions Paid Per Unit          |       | $                            | 2.64       |   | $ | 2.50 |   | $ | 2.35 |   |

 

On February 7, 2005, we paid a cash distribution of $0.6625per Unit for the quarter ended December 31, 2004.  The fourth quarter 2004 cash distributiontotaled $58.7 million.

 

**General Partner Interest**

 

Asof December 31, 2004 and 2003, we had deficit balances of $33.0 million and$7.2 million, respectively, in our General Partner’s equity account. Thisnegative balance does not represent an asset to us and does not represent anobligation of the General Partner to contribute cash or other property to us.The General Partner’s equity account generally consists of its cumulative shareof our net income less cash distributions made to it plus capital contributionsthat it has made to us (see our Consolidated Statements of Partners’ Capitalfor a detail of the General Partner’s equity account).  For the years ended December 31, 2004 and2003, the General Partner was allocated $41.1 million (representing 28.85%) and$34.8 million (representing 27.65%), respectively, of our net income andreceived $66.9 million and $54.7 million, respectively, in cash distributions.

 

CapitalAccounts, as defined under our Partnership Agreement, are maintained for ourGeneral Partner and our limited partners. The Capital Account provisions of our Partnership Agreement incorporateprinciples established for U.S. federal income tax purposes and are notcomparable to the equity accounts reflected under accounting principlesgenerally accepted in the United States in our financial statements.  Under our Partnership Agreement, the GeneralPartner is required to make additional capital contributions to us upon theissuance of any additional Units if necessary to maintain a Capital Accountbalance equal to 1.999999% of the total Capital Accounts of all partners.  At December 31, 2004 and 2003, the GeneralPartner’s Capital Account balance substantially exceeded this requirement.

 

Netincome is allocated between the General Partner and the limited partners in thesame proportion as aggregate cash distributions made to the General Partner andthe limited partners during the period. This is generally consistent with the manner of allocating net incomeunder our Partnership Agreement.  Netincome determined under our Partnership Agreement, however, incorporatesprinciples established for U.S. federal income tax purposes and is notcomparable to net income reflected under accounting principles generallyaccepted in the United States in our financial statements.

 

Cashdistributions that we make during a period may exceed our net income for theperiod.  We make quarterly cashdistributions of all of our Available Cash, generally defined as consolidatedcash receipts less consolidated cash disbursements and cash reserves establishedby the General Partner in its sole discretion. Cash distributions in excess of net income allocations and capitalcontributions during the years ended December 31, 2004 and 2003, resulted in adeficit in the General Partner’s equity account at December 31, 2004 and 2003.  Future cash distributions that exceed netincome will result in an increase in the deficit balance in the General Partner’sequity account.

 

F-30

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Accordingto the Partnership Agreement, in the event of our dissolution, after satisfyingour liabilities, our remaining assets would be divided among our limitedpartners and the General Partner generally in the same proportion as AvailableCash but calculated on a cumulative basis over the life of the Partnership.  If a deficit balance still remains in theGeneral Partner’s equity account after all allocations are made between thepartners, the General Partner would not be required to make whole any suchdeficit.

 

**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 receivablebalances due from major integrated oil companies, independent oil companies andother pipelines and wholesalers. These concentrations of customers may affect ouroverall credit risk in that the customers may be similarly affected by changesin economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future creditpositions prior to extending credit.  Wemanage our exposure to credit risk through credit analysis, credit approvals,credit limits and monitoring procedures, and for certain transactions mayutilize letters of credit, prepayments and guarantees.

 

For each of the years ended December 31, 2004, 2003and 2002, we had one customer from the Upstream Segment, Valero Energy Corp.,which accounted for 16% of our total consolidated revenues.  No other single customer accounted for 10% ormore of our total consolidated revenues for the years ended December 31, 2004,2003 and 2002.

 

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

 

**NOTE 13.              UNIT-BASED COMPENSATION**

** **

## **1994 Long Term Incentive Plan**

## ** **

During 1994, the Company adopted the Texas EasternProducts Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994LTIP provides certain key employees with an incentive award whereby aparticipant is granted an option to purchase Units.  These same employees are also granted a stipulatednumber of Performance Units, the cash value of which may be used to pay for theexercise of the respective Unit options awarded.  Under the provisions of the 1994 LTIP, nomore than one million options and two million Performance Units may be granted.

 

When our calendar year earnings per unit (exclusive ofcertain special items) exceeds a stated threshold, each participant receives acredit to their respective Performance Unit account equal to the earnings perunit excess multiplied by the number of Performance Units awarded.  The balance in the Performance Unit account maybe used to offset the cost of exercising Unit options granted in connectionwith the Performance Units or may be withdrawn two years after the underlyingoptions expire, usually 10 years from the date of grant.  Any unused balance previously credited isforfeited upon termination.  We accrue compensationexpense for the Performance Units awarded annually based upon the terms of theplan discussed above.

 

Under the agreement for such Unit options, the optionsbecome exercisable in equal installments over periods of one, two, and threeyears from the date of the grant.  AtDecember 31, 2004,  all options have beenfully exercised. The Performance Unit account has a minimal liability balancewhich may be withdrawn by the participants after December 31, 2006.

 

F-31

----

 

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

 
| ** **                        | ** ** | **Options  Outstanding** | ** ** | **Options  Exercisable** | ** ** | **Exercise  Range** | ** ** |
|-----------------------------------|------------|--------------------------|------------|--------------------------|------------|---------------------|------------|
| Unit 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 |       | —                   |       | —                   |       |                |       |

 

We have not granted options for any periodspresented.  During the year endedDecember 31, 2003, all remaining outstanding Unit options were exercised.  For options previously outstanding, we followedthe intrinsic value method for recognizing stock-based compensationexpense.  The exercise price of alloptions awarded under the 1994 LTIP equaled the market price of our Units onthe date of grant.  Accordingly, werecognized no compensation expense at the date of grant.  Had compensation expense been determinedconsistent with SFAS No. 123, *Accounting for Stock-BasedCompensation*, compensation expense related to option grants wouldhave been immaterial for the year ended December 31, 2002, and no compensationexpense would have been recognized for the years ended December 31, 2004 and2003.

 

## **1999 and 2002 Phantom Unit Plans**

## ** **

Effective September 1, 1999, the Company adopted theTexas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999PURP”).  Effective June 1, 2002, the Companyadopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit RetentionPlan (“2002 PURP”). The 1999 PURP and the 2002 PURP provide key employees withincentive awards whereby a participant is granted phantom units.  These phantom units are automatically redeemedfor cash based on the vested portion of the fair market value of the phantomunits at stated redemption dates.  The fairmarket value of each phantom unit is equal to the closing price of a Unit asreported on the New York Stock Exchange on the redemption date.

 

Under the agreement for the phantom units, eachparticipant will vest 10% of the number of phantom units initially grantedunder his or her award at the end of each of the first four years and will vestthe final 60% at the end of the fifth year. Each participant is required to redeem their phantom units as theyvest.   They are also entitled toquarterly cash distributions equal to the product of the number of phantomunits outstanding for the participant and the amount of the cash distributionthat we paid per Unit to unitholders.  Atotal of 1,800 phantom units granted under the 1999 PURP remain outstanding atDecember 31, 2004.  A total of 57,600 phantomunits granted under the 2002 PURP remain outstanding at December 31, 2004.  We accrue compensation expense annually basedupon the terms of the 1999 PURP and 2002 PURP discussed above.  At December 31, 2004 and 2003, we had anaccrued liability balance of $1.6 million and $2.1 million, respectively, forcompensation related to the 1999 PURP and 2002 PURP.

 

## **2000 Long Term Incentive Plan**

## ** **

Effective January 1, 2000, the General Partnerestablished the Texas Eastern Products Pipeline Company, LLC 2000 Long TermIncentive Plan (“2000 LTIP”) to provide key employees incentives to achieveimprovements in our financial performance. Generally, upon the close of a three-year performance period, if theparticipant is then still an employee of the General Partner, the participantwill receive a cash payment in an amount equal to (1) the applicableperformance percentage specified in the award multiplied by (2) the number ofphantom units granted under the award multiplied by (3) the average of theclosing prices of a Unit over the ten consecutive trading days immediatelypreceding the last day of the performance period.  Generally, a participant’s performancepercentage is 

 

F-32

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based upon theimprovement of our Economic Value Added (as defined below) during a three-yearperformance period over the Economic Value Added during the three-year periodimmediately preceding the performance period. If a participant incurs a separation from service during the performanceperiod due to death, disability or retirement (as such terms are defined in the2000 LTIP), the participant will be entitled to receive a cash payment in anamount equal to the amount computed as described above multiplied by afraction, the numerator of which is the number of days that have elapsed duringthe performance period prior to the participant’s separation from service andthe denominator of which is the number of days in the performance period.  At December 31, 2004, phantom unitsoutstanding were 23,600, 30,600 and 21,200 for awards granted for the yearsended December 31, 2004, 2003 and 2002, respectively.

 

Economic Value Added means our average annual EBITDA forthe performance period minus the product of our average asset base and our costof capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDAmeans our earnings before net interest expense, depreciation and amortizationand our proportional interest in EBITDA of our joint ventures as presented inour consolidated financial statements prepared in accordance with generallyaccepted accounting principles, except that in its discretion the CompensationCommittee of the General Partner may exclude gains or losses fromextraordinary, unusual or non-recurring items. For the years ended December 31, 2004 and 2003, EBITDA means, inaddition to the above, earnings before other income – net.  Average asset base means the quarterlyaverage, during the performance period, of our gross value of property, plantand equipment, *plus* products and crude oil operatingoil supply and the gross value of intangibles and equity investments.  Our cost of capital is approved by the CompensationCommittee at the date of award grant.

 

In addition to the payment described above, during theperformance period, the General Partner will pay to the participant the amountof cash distributions that we would have paid to our unitholders had theparticipant been the owner of the number of Units equal to the number ofphantom units granted to the participant under this award.  We accrue compensation expense annually basedupon the terms of the 2000 LTIP discussed above.  At December 31, 2004 and 2003, we had anaccrued liability balance of $2.4 million and $2.9 million, respectively, forcompensation related to the 2000 LTIP.

 

**NOTE 14.              OPERATING LEASES**

** **

We use leased assets in several areas of ouroperations.  Total rental expense for theyears ended December 31, 2004, 2003 and 2002, was $22.1 million, $18.8 millionand $14.2 million, respectively.  Thefollowing table sets forth our minimum rental payments under our variousoperating leases for the years ending December 31 (in thousands):

 
| 2005       |   | $      | 18,178 |   |
|------------|--------|--------|--------|--------|
| 2006       |   | 15,991 |   |
| 2007       |   | 12,698 |   |
| 2008       |   | 7,406  |   |
| 2009       |   | 5,465  |   |
| Thereafter |   | 19,568 |   |
|       |   | $      | 79,306 |   |

 

**NOTE 15.              EMPLOYEE BENEFITS**

** **

## **Retirement Plans**

## ** **

We have adopted the TEPPCO Retirement Cash BalancePlan (“TEPPCO RCBP”), which is a non-contributory, trustee-administered pensionplan.  In addition, certain executiveofficers participate in the TEPPCO 

 

F-33

----

 

Supplemental Benefit Plan(“TEPPCO SBP”), which is a non-contributory, nonqualified, defined benefitretirement plan.  The TEPPCO SBP wasestablished to restore benefit reductions caused by the maximum benefitlimitations that apply to qualified plans. The benefit formula for all eligible employees is a cash balanceformula.  Under a cash balance formula, aplan participant accumulates a retirement benefit based upon pay credits andcurrent interest credits.  The paycredits are based on a participant’s salary, age and service.  We use a December 31 measurement date forthese plans.

 

The components of net pension benefits costs for theTEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2004, 2003 and2002, were as follows (in thousands):

 
| ** **                                     | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost  benefit earned during the year   |       | $        | 3,653      |     | $          | 3,179    |       | $ | 2,925 |   |
| Interest cost on  projected benefit obligation |       | 719      |       | 504      |       | 315      |       |
| Expected return  on plan assets                |       | (878     | )          | (604     | )          | (390     | )          |
| Amortization of  prior service cost            |       | 7        |       | 7        |       | 7        |       |
| Recognized net  actuarial loss                 |       | 57       |       | 24       |       | 12       |       |
| Net pension  benefits costs                    |       | $        | 3,558      |     | $          | 3,110    |       | $ | 2,869 |   |

 

## **Other Postretirement Benefits**

## ** **

Effective January 1, 2001, we provide employees withcertain health care and life insurance benefits for retired employees on acontributory and non-contributory basis (“TEPPCO OPB”).  Employees become eligible for these benefitsif they meet certain age and service requirements at retirement, as defined inthe plans.  We provide a fixed dollarcontribution, which does not increase from year to year, towards retiredemployee medical costs.  The retiree paysall health care cost increases due to medical inflation.  We use a December 31 measurement date forthis plan.

 

The components of net postretirement benefits cost forthe TEPPCO OPB for the years ended December 31, 2004, 2003 and 2002, were asfollows (in thousands):

 
| ** **                                                      | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost  benefit earned during the year                    |       | $        | 165        |     | $          | 137      |       | $ | 115 |   |
| Interest cost on  accumulated postretirement benefit obligation |       | 153      |       | 137      |       | 119      |       |
| Amortization of  prior service cost                             |       | 126      |       | 126      |       | 126      |       |
| Recognized net  actuarial loss                                  |       | 1        |       | —   |       | —   |       |
| Net  postretirement benefits costs                              |       | $        | 445        |     | $          | 400      |       | $ | 360 |   |

 

We employ a building block approach in determining thelong-term rate of return for plan assets. Historical markets are studied and long-term historical relationshipsbetween equities and fixed-income are preserved consistent with a widelyaccepted capital market principle that assets with higher volatility generate agreater return over the long run. Current market factors such as inflation and interest rates areevaluated before long-term capital market assumptions are determined.  The long-term portfolio return is establishedvia a building block approach with proper consideration of diversification andrebalancing.  Peer data and historicalreturns are reviewed to check for reasonability and appropriateness.

 

F-34

----

 

The weighted average assumptions used to determinebenefit obligations for the retirement plans and other postretirement benefitplans 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 netperiodic benefit cost for the retirement plans and other postretirement benefitplans 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 our pension and otherpostretirement benefits changes in benefit obligation, fair value of planassets 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        |       | $                    | 11,256     |                                | $          | 7,578 |   | $ | 2,467 |   | $ | 2,001 |   |
| Service cost                                    |       | 3,653                |       | 3,179                               |       | 165 |   | 137 |   |
| Interest cost                                   |       | 719                  |       | 504                                 |       | 153 |   | 137 |   |
| Actuarial  (gain)/loss                          |       | 572                  |       | 236                                 |       | 205 |   | 209 |   |
| Retiree  contributions                          |       | —               |       | —                              |       | 60 |   | 54 |   |
| Benefits paid                                   |       | (260                 | )          | (241                                | )          | (86 | ) | (71 | ) |
| Benefit  obligation at end of year              |       | $                    | 15,940     |                                | $          | 11,256 |   | $ | 2,964 |   | $ | 2,467 |   |
|                                            |       |                 |       |                                |       |   |   |   |   |
| **Change  in plan assets**                      |       |                 |       |                                |       |   |   |   |   |
| Fair value of  plan assets at beginning of year |       | $                    | 10,921     |                                | $          | 6,820 |   | $ | — |   | $ | — |   |
| Actual return on  plan assets                   |       | 808                  |       | 650                                 |       | — |   | — |   |
| Retiree  contributions                          |       | —               |       | —                              |       | 60 |   | 54 |   |
| Employer  contributions                         |       | 3,500                |       | 3,692                               |       | 26 |   | 17 |   |
| Benefits paid                                   |       | (260                 | )          | (241                                | )          | (86 | ) | (71 | ) |
| Fair value of  plan assets at end of year       |       | $                    | 14,969     |                                | $          | 10,921 |   | $ | — |   | $ | — |   |
|                                            |       |                 |       |                                |       |   |   |   |   |
| **Reconciliation  of funded status**            |       |                 |       |                                |       |   |   |   |   |
| Funded status                                   |       | $                    | (971       | )                                   | $          | (335 | ) | $ | (2,964 | ) | $ | (2,467 | ) |
| Unrecognized  prior service cost                |       | 33                   |       | 40                                  |       | 1,003 |   | 1,129 |   |
| Unrecognized  actuarial loss                    |       | 2,006                |       | 1,421                               |       | 472 |   | 267 |   |
| Net amount  recognized                          |       | $                    | 1,068      |                                | $          | 1,126 |   | $ | (1,489 | ) | $ | (1,071 | ) |

 

F-35

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## **Plan Assets**

## ** **

We employ a total returninvestment approach whereby a mix of equities and fixed income investments areused to maximize the long-term return of plan assets for a prudent level ofrisk.  Risk tolerance is establishedthrough careful consideration of plan liabilities, plan funded status and corporatefinancial condition.  The investmentportfolio contains a diversified blend of equity and fixed-incomeinvestments.  Furthermore, equityinvestments are diversified across U.S. and non-U.S. stocks, both growth and valueequity style, and small, mid and large capitalizations.  Investment risk and return parameters arereviewed and evaluated periodically to ensure compliance with stated investmentobjectives and guidelines.  Thiscomprehensive review incorporates investment portfolio performance, annual liabilitymeasurements and periodic asset/liability studies.

 

The following table setsforth the weighted average asset allocations for the retirement plans and otherpostretirement benefit plans as of December 31, 2004 and 2003, by assetcategory (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 | % |

 

We expect to contribute approximately $3.5 million toour retirement plans and other postretirement benefit plans in 2005.

 

## **Other Plans**

## ** **

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

 

**NOTE 16.              COMMITMENTS AND CONTINGENCIES**

** **

In the fall of 1999 and on December 1, 2000, theGeneral Partner and the Partnership were named as defendants in two separatelawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled *Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas EasternCorporation, et al.*(including the General Partner and Partnership)and*Gilbert Richards and Jean Richards v. TexasEastern Corporation, et al.*(including the General Partner andPartnership).* *Inboth cases, the plaintiffs contend, among other things, that we and otherdefendants stored and disposed of toxic and hazardous substances and hazardouswastes in a manner that caused the materials to be released into the air, soiland water.  They further contend that therelease caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for bothpersonal injury and property damage together with gross negligence, continuingnuisance, trespass, criminal mischief and loss of consortium. The plaintiffsare seeking compensatory, punitive and treble damages.  On January 27, 2005, we entered into Releaseand Settlement Agreements with the McCleery plaintiffs and the Richardsplaintiffs dismissing all of these plaintiffs’ claims.  The settlement terms include a $2.0 millionpayment to the plaintiffs, which has been accrued for in our consolidatedfinancial statements.  The terms of thesettlements did not have a material adverse effect on our financial position,results of operations or cash flows.

 

Although we did not settle with all plantiffs and wetherefore remain named parties in the *Ryan E. McCleery andMarcia S. McCleery, et al. v. Texas Eastern Corporation, et al*.action, a co-defendant has agreed to indemnify us for all remaining claimsasserted against us.  Consequently, we donot believe that the outcome of 

 

F-36

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these remaining claimswill have a material adverse effect on our financial position, results ofoperations or cash flows.

 

On December 21, 2001, TE Products was named as adefendant in a lawsuit in the 10th Judicial District, Natchitoches Parish,Louisiana, styled *Rebecca L. Grisham et al. v.  TE Products Pipeline Company, LimitedPartnership*.  In this case,the plaintiffs contend that our pipeline, which crosses the plaintiffs’property, leaked toxic products onto their property and, consequently causeddamages to them.  We have filed an answerto the plaintiffs’ petition denying the allegations, and we are defendingourselves vigorously against the lawsuit. The plaintiffs have not stipulated the amount of damages they areseeking in the suit; however, this case is covered by insurance.  We do not believe that the outcome of thislawsuit will have a material adverse effect on our financial position, resultsof operations or cash flows.

 

On April 19, 2002, we, through our subsidiary TEPPCOCrude Oil, L.P., filed a declaratory judgment action in the U.S. District Courtfor the Western District of Oklahoma against D.R.D. Environmental Services,Inc. (“D.R.D.”) seeking resolution of billing and other contractual disputesregarding potential overcharges for environmental remediation services providedby D.R.D.  On May 28, 2002, D.R.D. fileda counterclaim for alleged breach of contract in the amount of $2,243,525, andfor unspecified damages for alleged tortious interference with D.R.D.’scontractual relations with DEFS.  On July16, 2003, the parties entered into a Settlement Agreement and Mutual Release,dismissing all claims and counterclaims against each other.  The terms of the Settlement Agreement andMutual Release did not have a material adverse effect on our financialposition, results of operations or cash flows.

 

In May 2003, the General Partner was named as adefendant in a lawsuit styled *John R. James, et al. v. JGraves Insulation Company, et al.* as filed in the first JudicialDistrict Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are allegedto have suffered damages as the result of alleged exposure toasbestos-containing products and materials. According to the petition and as a result of a preliminary investigation,the General Partner believes that the only claim asserted against it resultsfrom one individual for the period from July 1971 through June 1972, who isalleged to have worked on a facility owned by the General Partner’spredecessor.  This period represents asmall portion of the total alleged exposure period from January 1964 throughDecember 2001 for this individual.  Theindividual’s claims involve numerous employers and alleged job sites.  The General Partner has been unable toconfirm involvement by the General Partner or its predecessors with the allegedlocation, and it is uncertain at this time whether this case is covered byinsurance. Discovery is planned, and the General Partner intends to defenditself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they areseeking in this suit.  We are obligatedto reimburse the General Partner for any costs it incurs related to thislawsuit.  We cannot estimate the loss, ifany, associated with this pending lawsuit. We do not believe that the outcome of this lawsuit will have a materialadverse effect on our financial position, results of operations or cash flows.

 

On April 2, 2003, Centennial was served with apetition in a matter styled *Adams, et al. v.Centennial Pipeline Company LLC, et al*.  This matter involves approximately 2,000plaintiffs who allege that over 200 defendants, including Centennial,generated, transported, and/or disposed of hazardous and toxic waste at twosites in Bayou Sorrell, Louisiana, an underground injection well and alandfill.  The plaintiffs allege personalinjuries, allergies, birth defects, cancer and death.  The underground injection well has been inoperation since May 1976.  Based uponcurrent information, Centennial appears to be a *de minimis*contributor, having used the disposal site during the two month time period ofDecember 2001 to January 2002.  Marathonhas been handling this matter for Centennial under its operating agreement withCentennial.  TE Products has a 50%ownership interest in Centennial.  On November30, 2004, the court approved a class settlement.  The time period for parties to appeal thissettlement has not expired, however, and the settlement will not be final untilit does so. If the approved class settlement becomes final, the terms of thesettlement will not have a material adverse effect on our financial position,results of operations or cash flows.

 

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On December 16, 2003, Centennial, the General Partner,the Partnership and other Partnership entities were named as defendants in alawsuit 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 ourpipeline leaked toxic substances on their property, causing them propertydamage.  On October 29, 2004, the partiesentered into a Settlement Agreement, dismissing all claims.  The terms of the settlement did not have amaterial adverse effect on our financial position, results of operations orcash flows.

 

On February 4, 2005, wereceived a letter notifying us of a claim for approximately $1.45 million indamages allegedly due to a shipper being delivered off-specification gasolineduring November 2004.  We are contestingliability for this matter, and to the extent there may be liability, we wouldseek reimbursement from the third party refiner who supplied the gasoline intoour pipeline system. We do not believe that the outcome of this matter willhave a future material adverse effect on our consolidated financial position,results of operations or cash flows.

 

On February 7, 2005, we received a letter from BPAmoco’s counsel placing us on notice of a lawsuit filed by ConocoPhillipsagainst BP Amoco Seaway Products Pipeline Company.  Pursuant to provisions of the Amended andRestated Purchase Agreement dated May 10, 2000, between us and ARCO Pipe LineCompany (BP Amoco), BP Amoco requested indemnity should BP Amoco have anyliability to ConocoPhillips.  Thelitigation arises out of an income tax liability alleged by ConocoPhillips dueto a partnership merger. The plaintiff estimates the income tax liability to be$3,964,788.  We have requestedinformation from BP Amoco that will allow us to assess liability, if any, thatwe may have in this matter.  We do notbelieve that the outcome of this lawsuit will have a future material adverseeffect on our consolidated financial position, results of operations or cashflows.

 

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

 

Our operations are subject to federal, state and locallaws and regulations governing the discharge of materials into the environment.Failure to comply with these laws and regulations may result in the assessmentof administrative, civil and criminal penalties, imposition of injunctionsdelaying or prohibiting certain activities and the need to performinvestigatory and remedial activities. Although we believe our operations are in material compliance withapplicable environmental laws and regulations, risks of significant costs andliabilities are inherent in pipeline operations, and we cannot assure you thatsignificant costs and liabilities will not be incurred. Moreover, it ispossible that other developments, such as increasingly strict environmentallaws and regulations and enforcement policies thereunder, and claims fordamages to property or persons resulting from our operations, could result insubstantial costs and liabilities to us. We believe that changes in environmental laws and regulations will nothave a material adverse effect on our financial position, results of operationsor cash flows in the near term.

 

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 withrespect to finding “changed circumstances” under the Energy Policy Act of 1992(“EP Act”).  The decision largelyclarifies, but does not fully quantify, the standard required for a complainantto demonstrate that an oil pipeline’s rates are no longer subject to the rateprotection of the EP Act by demonstrating that a substantial change incircumstances has occurred since 1992 with respect to the basis of the ratesbeing challenged.  In the decision, theFERC found that a limited number of rate elements will significantly affect theeconomic basis for a pipeline company’s rates. The elements identified in the decision are volume changes, allowedtotal return and total cost-of-service (including major cost elements of ratebase such as tax rates and tax allowances, among others).  The FERC did reject, however, the use ofchanges in tax rate and income tax allowances as standalone factors.  It appears likely that the decision will beappealed.  We have not yet determined theimpact, if any, that the decision, if it is ultimately upheld, would have onour rates if they were reviewed under the criteria of this decision.

 

On July 20, 2004, the Court of Appeals for theDistrict of Columbia Circuit issued an opinion in *BP WestCoast Producers LLC v. FERC*. In reviewing a series of orders involving SFPP, L.P. the court heldamong other things that the FERC had not adequately justified its policy ofproviding an oil pipeline limited partnership with an income tax allowanceequal to the proportion of its limited partnership interests owned by corporatepartners.  Under the FERC’s initialruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-servicefiling for 42.7% of the net operating (pre-tax) income expected from operationsand was denied an income tax allowance equal to 57.3% of its limitedpartnership interests that were held by non-corporate partners.  The court remanded the case back to the FERCfor further review.  As a result of thecourt’s remand, the FERC on December 2, 2004, issued a Request for Commentsseeking comments on whether the court’s ruling applies only to the specificfacts of the SFPP, L.P. proceeding or also extends to other capital structuresinvolving partnerships and other forms of ownership.  The ultimate outcome of the FERC’s inquiry onincome tax allowance should not affect our current rates and rate structurebecause our rates are not based on cost-of-service methodology.  However, the outcome of the income taxallowance would become relevant to us should we (i) elect in the future to usecost-of-service to support our rates, or (ii) be required to use such methodologyto defend our indexed rates.

 

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In 1994, the Louisiana Department of EnvironmentalQuality (“LDEQ”) issued a compliance order for environmental contamination atour Arcadia, Louisiana, facility.  In1999, our Arcadia facility and adjacent terminals were directed by theRemediation Services Division of the LDEQ to pursue remediation of thiscontamination.  At December 31, 2004, wehave an accrued liability of $0.2 million for remediation costs at our Arcadiafacility.  Effective in March 2004, weexecuted an access agreement with an adjacent industrial landowner who islocated upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediationactivities at our Arcadia facility for which it has accepted sharedresponsibility.  We do not expect thatthe completion of the remediation program proposed to the LDEQ will have afuture material adverse effect on our financial position, results of operationsor cash flows.

 

On March 17, 2003, weexperienced a release of 511 barrels of jet fuel from a storage tank at ourBlue Island terminal located in Cook County, Illinois.  As a result of the release, we have enteredinto an Agreed Order with the State of Illinois which required us to conduct anenvironmental investigation.  At thistime, we have complied with the terms of the Agreed Order, and the results ofthe environmental investigation indicated there were no soil or groundwaterimpacts from the release.  We are in theprocess of negotiating a final settlement with the State of Illinois, and wedo not expect that compliance with the settlement will have a future materialadverse effect on our financial position, results of operations or cash flows.

 

On July 22, 2004, weexperienced a release of approximately 12 barrels of jet fuel from a sump atour Lebanon, Ohio, terminal.  Thereleased jet fuel was contained within a storm water retention pond located onthe terminal property.  Six migratorywaterfowl were affected by the jet fuel and were subsequently euthanized by orat the request of the United States Fish and Wildlife Service (“USFWS”).  On October 1, 2004, the USFWS served us witha Notice of Violation, alleging that we violated 16 USC 703 of the MigratoryBird Treaty Act for the “take[ing] of migratory birds by illegal methods.”  On February 7, 2005, we entered into aMemorandum of Understanding with the USFWS, settling all aspects of thismatter.  The terms of this settlement didnot have a material effect on our financial position, results of operations orcash flows.

 

On July 27, 2004, wereceived notice from the United States Department of Justice (“DOJ”) of itsintent 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 diameterpipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, isseeking a civil penalty against us for alleged violations of the Clean WaterAct (“CWA”) arising out of this release. The maximum statutory penalty calculated for this alleged violation ofthe CWA is $2.8 million.  We are indiscussions with the DOJ regarding this matter and have responded to itsrequest for additional information.  Wedo not expect a civil penalty, if any, to have a material adverse effect on ourfinancial position, results of operations or cash flows.

 

At December 31, 2004, we have an accrued liability of$5.0 million, related to various TCTM and TE Products sites requiring environmentalremediation activities.   At December 31,2003, we had an accrued liability of $5.9 million related to various TCTM sitesrequiring environmental remediation activities. Under the terms of a 1998 agreement through which we acquired variouscrude oil assets from DETTCO, we received a five year contractual indemnityobligation for certain environmental liabilities attributable to the operationsof the assets prior to our acquisition. Concurrent with the expiration of this indemnity in 2003, we enteredinto a Settlement Agreement and Release with DETTCO releasing DETTCO fromfuture obligations pertaining to certain environmental liabilities, requiringus to share in certain costs for the remediation of a crude oil site inOklahoma, and the assumption of responsibility by DETTCO for environmentalliabilities associated with three sites located in Texas and Oklahoma.  We do not expect that the completion ofremediation programs associated with TCTM and TE Products activities will havea future material adverse effect on our financial position, results ofoperations or cash flows.

 

Centennial entered into credit facilities totaling$150.0 million, and as of December 31, 2004, $150.0 million was outstandingunder those credit facilities.  Theproceeds were used to fund construction and conversion 

 

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costs of its pipelinesystem.  TE Products and Marathon haveeach guaranteed one-half of Centennial’s debt, up to a maximum amount of $75.0million each.

 

Rates of interstate petroleum products and crude oilpipeline companies, like us, are currently regulated by the FERC primarilythrough an index methodology, which allows a pipeline to change its rates basedon the change from year to year in the Producer Price Index for finished goods(“PPI Index”).  Effective as of February24, 2003, FERC Order on Remand modified the PPI Index from PPI – 1% toPPI.  On April 22, 2003, several shippersfiled a petition in the United States Court of Appeals for the District ofColumbia Circuit (the “Court”), *Flying J. Inc,. Lion OilCompany, Sinclair Oil Corporation and Tesoro Refining and Marketing Company vs.Federal Energy Regulatory Commission*; Docket No. 03-1107, seeking areview of whether the FERC’s adoption of the PPI Index was reasonable andsupported by the evidence.  On April 9,2004, the Court handed down a decision denying the shippers’ petition forreview, stating the shippers failed to establish that any of the FERC’smethodological choices (or combination of choices) were both erroneous andharmful.

 

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

 

Substantially all of the petroleum products that we transportand store are owned by our customers.  AtDecember 31, 2004, TCTM and TE Products had approximately 2.9 million barrelsand 20.8 million barrels, respectively, of products in their custody that wasowned by customers.  We are obligated forthe transportation, storage and delivery of such products on behalf of our customers.  We maintain insurance adequate to coverproduct losses through circumstances beyond our control.

 

We carry insurance coverage consistent with companiesengaged in similar operations with similar type properties.  Our insurance coverage includes (1)commercial general public liability insurance for liabilities to third partiesfor bodily injury and property damage resulting from our operations; (2)workers’ compensation liability coverage to required statutory limits;  (3) automobile liability insurance for allowned, non-owned and hired vehicles covering liabilities to third parties forbodily injury and property damage, and (4) property insurance covering thereplacement value of all real and personal property damage, including damagesarising from earthquake, flood damage and business interruption/extraexpense.  For select assets, we alsocarry pollution liability insurance that provides coverage for historical andgradual pollution events.  All coveragesare subject to certain deductibles, terms and conditions common for companieswith similar types of operations.

 

We also maintain excess liability insurance coverageabove the established primary limits for commercial general liability andautomobile liability insurance.  Limits,terms, conditions and deductibles are comparable to those carried by otherenergy companies of similar size.  Thecost of our general insurance coverages continued to fluctuate over the pastyear reflecting the changing conditions of the insurance markets.  These insurance policies, except for thepollution liability policies, are with Bison Insurance Company Limited, aninsurance company that is wholly owned by Duke Energy (see Note 7.  Related Party Transactions).

 

**NOTE 17.              SEGMENT INFORMATION**

** **

We have three reporting segments:

 

•                  transportation and storage of refinedproducts, LPGs and petrochemicals, which operates as the Downstream Segment;

 

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•                  gathering, transportation, marketingand storage of crude oil and distribution of lubrication oils and specialtychemicals, which operates as the Upstream Segment; and

 

•                  gathering of natural gas,fractionation of NGLs and transportation of NGLs, which operates as theMidstream Segment.

 

The amounts indicated below as “Partnership and Other”relate primarily to intersegment eliminations and assets that we hold that havenot been allocated to any of our reporting segments.

 

Our Downstream Segment revenues are earned fromtransportation and storage of refined products and LPGs, intrastatetransportation of petrochemicals, sale of product inventory and other ancillaryservices. The two largest operating expense items of the Downstream Segment arelabor and electric power.  We generallyrealize higher revenues during the first and fourth quarters of each year sinceour operations are somewhat seasonal. Refined products volumes are generallyhigher during the second and third quarters because of greater demand forgasolines during the spring and summer driving seasons. LPGs volumes are generallyhigher from November through March due to higher demand in the Northeast forpropane, a major fuel for residential heating. Our Downstream Segment also includes the results of operations of thenorthern portion of the Dean Pipeline, which transports, refinery gradepropylene from Mont Belvieu to Point Comfort, Texas.  Our Downstream Segment also includes ourequity investments in Centennial and MB Storage (see Note 6.  Equity Investments).

 

Our Upstream Segment revenues are earned fromgathering, transportation, marketing and storage of crude oil and distributionof lubrication oils and specialty chemicals, principally in Oklahoma, Texas,New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crudeoil along our pipeline systems, or from third party pipeline systems, andarranging the necessary transportation logistics for the ultimate sale of thecrude oil to local refineries, marketers or other end users.  Our Upstream Segment also includes our equityinvestment in Seaway.  Seaway consists oflarge diameter pipelines that transport crude oil from Seaway’s marineterminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distributionpoint for the central United States, and to refineries in the Texas City andHouston areas.

 

Our Midstream Segment revenues are earned from thefractionation of NGLs in Colorado, transportation of NGLs from two trunklineNGL pipelines in South Texas, two NGL pipelines in East Texas and a pipelinesystem (Chaparral) from West Texas and New Mexico to Mont Belvieu; thegathering of natural gas in the Green River Basin in southwestern Wyoming,through Jonah, and the gathering of CBM and conventional natural gas in the SanJuan Basin in New Mexico and Colorado, through Val Verde.  DEFS manages and operates the Val Verde,Jonah and Chaparral assets for us under contractual agreements.  The results of operations of the acquisitionsare included in our consolidated financial statements in periods subsequent totheir respective acquisition dates (see Note 5. Acquisitions and Dispositions).

 

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The tables below include financial information byreporting segment for the years ended December 31, 2004, 2003 and 2002 (inthousands):

 
| ** **                             | ** ** | **Year Ended December 31, 2004** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| ** **                             | ** ** | **Downstream  Segment**          | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
| ** **                             | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Sales of  petroleum products           |       | $                                | —     |   | $ | 5,426,832 |   | $ | 7,295 |   | $ | 5,434,127 |   | $ | — |   | $ | 5,434,127 |   |
| Operating  revenues                    |       | 279,400                          |       | 49,163 |   | 198,709 |   | 527,272 |   | (3,207 | ) | 524,065 |   |
| Purchases of  petroleum products       |       | —                           |       | 5,370,234 |   | 5,944 |   | 5,376,178 |   | (3,207 | ) | 5,372,971 |   |
| Operating  expenses, including power   |       | 165,528                          |       | 60,893 |   | 59,826 |   | 286,247 |   | — |   | 286,247 |   |
| Depreciation and  amortization expense |       | 43,135                           |       | 13,130 |   | 56,629 |   | 112,894 |   | — |   | 112,894 |   |
| Gains on sales  of assets              |       | (526                             | )          | (527 | ) | — |   | (1,053 | ) | — |   | (1,053 | ) |
| Operating income                       |       | 71,263                           |       | 32,265 |   | 83,605 |   | 187,133 |   | — |   | 187,133 |   |
| Equity earnings  (losses)              |       | (3,402                           | )          | 29,383 |   | — |   | 25,981 |   | — |   | 25,981 |   |
| Other income,  net                     |       | 787                              |       | 406 |   | 127 |   | 1,320 |   | — |   | 1,320 |   |
| Earnings before  interest              |       | $                                | 68,648     |   | $ | 62,054 |   | $ | 83,732 |   | $ | 214,434 |   | $ | — |   | $ | 214,434 |   |

 
| ** **                             | ** ** | **Year Ended December 31, 2003** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| ** **                             | ** ** | **Downstream  Segment**          | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
| ** **                             | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Sales of  petroleum products           |       | $                                | —     |   | $ | 3,766,651 |   | $ | — |   | $ | 3,766,651 |   | $ | — |   | $ | 3,766,651 |   |
| Operating  revenues                    |       | 266,427                          |       | 39,564 |   | 185,105 |   | 491,096 |   | (1,915 | ) | 489,181 |   |
| Purchases of  petroleum products       |       | —                           |       | 3,713,122 |   | — |   | 3,713,122 |   | (1,915 | ) | 3,711,207 |   |
| Operating  expenses, including power   |       | 151,103                          |       | 57,314 |   | 47,020 |   | 255,437 |   | — |   | 255,437 |   |
| Depreciation and  amortization expense |       | 31,620                           |       | 11,311 |   | 57,797 |   | 100,728 |   | — |   | 100,728 |   |
| Gain on sale of  assets                |       | —                           |       | (3,948 | ) | — |   | (3,948 | ) | — |   | (3,948 | ) |
| Operating income                       |       | 83,704                           |       | 28,416 |   | 80,288 |   | 192,408 |   | — |   | 192,408 |   |
| Equity earnings  (losses)              |       | (4,086                           | )          | 20,949 |   | — |   | 16,863 |   | — |   | 16,863 |   |
| Other income,  net                     |       | 226                              |       | 306 |   | 289 |   | 821 |   | (73 | ) | 748 |   |
| Earnings before  interest              |       | $                                | 79,844     |   | $ | 49,671 |   | $ | 80,577 |   | $ | 210,092 |   | $ | (73 | ) | $ | 210,019 |   |

 

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| ** **                             | ** ** | **Year Ended December 31, 2002** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| ** **                             | ** ** | **Downstream  Segment**          | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
| ** **                             | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Sales of  petroleum Products           |       | $                                | —     |   | $ | 2,823,800 |   | $ | — |   | $ | 2,823,800 |   | $ | — |   | $ | 2,823,800 |   |
| Operating  revenues                    |       | 243,538                          |       | 37,900 |   | 138,922 |   | 420,360 |   | (1,997 | ) | 418,363 |   |
| Purchases of  petroleum products       |       | —                           |       | 2,774,325 |   | — |   | 2,774,325 |   | (1,997 | ) | 2,772,328 |   |
| Operating  expenses, including power   |       | 130,324                          |       | 49,781 |   | 33,451 |   | 213,556 |   | — |   | 213,556 |   |
| Depreciation and  amortization expense |       | 30,116                           |       | 11,186 |   | 44,730 |   | 86,032 |   | — |   | 86,032 |   |
| Operating income                       |       | 83,098                           |       | 26,408 |   | 60,741 |   | 170,247 |   | — |   | 170,247 |   |
| Equity earnings  (losses)              |       | (6,815                           | )          | 18,795 |   | — |   | 11,980 |   | — |   | 11,980 |   |
| Other income,  net                     |       | 832                              |       | 1,532 |   | 269 |   | 2,633 |   | (806 | ) | 1,827 |   |
| Earnings before  interest              |       | $                                | 77,115     |   | $ | 46,735 |   | $ | 61,010 |   | $ | 184,860 |   | $ | (806 | ) | $ | 184,054 |   |

 

The following table provides the total assets, capitalexpenditures and significant non-cash investing activites for each segment asof and for the years ended December 31, 2004, 2003 and 2002 (in thousands):

 
| ** **                     | ** ** | **Downstream  Segment** | ** ** | **Upstream  Segment** | ** ** | **Midstream  Segment** | ** ** | **Segments  Total** | ** ** | **Partnership  and Other** | ** ** | **Consolidated** | ** ** |
|--------------------------------|------------|-------------------------|------------|-----------------------|------------|------------------------|------------|---------------------|------------|----------------------------|------------|------------------|------------|
| ** **                     | ** ** | ** **              | ** ** | ** **            | ** ** | ** **             | ** ** | ** **          | ** ** | ** **                 | ** ** | ** **       | ** ** |
| December 31,  2004:            |       |                    |       |                  |       |                   |       |                |       |                       |       |             |       |
| Total assets                   |       | $                       | 968,993    |                  | $          | 1,070,477              |       | $                   | 1,184,184  |                       | $          | 3,223,654        |       | $ | (25,949 | ) | $ | 3,197,705 |   |
| Capital  expenditures          |       | 80,930                  |       | 37,448                |       | 45,075                 |       | 163,453             |       | 694                        |       | 164,147          |       |
|                           |       |                    |       |                  |       |                   |       |                |       |                       |       |             |       |
| December 31,  2003:            |       |                    |       |                  |       |                   |       |                |       |                       |       |             |       |
| Total assets                   |       | $                       | 916,917    |                  | $          | 834,502                |       | $                   | 1,194,844  |                       | $          | 2,946,263        |       | $ | (5,271 | ) | $ | 2,940,992 |   |
| Capital expenditures           |       | 59,061                  |       | 13,427                |       | 67,882                 |       | 140,370             |       | 147                        |       | 140,517          |       |
| Non-cash  investing activities |       | 61,042                  |       | —                |       | —                 |       | 61,042              |       | —                     |       | 61,042           |       |
|                           |       |                    |       |                  |       |                   |       |                |       |                       |       |             |       |
| December 31,  2002:            |       |                    |       |                  |       |                   |       |                |       |                       |       |             |       |
| Total assets                   |       | $                       | 881,101    |                  | $          | 724,860                |       | $                   | 1,174,139  |                       | $          | 2,780,100        |       | $ | (11,678 | ) | $ | 2,768,422 |   |
| Capital  expenditures          |       | 60,900                  |       | 10,212                |       | 62,260                 |       | 133,372             |       | —                     |       | 133,372          |       |

 

The following table reconciles the segments totalearnings before interest to consolidated net income for the three years endedDecember 31, 2004, 2003 and 2002 (in thousands):

 
| ** **                   | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------|------------|------------------------------|------------|
| ** **                   | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                   | ** ** | ** **                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Earnings before  interest    |       | $                            | 214,434    |   | $ | 210,019 |   | $ | 184,054 |   |
| Interest expense  – net |       | (72,053                      | )          | (84,250 | ) | (66,192 | ) |
| Net income                   |       | $                            | 142,381    |   | $ | 125,769 |   | $ | 117,862 |   |

 

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**NOTE 18.              COMPREHENSIVE INCOME**

** **

SFAS No. 130, *Reporting ComprehensiveIncome* requires certain items such as foreign currency translationadjustments, minimum pension liability adjustments and unrealized gains andlosses on certain investments to be reported in a financial statement.  As of and for the years ended December 31,2004, 2003 and 2002, the components of comprehensive income were due to theinterest rate swap related to our variable rate revolving credit facility,which was designated as a cash flow hedge. The interest rate swap matured in April 2004.  While the interest rate swap was in effect, changesin the fair value of the cash flow hedge, to the extent the hedge waseffective, were recognized in other comprehensive income until the hedgeinterest costs were recognized in net income. As of December 31, 2004, all other comprehensive income has beenrecognized in net income.

 

The table below reconciles reported net income tototal comprehensive income for the years ended December 31, 2004, 2003 and 2002(in thousands):

 
| ** **                      | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------|------------|------------------------------|------------|
| ** **                      | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net income                      |       | $                            | 142,381    |   | $ | 125,769 |   | $ | 117,862 |   |
| Net income on  cash flow hedges |       | —                       |       | 16,164 |   | 269 |   |
| Total  comprehensive income     |       | $                            | 142,381    |   | $ | 141,933 |   | $ | 118,131 |   |

 

The accumulated balance of other comprehensive lossrelated to our cash flow hedge is as follows (in thousands):

 
| Balance at  December 31, 2001                                    |   | $       | (20,324) |   |
|------------------------------------------------------------------|--------|---------|----------|--------|
| Transferred to  earnings                                         |   | 12,883  |     |
| Change in fair  value of cash flow hedge                         |   | (12,614 | )        |
| Balance at  December 31, 2002                                    |   | $       | (20,055  | )      |
| Reclassification  due to discontinued portion of cash flow hedge |   | 989     |     |
| Transferred to  earnings                                         |   | 14,417  |     |
| Change in fair  value of cash flow hedge                         |   | 1,747   |     |
| Balance at  December 31, 2003                                    |   | $       | (2,902   | )      |
| Transferred to  earnings                                         |   | 2,939   |     |
| Change in fair  value of cash flow hedge                         |   | (37     | )        |
| Balance at  December 31, 2004                                    |   | $       | —   |   |

 

**NOTE 19.              SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIALINFORMATION**

** **

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

 

The following supplemental condensed consolidatingfinancial information reflects our separate accounts, the combined accounts ofthe Guarantor Subsidiaries, the combined accounts of our other non-guarantorsubsidiaries, the combined consolidating adjustments and eliminations and ourconsolidated accounts for the dates

 

F-44

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and periods indicated.  Forpurposes of the following consolidating information, our investments in oursubsidiaries and the Guarantor Subsidiaries’ investments in their subsidiariesare accounted for under the equity method of accounting.

 
| ** **                                    | ** ** | **December 31, 2004**      | ** ** |
|-----------------------------------------------|------------|----------------------------|------------|
| ** **                                    | ** ** | **TEPPCO  Partners, L.P.** | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                                    | ** ** | **(in thousands)**         | ** ** |
| Assets                                        |       |                       |       |   |   |   |   |   |   |   |   |
| Current assets                                |       | $                          | 44,125     |   | $ | 87,068 |   | $ | 576,365 |   | $ | (62,928 | ) | $ | 644,630 |   |
| Property, plant  and equipment – net     |       | —                     |       | 1,211,312 |   | 492,390 |   | — |   | 1,703,702 |   |
| Equity  investments                           |       | 1,021,476                  |       | 430,688 |   | 203,796 |   | (1,282,308 | ) | 373,652 |   |
| Intercompany  notes receivable                |       | 1,084,034                  |       | — |   | — |   | (1,084,034 | ) | — |   |
| Intangible  assets                            |       | —                     |       | 372,621 |   | 34,737 |   | — |   | 407,358 |   |
| Other assets                                  |       | 5,980                      |       | 22,183 |   | 40,200 |   | — |   | 68,363 |   |
| Total assets                                  |       | $                          | 2,155,615  |   | $ | 2,123,872 |   | $ | 1,347,488 |   | $ | (2,429,270 | ) | $ | 3,197,705 |   |
| Liabilities and  partners’ capital       |       |                       |       |   |   |   |   |   |   |   |   |
| Current  liabilities                          |       | $                          | 45,255     |   | $ | 143,589 |   | $ | 556,474 |   | $ | (62,930 | ) | $ | 682,388 |   |
| Long-term debt                                |       | 1,086,909                  |       | 393,317 |   | — |   | — |   | 1,480,226 |   |
| Intercompany  notes payable                   |       | —                     |       | 676,993 |   | 407,040 |   | (1,084,033 | ) | — |   |
| Other long term  liabilities                  |       | 2,003                      |       | 9,980 |   | 1,660 |   | — |   | 13,643 |   |
| Total partners’  capital                 |       | 1,021,448                  |       | 899,993 |   | 382,314 |   | (1,282,307 | ) | 1,021,448 |   |
| Total  liabilities and partners’ capital |       | $                          | 2,155,615  |   | $ | 2,123,872 |   | $ | 1,347,488 |   | $ | (2,429,270 | ) | $ | 3,197,705 |   |

 
| ** **                                    | ** ** | **December 31, 2003**      | ** ** |
|-----------------------------------------------|------------|----------------------------|------------|
| ** **                                    | ** ** | **TEPPCO  Partners, L.P.** | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P Consolidated** | ** ** |
| ** **                                    | ** ** | **(in thousands) **   | ** ** |
| Assets                                        |       |                       |       |   |   |   |   |   |   |   |   |
| Current assets                                |       | $                          | 38,281     |   | $ | 92,817 |   | $ | 360,564 |   | $ | (38,844 | ) | $ | 452,818 |   |
| Property, plant  and equipment – net     |       | —                     |       | 1,146,455 |   | 472,708 |   | — |   | 1,619,163 |   |
| Equity  investments                           |       | 1,112,252                  |       | 404,886 |   | 209,438 |   | (1,361,290 | ) | 365,286 |   |
| Intercompany  notes receivable                |       | 943,447                    |       | — |   | — |   | (943,447 | ) | — |   |
| Intangible  assets                            |       | —                     |       | 401,404 |   | 37,161 |   | — |   | 438,565 |   |
| Other assets                                  |       | 6,157                      |       | 21,444 |   | 37,559 |   | — |   | 65,160 |   |
| Total assets                                  |       | $                          | 2,100,137  |   | $ | 2,067,006 |   | $ | 1,117,430 |   | $ | (2,343,581 | ) | $ | 2,940,992 |   |
| Liabilities and  partners’ capital       |       |                       |       |   |   |   |   |   |   |   |   |
| Current  liabilities                          |       | $                          | 41,895     |   | $ | 105,285 |   | $ | 367,260 |   | $ | (38,849 | ) | $ | 475,591 |   |
| Long-term debt                                |       | 947,486                    |       | 392,164 |   | — |   | — |   | 1,339,650 |   |
| Intercompany  notes payable                   |       | —                     |       | 557,842 |   | 385,604 |   | (943,446 | ) | — |   |
| Other long term  liabilities                  |       | 1,435                      |       | 14,995 |   | — |   | — |   | 16,430 |   |
| Total partners’  capital                 |       | 1,109,321                  |       | 996,720 |   | 364,566 |   | (1,361,286 | ) | 1,109,321 |   |
| Total  liabilities and partners’ capital |       | $                          | 2,100,137  |   | $ | 2,067,006 |   | $ | 1,117,430 |   | $ | (2,343,581 | ) | $ | 2,940,992 |   |

 

F-45

----

 
| ** **                   | ** ** | **Year  Ended December 31, 2004** | ** ** |
|------------------------------|------------|-----------------------------------|------------|
| ** **                   | ** ** | **TEPPCO  Partners, L.P.**        | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
| ** **                   | ** ** | **(in  thousands)**               | ** ** |
| Operating  revenues          |       | $                                 | —     |   | $ | 430,162 |   | $ | 5,531,237 |   | $ | (3,207 | ) | $ | 5,958,192 |   |
| Costs  and expenses          |       | —                            |       | 301,568 |   | 5,473,751 |   | (3,207 | ) | 5,772,112 |   |
| Gains  on sales of assets    |       | —                            |       | (526 | ) | (527 | ) | — |   | (1,053 | ) |
| Operating  income            |       | —                            |       | 129,120 |   | 58,013 |   | — |   | 187,133 |   |
| Interest  expense – net |       | —                            |       | (48,902 | ) | (23,151 | ) | — |   | (72,053 | ) |
| Equity  earnings             |       | 142,381                           |       | 61,287 |   | 29,383 |   | (207,070 | ) | 25,981 |   |
| Other  income – net     |       | —                            |       | 876 |   | 444 |   | — |   | 1,320 |   |
| Net  income                  |       | $                                 | 142,381    |   | $ | 142,381 |   | $ | 64,689 |   | $ | (207,070 | ) | $ | 142,381 |   |

 
| ** **                   |       | **Year  Ended December 31, 2003** |       |
|------------------------------|------------|-----------------------------------|------------|
| ** **                   | ** ** | **TEPPCO  Partners, L.P.**        | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P.  Consolidated** | ** ** |
|                         |       | **(in  thousands)**               |       |
| Operating  revenues          |       | $                                 | —     |   | $ | 399,504 |   | $ | 3,858,243 |   | $ | (1,915 | ) | $ | 4,255,832 |   |
| Costs  and expenses          |       | —                            |       | 262,971 |   | 3,806,316 |   | (1,915 | ) | 4,067,372 |   |
| Gain  on sale of assets      |       | —                            |       | — |   | (3,948 | ) | — |   | (3,948 | ) |
| Operating  income            |       | —                            |       | 136,533 |   | 55,875 |   | — |   | 192,408 |   |
| Interest  expense – net |       | —                            |       | (52,903 | ) | (31,420 | ) | 73 |   | (84,250 | ) |
| Equity  earnings             |       | 125,769                           |       | 41,678 |   | 20,949 |   | (171,533 | ) | 16,863 |   |
| Other  income – net     |       | —                            |       | 461 |   | 360 |   | (73 | ) | 748 |   |
| Net  income                  |       | $                                 | 125,769    |   | $ | 125,769 |   | $ | 45,764 |   | $ | (171,533 | ) | $ | 125,769 |   |

 
|                         |       | **Year  Ended December 31, 2002** |       |
|------------------------------|------------|-----------------------------------|------------|
| ** **                   | ** ** | **TEPPCO  Partners, L.P.**        | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P. Consolidated** |   |
|                         |       | **(in  thousands)**               |       |
| Operating  revenues          |       | $                                 | —     |   | $ | 336,045 |   | $ | 2,908,115 |   | $ | (1,997 | ) | $ | 3,242,163 |   |
| Costs  and expenses          |       | —                            |       | 216,552 |   | 2,857,361 |   | (1,997 | ) | 3,071,916 |   |
| Operating  income            |       | —                            |       | 119,493 |   | 50,754 |   | — |   | 170,247 |   |
| Interest  expense – net |       | —                            |       | (40,651 | ) | (26,347 | ) | 806 |   | (66,192 | ) |
| Equity  earnings             |       | 117,862                           |       | 38,053 |   | 18,795 |   | (162,730 | ) | 11,980 |   |
| Other  income – net     |       | —                            |       | 967 |   | 1,666 |   | (806 | ) | 1,827 |   |
| Net  income                  |       | $                                 | 117,862    |   | $ | 117,862 |   | $ | 44,868 |   | $ | (162,730 | ) | $ | 117,862 |   |

 

F-46

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| ** **                                                                         | ** ** | **Year  Ended December 31, 2004** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                         | ** ** | **TEPPCO  Partners, L .P.**       | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P. Consolidated** | ** ** |
| ** **                                                                         | ** ** | **(in  thousands)**               | ** ** |
| Cash  flows from operating activities                                              |       |                              |       |   |   |   |   |   |   |   |   |
| Net  income                                                                        |       | $                                 | 142,381    |   | $ | 142,381 |   | $ | 64,689 |   | $ | (207,070 | ) | $ | 142,381 |   |
| Adjustments  to reconcile net income to net cash provided by operating activities: |       |                              |       |   |   |   |   |   |   |   |   |
| Depreciation  and amortization                                                     |       | —                            |       | 90,048 |   | 22,846 |   | — |   | 112,894 |   |
| Earnings  in equity investments, net of distributions                              |       | 90,676                            |       | (3,963 | ) | 7,517 |   | (72,998 | ) | 21,232 |   |
| Gains  on sales of assets                                                          |       | —                            |       | (526 | ) | (527 | ) | — |   | (1,053 | ) |
| Changes  in assets and liabilities and other                                       |       | (158,726                          | )          | 29,679 |   | (31,887 | ) | 151,690 |   | (9,244 | ) |
| Net  cash provided by operating activities                                         |       | 74,331                            |       | 257,619 |   | 62,638 |   | (128,378 | ) | 266,210 |   |
| Cash  flows from investing activities                                              |       | 98                                |       | (34,060 | ) | (39,907 | ) | (115,331 | ) | (189,200 | ) |
| Cash  flows from financing activities                                              |       | (90,057                           | )          | (229,206 | ) | (25,575 | ) | 254,781 |   | (90,057 | ) |
| Net  decrease in cash and cash equivalents                                         |       | (15,628                           | )          | (5,647 | ) | (2,844 | ) | 11,072 |   | (13,047 | ) |
| Cash  and cash equivalents at beginning of period                                  |       | 19,744                            |       | 19,243 |   | 5,670 |   | (15,188 | ) | 29,469 |   |
| Cash  and cash equivalents at end of period                                        |       | $                                 | 4,116      |   | $ | 13,596 |   | $ | 2,826 |   | $ | (4,116 | ) | $ | 16,422 |   |

 
| ** **                                                                         | ** ** | **Year  Ended December 31, 2003** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                         | ** ** | **TEPPCO  Partners, L .P.**       | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P. Consolidated** | ** ** |
| ** **                                                                         | ** ** | **(in  thousands)**               | ** ** |
| Cash  flows from operating activities                                              |       |                              |       |   |   |   |   |   |   |   |   |
| Net  income                                                                        |       | $                                 | 125,769    |   | $ | 125,769 |   | $ | 45,764 |   | $ | (171,533 | ) | $ | 125,769 |   |
| Adjustments  to reconcile net income to net cash provided by operating activities: |       |                              |       |   |   |   |   |   |   |   |   |
| Depreciation  and amortization                                                     |       | —                            |       | 80,114 |   | 20,614 |   | — |   | 100,728 |   |
| Earnings  in equity investments, net of distributions                              |       | 76,729                            |       | 3,559 |   | 1,791 |   | (70,939 | ) | 11,140 |   |
| Gain  on sale of assets                                                            |       | —                            |       | — |   | (3,948 | ) | — |   | (3,948 | ) |
| Changes  in assets and liabilities and other                                       |       | 48,432                            |       | 5,576 |   | (1,995 | ) | (46,348 | ) | 5,665 |   |
| Net  cash provided by operating activities                                         |       | 250,930                           |       | 215,018 |   | 62,226 |   | (288,820 | ) | 239,354 |   |
| Cash  flows from investing activities                                              |       | (175,568                          | )          | (178,682 | ) | (34,519 | ) | 203,531 |   | (185,238 | ) |
| Cash  flows from financing activities                                              |       | (55,618                           | )          | (25,340 | ) | (44,758 | ) | 70,101 |   | (55,615 | ) |
| Net  increase (decrease) in cash and cash equivalents                              |       | 19,744                            |       | 10,996 |   | (17,051 | ) | (15,188 | ) | (1,499 | ) |
| Cash  and cash equivalents at beginning of period                                  |       | —                            |       | 8,247 |   | 22,721 |   | — |   | 30,968 |   |
| Cash  and cash equivalents at end of period                                        |       | $                                 | 19,744     |   | $ | 19,243 |   | $ | 5,670 |   | $ | (15,188 | ) | $ | 29,469 |   |

 

F-47

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|                                                                                          |       | **Year  Ended December 31, 2002** |       |
|-----------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                    | ** ** | **TEPPCO  Partners, L .P.**       | ** ** | **Guarantor  Subsidiaries** | ** ** | **Non-Guarantor  Subsidiaries** | ** ** | **Consolidating  Adjustments** | ** ** | **TEPPCO  Partners, L.P. Consolidated** |   |
|                                                                                          |       | **(in  thousands)**               |       |
| Cash  flows from operating activities                                                         |       |                              |       |   |   |   |   |   |   |   |   |
| Net  income                                                                                   |       | $                                 | 117,862    |   | $ | 117,862 |   | $ | 44,868 |   | $ | (162,730 | ) | $ | 117,862 |   |
| Adjustments  to reconcile net income to net cash provided by (used in) operating  activities: |       |                              |       |   |   |   |   |   |   |   |   |
| Depreciation  and amortization                                                                |       | —                            |       | 66,175 |   | 19,857 |   | — |   | 86,032 |   |
| Earnings  in equity investments, net of distributions                                         |       | 33,994                            |       | 18,879 |   | 11,586 |   | (46,058 | ) | 18,401 |   |
| Changes  in assets and liabilities and other                                                  |       | (269,102                          | )          | 48,638 |   | 40,254 |   | 192,832 |   | 12,622 |   |
| Net  cash provided by (used in) operating activities                                          |       | (117,246                          | )          | 251,554 |   | 116,565 |   | (15,956 | ) | 234,917 |   |
| Cash  flows from investing activities                                                         |       | (378,039                          | )          | (1,150,967 | ) | (253,879 | ) | 1,058,170 |   | (724,715 | ) |
| Cash  flows from financing activities                                                         |       | 495,285                           |       | 904,006 |   | 138,210 |   | (1,042,214 | ) | 495,287 |   |
| Net  increase in cash and cash equivalents                                                    |       | —                            |       | 4,593 |   | 896 |   | — |   | 5,489 |   |
| Cash  and cash equivalents at beginning of period                                             |       | —                            |       | 3,654 |   | 21,825 |   | — |   | 25,479 |   |
| Cash  and cash equivalents at end of period                                                   |       | $                                 | —     |   | $ | 8,247 |   | $ | 22,721 |   | $ | — |   | $ | 30,968 |   |

** **

**NOTE 20.              QUARTERLY FINANCIAL INFORMATION (UNAUDITED)**

 
| ** **                                                            | ** ** | **First  Quarter**                          | ** ** | **Second  Quarter** | ** ** | **Third  Quarter** | ** ** | **Fourth  Quarter** | ** ** |
|-----------------------------------------------------------------------|------------|---------------------------------------------|------------|---------------------|------------|--------------------|------------|---------------------|------------|
| ** **                                                            | ** ** | **(in thousands, except per Unit amounts)** | ** ** |
| **2004**                                                              |       |                                        |       |                |       |               |       |                |       |
| Operating  revenues                                                   |       | $                                           | 1,318,061  |                | $          | 1,354,564          |       | $                   | 1,490,010  |   | $ | 1,795,557 |   |
| Operating income                                                      |       | 53,901                                      |       | 42,401              |       | 37,081             |       | 53,750              |       |
| Net income                                                            |       | 40,433                                      |       | 37,759              |       | 25,855             |       | 38,334              |       |
| Basic and  diluted income per Limited Partner and Class B Unit        |       | $                                           | 0.46       |                | $          | 0.43               |       | $                   | 0.29       |   | $ | 0.43 |   |
|                                                                  |       |                                        |       |                |       |               |       |                |       |
| **2003**                                                              |       |                                        |       |                |       |               |       |                |       |
| Operating  revenues                                                   |       | $                                           | 1,099,239  |                | $          | 1,040,800          |       | $                   | 1,066,889  |   | $ | 1,048,904 |   |
| Operating income                                                      |       | 51,342                                      |       | 47,986              |       | 45,265             |       | 47,815              |       |
| Net income                                                            |       | 33,925                                      |       | 33,944              |       | 30,491             |       | 27,409              |       |
| Basic and  diluted income per Limited Partner and Class B Unit (1)(2) |       | $                                           | 0.43       |                | $          | 0.43               |       | $                   | 0.36       |   | $ | 0.31 |   |

 

----

(1)          The sum of the fourquarters does not equal the total year due to rounding.

 

(2)   Per Unit calculation includes 3,938,750 Unitsissued in April 2003, 3,916,547 Units repurchased and retired in April 2003,5,162,900 Units issued in August 2003, and 87,307 Units issued through theexercise of Unit options in 2003.

 

F-48

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**NOTE 21.              SUBSEQUENT EVENT**

 

On February 24, 2005, Texas Eastern Products PipelineCompany, LLC, our General Partner, was acquired by EPCO, Inc. (“EPCO”), aprivately held company controlled by Dan L. Duncan. The acquisition was valuedat $1.1 billion. Additionally, in a separate transaction, EPCO and itsaffiliates have agreed to purchase 2.5 million of our Units, valued atapproximately $100.0 million, from Duke Energy. EPCO and its affiliates own thegeneral partner of Enterprise Products Partners L.P. (“Enterprise”) and  approximately 145 million Enterprise commonunits. Enterprise is one of the largest publicly traded master limitedpartnerships. The general partners of both TEPPCO Partners, L.P. (“TEPPCO”) andEnterprise will continue to operate independently and will maintain separateboards of directors, management teams and offices. 

 

F-49

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