**UNITED STATES**

**SECURITIES AND EXCHANGECOMMISSION**

**Washington,D.C. 20549**

 

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**FORM 10-K**

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

**SECURITIES EXCHANGE ACT OF 1934**

 

**For the fiscal year ended December 31, 2005**

 

**OR**

 

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

**OF THE SECURITIES EXCHANGE ACT OF1934**

 

**Commission File Number 1-10403**

 

**TEPPCO Partners, L.P.**

(Exactname of Registrant as specified in its charter)

 
| **Delaware**                                                          | ** ** | **76-0291058**                                |
|-----------------------------------------------------------------------|------------|-----------------------------------------------|
| (State  of Incorporation or Organization)                             |       | (I.R.S.  Employer Identification Number)      |
|                                                                  |       |                                          |
| **2929 Allen Parkway**                                                |
| **P.O. Box 2521**                                                |
| **Houston, Texas 77252-2521**                                         |
| (Address  of principal executive offices, including zip code)         |
|                                                                  |
| **(713) 759-3636**                                                    |
| (Registrant’s  telephone number, including area code)            |
|                                                                  |       |                                          |
| Securities registered pursuant to Section 12(b) of the Act: |
|                                                                  |       |                                          |
| **Title of each class**                                               | ** ** | **Name of each exchange on which registered** |
| Limited Partner Units representing Limited                            |       | New York Stock Exchange                       |
| Partner Interests                                                     |       |                                          |

 

Securities registered pursuant to Section 12(g) of theAct:  **None**

 

Indicate by check mark if theregistrant is a well-known seasoned issuer, as defined in Rule 405 of theSecurities Act.  Yes ýNo o

 

Indicate by check mark if theregistrant is not required to file reports pursuant to Section 13 or Section 15(d) ofthe Act.  Yes oNo ý

 

Indicate by check mark whetherthe registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the precedingtwelve months (or for such shorter period that the registrant was required tofile such reports), and (2) has been subject to such filing requirementsfor the past 90 days. Yes ýNo o

 

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained 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 Form 10-K.  o

 

Indicate by check mark whetherthe registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer.  See definition of“accelerated filer and large accelerated filer” in Rule 12b-2 of theExchange Act.  (Check one):    Large accelerated filer ý     Accelerated Filer o     Non-accelerated Filer o

 

Indicate by check mark whetherthe registrant is a shell company (as defined in Rule 12b-2 of theAct).  Yes oNo ý

 

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

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

 

Documents Incorporated by Reference: **None**

 

 

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**TABLE OF CONTENTS**

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

 

 

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****EXPLANATORY NOTE****

 

****This Form 10-K includes restated financial statementsand selected financial information for the fiscal years ended December 31,2004 and 2003, and restated quarterly financial information for the quarterlyperiods ended December 31, 2004 and for the first three quarters of2005.  This filing also includes theinitial issuance of our financial statements for the year ended December 31,2005, which have not previously been issued and are not restated.  The restated financial statements for thefiscal year ended December 31, 2002 are unaudited and, in the opinion ofmanagement, have been prepared in accordance with accounting principlesgenerally accepted in the United States of America and reflect all adjustmentswhich are, in the opinion of management, necessary for a fair presentation ofresults for those periods.****

 

The restated financial statements include theeffect of correcting the accounting for our excess investments in CentennialPipeline LLC and Seaway Crude Pipeline Company from an intangible asset with anindefinite life and equity method goodwill, respectively, to intangible assetswith definite lives.  The restatementcaused a $3.8 million, or $0.05 per unit, and $4.0 million, or $0.05 per unit,reduction to net income and earnings per unit as previously reported for thefiscal years ended December 31, 2004 and 2003, respectively.  As a result of the accounting correction, netincome for the fiscal year ended December 31, 2005, includes a charge of$4.8 million, of which $3.8 million relates to the first nine months of2005.  Additionally, partners’ capital atDecember 31, 2002, reflects a $2.5 million reduction representing thecumulative effect of this correction for fiscal years ended December 31,2000 through 2002.

 

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

 

In addition to the restatement reported inthis Annual Report on Form 10-K, this restatement will also be reported inour Quarterly Reports on Form 10-Q for the quarterly periods ended March 31,2006, June 30, 2006, and September 30, 2006.  As we have included restated financialstatements and related selected financial information for (i) restatedfinancial information for the quarterly periods ended March 31, 2005 and2004, June 30, 2005 and 2004, and September 30, 2005 and 2004, (ii) restatedfinancial statements for the fiscal years ended December 31, 2004 and2003, and (iii) restated selected financial information for the fiscalyears ended December 31, 2002 and 2001, we do not plan to file any otheramendments to our previously filed Annual Report on Form 10-K or QuarterlyReports on Form 10-Q, except as described above.

 

****CAUTIONARY NOTEREGARDING FORWARD-LOOKING STATEMENTS****

 

*The matters discussed in thisAnnual Report on Form 10-K (this “Report”) include “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933 and Section 21E of the Securities Exchange Act of 1934.  All statements that express belief,expectation, estimates or intentions, as well as those that are not statementsof historical facts are forward-looking statements.  The words “proposed”, “anticipate”, “potential”,“may”, “will”, “could”, “should”, “expect”, “estimate”, “believe”, “intend”, “plan”,“seek” and similar expressions are intended to identify forward-lookingstatements.  Without limiting the broaderdescription of forward-looking statements above, we specifically note thatstatements included in this document that address activities, events ordevelopments that we expect or anticipate will or may occur in the future,including such things as estimated future capital expenditures (including theamount and nature thereof), business strategy and measures to implementstrategy, competitive strengths, goals, expansion and growth of our businessand operations, plans, references to future success, references to intentionsas to future matters and other such matters are forward-lookingstatements.  These statements are basedon certain assumptions and analyses made by us in light of our experience andour perception of historical trends, current conditions and expected futuredevelopments as well as other factors we believe are appropriate under thecircumstances.  While we believe ourexpectations reflected in these forward-looking statements are reasonable,whether actual results and developments will conform with our expectations andpredictions is subject to a number of risks and uncertainties, includinggeneral economic, market or business conditions, the opportunities (or lackthereof) that may be presented to and pursued by us, competitive actions byother pipeline companies, changes in laws or regulations and other factors,many of which are beyond our control. For example, the demand for refined products is dependent upon theprice, prevailing economic*

 

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*conditionsand demographic changes in the markets served, trucking and railroad freight,agricultural usage and military usage; the demand for propane is sensitive tothe weather and prevailing economic conditions; the demand for petrochemicalsis dependent upon prices for products produced from petrochemicals; the demandfor crude oil and petroleum products is dependent upon the price of crude oiland the products produced from the refining of crude oil; and the demand fornatural gas is dependent upon the price of natural gas and the locations inwhich natural gas is drilled.  We arealso subject to regulatory factors such as the amounts we are allowed to chargeour customers for the services we provide on our regulated pipelinesystems.  Consequently, all of theforward-looking statements made in this document are qualified by thesecautionary statements, and we cannot assure you that actual results ordevelopments that we anticipate will be realized or, even if substantiallyrealized, will have the expected consequences to or effect on us or ourbusiness or operations.  Also note thatwe provide a cautionary discussion of risks and uncertainties under thecaptions “Risk Factors”, “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” and elsewhere in this Form 10-K.*

 

*The forward-looking statementscontained in this Report speak only as of the date hereof.  Except as required by the federal and statesecurities laws, we undertake no obligation to publicly update or revise anyforward-looking statements, whether as a result of new information, futureevents or any other reason.  Allforward-looking statements attributable to TEPPCO Partners, L.P. or any personacting on its behalf are expressly qualified in their entirety by thecautionary statements contained or referred to in this Annual Report on Form 10-Kand in our future periodic reports filed with the Securities and ExchangeCommission.  In light of these risks,uncertainties and assumptions, the forward-looking events discussed in thisReport may not occur.*

 

# **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.

 

On July 26, 2001,the Company restructured its general partner ownership of the OperatingPartnerships to cause them to be indirectly wholly owned by us.  TEPPCO GP, Inc. (“TEPPCO GP”), oursubsidiary, succeeded the Company as general partner of the OperatingPartnerships. All remaining partner interests in the Operating Partnerships notalready owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our generalpartner was increased to 2%.  Theincreased percentage is the economic equivalent of the aggregate interest thatthe Company had prior to the restructuring through its combined interests in usand the Operating Partnerships.  As aresult, we hold a 99.999% limited partner interest in the OperatingPartnerships and TEPPCO GP holds a 0.001% general partner interest.  This reorganization was undertaken tosimplify required financial reporting by the Operating Partnerships when theOperating Partnerships issue guarantees of our debt.

 

Through February 23,2005, the General Partner was an indirect wholly owned subsidiary of DukeEnergy Field Services, LLC (“DEFS”), a joint venture between Duke EnergyCorporation (“Duke Energy”) and ConocoPhillips. Duke Energy held an interest of approximately 70% in DEFS, andConocoPhillips held the remaining interest of approximately 30%.  On February 24, 2005, the GeneralPartner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP HoldingsL.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately heldcompany controlled by Dan L. Duncan, for approximately $1.1 billion.  As a result of the transaction, DFI owns andcontrols the 2% general partner interest in us and has the right to receive theincentive distribution rights associated with the general partnerinterest.  In conjunction with an amendedand restated administrative services agreement, EPCO performs all management,administrative and operating functions required for us, and we reimburse EPCOfor all direct and indirect expenses that have been incurred in managingus.  As a result of the sale of ourGeneral Partner, DEFS and Duke Energy continued to provide some administrativeservices for us for a period of up to one year after the sale, at which time,we assumed these services.  In connectionwith us assuming 

 

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

 

At formation in 1990, wecompleted an initial public offering of 26,500,000 Units representing LimitedPartner Interests (“Limited Partner Units”). In connection with our formation, the Company received 2,500,000Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs were converted to Limited PartnerUnits (“Units”), but they have not been listed for trading on the New YorkStock Exchange.  These Units wereassigned to Duke Energy when ownership of the Company was transferred from DukeEnergy to DEFS in 2000.  On February 24,2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energyand purchased these 2,500,000 Units for $104.0 million.  At December 31, 2005, we had outstanding69,963,554 Units, including 2,500,000 Units held by DFI.

 

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

 

We operate and report 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.

 

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

 

**BusinessStrategy**

 

Our corporate businessstrategy is to grow sustainable cash flow and cash distributions to ourunitholders.  The key elements of ourstrategy are:

 

•                  To focus oninternal growth prospects in order to increase the pipeline system and terminalthroughput, expand and upgrade existing assets and services and construct newpipelines, terminals and facilities;

•                  To targetaccretive and complementary acquisitions and expansion opportunities thatprovide attractive growth potential;

•                  To maintain anappropriate mix of assets; and

•                  To operate in asafe, efficient and environmentally responsible manner.

 

The following is adiscussion of our business strategy by segment.

 

***DownstreamSegment Strategy***

 

Our Downstream Segment isone of our core business segments, having been the primary business of thePartnership since our formation.  OurDownstream Segment is one of the largest pipeline common carriers of refinedpetroleum products and LPGs in the United States.  Over the past few years, we have continued topursue growth opportunities and acquisitions to expand our market share anddeliveries into existing and new markets. Key elements to our Downstream Segment business strategy include thefollowing:

 

•                  Expandingservice to the Midwest markets experiencing a supply shortfall.

•                  Pursuing growthof refined products market share by expanding deliveries to existing marketsand by developing new markets.

•                  Pursuing growthof LPGs market share through capacity expansions and improved operatingperformance.

 

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

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

•                  Enhancingrefined products storage business.

 

***UpstreamSegment Strategy***

 

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

 

•                  Strengtheningmarket position around existing market base by focusing on activities in WestTexas, South Texas and Red River areas, aligning Seaway Crude Pipeline Companywith key refiners and suppliers and increase margins by expanding services andmanaging costs.

•                  Focusing on newrefinery supply markets with existing assets and expand our asset base in theupper Texas Gulf Coast as well as utilize the Cushing, Oklahoma, acquiredstorage for mid-continent refineries.

•                  Pursuingstrategic acquisitions to complement existing assets.

 

***MidstreamSegment Strategy***

 

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

 

•                  Increasingthroughput on the Jonah system and NGL systems and maintaining or increasing therevenue stream with new volumes and increasing operating efficiency on the ValVerde system.

•                  Further expansionof the Jonah system to enhance our ability to serve the growing needs of ourcustomers.

•                  Capitalizing onour assets that are positioned in active producing areas important to futuredomestic gas supply.

•                  Pursuingacquisitions providing long-lived, fee-based cash flows.

 

**FinancialInformation by Business Segment**

 

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

 

**RecentDevelopments since December 31, 2004**

 

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

 

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

 

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

 

On July 12, 2005, wepurchased a refined products terminal and truck loading rack in North LittleRock, Arkansas, for $6.9 million from ExxonMobil Corporation.  The assets include three storage tanks and atwo-bay truck loading rack.  The terminalserves the central Arkansas refined products market and complements ourexisting Downstream Segment infrastructure in North Little Rock, Arkansas.

 

On July 15, 2005, weacquired from Texas Genco, LLC (“Genco”) all of its interests in certaincompanies that own a 90-mile pipeline system and 5.5 million barrels of storagecapacity for $62.1 million.  The assetsof the purchased companies will be integrated into our Downstream Segmentorigin infrastructure in Texas City and Baytown, Texas. **** As a resultof this acquisition, we initiated the expansion of refined products origincapabilities in the Houston and Texas City, Texas, areas.  Our existing Texas City origin facility and a10-inch diameter, 70,000 barrel per day pipeline system from Texas City toBaytown will be replaced by an 18-inch diameter, 180,000 barrel per daypipeline. The 18-inch diameter pipeline will provide additional receipt anddelivery capabilities through the system at major exchange terminals in theHouston area.****The integration and other system enhancementsshould be in service by the fourth quarter of 2006, at an estimated cost of$45.0 million.  The strategic location ofthese assets, with refined products interconnections to major exchangeterminals in the Houston area, will provide significant long-term value to ourcustomers and our Texas Gulf Coast refining and logistics system.

 

In 2005, we began a PhaseIV expansion project on the Jonah Gas Gathering System, which is part of ourMidstream Segment.  This expansion isexpected to increase system capacity to 1.5 billion cubic feet per day with theaddition of 33,000 horsepower of compression and approximately 50 miles ofpipeline.  The Phase IV expansion wassubstantially completed in December 2005, with total costs anticipated tobe approximately $116.0 million.

 

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

 

On February 13,2006, we and Enterprise entered into a letter agreement related to anadditional expansion (the “Jonah Expansion”) of the Jonah system (the “LetterAgreement”).  The Jonah Expansion willconsist of the installation of approximately 90,000 horsepower of gas turbinecompression at a new compression station, related new piping and certainrelated facilities, which is expected to increase capacity of the Jonah system from1.5 billion cubic feet per day to 2.0 billion cubic feet per day.  We expect to enter into a joint venture (“JointVenture”) agreement relating to the construction and financing of the JonahExpansion.  Enterprise will beresponsible for all activities relating to the construction of the JonahExpansion and will advance all amounts necessary to plan, engineer, constructor complete the Jonah Expansion (anticipated to be approximately $200.0million).  Such advance will constitute asubscription for an equity interest in the proposed Joint Venture (the “Subscription”).  We expect the Jonah Expansion to be put intoservice in late 2006.  We have the optionto return to Enterprise up to 100% of the amount of the Subscription.  If we return a portion of the Subscription toEnterprise, our relative interests in the proposed Joint Venture will beadjusted accordingly.  The proposed JointVenture will terminate without liability to either party if we return 100% ofthe Subscription.

 

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

## ** **

We conduct business inour Downstream Segment through the following:

 

•                  TE Products;

 

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

 

•                  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”).

 

***Propertiesand Operations***

 

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.  Otheractivities are related to the intrastate transportation of petrochemicals undera throughput and deficiency contract.

 

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 conditions andspecifications contained in the applicable tariff are satisfied.  In addition to services for transportation ofproducts, we also provide storage and other related services at key pointsalong our pipeline systems.  Substantiallyall of the refined petroleum products and LPGs transported and stored in ourpipeline systems are owned by our customers. The products are received from refineries, connecting pipelines and bulkand marine terminals located principally on the southern end of the pipelinesystem.  The Gulf Coast region is asignificant supply source for our facilities and is a major hub for petroleumrefining.  The products are stored andscheduled into the pipeline in accordance with customer nominations and shippedto delivery terminals for ultimate delivery to the final distributor (includinggas stations and retail propane distribution centers) or to otherpipelines.  The growth in refiningcapacity and increased product flow attributable to the Gulf Coast region hasincreased demand for transportation, storage and distribution facilities.  Pipelines are generally the lowest costmethod for intermediate and long-haul overland transportation of petroleumproducts and LPGs.

 

The following table liststhe material properties and investments of and ownership percentages in ourDownstream Segment assets as of December 31, 2005:

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

 

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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%.

 

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

 

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

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

 

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

 

*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 andoperates an approximately 4,700-mile pipeline system (together with thereceiving, storage and terminaling facilities mentioned below, the “ProductsPipeline System”) extending from southeast Texas through the central andmidwestern United States to the northeastern United States.

 

Excluding the storagefacilities of Centennial and MB Storage, the Products Pipeline System includes33 storage facilities with an aggregate storage capacity of 21 million barrelsof refined petroleum products and 5 million barrels of LPGs, including storagecapacity leased to outside parties.  TheProducts Pipeline System makes deliveries to customers at 62 locations including19 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.  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 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,Ohio.  The Products Pipeline Systemcontinues eastward from Todhunter, Ohio, to Greensburg, Pennsylvania, at whichpoint it branches into two segments, one ending in Selkirk, New York (nearAlbany), 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.  A secondline, which also originates at Baytown, is 16 inches in diameter until itreaches Beaumont, Texas, at which point it reduces to a 14-inch diameterline.  This second line extends along thesame path as the 20-inch diameter line to the Products Pipeline System’sterminal in El Dorado, Arkansas, before continuing as a 16-inch diameter lineto Seymour, Indiana.

 

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 

 

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Products Pipeline System alsohas a 6-inch diameter pipeline connection to the Greater Cincinnati/NorthernKentucky International Airport.

 

In addition, the ProductsPipeline System contains numerous lines, ranging in size from 6 inches to 20inches in diameter, associated with the gathering and distribution system,extending from Baytown to Beaumont; Texas City to Baytown; Pasadena, Texas, toBaytown and Baytown to Mont Belvieu and an 8-inch diameter pipeline connectionto the George Bush Intercontinental Airport terminal in Houston.

 

The Products PipelineSystem also has smaller diameter lines that extend laterally from El Dorado toHelena, Arkansas, from Shreveport, Louisiana, to El Dorado and from McRae,Arkansas, to West Memphis, Arkansas.  Theline from El Dorado to Helena has a 10-inch diameter.  The line from Shreveport to El Dorado variesin diameter from 8 inches to 10 inches. The line from McRae to West Memphis has a 12-inch diameter.

 

TE Products also ownsthree parallel 12-inch diameter common carrier petrochemical pipelines betweenMont Belvieu and Port Arthur.  Each ofthese pipelines is approximately 70 miles in length.  The pipelines transport ethylene, propylene,natural gasoline and naphtha.  We enteredinto a 20-year agreement in 2002 with a major petrochemical producer forguaranteed throughput commitments. During the years ended December 31, 2005, 2004, and 2003, werecognized $12.1 million, $12.0 million and $11.9 million, respectively, ofrevenue 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 Belvieuto Point Comfort.  The northern portionof the Dean Pipeline consists of 138 miles of pipeline from Mont Belvieu toPoint Comfort.

 

*CentennialPipeline Equity Investment*

* *

 TE Products owns a 50% ownership interest inCentennial and Marathon Petroleum Company LLC (“Marathon”) owns the remaining50% interest.  Centennial, whichcommenced operations in April 2002, owns an interstate refined petroleumproducts pipeline extending from the upper Texas Gulf Coast to centralIllinois.  Centennial constructed a 74-mile,24-inch diameter pipeline connecting TE Products’ facility in Beaumont, Texas,with an existing 720-mile, 26-inch diameter pipeline extending from Longville,Louisiana, to Bourbon, Illinois.  TheCentennial 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.

 

Through December 31,2005, including the amount paid for the acquisition of an additional ownershipinterest in February 2003, TE Products has invested $104.8 million inCentennial.  TE Products has not receivedany distributions from Centennial since its formation.

 

*Mont BelvieuStorage Equity Investment*

* *

On January 1,2003, TE Products and Louis Dreyfus formed MB Storage, and each own a 50%ownership interest in MB Storage.  MBStorage owns storage capacity at the Mont Belvieu fractionation and storagecomplex and a short haul transportation shuttle system that ties Mont Belvieu,Texas, to the upper Texas Gulf Coast energy marketplace.  The Mont Belvieu fractionation and storagecomplex is the largest complex of its kind in the United States.   MB Storage is a service-oriented, fee-basedventure serving the fractionation, refining and petrochemical industries withsubstantial capacity and flexibility for the transportation, terminaling andstorage of NGLs, LPGs and refined products. MB Storage receives revenue from the storage, receipt and delivery ofproduct from refineries and fractionators to pipelines, refineries andpetrochemical facilities on the upper Texas Gulf Coast.  MB Storage has no commodity tradingactivity.   TE Products operates thefacilities for MB Storage.

 

MBStorage has approximately 36 million barrels of LPGs storage capacity andapproximately 7 million barrels of refined products storage capacity, includingstorage capacity leased to outside parties. MB Storage includes a short-haul transportation shuttle system,consisting of a complex system of pipelines and interconnects, that ties MontBelvieu to nearly all of the refinery and petrochemical facilities on the upperTexas Gulf Coast.  MB 

 

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Storage also provides truck andrail car loading capability and includes a 400-acre parcel of property forfuture expansion.  Total shuttle volumesfor the three years ended December 31, 2005, 2004 and 2003, were 37.7million barrels, 39.3 million barrels and 33.1 million barrels, respectively.

 

For the years ended December 31,2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storagewas 64.2%, 69.4% and 70.4%, respectively. During the years ended December 31, 2005, 2004 and 2003, TEProducts received distributions of $12.4 million, $10.3 million and $5.3million, respectively, from MB Storage. During the years ended December 31, 2005, 2004 and 2003, TEProducts contributed $5.6 million, $21.4 million and $2.5 million,respectively, to MB Storage. The 2005 contribution includes a combination ofnon-cash asset transfers of $1.4 million and cash contributions of $4.2million. The 2004 contribution includes $16.5 million for the acquisition ofstorage and pipeline assets in April 2004. The remaining contributionshave been for capital expenditures.

 

***Seasonality***

 

The mix of productsdelivered varies seasonally.  Gasolinedemand is generally stronger in the spring and summer months, and LPGs demandis generally stronger in the fall and winter months, including the demand fornormal butane which is used for the blending of gasoline.  Weather and economic conditions in thegeographic areas served by our Products Pipeline System also affect the demandfor, and the mix of, the products delivered. Because propane demand is generally sensitive to weather in the wintermonths, year-to-year variations of propane deliveries have occurred and willlikely continue to occur.

 

***MajorBusiness Sector Markets***

* *

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.

 

Our Products PipelineSystem transports LPGs from the upper Texas Gulf Coast to the Central, Midwestand Northeast regions of the United States and is the only pipeline thattransports LPGs from the upper Texas Gulf Coast to the Northeast. The ProductsPipeline System east of Todhunter, Ohio, is devoted solely to thetransportation of LPGs.  Our ProductsPipeline System also transports normal butane and isobutane in the Midwest andNortheast for use in the production of motor gasoline.

 

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.  Generally, higher marketprices of gasoline has little impact on deliveries in the short-term, but mayhave a more significant impact on us in the long-term due to the cyclicalnature of the refined products market. Increases in the market price of jet fuel deliveries and the impact onairlines has resulted in the use of more efficient airplanes and reductions intotal capacity and the number of scheduled flights.  High market price of propane could result inthe use of alternative fuel sources and tend to reduce the summer and earlyfall fill of consumer storage of propane. Distillate is more sensitive to short-term changes in price as customersshift from the use of trucking for freight transportation to railcars.  As a result, market price volatility mayaffect transportation volumes and revenues from period to period.

 

Our ability in theDownstream Segment to serve propane markets in the Northeast is enhanced by ourmarine import terminal at Providence, Rhode Island.  This facility includes a 400,000-barrelrefrigerated storage tank along with ship unloading and truck loadingfacilities.  We operate the terminal andprovide propane loading services to an affiliate of DEFS.  During the years ended December 31,2005, 2004 and 2003, revenues of $4.3 million, $4.3 million and $3.2 million,respectively, from an affiliate of DEFS were recognized pursuant to this agreement.

 

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Our major operations 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, 2005, 2004 and 2003, were as follows:

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

 

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(1)           Arkansas, Louisiana, Missouri and Texas.

 

(2)           Illinois and Indiana.

 

(3)           New York and Pennsylvania.

 

(4)                                  IncludesDean North RGP volumes.  Petrochemicaltransportation between Mont Belvieu and Port Arthur, Texas, has not beenincluded as those volumes are with one customer.

 

***Customers***

* *

Our customers for the transportationof refined petroleum products include major integrated oil companies,independent oil companies, the airline industry and wholesalers.  End markets for these deliveries areprimarily retail service stations, truck stops, railroads, agriculturalenterprises, refineries and military and commercial jet fuel users.  Propane customers include wholesalers andretailers who, in turn, sell to commercial, industrial, agricultural andresidential heating customers, utilities who use propane as a back-up fuelsource and petrochemical companies who use propane as a process feedstock.  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. Our Downstream Segment depends in large part on the level of demand forrefined petroleum products and LPGs in the geographic locations that we serveand the ability and willingness of customers having access to the pipelinesystem to supply this demand.

 

At December 31,2005, our Downstream Segment had approximately 155 customers.  During the year ended December 31, 2005,total revenues (and percentage of total revenues) attributable to the top 10customers were $151.6 million (53%), of which Marathon accounted forapproximately 14% of total Downstream Segment revenues.  At December 31, 2004, our DownstreamSegment had approximately 139 customers. During the year ended December 31, 2004, total revenues (andpercentage of total revenues) attributable to the top 10 customers were $151.7million (54%), of which Marathon accounted for approximately 17% of totalDownstream Segment revenues.  During theyear ended December 31, 2003, total revenues (and percentage of totalrevenues) attributable to the top 10 customers were $149.5 million (56%), ofwhich Marathon accounted for approximately 18% of total Downstream Segmentrevenues.  During each of the three yearsended December 31, 2005, 2004 and 2003, no single customer of theDownstream Segment accounted for 10% or more of total consolidated revenues.

 

***Competition***

* *

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

 

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The Products PipelineSystem faces competition from numerous sources. Because pipelines are generally the lowest cost method for intermediateand long-haul overland movement of refined petroleum products and LPGs, theProducts Pipeline System’s most significant competitors (other than indigenousproduction in its markets) are pipelines in the areas where the ProductsPipeline System delivers products. Competition among common carrier pipelinesis based primarily on transportation charges, quality of customer service andproximity to end users.  We believe ourDownstream Segment is competitive with other pipelines serving the samemarkets; however, comparison of different pipelines is difficult due to varyingproduct 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 railand pipeline movements of LPGs from Sarnia, Ontario, Canada, and waterborneimports into terminals located along the upper East Coast.

 

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

## ** **

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”).

 

***Propertiesand Operations***

 

Our Upstream Segmentgathers, transports, markets and stores crude oil, and distributes lubricationoils and specialty chemicals, principally in Oklahoma, Texas, New Mexico andthe Rocky Mountain region.  We commencedour Upstream Segment business in connection with the acquisition of assets froman affiliate 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 and trading locations.  The crude oil is purchased from independentproducers under contracts, the majority of which range in term from athirty-day evergreen to one year.  Thecrude oil is then sold to refiners and other customers.  The Upstream Segment transports crude oilthrough proprietary gathering systems, common carrier pipelines, equity ownedpipelines, trucking operations and third party pipelines.  The Upstream Segment also exchanges crude oilfor another grade of crude oil or at a different geographic location, asappropriate, in order to maximize margins or meet contract deliveryrequirements.

 

The areas served by ourgathering and transportation operations are geographically diverse, and theforces that affect the supply of the products gathered and transported vary byregion.  Crude oil prices and productionlevels affect the supply of these products. The demand for gathering and transportation is affected by the demandfor crude oil by large industrial, refineries, and similar customers in theregions served by this business.

 

TCO purchases crude oiland establishes a margin by selling crude oil for physical delivery to thirdparty users.  These purchases and salesare generally contracted to occur in the same calendar month.  We seek to maintain a balanced marketingposition to minimize our exposure to price fluctuations occurring after theinitial purchase.  However, basis riskscannot be completely eliminated.

 

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Product deliveries onTCPL’s 100% owned pipeline systems, undivided joint interest pipelines andSeaway for the years ended December 31, 2005, 2004 and 2003, were asfollows (in millions):

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

 

*Properties*

* *

The following tabledescribes the major crude oil pipelines and pipeline systems and the ownershippercentages in our Upstream Segment as of December 31, 2005:

** **
| **Crude Oil   Pipeline**  | ** ** | **Our  Ownership**                  | ** ** | **Operator**                        | ** ** | **Description**                                                                                                                             |
|---------------------------|------------|-------------------------------------|------------|-------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------|
| Red River   System        |       | 100%                                |       | TCPL                                |       | 1,690 miles of  pipeline; 1,491,000 barrels of storage – North Texas to South Oklahoma                                                 |
|                      |       |                                |       |                                |       |                                                                                                                                        |
| South Texas  System       |       | 100%                                |       | TCPL                                |       | 1,000 miles of  pipeline; 1,161,000 barrels of storage – South Central Texas to Houston,  Texas area                                   |
|                      |       |                                |       |                                |       |                                                                                                                                        |
| West Texas   Trunk System |       | 100%                                |       | TCPL                                |       | 275 miles of  smaller diameter pipeline – connecting West Texas and Southeast New Mexico to  TCPL’s Midland, Texas terminal       |
|                      |       |                                |       |                                |       |                                                                                                                                        |
| Cushing   Terminal        |       | 100%                                |       | TCPL                                |       | 15 tanks with  1,870,000 barrels of storage in Cushing, Oklahoma                                                                            |
|                      |       |                                |       |                                |       |                                                                                                                                        |
| Midland   Station         |       | 100%                                |       | TCPL                                |       | 10 tanks with  900,000 barrels of storage in Midland, Texas                                                                                 |
|                      |       |                                |       |                                |       |                                                                                                                                        |
| Seaway (1)                |       | 50%  general partnership   interest |       | TCPL                                |       | 500-mile,  30-inch diameter pipeline; 5,636,000 barrels of storage – Texas Gulf Coast to  Cushing, Oklahoma; 30-mile Texas City system |
|                      |       |                                |       |                                |       |                                                                                                                                        |
| Basin                     |       | 13%  joint ownership                |       | Plains  All American Pipeline, L.P. |       | 416-mile  pipeline – Permian Basin (New Mexico and Texas) to Cushing, Oklahoma                                                         |

 

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

 

The majority of the RedRiver System crude oil is delivered to Cushing, Oklahoma, via third partypipelines, or to two local refineries. The majority of the crude oil on the South Texas System is delivered ona tariff basis to Houston area refineries. The West Texas Trunk System is a fee based system which connectsgathering systems to TCPL’s Midland, Texas, terminal.  Other crude oil assets, located primarily inTexas and Oklahoma, consist of 265 miles of pipeline and 295,000 barrels ofstorage capacity.

 

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*Seaway CrudePipeline Equity Investment*

* *

Seaway is a partnershipbetween TEPPCO Seaway, L.P. (“TEPPCO Seaway”), a subsidiary of TCTM, andConocoPhillips.  We operate the Seawayassets.  The 30-inch diameter, 500-milepipeline transports crude oil from Freeport, Texas, on the U.S. Gulf Coast toCushing, a central crude distribution point for the central United States and adelivery point for the New York Mercantile Exchange (“NYMEX”).  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 approximately3.3 million barrels.  Seaway is currentlyconstructing two additional tanks at Texas City with a combined capacity of 1.2million barrels, which are expected to be completed in April 2006.  Seaway has the capability to provide marineterminaling and crude oil storage services for all Houston area refineries.

 

The Seaway partnershipagreement provides for varying participation ratios throughout the life ofSeaway. From July 20, 2000, through May 2002, we received 80% ofrevenue and 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.  During the yearsended December 31, 2005, 2004 and 2003, we received distributions fromSeaway of $24.7 million, $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 and sellers.  This line transfer documentation service isrelated to the trading activity by TCPL’s customers of NYMEX open-interestcrude oil contracts and other physical trading activity. This service providesa record of receipts, deliveries and transactions to each customer, includingconfirmation of trade matches, inventory management and scheduled movements.

 

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 3.1 million barrels to facilitate thepumpover business.

 

LSI distributeslubrication oils and specialty chemicals to natural gas pipelines, gasprocessors and industrial and commercial accounts.  LSI’s distribution networks are located inColorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas and Louisiana.

 

***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 $5.9 billion (73%), $3.8 billion (70%)and $2.6 billion (67%) for the years ended December 31, 2005, 2004 and2003, respectively.  For the years ended December 31,2005, 2004 and 2003, Valero Energy Corp. (“Valero”) accounted for 15%, 17% and18%, respectively, of the Upstream gross sales revenue.  For the years ended December 31, 2005,2004 and 2003, Valero accounted for 14%, 16% and 16%, respectively, of ourtotal consolidated revenues.

 

***Competition***

* *

The Upstream Segment facescompetition from numerous sources.  Themost significant competitors in pipeline operations in our Upstream Segment areprimarily common carrier and proprietary pipelines owned and operated by majoroil companies, large independent pipeline companies and other companies in theareas where our pipeline systems deliver crude oil.  Competition among common carrier pipelines isbased primarily on posted tariffs, quality of customer service, knowledge ofproducts and markets, and proximity to refineries and connecting 

 

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pipelines.  The crude oil gathering and marketingbusiness is characterized by thin margins and intense competition for suppliesof crude oil at the wellhead.

 

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

## ** **

We conduct business inour Midstream Segment through the following:

 

•                  Jonah GasGathering Company and Val Verde Gas Gathering Company, L.P., which gather andprocess 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.

 

***Propertiesand Operations***

 

Our Midstream Segmentgathers natural gas, transports NGLs and fractionates NGLs to customers inColorado.  Our Midstream Segment alsosells condensate liquid extracted from the natural gas stream to TCO.  We generally do not purchase or sell thenatural gas gathered, NGLs transported or NGLs fractionated, except for theNGLs produced at one gas processing plant. Our Midstream Segment has multiple long-term contracts with producersconnected to the Jonah and Val Verde systems. We cannot influence or control the operation, development or productionlevels of the gas fields served by the Jonah and Val Verde systems, which maybe affected by price and price volatility, market demand, depletion rates ofexisting wells and changes in laws and regulations.

 

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

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

 

The majority of 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.

 

*JonahGas Gathering System*

* *

We entered the naturalgas gathering industry in late 2001 when we purchased Jonah from Alberta EnergyCompany.  DEFS managed and operated Jonahon our behalf under a contractual agreement through the second quarter of 2005,when we assumed these operations as a result of the change in ownership of ourGeneral Partner.

 

The Jonah system consistsof approximately 580 miles of pipelines ranging in size from three inches to 24inches in diameter, four compressor stations with an aggregate of approximately125,000 horsepower and related metering facilities.  Gas gathered on the Jonah system is collectedfrom approximately 930 producing wells in southwestern Wyoming’s Green RiverBasin, which is one of the most prolific natural gas basins in the UnitedStates.  Gas is also delivered to gasprocessing facilities owned by others. From these processing facilities, the 

 

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natural gas is delivered toseveral interstate pipeline systems located in the region for transportation toend-use markets throughout the Midwest, the West Coast and the Rocky Mountainregions.  Interstate pipelines in theregion include Kern River, Northwest, Colorado Interstate Gas and Questar.

 

Since the acquisition ofJonah for approximately $360.0 million, we have expanded both the pipelinecapacity and processing capacity of the Jonah system as follows:

 

•                  The Phase Iexpansion was completed in May 2002 at a cost of approximately $25.0million and increased system capacity by 62%, from approximately 450 millioncubic 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-milepipeline loop and 3,700 horsepower of new compression on the system and thebuilding of a 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.

 

•                  Additionalcapacity of 100 MMcf/day was completed during the fourth quarter of 2004, at acost of approximately $13.0 million.

 

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

 

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

 

We expect to expand theJonah system with a service date for such expansion being late 2006.  The Jonah Expansion will consist of the installationof approximately 90,000 horsepower of gas turbine compression at a newcompression station, related new piping and certain related facilities, whichis expected to increase capacity of the Jonah system from 1.5 billion cubicfeet per day to 2.0 billion cubic feet per day. We expect to enter into a joint venture agreement with Enterprise relatingto the construction and financing of the expansion.  Enterprise will be responsible for allactivities relating to the construction of the Jonah Expansion and will advanceall amounts necessary to plan, engineer, construct or complete the JonahExpansion (anticipated to be approximately $200.0 million).  Such advance will constitute a Subscriptionfor an equity interest in the proposed Joint Venture.  We have the option to return to Enterprise upto 100% of the amount of the Subscription. If we return a portion of the Subscription to Enterprise, our relativeinterests in the proposed Joint Venture will be adjusted accordingly.  The proposed Joint Venture will terminatewithout liability to either party if we return 100% of the Subscription.

 

*ValVerde Gas Gathering System*

* *

On June 30, 2002, wepurchased Val Verde for approximately $444.0 million from Burlington ResourcesGathering Inc., a subsidiary of Burlington Resources Inc.  The acquisition increased our presence in thenatural gas gathering industry.  DEFSmanaged and operated Val Verde on our behalf under a contractual agreementthrough the second quarter of 2005, when we assumed these operations as aresult of the change in ownership of our General Partner.

 

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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 agathering 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 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,and provides gathering and treating services pursuant to long-term contractswith approximately 40 natural gas producers in the San Juan Basin.  The Val Verde system delivers gas to severalinterstate pipeline systems serving the western United States, as well as localNew Mexico markets.

 

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. Wells have been drilled on approximately half of the available locationson acreage dedicated to the Val Verde system.

 

In December 2004, wecompleted a 16-mile project to connect Val Verde with a third party gatheringsystem originating in Colorado and entered into a seven year agreement totransport and treat natural gas through this connection.  Val Verde transported an average of 104MMcf/day from this interconnection in 2005.

 

In 2005, the Colorado Oiland Gas Conservation Commission approved two applications to double welldensity in the Fruitland Coal to one well per 80 acres.  One other operator in Colorado has submitteda similar application.  Thesedownspacings could result in increased volumes to Val Verde from Colorado.

 

*NGLTransportation and Fractionation*

 

The NGL pipelines of theMidstream Segment are located along the Texas Gulf Coast, East Texas and fromsoutheastern New Mexico and West Texas to Mont Belvieu. They are all whollyowned and operated by our subsidiaries. Information about these NGL pipelines as of December 31, 2005, isset forth in the following table:

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

 

On March 1, 2002, wepurchased the Chaparral NGL system for approximately $132.4 million fromDiamond-Koch II, L.P. and Diamond-Koch III, L.P.  The Chaparral NGL system extends from WestTexas and New Mexico to Mont Belvieu. The Panola Pipeline and San Jacinto Pipeline originate at an East TexasPlant Complex in Panola County, Texas, and transport NGLs for major integratedoil and gas companies.  The southernportion of the Dean Pipeline originates in South Texas and transports NGLs forone customer into its pipeline at Point Comfort, Texas.  The Wilcox Pipeline transports NGLs for acustomer from its natural gas processing plant and is currently supported by athroughput agreement with that customer through November 2006.

 

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TEPPCO Colorado has twoNGL fractionation facilities which separate NGLs into individual components.TEPPCO Colorado is currently supported by a fractionation agreement with DEFSthrough 2018, under which TEPPCO Colorado receives a variable fee for allfractionated volumes delivered to DEFS. Under an operation and maintenance agreement, DEFS also operates andmaintains the fractionation facilities for TEPPCO Colorado.  For these services, TEPPCO Colorado pays DEFSa set volumetric rate for all fractionated volumes delivered to DEFS.

 

***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, affiliates of EPCO, and other major integrated oil and gascompanies.  Condensate sales from theJonah system are primarily to TCO.

 

At December 31,2005, the Midstream Segment had approximately 70 customers.  Revenue attributable to the top 10 customerswas $190.0 million (85%) for the year ended December 31, 2005, of whichEnCana Corporation (formerly Alberta Energy Company), DEFS and its affiliatesand Burlington Resources Inc. accounted for approximately 20%, 19% and 12%,respectively, of revenues of the Midstream Segment.  At December 31, 2004, the MidstreamSegment had approximately 75 customers. Revenue attributable to the top 10 customers was $172.8 million (83%)for the year ended December 31, 2004, of which EnCana Corporation, DEFSand its affiliates and Burlington Resources Inc. accounted for approximately21%, 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.  During each of the three yearsended December 31, 2005, 2004 and 2003, no single customer of theMidstream Segment accounted for 10% or more of total consolidated revenues.

 

***Competition***

* *

The Midstream Segment’sNGL pipeline operations face competition from a few sources.  The most significant competition for the NGLpipeline operations of our Midstream Segment comes from pipelines owned andoperated by major oil and gas companies and other large independent pipelinecompanies with contiguous operations. The ability to compete in the NGL pipeline area is based primarily onthe quality of customer service and knowledge of products and markets.

 

Competition in thenatural gas gathering operations of our Midstream Segment is based largely onreputation, efficiency, system reliability, system capacity and pricearrangements.  Key competitors in thegathering and treating segment include independent gas gatherers as well as othermajor integrated energy companies.   Alternategathering facilities may be available to producers served by our MidstreamSegment, and those producers could also elect to construct proprietary gasgathering systems.  Success in the gasgathering and treating business segment is based primarily on a thoroughunderstanding of the needs of the producers served, a strong commitment toproviding responsive, high-quality customer service, as well as proximity tonew drilling and development.

 

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

## ** **

We believe we havesatisfactory title to all of our assets. The properties are subject toliabilities in certain cases, such as contractual interests associated withacquisition 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 withtheir use in the operation of our business.

 

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

## ** **

Capital expenditures,excluding acquisitions, totaled $220.6 million for the year ended December 31,2005.  Revenue generating projectsinclude those projects which expand service into new markets or expand capacityinto 

 

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current markets.  Capital expenditures to sustain existingoperations include projects required by regulatory agencies or requiredlife-cycle replacements.  System upgradeprojects improve operational efficiencies or reduce cost.  We capitalize interest costs incurred duringthe period that construction is in progress. The following table identifies capital expenditures by segment for theyear ended December 31, 2005 (in millions):

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

 

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

 

We estimate that capitalexpenditures, excluding acquisitions, for 2006 will be approximately $209.7million (including $6.0 million of capitalized interest).  We expect to spend approximately $147.4million for revenue generating projects. Capital spending on revenue generating projects and facilityimprovements will include approximately $70.9 million for the expansion of ourDownstream Segment facilities.  We expectto spend $16.3 million to expand our Upstream Segment pipelines and facilitiesin West Texas and Oklahoma and approximately $60.2 million to expand ourMidstream Segment assets, with further expansions on our Jonah system.  We expect to spend approximately $37.8million to sustain existing operations, including life-cycle replacements forequipment at various facilities and pipeline and tank replacements among all ofour business segments.  We expect tospend approximately $18.5 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 petroleumproducts and crude oil pipeline rates be posted publicly and that these ratesbe “just and reasonable” and nondiscriminatory.

 

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

 

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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 agreementswith all of the pipeline’s shippers that the 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.

 

On March 26, 2004, adecision in *ARCO Products Co., et al. v. SFPP*,Docket OR96-2-000, was issued by the FERC, which made several significantdeterminations with respect to finding “changed circumstances” under the EnergyPolicy Act of 1992 (“EP Act”).  Thedecision largely clarifies, but does not fully quantify, the standard requiredfor a complainant to demonstrate that an oil pipeline’s rates are no longersubject to the rate protection of the EP Act by demonstrating that asubstantial change in circumstances has occurred since 1992 with respect to thebasis of the rates being challenged.  Inthe decision, the FERC found that a limited number of rate elements willsignificantly affect the economic basis for a pipeline company’s rates.  The elements identified in the decision arevolume changes, allowed total return and total cost-of-service (including majorcost elements such as rate base, tax rates and tax allowances, amongothers).  The FERC did reject, however,the use of changes in tax rates and income tax allowances as stand-alonefactors.  Judicial review of thatdecision, which has been sought by a number of parties to the case, iscurrently pending before the U.S. Court of Appeals for the District of ColumbiaCircuit.  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 District of Columbia Circuit issued an opinion in *BP WestCoast Products 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 income attributable to partnership interestsowned by corporate partners.  Under theFERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on itscost-of-service filing for the percentage of its net operating (pre-tax) incomeattributable to partnership units held by corporations, and was denied an incometax allowance equal to the percentage attributable to partnership units held bynon-corporate partners.  The courtremanded the case back to the FERC for further review.  As a result of the court’s remand, on May 4,2005, the FERC issued its Policy Statement on Income Tax Allowances, whichpermits regulated partnerships, limited liability companies and otherpass-through entities an income tax allowance on their income attributable toany owner that has an actual or potential income tax liability on that income,regardless whether the owner is an individual or corporation.  If there is more than one level ofpass-through entities, the regulated company income must be traced to where theultimate tax liability lies.  The PolicyStatement is to be applied in individual cases, and the regulated entity bearsthe burden of proof to establish the tax status of its owners.  On December 16, 2005, the FERC issuedthe first of those decisions, in an order involving SFPP (the “SFPP Order”).  The SFPP Order confirmed that a masterlimited partnership is entitled to a tax allowance with respect to partnershipincome for which there is an “actual or potential income tax liability” anddetermined that a unitholder that is required to file a Form 1040 or Form 1120tax return that includes partnership income or loss is presumed to have anactual or potential income tax liability sufficient to support a tax allowanceon that partnership income.  The FERCalso established certain other presumptions, including that corporateunitholders are presumed to be taxed at the maximum corporate tax rate of 35%while individual unitholders (and certain other types of unitholders taxed likeindividuals) are presumed to be taxed at a 28% tax rate.  The SFPP Order remains subject to furtheradministrative proceedings (including compliance filings by SFPP and possiblerehearing requests), as well as potential judicial review.  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 touse cost-of-service to support our rates, or (ii) be required to use suchmethodology 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 itsinfluences on the parties that produce the natural gas gathered on the Jonahand Val Verde systems.  In addition, 

 

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in recent years, the FERC haspursued pro-competition policies in its regulation of interstate natural gaspipelines.  If the FERC does not continuethe pro-competition policies as it considers pipeline rate case proposals,revisions to rules and policies that affect shipper rights of access tointerstate 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 and SafetyMatters****

## ** **

Our operations aresubject to federal, state and local laws and regulations governing the dischargeof materials into the environment and various safety matters. Failure to complywith these laws and regulations may result in the assessment of administrative,civil and criminal penalties, imposition of injunctions delaying or prohibitingcertain activities and the need to perform investigatory and remedialactivities.  We believe our operationshave been and are in material compliance with applicable environmental andsafety laws and regulations, and that compliance with existing environmental lawsand regulations are not expected to have a material adverse effect on ourcompetitive position, financial positions, results of operations or cashflows.  However, risks of significantcosts and liabilities are inherent in pipeline operations, and we cannot assurethat significant costs and liabilities will not be incurred. Moreover, it ispossible that other developments, such as increasingly strict environmental andsafety laws 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. At December 31, 2005, we have an accrued liability of $2.4 millionrelated to sites requiring environmental remediation activities.

 

*Water*

* *

The Federal WaterPollution Control Act of 1972, as renamed and amended as the Clean Water Act (“CWA”),and comparable state laws impose strict controls against the discharge of oiland its derivatives into navigable waters. The CWA provides penalties for any discharges of petroleum products inreportable quantities and imposes substantial potential liability for the costsof removing petroleum or other hazardous substances.  State laws for the control of water pollutionalso provide varying civil and criminal penalties and liabilities in the caseof a release of petroleum or its derivatives in navigable waters or intogroundwater. Spill prevention control and countermeasure requirements offederal laws require appropriate containment berms and similar structures tohelp prevent a petroleum tank release from impacting navigable waters.  The Environmental Protection Agency (“EPA”)has adopted regulations that require us to have permits in order to dischargecertain storm water run-off.  Storm waterdischarge permits may also be required by certain states in which weoperate.  These permits may require us tomonitor and sample the storm water run-off.

 

Contamination resultingfrom spills or releases of petroleum products is an inherent risk within thepetroleum pipeline industry.  To theextent that groundwater contamination requiring remediation exists along ourpipeline systems as a result of past operations, we believe any suchcontamination could be controlled or remedied without having a material adverseeffect on our financial position, but such costs are site specific, and wecannot be assured that 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 United States Coast Guard, the United StatesDepartment of Transportation Office of Pipeline Safety (“OPS”) or the EPA, asappropriate.  Numerous states haveenacted laws similar to OPA.  Under OPAand similar state laws, responsible parties for a regulated facility from whichoil is discharged may be liable for removal costs and natural resource damages.

 

*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 requireour operations to incur future capital expenditures in connection with theaddition or modification of existing air emission control equipment andstrategies.  In addition, some of ourfacilities are included within the categories of hazardous air pollutantsources, 

 

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which are subject to increasingregulation under the Clean Air Act.  TheClean Air Act requires federal operating permits for major sources of airemissions.  Under this program, a federaloperating permit (a “Title V” permit) may be issued.  The permit acts as an umbrella that includesother federal, state and local preconstruction and/or operating permitprovisions, emission standards, grandfathered rates and record keeping, reportingand monitoring requirements in a single document. The federal operating permitis the tool that the public and regulatory agencies use to review and enforce asite’s compliance with all aspects of clean air regulation at the federal,state and local level. We have completed applications for the facilities forwhich 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 regulationrequired us to develop and implement a risk management program that includes afive-year accident history, an offsite consequence analysis process, aprevention program and an emergency response program.  We are operating in compliance with our riskmanagement program.

 

*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.We also utilize waste minimization and recycling processes to reduce thevolumes of our waste.  Amendments to RCRArequired the EPA to promulgate regulations banning the land disposal of allhazardous wastes unless the wastes meet certain treatment standards or theland-disposal method meets certain waste containment criteria.

 

*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 the owneror operator of a facility where a release occurred and companies that disposedor arranged for the disposal of the hazardous substances found at a facility.Under CERCLA, these persons may be subject to joint and several liability forthe costs of cleaning up the hazardous substances that have been released intothe environment, for damages to natural resources and for the costs of certainhealth studies.  CERCLA also authorizesthe EPA and, in some instances, third parties to take actions in response tothreats to the public health or the environment and to seek to recover thecosts 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 withinCERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by us requires clean upin the future, we may be responsible under CERCLA for all or part of the costsrequired to clean up sites at which such wastes have been disposed.

 

*****DOTPipeline Compliance Matters*****

* *

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. 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 

 

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and consequence of incidentscaused by human error.  The regulationestablishes qualification requirements for individuals performing coveredtasks.  We believe that we are inmaterial compliance with these DOT regulations.

 

We are also subject tothe DOT Integrity Management regulations, which specify how companies shouldassess, evaluate, validate and maintain the integrity of pipeline segmentsthat, in the event of a release, could impact High Consequence Areas (“HCA”).  HCA are defined as populated areas, unusuallysensitive environmental areas and commercially navigable waterways.  The regulation requires the development andimplementation of an Integrity Management Program (“IMP”) that utilizesinternal pipeline inspection, pressure testing, or other equally effectivemeans to assess the integrity of HCA pipeline segments.  The regulation also requires periodic reviewof HCA pipeline segments to ensure adequate preventative and mitigativemeasures exist and that companies take prompt action to address integrityissues raised by the assessment and analysis. In compliance with these DOT regulations, we identified our HCA pipelinesegments and have developed an IMP.  Webelieve that we have substantially complied with our IMP and all assessmentrequirements imposed by the DOT regulations.

 

*SafetyMatters*

 

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.

 

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 certain flammable liquid or gas.  We believe we are in material compliance withthe OSHA regulations.

 

## ****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 EPCO.  EPCO performs all management, administrativeand operating functions required for us, and we reimburse EPCO for all directand indirect expenses that have been incurred in managing us and oursubsidiaries.  As of December 31,2005, EPCO had 1,270 employees dedicated to managing and operating us and oursubsidiaries.  None of these employeesare represented by labor unions, and our relations with these employees aregood.

 

## ****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 SECat 1-800-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,and other information statements and, if applicable, amendments to thosereports filed or furnished pursuant to Section 13(a) of the ExchangeAct as soon as reasonably practicable after we electronically file suchmaterial with, or furnish it to, the SEC.

 

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# **Item1A*.   RiskFactors***

 

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

 

**RisksRelating to Our Business**

 

***Potential future acquisitionsand expansions may affect our business by substantially increasing the level ofour indebtedness and contingent liabilities and increasing our risks of beingunable to effectively integrate these new operations.***

 

As part of ourbusiness strategy, we evaluate and acquire assets and businesses and undertakeexpansions that we believe complement our existing assets and businesses.  Acquisitions and expansions may requiresubstantial capital or the incurrence of substantial indebtedness.  Consummation of future acquisitions andexpansions may significantly change our capitalization and results ofoperations.  Our growth may be limited ifacquisitions or expansions are not made on economically favorable terms.

 

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

 

Acquisitionsand business expansions involve numerous risks, including difficulties in theassimilation of the assets and operations of the acquired businesses,inefficiencies and difficulties that arise because of unfamiliarity with newassets, personnel and the businesses associated with them and new geographicareas and the diversion of management’s attention from other businessconcerns.  Further, unexpected costs andchallenges may arise whenever businesses with different operations ormanagement are combined, and we may experience unanticipated delays inrealizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilitiesassociated with the acquired business for which we have no recourse underapplicable indemnification provisions.

 

***Our debtinstruments may limit our ability to borrow additional funds and increase thecosts of borrowing.***

 

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

 

***Our cash distributions may vary based on ourperformance and level of reserves.***

 

Distributionsare dependent on the amount of cash we generate and may fluctuate based on ourperformance.  The cash that isdistributed will vary based on many factors, some of which are outside of ourcontrol.  Cash distributions are based oncash flow measures, and are not determined by our level of profitability.

 

***Expanding our natural gasgathering business by constructing new pipelines and compression facilitiessubjects us to construction risks and risks that natural gas supplies will notbe available upon completion of the new pipelines.***

 

We expect toexpand the capacity of our existing natural gas gathering systems through theconstruction of additional facilities. The construction of gathering facilitiesrequires the expenditure of significant amounts of capital, which may exceedour estimates.  Generally, we may haveonly limited natural gas supplies committed to these facilities prior to theirconstruction.  Moreover, we may constructfacilities to capture anticipated future growth in production in a region inwhich anticipated production growth does not materialize.  As a result, there is the risk that newfacilities may not be able to attract enough natural gas to achieve ourexpected investment return, which could adversely affect our financial positionor results of operations.

 

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***Our interstate tariff rates aresubject to review and possible adjustment by federal regulators, which couldhave a material adverse effect on our financial condition and results ofoperations.***

 

The FERC,pursuant to the Interstate Commerce Act, regulates the tariff rates for ourinterstate common carrier pipeline operations. To be lawful under that Act,interstate tariff rates must be just and reasonable and not undulydiscriminatory.  Shippers may protest,and the FERC may investigate, the lawfulness of new or changed tariffrates.  The FERC can suspend those tariffrates for up to seven months.  It canalso require refunds of amounts collected under rates ultimately foundunlawful.  The FERC can also challengetariff rates that have become final and effective.  Because of the complexity of rate making, thelawfulness of any rate is never assured.

 

The FERC usesprescribed rate methodologies for approving regulated tariff rates fortransporting crude oil and refined products. These methodologies may limit our ability to set rates based on ouractual costs or may delay the use of rates reflecting increased costs.  Changes in the FERC’s approved methodologyfor approving rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates couldadversely affect our cash flow. Additional challenges to our tariff rates could be filed with the FERC.

 

Although ourintrastate natural gas gathering systems are generally exempt from FERCregulation under the Natural Gas Act of 1938, FERC regulation stillsignificantly affects our natural gas gathering business.  In recent years, the FERC has pursuedpro-competition policies in its regulation of interstate natural gaspipelines.  If the FERC does not continuethis approach as it considers proposals by natural gas pipelines to allownegotiated gathering rates that are not limited by rate ceilings, pipeline ratecase proposals and revisions to rules and policies that may affect our shippers’rights of access to interstate natural gas transportation capacity, it couldhave an adverse effect on the rates we are able to charge in the future.

 

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

 

In a 1995decision involving an unrelated oil pipeline limited partnership, the FERCpartially disallowed the inclusion of income taxes in that partnership’s costof service.  In another FERC proceedinginvolving a different oil pipeline limited partnership, the FERC held that theoil pipeline limited partnership may not claim an income tax allowance forincome attributable to non-corporate limited partners, both individuals andother entities.  Because corporations aretaxpaying entities, income taxes are generally allowed to be included as acorporate cost-of-service. While we currently do not use the cost-of-servicemethodology to support our rates, these decisions might adversely affect usshould we elect in the future to use the cost-of-service methodology or shouldwe be required to use that methodology to defend our rates if challenged by ourcustomers.  This could put us at acompetitive disadvantage.

 

***Competition could adverselyaffect our operating results.***

 

Our refinedproducts and LPG transportation business competes with other pipelines in theareas where we deliver products.  We alsocompete with trucks, barges and railroads in some of the areas we serve.  Competitive pressures may adversely affectour tariff rates or volumes shipped.  Thecrude oil gathering and marketing business is characterized by thin margins andintense competition for supplies of crude oil at the wellhead.  A decline in domestic crude oil productionhas intensified competition among gatherers and marketers.  Our crude oil transportation businesscompetes with common carriers and proprietary pipelines owned and operated bymajor oil companies, large independent pipeline companies and other companiesin the areas where our pipeline systems deliver crude oil and natural gasliquids.

 

New suppliesof natural gas are necessary to offset natural declines in production fromwells connected to our gathering system and to increase throughput volume, andwe encounter competition in obtaining contracts to gather natural gassupplies.  Competition in natural gasgathering is based in large part on reputation, efficiency, system reliability,gathering system capacity and price arrangements.  Our key competitors in the gas gatheringsegment include independent gas gatherers and major integrated energycompanies.  Alternate gatheringfacilities are available to producers we serve, and those producers may alsoelect to construct proprietary gas gathering systems. If the production deliveredto our gathering system declines, our revenues from such operations willdecline.

 

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***Our business requires extensivecredit risk management that may not be adequate to protect against customernonpayment.***

 

Risks of nonpayment and nonperformance by customers are a majorconsideration in our businesses.  Ourcredit procedures and policies may not be adequate to fully eliminate customercredit risk.  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 each of the years ended December 31, 2005, 2004 and 2003, we expensedless than $1.0 million of uncollectible receivables.

 

***Our crude oil marketingbusiness involves risks relating to product prices.***

 

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

 

***Pipelines are dependent on theirinterconnections with other pipelines to reach their destination markets.***

 

Decreased throughput on interconnected pipelines dueto testing, line repair and reduced pressures could result in reducedthroughput on our own pipeline systems. Such reduced throughput may adversely impact our profitability.

 

***Reduced demand could affectshipments on the pipelines.***

 

Our productspipeline business depends in large part on the demand for refined products andLPGs in the markets served by our pipelines. Reductions in that demand adversely affect our pipeline business.   Market demand varies based upon thedifferent end uses of the products we ship. We cannot predict the impact of future fuel conservation measures,alternate fuel requirements, government regulation or technological advances infuel economy and energy-generation devices, all of which could reduce thedemand for refined petroleum products and LPGs in the areas we serve.  Demand for gasoline, which has in recentyears accounted for approximately forty percent of our refined productstransportation revenues, depends upon price, prevailing economic conditions anddemographic changes in the markets we serve. Weather conditions, government policy and crop prices affect the demandfor refined products used in agricultural operations.  Demand for jet fuel, which has in recentyears accounted for approximately twenty percent of our refined productsrevenues, depends on prevailing economic conditions and military usage.  Propane deliveries are generally sensitive tothe weather and meaningful year-to-year variances have occurred and will likelycontinue to occur.

 

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

 

Regionalproduction levels drive the volume of natural gas gathered on our system.  We cannot influence or control the operationor development of the gas fields we serve. Production levels may be affected by:

 

•                  the absoluteprice of, volatility in the price of, and market demand for natural gas;

•                  changes in lawsand regulations, particularly with regard to taxes, denial of reduced welldensity spacing, safety and protection of the environment;

•                  the depletionrates of existing wells;

•                  adverse weatherand other natural phenomena;

•                  the availabilityof drilling and service rigs; and

•                  industrychanges, including the effect of consolidations or divestitures.

 

Any declinesin the volumes of natural gas delivered for gathering on our system willadversely affect our revenues and could, if sustained or pronounced, materiallyadversely affect our financial position or results of operations.

 

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***Our operations are subject togovernmental laws and regulations relating to the protection of the environmentand safety which may expose us to significant costs and liabilities.***

 

Our current operations as well as the construction of new facilitiesare subject to federal, state and local laws and regulations relating toprotection of the environment and occupational health and safety.  There is inherent risk of the incurrence ofenvironmental costs and liabilities in our operations due to permitrequirements, our handling of the products we gather or transport, airemissions related to our operations, historical industry operations, wastedisposal practices and the construction of new facilities in environmentallyprotected areas, some of which may be material. We currently own or lease, and have owned or leased, many propertiesthat have been used for many years to terminal or store crude oil, petroleumproducts or other chemicals.  Owners,tenants or users of these properties may have disposed of or releasedhydrocarbons or solid wastes on or under them. Additionally, some sites we operate are located near current or formerrefining and terminaling operations. There is a risk that contamination has migrated from those sites toours.  In addition, the possibilityexists that stricter laws, regulations or enforcement policies couldsignificantly increase our compliance costs and the cost of any remediationthat may become necessary, some of which may be material.

 

Various stateand federal governmental authorities including the U.S. EnvironmentalProtection Agency, the Bureau of Land Management, the Department ofTransportation and the Occupational Safety and Health Administration have thepower to enforce compliance with these regulations and the permits issued underthem, and violators are subject to administrative, civil and criminalpenalties, including civil fines, injunctions or both.  Liability may be incurred without regard tofault under CERCLA, RCRA, and analogous state laws for the remediation ofcontaminated areas.  Private parties,including the owners of properties through which our pipeline systems pass, mayalso have the right to pursue legal actions to enforce compliance as well as toseek damages for non-compliance with environmental laws and regulations or forpersonal injury or property damage.

 

Our insurancemay not cover all environmental risks and costs or may not provide sufficientcoverage in the event an environmental claim is made against us.  Our business may be adversely affected byincreased costs due to stricter pollution control requirements or liabilitiesresulting from non-compliance with required operating or other regulatorypermits.  New environmental regulationsmight adversely affect our products and activities, including processing, storage,transportation and construction and maintenance activities, as well as wastemanagement and air emissions.  Federaland state agencies also could impose additional safety requirements, any ofwhich could affect our profitability.

 

Contaminationresulting from spills or releases of petroleum products is an inherent riskwithin the petroleum pipeline industry. To the extent that groundwater contamination requiring remediationexists along our pipeline systems as a result of past operations, we believe anysuch contamination could be controlled or remedied without having a materialadverse effect on our financial position, but such costs are site specific, andwe cannot be assured that the effect will not be material in the aggregate.

 

***Terrorist attacks aimed at ourfacilities could adversely affect our business.***

 

On September11, 2001, the United States was the target of terrorist attacks ofunprecedented scale.  Since the September11th attacks, the United States government has issued warnings that energyassets, specifically our nation’s pipeline infrastructure, may be the futuretarget of terrorist organizations.  Thesedevelopments have subjected our operations to increased risks.  Any future terrorist attack on ourfacilities, those of our customers and, in some cases, those of other pipelines,could have a material adverse effect on our business.

 

***Our business involves manyhazards and operational risks, some of which may not be covered by insurance.***

 

Our operationsare subject to the many hazards inherent in the transportation of refined petroleumproducts, LPGs and petrochemicals, the transportation of crude oil and thegathering, compressing, treating and processing of natural gas and NGLs and inthe storage of residue gas, including ruptures, leaks and fires.  These risks could result in substantiallosses due to personal injury or loss of life, severe damage to and destructionof property and equipment and pollution or other environmental damage and mayresult in curtailment or suspension of our related operations.  We are not fully insured against all risksincident to our business.  If asignificant accident or event occurs that is not fully insured, it couldadversely affect our financial position or results of operations.

 

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***We depend on the leadership and involvementof our key personnel for the success of our business.***

 

We depend on the leadership and involvement of our key personnel toidentify and develop business opportunities and make strategic decisions.  We are currently searching for a permanentchief executive officer.  Our chieffinancial officer was appointed in January 2006, and our general counsel willbe appointed effective March 1, 2006, each having approximately twenty or moreyears of relevant experience.  However,while retention plans are in place for certain senior executives, any futureunplanned departures could have a material adverse effect on our business,financial conditions and results of operations. Legacy senior executives have compensation agreements in place; however,new leadership appointments are not party to any compensation agreements.

 

**RisksRelating to Our Partnership Structure**

 

***We are a holding company anddepend entirely on our operating subsidiaries’ distributions to service ourdebt obligations.***

 

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

 

The debtsecurities issued by us and the guarantees issued by our subsidiary guarantorswill be structurally subordinated to the claims of the creditors of ouroperating subsidiaries who are not guarantors of the debt securities.   Our non-guarantor operating subsidiariescurrently have no indebtedness for borrowed money.  Holders of the debt securities will not becreditors of our operating partnerships that have not guaranteed the debtsecurities.  The claims to the assets ofnon-guarantor operating subsidiaries derive from our own partnership interestsin those operating subsidiaries.  Claimsof our non-guarantor operating subsidiaries’ creditors will generally havepriority as to the assets of those operating subsidiaries over our ownpartnership interest claims and will therefore have priority over the holdersof our debt, including the debt securities. Our non-guarantor operating subsidiaries’ creditors may include:

 

•                  generalcreditors,

•                  trade creditors,

•                  securedcreditors,

•                  taxingauthorities, and

•                  creditorsholding guarantees.

 

***We may issue additional limitedpartnership interests, diluting existing interests of unitholders andbenefiting our General Partner*.**

 

Ourpartnership agreement allows us to issue additional Units and other equitysecurities without unitholder approval. These additional securities may be issued to raise cash or acquireadditional assets or businesses or for other partnership purposes.  Our partnership agreement does not limit thenumber of Units and other equity securities we may issue.  If we issue additional Units or other equitysecurities, the proportionate partnership interest and voting power of ourexisting unitholders will decrease.  Theissuance could negatively affect the amount of cash distributed to unitholdersand the market price of our Units.  Atour current level of cash distributions, our General Partner receives asincentive distributions approximately 50% of any incremental increase in ourdistributions.  As a result, acquisitionsfunded through the issuance of additional Units may benefit our General Partnermore than our unitholders.

 

***Our tax treatment depends on our status as a partnership forfederal income tax purposes and our exemption from state-level taxation bystates.***

 

Ifwe were treated as a corporation, cash distributions would be reducedsubstantially.  One of the primarybenefits of investing in our Units is dependent on the treatment of our entityas a partnership for federal income tax purposes.   Currently, to maintain our partnershipstatus under the “Qualifying Income Exception”, we must derive 90% of annualgross income from certain activities.  We may not be able to meet this requirement despite our best

 

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

 

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

 

***Some of our executive officersand directors face potential conflicts of interest in managing our business.***

 

Certain of ourexecutive officers and directors are also officers and/or directors of EPCO andother affiliates of EPCO.  Theserelationships may create conflicts of interest regarding corporateopportunities and other matters.  Theresolution of any such conflicts may not always be in our or our unitholders’best interests.  In addition, theseoverlapping executive officers and directors allocate their time among us, EPCOand other affiliates of EPCO.  Theseofficers and directors face potential conflicts regarding the allocation oftheir time, which may adversely affect our business, results of operations andfinancial condition.  See Item 10 of thisReport for more detailed information.

 

***Our General Partner and itsaffiliates may have conflicts with our partnership.***

 

The directorsand officers of our General Partner and its affiliates (including EPCO and otheraffiliates of EPCO) have duties to manage the General Partner in a manner thatis beneficial to its member.  At the sametime, the General Partner has duties to manage us in a manner that isbeneficial to us.  Therefore, the GeneralPartner’s duties to us may conflict with the duties of its officers anddirectors to its member.  Provisions ofour partnership agreement, the partnership agreements for each of our operatingpartnerships and/or the administrative services agreement provide for astandard of care that may allow our General Partner to approve actions in thecontext of possible conflicts, which under state law a corporation would berequired to analyze with greater scrutiny. Possible conflicts may include, among others, the following:

 

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

•                  decisionsof our General Partner regarding our acquisitions, expansions or businessstrategy, which may provide benefits to the General Partner and its affiliates;

•                  underour partnership agreement we reimburse the General Partner for the costs ofmanaging and operating us;

•                  underour partnership agreement, it is not a breach of our General Partner’sfiduciary duties for affiliates of our General Partner to engage in activitiesthat compete with us;

•                  thedirectors and officers of our General Partner are allowed to resolve conflictsof interest involving us and EPCO and its affiliates;

•                  thedirectors and officers of our General Partner are allowed to take into accountthe interests of parties other than us, such as EPCO and its affiliates, inresolving conflicts of interest;

•                  anyresolution of a conflict of interest by the directors and officers of ourGeneral Partner not made in bad faith and that is fair and reasonable to usshall be binding on the partners and shall not be a breach of our partnershipagreement;

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

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

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

 

 

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

 

***Unitholders have limited votingrights and control of management.***

 

Our GeneralPartner manages and controls our activities and the activities of our operatingpartnerships.  Unitholders have no rightto elect the General Partner or the directors of the General Partner on anannual or other ongoing basis.  However,if the General Partner resigns or is removed, its successor may be elected byholders of a majority of the Units. Unitholders may remove the General Partner only by a vote of the holdersof at least 66 2/3% of the Units and only after receiving state regulatoryapprovals required for the transfer of control of a public utility.  As a result, unitholders will have limitedinfluence on matters affecting our operations, and third parties may find itdifficult to gain control of us or influence our actions.

 

***If EPCO or other entities thatown or control our General Partner are presented with certain businessopportunities, Enterprise will have the first right to pursue suchopportunities.***

 

Our previous relationship with DEFS and Duke Energyfrom time to time resulted in business opportunities for us.  We do not know whether similar opportunitieswill be available from EPCO or its affiliates.  EPCO, Enterprise, DFI and certain affiliatedentities (collectively, the “Group”), our General Partner and us, are partiesto an administrative services agreement that provides, among other things, thatneither the Group, on one hand, nor our General Partner, on the other hand,have any obligation to present business opportunities to the other.

 

***To the extent that our GeneralPartner shares executive offices or other personnel with EPCO and itsaffiliates, there may be conflicts in the allocation of their time andcompensation costs between our business and the business of EPCO and its otheraffiliates.***

 

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

 

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to us may also have duties and responsibilitiesrelated to EPCO and its affiliates, including Enterprise.  The services performed by these sharedpersonnel will generally be limited to non-commercial functions, including butnot limited to human resources, information technology, financial andaccounting services and legal services. EPCO may encounter conflicts of interest in allocating the availabletime and employee costs of shared personnel between us and other EPCOaffiliates.

 

We do not havean independent compensation committee and our independent directors do notdeliberate, decide or approve recommendations related to the compensation ofour executive officers or other key employees. The determination of executive officer and key employee compensationcould involve conflicts of interest resulting in economically unfavorablearrangements for us.

 

# **Item1B.   *Unresolved Staff Comments***

 

None.

 

***Item 3.     *Legal Proceedings**

 

In the fall of 1999 and on December 1, 2000, the General Partner andthe Partnership were named as defendants in two separate lawsuits in JacksonCounty Circuit Court, Jackson County, Indiana, styled *Ryan E.McCleery and Marcia 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 Settlement Agreementswith the McCleery plaintiffs and the Richards plaintiffs dismissing all ofthese plaintiffs’ claims on terms that did not have a material adverse effecton our financial position, results of operations or cash flows.  Although we did not settle with allplaintiffs and we therefore remain named parties in the *Ryan E.McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al*.action, a co-defendant has agreed to indemnify us for all remaining claimsasserted against us.  Consequently, we donot believe that the outcome of these remaining claims will have a materialadverse effect on our financial position, results of operations or cash flows.

 

On December 21, 2001, TE Products was named as a defendant in a lawsuitin 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.

 

In May 2003, the General Partner was named as a defendant in a lawsuitstyled *John R. James, et al. v. J Graves InsulationCompany, et al.* as filed in the first Judicial District Court, CaddoParish, Louisiana.  There are numerousplaintiffs identified in the action that are alleged to have suffered damagesas a result of alleged exposure to asbestos-containing products andmaterials.  According to the petition andas a result of a preliminary investigation, the General Partner believes thatthe only claim asserted against it results from one individual for the periodfrom July 1971 through June 1972, who is alleged to have worked on a facilityowned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposureperiod from January 1964 through December 2001 for this individual.  The individual’s claims involve numerousemployers and alleged job

 

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sites.  TheGeneral Partner has been unable to confirm involvement by the General Partneror its predecessors with the alleged location, and it is uncertain at this timewhether this case is covered by insurance. Discovery is planned, and theGeneral Partner intends to defend itself vigorously against this lawsuit.  The plaintiffs have not stipulated the amountof damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs itincurs related to this lawsuit.  Wecannot estimate the loss, if any, associated with this pending lawsuit.  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 August 5, 2005, we were named as a third-party defendant in a matterstyled *ConocoPhillips, et al. v. BP Amoco Seaway ProductsPipeline Company*as filed in the 55th Judicial Districtof Harris County, Texas.  ConocoPhillipsalleges a right to indemnity from BP Amoco Seaway Products Pipeline Company (“BPAmoco”) for tax liability incurred by ConocoPhillips as a result of the reversemerger of Seaway Pipeline Company (the “Original Seaway Partnership”).  The reverse merger of the Original SeawayPartnership was undertaken in preparation for our purchase of ARCO Pipe LineCompany pursuant to the Amended and Restated Purchase Agreement (the “PurchaseAgreement”) dated May 10, 2000, between us and Atlantic Richfield Company. BPAmoco has claimed a right to indemnity from us under the Purchase Agreementshould BP Amoco have any indemnity liability to ConocoPhillips.  ConocoPhillips alleged the income taxliability to be approximately $4.0 million. On January 20, 2006, we entered into a settlement agreement with BPAmoco dismissing and resolving all of BP Amoco’s claims. The terms of thesettlement did not have a material adverse effect on our financial position,results of operations or cash flows.

 

In 1991, we were named as a defendant in a matter styled *Jimmy R. Green, et al. v. Cities Service Refinery, et al.*asfiled in the 26th Judicial District Court of Bossier Parish,Louisiana.  The plaintiffs in this matterreside or formerly resided on land that was once the site of a refinery ownedby one of our co-defendants.  The formerrefinery is located near our Bossier City facility.  Plaintiffs have claimed personal injuries andproperty damage arising from alleged contamination of the refineryproperty.  The plaintiffs have recentlypursued certification as a class and have significantly increased their demandto approximately $175.0 million.  Thisrevised demand includes amounts for environmental restoration not previouslyclaimed by the plaintiffs.  We have neverowned any interest in the refinery property made the basis of this action, andwe do not believe that we contributed to any alleged contamination of this property.  While we cannot predict the ultimate outcome,we do not believe that the outcome of this lawsuit will have a material adverseeffect on our financial position, results of operations or cash flows.

 

In 1994, the Louisiana Department of Environmental Quality (“LDEQ”)issued a compliance order for environmental contamination at our Arcadia,Louisiana, facility.  In 1999, ourArcadia facility and adjacent terminals were directed by the RemediationServices Division of the LDEQ to pursue remediation of this contamination.  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.  At December 31, 2005, we have an accruedliability of $0.2 million for remediation costs at our Arcadia facility.  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.

 

On July 27, 2004, we received notice from theUnited States Department of Justice (“DOJ”) of its intent to seek a civilpenalty against us related to our November 21, 2001, release of approximately2,575 barrels of jet fuel from our 14-inch diameter pipeline located in OrangeCounty, Texas.  The DOJ, at the requestof the EPA, is seeking a civil penalty against us for alleged violations of theCWA arising out of this release.  We arein discussions with the DOJ regarding this matter and have responded to itsrequest for additional information.  Themaximum statutory penalty proposed by the DOJ for this alleged violation of theCWA is $2.1 million.  We do not expect acivil penalty to have a material adverse effect on our financial position,results of operations or cash flows.

 

On February 24, 2005, the General Partner was acquired from DEFS byDFI.  The General Partner owns a 2%general partner interest in us and is the general partner of thePartnership.  On March 11, 2005, theBureau of Competition of the Federal Trade Commission (“FTC”) delivered writtennotice to DFI’s legal advisor that it was conducting a non-public investigationto determine whether DFI’s acquisition of the General Partner may substantiallylessen competition.  The General Partneris cooperating fully with this investigation.

 

On September18, 2005, a propane release and fire occurred at our Todhunter facility, nearMiddletown, Ohio.  The incident resultedin the death of one of our employees. There were no other injuries. On or aboutFebruary 22, 2006, we received verbal notification from a representative of theOccupational Safety and Health Administration that they intend to serve us witha citation arising out of this incident. At this time, we have not received any citation, and we cannot predictwith certainty the amount of any fine or penalty associated with any suchcitation; however, we do not expect any fine or penalty to have a materialadverse effect on our financial position, results of operations or cash flows. 

 

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In addition to the proceedings discussed above, we have been, in theordinary course of business, a defendant in various lawsuits and a party tovarious other legal proceedings, some of which are covered in whole or in partby 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.

 

***Item 4.     *Submission of Matters to aVote of Security Holders**

 

None.

 

**PART II**

 

***Item 5.     *Market for Registrant’sUnits and Related Unitholder Matters**

 

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

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

 

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

 

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

 
| **Record Date**   | ** ** | **Payment Date**  | ** ** | **Amount   Per Unit** | ** ** |
|-------------------|------------|-------------------|------------|-----------------------|------------|
| April 30,  2004   |       | May 7, 2004       |       | $                     | 0.6625     |   |
| July 30,  2004    |       | August 6,  2004   |       | 0.6625                |       |
| October 29,  2004 |       | November 5,  2004 |       | 0.6625                |       |
| January 31,  2005 |       | February 7,  2005 |       | 0.6625                |       |
|              |       |              |       |                  |       |
| April 29,  2005   |       | May 6, 2005       |       | $                     | 0.6625     |   |
| July 29, 2005     |       | August 5,  2005   |       | 0.675                 |       |
| October 31,  2004 |       | November 7,  2005 |       | 0.675                 |       |
| January 31,  2006 |       | February 7,  2006 |       | 0.675                 |       |

 

We make quarterly cash distributions of all of our Available Cash,generally defined as consolidated cash receipts less consolidated cashdisbursements and cash reserves established by the General Partner in its solediscretion.  Pursuant to the PartnershipAgreement, the General Partner receives incremental incentive cashdistributions when unitholders’ cash distributions exceed certain targetthresholds (see Note 11 in the Notes to the Consolidated FinancialStatements).  We expect to continue topay comparable quarterly cash distributions, assuming no adverse change in ourfinancial position, results of operations or cash flows.

 

31

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We are a publicly traded master limited partnership and are not subjectto federal income tax. Instead, unitholders are required to report theirallocated share of our income, gain, loss, deduction and credit, regardless ofwhether we make distributions.  We havemade quarterly distribution payments since May 1990.

 

Distributions of cash paid by us to a unitholder will not result intaxable gain or income except to the extent the aggregate amount distributed exceedsthe tax basis of the Units owned by the unitholder.

 

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

 

The following tables set forth, for the periods and atthe dates indicated, our selected consolidated financial and operatingdata.  The selected financial data as ofDecember 31, 2005, 2004 and 2003 and for the years ended December 31, 2005,2004 and 2003, is derived from audited consolidated financial statements, whichis included elsewhere in this Report. The selected financial data for the years ended December 31, 2002 and2001, is derived from unaudited consolidated financial statements and, in theopinion of management, has been prepared in accordance with accountingprinciples generally accepted in the United States of America and reflects alladjustments which are, in the opinion of management, necessary for a fairpresentation of results for these periods. With the exception of December 31, 2005, the financial information shownbelow has been restated to reflect a restatement adjustment for an accounting correction(see also “Explanatory Note” in this Form 10-K and Note 20 in the Notes to theConsolidated Financial Statements).  Thefinancial data should be read in conjunction with our audited consolidatedfinancial statements included in the Index to Consolidated Financial Statementson page F-1 of this Report. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Resultsof Operations.

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

 

32

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

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

 

----

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

 

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

 

(3)          See Note 20of the Notes to Consolidated Financial Statements for the effect of therestatement adjustment on net income for the years ended December 31, 2004 and2003.  The restatement adjustmentdecreased net income for the year ended December 31, 2002, by $3.1 million, or$0.05 per Unit, and increased net income for the year ended December 31, 2001,by $0.2 million, or $0.01 per Unit, respectively.

 

(4)          Per Unitcalculation includes 7,750,000 Units issued in 2001, 13,359,597 Units issued in2002 and 9,188,957 Units issued in 2003, net of retirement of Class B Units of3,916,547.  No Units were issued in2004.  In 2005, 6,965,000 Units wereissued.

 

***Item7.   *Management’sDiscussion and Analysis of Financial Condition and Results of Operations**

 

The following information should be read in conjunction with ourconsolidated financial statements and our accompanying notes listed in theIndex to Consolidated Financial Statements on page F-1 of this Report.  Our discussion and analysis includes thefollowing:

 

•                  Overview of Business.

 

•                  Restatement of Consolidated FinancialStatements – Discusses the restatement adjustment.

 

•                  Critical Accounting Policies andEstimates – Presents accounting policies that are among the most critical tothe portrayal of our financial condition and results of operations.

 

•                  Results of Operations – Discussesmaterial period-to-period variances in the consolidated statements of income.

 

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

 

•                  Other Considerations – Addresses availablesource of liquidity, trends, future plans and contingencies that are reasonablylikely to materially affect future liquidity or earnings.

 

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This discussion contains forward-looking statements based on currentexpectations that are subject to risks and uncertainties, such as statements ofour plans, objectives, expectations and intentions.  When used in this discussion, the words “proposed,”“anticipate,” “potential,” “may,” “will,” “could,” “should,” “expect,”estimate,” “believe,” “intend,” “plan,” “seek” and similar expressions areintended to identify forward-looking statements.  Our actual results and the timing of eventscould differ materially from those anticipated or implied by theforward-looking statements discussed here as a result of various factors,including, among others, those set forth under the “Cautionary Note RegardingForward-Looking Statements” and “Risk Factors” herein.  You should not place undue reliance on theseforward-looking statements, which speak only as of the date of thisReport.  Except as required by law, weundertake no obligation to publicly update or revise any of the forward-lookingstatements in this discussion after the date of this Report.

 

## ****Overview of Business****

 

Our corporate business strategy is to grow sustainable cash flow andcash distributions to our unitholders. The key elements of our strategy are to focus on internal growthprospects in order to increase the pipeline system and terminal throughput,expand and upgrade existing assets and services and construct new pipelines,terminals and facilities, to target accretive and complementary acquisitionsand expansion opportunities that provide attractive growth potential; tomaintain an appropriate mix of assets; and to operate in a safe, efficient andenvironmentally responsible manner.

 

Certain factors are key to our operations.  These include the safe, reliable andefficient operation of the pipelines and facilities that we own or operatewhile meeting the regulations that govern the operation of our assets and thecosts 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.  We operate andreport in three business segments:

 

•                  Our Downstream Segment, which isengaged in the transportation and storage of refined products, LPGs andpetrochemicals;

 

•                  Our Upstream Segment, which isengaged in the gathering, transportation, marketing and storage of crude oiland distribution of lubrication oils and specialty chemicals; and

 

•                  Our MidstreamSegment, which is engaged in the gathering of natural gas, transportation ofNGLs and fractionation of NGLs.

 

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

 

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 consist primarilyof aggregating purchased crude oil along our pipeline systems, or from thirdparty 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 in the Notes to theConsolidated Financial Statements). Seaway consists of large diameter pipelines that transport crude oilfrom Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, acrude oil distribution point for the central United States, and to refineriesin the Texas City and Houston areas.

 

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

 

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

 

•                  Substantially completingthe Phase IV expansion on the Jonah system, increasing capacity toapproximately 1.5 billion cubic feet per day.

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

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

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

•                  Continuing the expansion of ourNortheast LPGs pipeline system.

•                  Acquiring a refined products terminaland truck rack in North Little Rock, Arkansas, to complement our existinginfrastructure.

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

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

 

In 2006, we remain confidentthat our business strategy will provide continued growth in earnings and cashdistributions.  This growth potential isbased on:

 

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

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

•                  Substantially completing an expansionproject to increase delivery capacity of gasoline and diesel fuel to theIndianapolis, Indiana, and Chicago market areas.

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

•                  Continued growth in our UpstreamSegment, resulting from expansions of our West Texas systems and storagecapacity at Cushing.

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

•                  Increasing the throughput on our NGLsystems.

 

Our Upstream Segment’sperformance will be impacted by a decrease in our participation ratio in therevenue and expense of Seaway, in accordance with the partnershipagreement.  From June 2002 through May2006, we receive 60% of revenue and expense of Seaway.  Thereafter, we will receive 40% of revenueand expense of Seaway.  On a pro-ratedbasis, our share of revenue and expense of Seaway will decrease toapproximately 47% for 2006.

 

35

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We expect to complete the sale of our ownershipinterest in the Pioneer silica gel natural gas processing plant located inOpal, Wyoming, to Enterprise by the middle of 2006.  The proposed sale of the Pioneer plant wasinitiated because it is not an integral part of our Midstream Segmentoperations, and natural gas processing is not a core business.  The anticipated sales proceeds would be usedto fund organic growth projects, retire debt, or for other general partnershippurposes.  The margin of the MidstreamSegment, calculated as revenues generated from the processing arrangements atthe Jonah Pioneer plant, less purchase of gas, will be reduced in 2006 as aresult of the anticipated sale of the Pioneer plant.  We do not expect that the sale of the Pioneerplant will have a material adverse effect on our financial condition, resultsof operations or cash flows.

 

We expect to expand the Jonah system with a servicedate for such expansion being late 2006. We expect to enter into a joint venture agreement with Enterprise relatingto the construction and financing of the expansion.  Enterprise will be responsible for allactivities relating to the construction of the Jonah Expansion and will advanceall amounts necessary to plan, engineer, construct or complete the JonahExpansion (anticipated to be approximately $200.0 million).  Such advance will constitute a Subscriptionfor an equity interest in the proposed Joint Venture.  We have the option to return to Enterprise upto 100% of the amount of the Subscription. If we return a portion of the Subscription to Enterprise, our relativeinterests in the proposed Joint Venture will be adjusted accordingly.  The proposed Joint Venture will terminatewithout liability to either party if we return 100% of the Subscription.

 

Consistent with our business strategy, we continuouslyevaluate possible acquisitions of assets that would complement our currentoperations, including assets which, if acquired, would have a material effecton our financial position, results of operations or cash flows.

 

**Restatement of Consolidated Financial Statements**

 

We arerestating our previously reported consolidated financial statements for thefiscal years ended December 31, 2003 and 2004. For the impact of the restated consolidated financial results for thequarterly periods during the years ended December 31, 2005 and 2004, see Note20 in the Notes to the Consolidated Financial Statements.  We have determined that our method ofaccounting for the $33.4 million excess investment in Centennial, previouslydescribed as an intangible asset with an indefinite life, and the $27.1 millionexcess investment in Seaway, previously described as equity method goodwill,was incorrect.  Through our accountingfor these excess investments in Centennial and Seaway as intangible assets withindefinite lives and equity method goodwill, respectively, we have been testingthe amounts for impairment on an annual basis as opposed to amortizing themover a determinable life.  We determinedthat it would be more appropriate to account for these excess investments asintangible assets with determinable lives. As a result, we made non-cash adjustments that reduced the net value ofthe excess investments in Centennial and Seaway, and increased amortizationexpense allocated to our equity earnings. The effect of this restatement caused a $3.8 million and $4.0 millionreduction to net income as previously reported for the fiscal years endedDecember 31, 2004 and 2003, respectively. As a result of the accounting correction, net income for the fiscal yearended December 31, 2005, includes a charge of $4.8 million, of which $3.8million relates to the first nine months. Additionally, partners’ capital at December 31, 2002, reflects a $2.5million reduction representing the cumulative effect of this correction forfiscal years ended December 31, 2000 through 2002.

 

While webelieve the impacts of these non-cash adjustments are not material to anypreviously issued financial statements, we determined that the cumulativeadjustment for these non-cash items was too material to record in the fourthquarter of 2005, and therefore it was most appropriate to restate prior periods’results.  These non-cash adjustments hadno effect on our operating income, compensation expense, debt balances orability to meet all requirements related to our debt facilities.  The restatement had no impact on total cashflows from operating activities, investing activities or financingactivities.  All amounts in theaccompanying consolidated financial statements have been adjusted for thisrestatement.

 

We will continue to amortize the $30.0 million excessinvestment in Centennial related to a contract using units-of-productionmethodology over a 10-year life.  Theremaining $3.4 million related to a pipeline will continue to be amortized on astraight-line basis over 35 years.  Wewill continue to

 

36

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

 

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

 

The preparation of financial statements in accordance with accountingprinciples generally accepted in the United States requires management to makeestimates and assumptions that affect the reported amounts of assets andliabilities as well as the disclosure of contingent assets and liabilities atthe date of the financial statements. Such estimates and assumptions also affect the reported amounts ofrevenues and expenses during the reporting period.  Changes in these estimates could materiallyaffect our financial position, results of operations or cash flows.  Although we believe that these estimates arereasonable, actual results could differ from these estimates.  Significant accounting policies that weemploy are presented in the notes to the consolidated financial statements (seeNote 2 in the Notes to the Consolidated Financial Statements).

 

Critical accounting policies are those that are most important to theportrayal of our financial position and results of operations.  These policies require management’s mostdifficult, subjective or complex judgments, often employing the use of estimatesand assumptions about the effect of matters that are inherently uncertain.  Our critical accounting policies pertain torevenue and expense accruals, environmental costs, property, plant andequipment and goodwill and intangible assets.

 

*Revenue and ExpenseAccruals*

 

We routinely make accruals based on estimates for both revenues andexpenses due to the timing of compiling billing information, receiving certainthird party information and reconciling our records with those of thirdparties.  The delayed information fromthird parties includes, among other things, actual volumes of crude oilpurchased, transported or sold, adjustments to inventory and invoices forpurchases, actual natural gas and NGL deliveries and other operating expenses.  We make accruals to reflect estimates forthese items based on our internal records and information from thirdparties.  Most of the estimated accrualsare reversed in the following month when actual information is received fromthird parties and our internal records have been reconciled.

 

The most difficult accruals to estimate are power costs, property taxesand crude oil margins.  Power costaccruals generally involve a two to three month estimate, and the amount variesprimarily for actual power usage.  Powercosts are dependent upon the actual volumes transported through our pipelinesystems and the various power rates charged by numerous power companies alongthe pipeline system.  Peak demand rates,which are difficult to predict, drive the variability of the power costs.  For the year ended December 31, 2005,approximately 12% of our power costs were recorded using estimates.  A variance of 10% in our aggregate estimatefor power costs would have an approximate $0.6 million impact on annualearnings.  Property tax accruals involvesignificant tax rate estimates in numerous jurisdictions.  Actual property taxes are often not knownuntil the tax bill is settled in subsequent periods, and the tax amount canvary for tax rate changes and changes in tax methods or elections.  A variance of 10% in our aggregate estimatefor property taxes could have up to an approximate $1.4 million impact onannual earnings.  Crude oil marginestimates are based upon an average of the past twelve months of crude oilmarketing volumes, factoring in current market events, and prices of crudeoil.  We use an average of prices thatwere in effect during the applicable month to determine the expected revenueamount, and we determine the margin by evaluating the actual margins of theprior twelve months.  As of December 31,2005, approximately 11% of our annual crude oil margin is recorded usingestimates.  A variance from this estimateof 10% would impact the respective line items by approximately $1.2 million onan annual basis.  Although the resolutionof these uncertainties has not historically had a material impact on ourreported results of operations or financial condition, because of the highvolume, low margin nature of our business, we cannot provide assurance thatactual amounts will not vary significantly from estimated amounts.  Variances from estimates are reflected in theperiod actual results become known, typically in the month following theestimate.

 

*EnvironmentalCosts*

 

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

 

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for remediation and restoration of sites determined tobe contaminated and ongoing monitoring costs, as well as damages and othercosts, when estimable.  We monitor thebalance of accrued undiscounted environmental liabilities on a regularbasis.  We record liabilities forenvironmental costs at a specific site when our liability for such costs isprobable and a reasonable 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 environmental lawsand regulations. A variance of 10% in our aggregate estimate for environmentalcosts would have an approximate $0.3 million impact on annual earnings.  For information concerning environmentalregulation and environmental costs and contingencies, see Items 1 and 2.Business and Properties – Environmental and Safety Matters.

 

*Property, Plantand Equipment*

 

We regularly review long-lived assets for impairment in accordance withStatement of Financial Accounting Standards (“SFAS”) No. 144, *Accounting for the Impairment or Disposal of Long-Lived Assets. *Long-lived assets are reviewed forimpairment whenever events or changes in circumstances indicate that thecarrying amount of an asset may not be recoverable.  Such events or changes include, among otherfactors:  operating losses, unusedcapacity; market value declines; technological developments resulting inobsolescence; changes in demand for products in a market area; changes incompetition and competitive practices; and changes in governmental regulationsor actions.  Recoverability of thecarrying amount of assets to be held and used is measured by a comparison ofthe carrying amount of the asset to estimated future undiscounted net cashflows expected to be generated by the asset. Estimates of future undiscounted net cash flows include anticipatedfuture revenues, expected future operating costs and other estimates.  Such estimates of future undiscounted netcash flows are highly subjective and are based on numerous assumptions aboutfuture operations and market conditions. 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 estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carryingamount or estimated fair value less costs to sell.

 

*Goodwill and Intangible Assets*

 

Goodwill and intangible assets represent the excess of considerationpaid over the estimated fair value of tangible net assets acquired.  Certain assumptions and estimates areemployed in determining the estimated fair value of assets acquired includinggoodwill and other intangible assets as well as determining the allocation ofgoodwill to the appropriate reporting unit. In addition, we assess the recoverability of these intangibles bydetermining whether the amortization of these intangibles over their remaininguseful lives can be recovered through undiscounted estimated future net cashflows of the acquired operations.  Theamount of impairment, if any, is measured by the amount by which the carryingamounts exceed the projected discounted estimated future operating cash flows.

 

During 2002, we adopted SFAS No. 142, *Goodwill andOther Intangible Assets*, which discontinues the amortization of goodwilland intangible assets that have indefinite lives and requires an annual test ofimpairment based on a comparison of the estimated fair value to carryingvalues.  The evaluation of impairment forgoodwill and intangible assets with indefinite lives under SFAS 142 requiresthe use of projections, estimates and assumptions as to the future performanceof the operations, including anticipated future revenues, expected futureoperating costs 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 in the Notes to the Consolidated FinancialStatements).  At December 31, 2005, therecorded value of goodwill was $16.9 million.

 

At December 31, 2005, we have $344.0 million of intangible assets, netof accumulated amortization, related to natural gas transportation contractswhich were recorded as part of our acquisitions of Jonah on September 30, 2001,and Val Verde on June 30, 2002.  Thevalue assigned to the natural gas transportation contracts required managementto make estimates regarding the fair value of the assets acquired.  In connection with the acquisition of Jonah,we assumed contracts that dedicate future production from natural gas wells inthe Green River Basin in

 

38

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Wyoming.  Weassigned $222.8 million of the purchase price to these production contractsbased upon a fair value appraisal at the time of the acquisition.  In connection with the acquisition of ValVerde, we assumed fixed-term gas transportation contracts with customers in theSan Juan Basin in New Mexico and Colorado. We assigned $239.6 million of the purchase price to these fixed termcontracts based upon a fair value appraisal at the time of theacquisition.  The value assigned tointangible assets is amortized on a unit-of-production basis, based upon theactual throughput of the system compared to the expected total throughput forthe lives of the contracts.  On aquarterly basis, we update throughput estimates and evaluate the remaining expecteduseful life of the contract assets based upon the best availableinformation.  A variance of 10% in ouraggregate production estimate for the Jonah and Val Verde systems would have anapproximate $7.5 million impact on annual amortization expense.  Changes in the estimated remaining productionwill impact the timing of amortization expense reported for future periods.

 

At December 31, 2005, we have $43.8 million of excess investments, netof accumulated amortization, in our equity investments in Centennial andSeaway, which are being amortized over periods ranging from 10 to 39 years (seeNote 3 in Notes to Consolidated Financial Statements). The value assigned toour excess investment in Centennial was created upon its formation.  Approximately $30.0 million is related to acontract and is being amortized on a unit-of-production basis based upon thevolumes transported under the contract compared to the guaranteed totalthroughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is beingamortized on a straight-line basis over the life of the pipeline, which is 35years.  The value assigned to our excessinvestment in Seaway was created upon acquisition of our 50% ownership interestin 2000.  We are amortizing the $27.1million excess investment in Seaway on a straight-line basis over a 39-yearlife related primarily to the life of the pipeline.  A variance of 10% in our amortization expenseallocated to equity earnings could have up to an approximate $0.5 millionimpact on annual earnings.

 

**Results of Operations**

 

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

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

 

Below is a detailed analysis of the results ofoperations, including reasons for changes in results, by each of our operatingsegments.

 

39

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## **Downstream Segment**

 

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

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

 

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

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

 

----

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

 

Our Downstream Segment’s results aredependent in large part on the demand for refined products and LPGs in themarkets served by its pipelines. Reductions in that demand adversely affect the pipeline business of theDownstream Segment.  Market demand variesbased upon the different end uses of the products shipped in the DownstreamSegment.  Demand for gasoline, which inrecent years has accounted for approximately forty percent of the DownstreamSegment’s refined products transportation revenues, depends upon price,prevailing economic conditions and demographic changes in the markets served inthe Downstream Segment.  Demand fordistillates is affected by truck and railroad freight, the price of natural gasused by utilities, which use distillates as a substitute for natural gas whenthe price of natural gas is high, and usage for agricultural operations, whichis affected by weather conditions, government policy and crop prices.  Demand for jet fuel, which in recent yearshas accounted for approximately twenty percent of the Downstream Segment’srefined products revenues, depends on prevailing economic conditions andmilitary usage.  Propane deliveries aregenerally sensitive to the weather and meaningful year-to-year variances haveoccurred in the past and will likely continue to occur in the future.

 

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

 

Revenues from refined productstransportation decreased $3.6 million for the year ended December 31, 2005,compared with the year ended December 31, 2004. Revenues from refined products transportation decreased primarily due tothe recognition of $4.1 million of deferred revenue in 2004 related to theexpiration of two customer transportation agreements.  Under some of our transportation agreementswith customers, the contracts specify minimum payments for transportationservices.  If the transportation servicespaid for are not used, the unused transportation service is recorded asdeferred revenue.  The contractsgenerally specify a subsequent period of time in which the customer cantransport 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 that period.

 

Additionally, refined productsrevenues decreased due to reduced deliveries of product as a result ofHurricanes Katrina and Rita in August and September 2005, as discussedbelow.  These decreases in revenues fromrefined products transportation resulting from the hurricanes were partiallyoffset by an overall increase in the refined products volumes deliveredprimarily due to deliveries of products moved on Centennial.  Volume increases were due to increased demandand market share for products supplied from the U.S. Gulf Coast into Midwestmarkets. The refined products average rate per barrel decreased from the prioryear period primarily due to the impact of greater growth in the volume ofproducts delivered under a Centennial tariff compared with the growth indeliveries under a TEPPCO tariff, which resulted in an increased proportion oflower tariff barrels transported on our system. In February 2003, we entered into a lease agreement with Centennial thatincreased our flexibility to deliver refined products to our market areas.  Volumes transported on Centennial increaseddue to increased demand and market share for products supplied from the U.S.Gulf Coast into Midwest markets. Centennial has provided our system with additional pipeline capacity forproducts originating in the U.S. Gulf Coast area.  Prior to the construction of Centennial,deliveries on our pipeline system were limited by our pipeline capacity, andtransportation services for our customers were allocated in accordance with aproration policy.  With this incrementalpipeline capacity, our previously constrained system has expanded deliveries inmarkets both south and north of Creal Springs, Illinois.

 

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

 

Revenues from refined products and LPGs were also impacted byHurricanes Katrina and Rita, which affected the U.S. Gulf Coast in August andSeptember 2005, respectively.  HurricaneKatrina disrupted refineries and other pipeline systems in the central U.S.Gulf Coast, which provided us with additional deliveries at Shreveport andArcadia, Louisiana, as shippers used alternative sources to supply product toareas where normal distribution patterns were disrupted.  Hurricane Katrina also resulted in higherprices of refined products and LPGs, which had a negative impact on the currentdemand for the products.  Hurricane Ritadisrupted production at western U.S. Gulf Coast refineries, many of whichdirectly supply us with product. Hurricane Rita also disrupted power to our Beaumont terminal, whichresulted in the mainline being shut down for four days and Centennial beingshut down for ten days.  Our 230,000barrel per day capacity, 20-inch diameter mainline system, which primarilydelivers LPGs and gasoline from the Texas Gulf Coast to the Midwest, waspumping from MB Storage’s facility at approximately 60% of normal operatingcapacity until mid-October.  Our 110,000barrel per day capacity, 14-inch and 16-inch diameter pipelines, whichprimarily deliver distillates and gasoline from the Texas Gulf Coast to theMidwest, were pumping at approximately 75% of normal operating capacity fromour Baytown, Texas, terminal until mid-October. We installed generators at our Beaumont, Texas, facility, which enabledreceipt and delivery of

 

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refinedproducts out of tankage at the terminal. Commercial power was restored to the Beaumont terminal and the Newton,Texas, pump station in mid-October and full operations were resumed.  Centennial resumed operating at its normalcapacity on October 1, 2005.

 

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

 

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

 

•                  a $15.1 million decrease in pipeline inspection andrepair costs associated with our integrity management program as we nearedcompletion of the first cycle of our integrity management program,

•                  a $2.6 million decrease in postretirement benefitaccruals related to plan amendments (see Note 15 in the Notes to theConsolidated Financial Statements),

•                  a $2.1 million decrease in products losses,

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

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

 

Thesedecreases to costs and expenses were partially offset by the following:

 

•                  a $3.4 million increase in labor and benefits expensesprimarily associated with vesting provisions in certain of our compensationplans as a result of changes in ownership of our General Partner, higher laborexpenses associated with an increase in the number of employees between yearsand higher incentive compensation expense as a result of improved operatingperformance,

•                  a $3.4 million increase in pipeline operating andmaintenance expense,

•                  a $1.8 million increase attributable to regulatorypenalties for past incidents,

•                  a $1.6 million increase in insurance expense,

•                  a $1.5 million increase related to transition costs dueto the changes in ownership of our General Partner,

•                  a $0.6 million increase in rental expense on a leaseagreement from the Centennial pipeline capacity lease agreement and

•                  an increase in other miscellaneous general andadministrative supplies expenses during the year, including a $0.4 millionincrease in environmental assessment and remediation expenses, a $0.4 millionincrease in labor and benefits expense related to retirement plan settlementswith DEFS and hurricane related expenses.

 

Depreciationexpense decreased $3.7 million primarily due to a $4.4 million non-cashimpairment charge in the third quarter of 2004, partially offset by a $0.8million write-off of assets related to the propane release and fire at astorage facility in Ohio (see Note 9 in the Notes to the Consolidated FinancialStatements), assets placed into service and assets retired to depreciationexpense in the 2005 period.  Taxes –other than income taxes increased $2.2 million primarily due to assetacquisitions and a higher tax base in the 2005 period.  Operating fuel and power expense increased$0.8 million primarily as a result of increased volumes and higher power rates duringthe 2005 period.  During the year endedDecember 31, 2004, we recognized net gains of $0.5 million from the sales ofvarious assets in the Downstream Segment.

 

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Netlosses from equity investments decreased $3.6 million for the year ended December31, 2005, compared with the year ended December 31, 2004, as shown below (inthousands):

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

 

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

 

Equityearnings in MB Storage decreased $0.2 million for the year ended December 31,2005, compared with the year ended December 31, 2004, primarily due toincreased depreciation and amortization expense and higher general andadministrative expenses, partially offset by higher rental and storage revenuesand volumes.  MB Storage was impacted byHurricane Rita, which reduced revenues and increased operating expenses.  Additionally, in April 2004, MB Storageacquired storage and pipeline assets and contracts for approximately $35.0million, of which TE Products contributed $16.5 million.  Increases in storage revenue, shuttlerevenue, rental revenue and depreciation and amortization expense for yearended December 31, 2005, compared with the year ended December 31, 2004, areprimarily related to the acquired storage assets and contracts.

 

Forthe year ended December 31, 2005, TE Products received the first $1.7 millionper quarter (or $6.78 million on an annual basis) of MB Storage’s income beforedepreciation expense, as defined in the operating agreement.  For the year ended December 31, 2004, TEProducts received the first $1.8 million per quarter (or $7.15 million on anannual basis) of MB Storage’s income before depreciation expense.  TE Products’ share of MB Storage’s earningsis adjusted annually by the partners of MB Storage.  Any amount of MB Storage’s annual incomebefore depreciation expense in excess of $6.78 million for 2005 and $7.15million for 2004 is allocated evenly between TE Products and LouisDreyfus.  Depreciation expense on assetseach party originally contributed to MB Storage is allocated between TEProducts and Louis Dreyfus based on the net book value of the assetscontributed.  Depreciation expense onassets constructed or acquired by MB Storage subsequent to formation isallocated evenly between TE Products and Louis Dreyfus. For the years endedDecember 31, 2005, 2004 and 2003, TE Products’ sharing ratio in the earnings ofMB Storage was approximately 64.2%, 69.4% and 70.4%, respectively.

 

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

 

Revenues from refined products transportation increased $9.2 millionfor the year ended December 31, 2004, compared with the year ended December 31,2003.  Refined products transportationrevenues increased primarily due to higher market-based tariff rates which wentinto effect 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 a leaseagreement with Centennial that increased our flexibility to deliver refinedproducts to our market areas.  Volumestransported on Centennial increased due to increased demand and market sharefor products supplied from the U.S. Gulf Coast into Midwest markets.  Refined products transportation revenues alsoincreased due to the recognition of $4.1 million of deferred revenue in the2004 period related to the expiration of two customer transportationagreements.

 

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

 

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propaneprices in 2004 also reduced the summer and early fall fill of consumer storageof propane during 2004.  These decreaseswere partially offset by increased deliveries of isobutane to Chicago arearefineries 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 to higher propaneinventory fees, higher margins on product inventory sales, higher revenue fromour Providence, Rhode Island import facility and higher refined products tenderdeduction, loading and custody transfer revenues.

 

Costsand expenses increased $25.4 million for the year ended December 31, 2004,compared with the year ended December 31, 2003, due to increased operating,general and administrative expenses, increased depreciation and amortizationexpense and increased operating fuel and power, partially offset by net gains onthe sales of assets.  Operating, generaland administrative expenses increased primarily due to a $6.2 million increasein 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 in the Notes to the Consolidated FinancialStatements), a $1.5 million increase in rental expense from the Centennialpipeline capacity lease agreement that we entered into in February 2003, a $1.3million increase in consulting and contract services related to compliance withthe Sarbanes-Oxley Act of 2002 and a $1.1 million increase in costs related tounsuccessful acquisition evaluations. These increases were partially offset by $0.8 million of lower expensesin the 2004 period associated with the write-off of receivables related tocustomer bankruptcies and non-payments in 2003. Depreciation expense increased from the prior year period because of a$4.4 million charge resulting from the impairment of marine assets in theBeaumont area (see Note 9 in the Notes to the Consolidated FinancialStatements).  In addition, we wrote offapproximately $2.1 million in assets taken out of service during the period todepreciation expense.  Depreciationexpense also increased approximately $5.0 million as a result of assets placedin service during 2003 and 2004, partially offset by an increase in theestimated remaining life of a section of our pipeline system in the Northeast,resulting from pipeline capital improvements made as part of our integritymanagement program.  Operating fuel andpower expense increased primarily as a result of higher power rates during the2004 period.  In addition, we recognizednet gains of $0.5 million during 2004 from the sales of various assets in theDownstream Segment.

 

Netlosses from equity investments decreased $0.8 million for the year endedDecember 31, 2004, compared with the year ended December 31, 2003, as shownbelow (in thousands):

 

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

 

Equitylosses in Centennial decreased $0.3 million for the year ended December 31,2004, compared with the year ended December 31, 2003, primarily due toincreased transportation revenues and volumes and lower operatingexpenses.  During 2003, we acquired anadditional 16.7% interest in Centennial on February 10, 2003, bringing TEProducts’ ownership interest to 50%. Included in the equity loss for the year ended December 31, 2004, is$1.2 million of equity income relating to the settlement of certain transmixmatters recognized in previous periods.

 

Equityearnings in MB Storage increased $0.5 million for the year ended December 31,2004, compared with the year ended December 31, 2003.  In April 2004, MB Storage acquired storageand pipeline assets and contracts for approximately $35.0 million, of which TEProducts contributed $16.5 million.  Theincrease in equity earnings is due to increased storage revenue, shuttlerevenue and rental revenue primarily from the acquired contracts and lowerpipeline rehabilitation expenses on the MB Storage system, partially offset byincreased amortization and depreciation expense on storage assets and contractsacquired.

 

44

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

**** ****

****Upstream Segment****

 

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

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

 

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 purchasescaused by variations in the level of volumes marketed and prices for productsmarketed.  Additionally, we use margininternally to evaluate the financial performance of the Upstream Segment as webelieve margin is a better indicator of performance than operating income asoperating, general and administrative expenses, operating fuel and power anddepreciation expense are not directly related to the margin activities.  Margin and volume information for the yearsended December 31, 2005, 2004 and 2003 is presented below (in thousands, exceptper barrel and per gallon amounts):

 

45

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| ** **                              | ** ** | **Years Ended**** ****December**** ****31,** | ** ** | **Percentage  Increase (Decrease)** | ** ** |
|-----------------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                              | ** ** | **2005**                                               | ** ** | **2004**                            | ** ** | **2003** | ** ** | **2005-2004** | ** ** | **2004-2003** | ** ** |
| Margins: (1)                            |       |                                                   |       |                                |       |   |   |   |   |   |   |
| Crude oil transportation                |       | $                                                      | 61,611     |                                | $          | 55,425 |   | $ | 45,794 |   | 11 | % | 21 | % |
| Crude oil marketing                     |       | 30,597                                                 |       | 22,468                              |       | 22,017 |   | 36 | % | 2 | % |
| Crude oil terminaling                   |       | 10,400                                                 |       | 9,388                               |       | 9,403 |   | 11 | % | — |   |
| Lubrication oil sales                   |       | 7,455                                                  |       | 6,494                               |       | 5,372 |   | 15 | % | 21 | % |
| Total margin                            |       | $                                                      | 110,063    |                                | $          | 93,775 |   | $ | 82,586 |   | 17 | % | 14 | % |
|                                    |       |                                                   |       |                                |       |   |   |   |   |   |   |
| Total barrels:                          |       |                                                   |       |                                |       |   |   |   |   |   |   |
| Crude oil transportation                |       | 94,743                                                 |       | 101,462                             |       | 95,541 |   | (7 | )% | 6 | % |
| Crude oil marketing                     |       | 203,325                                                |       | 177,273                             |       | 159,710 |   | 15 | % | 11 | % |
| Crude oil terminaling                   |       | 110,254                                                |       | 113,197                             |       | 115,076 |   | (3 | )% | (2 | )% |
|                                    |       |                                                   |       |                                |       |   |   |   |   |   |   |
| Lubrication  oil volume (total gallons) |       | 14,844                                                 |       | 13,964                              |       | 10,449 |   | 6 | % | 34 | % |
|                                    |       |                                                   |       |                                |       |   |   |   |   |   |   |
| Margin per  barrel:                     |       |                                                   |       |                                |       |   |   |   |   |   |   |
| Crude oil transportation                |       | $                                                      | 0.650      |                                | $          | 0.546 |   | $ | 0.479 |   | 19 | % | 14 | % |
| Crude oil marketing                     |       | 0.150                                                  |       | 0.127                               |       | 0.138 |   | 19 | % | (8 | )% |
| Crude oil terminaling                   |       | 0.094                                                  |       | 0.083                               |       | 0.082 |   | 14 | % | 1 | % |
|                                    |       |                                                   |       |                                |       |   |   |   |   |   |   |
| Lubrication  oil margin (per gallon):   |       | $                                                      | 0.502      |                                | $          | 0.465 |   | $ | 0.514 |   | 8 | % | (10 | )% |

 

----

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

 

The following table reconciles the Upstream Segment margin to operatingincome in the consolidated statements of income using the information presentedin the tables above, in the consolidated statements of income and in thestatements of income in Note 17 in the Notes to the Consolidated FinancialStatements (in thousands):

 
| ** **                             | ** ** | **Years Ended**** ****December**** ****31,** | ** ** |
|----------------------------------------|------------|--------------------------------------------------------|------------|
| ** **                             | ** ** | **2005**                                               | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                             | ** ** | ** **                                             | ** ** | **(as restated)** | ** ** | **(as restated)** | ** ** |
|                                   |       |                                                   |       |   |   |   |   |
| Sales of  petroleum products           |       | $                                                      | 8,062,131  |   | $ | 5,426,832 |   | $ | 3,766,651 |   |
| Transportation  – Crude oil       |       | 37,614                                                 |       | 37,177 |   | 29,057 |   |
| Less:  Purchases of petroleum products |       | (7,989,682                                             | )          | (5,370,234 | ) | (3,713,122 | ) |
| Total margin                           |       | 110,063                                                |       | 93,775 |   | 82,586 |   |
| Other  operating revenues              |       | 10,494                                                 |       | 11,986 |   | 10,507 |   |
| Total operating revenues               |       | 120,557                                                |       | 105,761 |   | 93,093 |   |
| Operating,  general and administrative |       | 59,885                                                 |       | 51,424 |   | 50,471 |   |
| Operating  fuel and power              |       | 5,122                                                  |       | 5,490 |   | 3,672 |   |
| Depreciation  and amortization         |       | 17,161                                                 |       | 13,130 |   | 11,311 |   |
| Taxes –  other than income taxes  |       | 5,333                                                  |       | 3,979 |   | 3,171 |   |
| Gains on  sales of assets              |       | (118                                                   | )          | (527 | ) | (3,948 | ) |
| Operating income                       |       | $                                                      | 33,174     |   | $ | 32,265 |   | $ | 28,416 |   |

 

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

 

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

 

46

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higher tariff segments,including higher tariffs on the assets acquired from BP in April 2005.  Lubrication oil sales margin increased $1.0million due to increased sales of lubrication oils and chemicals and theacquisitions of lubrication oil distributors in Casper, Wyoming, in August2004, and in Dumas, Texas, in August 2005. Crude oil terminaling margin increased $1.0 million as a result ofincreased pumpover volumes at Cushing, Oklahoma, partially offset by decreasedpumpover volumes at Midland, Texas.

 

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

 

Costsand expenses, excluding expenses associated with purchases of crude oil andlubrication oil, increased $13.9 million for the year ended December 31, 2005,compared with the year ended December 31, 2004, due to increased operating,general and administrative expenses, increased depreciation and amortizationexpense, increased taxes – other than income taxes and lower gains on sales ofassets in the 2005 period, partially offset by decreased operating fuel andpower.  Operating, general andadministrative expenses increased $8.5 million from the prior year period as aresult of the following:

 

•      a $4.8 million increase in pipeline operating and maintenance expenseprimarily due to acquisitions and the continued integration of the Genesisassets into our system,

•      a $2.7 million increase in labor and benefits expense related tovesting provisions in certain of our compensation plans as a result of changesin ownership of our General Partner, an increase in the number of employeesbetween periods, and higher incentive compensation expense as a result ofimproved operating performance,

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

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

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

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

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

•      increases in miscellaneous administrative supplies and expenses.

 

These increases werepartially offset by a $2.3 million decrease in product measurement losses, a$1.9 million decrease in pipeline inspection and repair costs associated withour integrity management program and a $1.2 million decrease in environmentalassessment and remediation costs. Depreciation and amortization expense increased $4.0 million primarilyas a result of a $2.6 million non-cash impairment charge in the third quarterof 2005, resulting from the impairment of two crude oil systems (see Note 9 inthe Notes to the Consolidated Financial Statements).  Depreciation expense also increased as aresult of assets placed in service and assets retired to depreciation expenseduring the period.  Taxes – other thanincome taxes increased $1.4 million due to asset acquisitions and a higherasset base in the 2005 period.  Duringthe year ended December 31, 2004, we recognized a gain of $0.4 million from thesale of our remaining interest in the original Rancho Pipeline system (see Note5 in the Notes to the Consolidated Financial Statements).  Operating fuel and power decreased $0.4million primarily as a result of lower transportation volumes in 2005.

 

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

 

AfterSeaway’s pipeline release in May 2005, the maximum operating pressure on thepipeline system was reduced by 20% until the cause of the failure is determinedand any required corrective measures are implemented.  A study of the failed pipe was performed byindependent, metallurgical experts who determined that the pipe failed due todamage that occurred during rail shipment associated with its installationthirty years ago.  The corrective actionsinclude running a very sophisticated, high definition inspection tool throughthe pipe to determine if there

 

47

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are any other sections of pipethat have similar damage.  This approachis consistent with directives from the United States Department ofTransportation’s Office of Pipeline Safety in past failures of this type.  The inspection tool has been run and theresulting data is currently being analyzed. We expect Seaway to be operating at reduced maximum pressures throughthe second quarter of 2006.  As a resultof operating at reduced maximum pressures, during the third quarter of 2005, webegan using a drag reducing agent to increase the flow of product through thepipeline system.  The drag reducing agentallowed us to maintain the higher volumes transported, but also increased ouroperating costs.  At this time, we do notbelieve the reduced pressures will have a material adverse effect on ourfinancial position, results of operations or cash flows.

 

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

 

Our margin increased $11.2million for the year ended December 31, 2004, compared with the year endedDecember 31, 2003.  Crude oiltransportation margin increased $9.6 million primarily due to an increase intransportation volumes and revenues on our South Texas and Red Riversystems.  Our Basin system also hadincreased transportation volumes and revenues primarily due to the expansion ofthe system between Midland, Texas, and Wichita Falls, Texas, resulting in anadditional capacity of ten thousand barrels per day on the system, andmovements of barrels on higher tariff segments. During the fourth quarter of 2003, we completed the purchase of crude supplyand transportation assets (Genesis), which have been integrated into our SouthTexas system (see Note 5 in the Notes to the Consolidated FinancialStatements).  Lubrication oil salesmargin increased $1.1 million due to increased sales of chemical volumes andincreased volumes related to the acquisitions of lubrication oil distributorsin Abilene, Texas, in December 2003 and in Casper, Wyoming, in August2004.  Crude oil marketing marginincreased $0.5 million as a result of increased volumes marketed, partiallyoffset by an unfavorable invoicing settlement on a marketing contract in thefirst quarter of 2003, which reduced the marketing margin in 2003, andincreased transportation costs.  Crudeoil terminaling margin remained unchanged as a result of higher pumpovervolumes at Cushing, Oklahoma, offset by 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, primarilydue to a $1.4 million favorable settlement of inventory imbalances, and higherrevenues from documentation and other services to support customers’ tradingactivity at Midland and Cushing.

 

Costsand expenses, 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 operating fueland power, increased depreciation and amortization expense, increased operating,general and administrative expenses and increased taxes – other than incometaxes.  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 tocompliance with the Sarbanes-Oxley Act of 2002 and a $0.6 million increase inrental expense due to 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. and $0.5 million oflower expenses in 2004 from the sale of the Rancho assets in 2003.  Taxes – other than income taxes increased$0.8 million due to increases in property tax accruals.

 

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

 

48

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Equity earnings from ourinvestment in Seaway increased $8.4 million for the year ended December 31,2004, compared with the year ended December 31, 2003, due to highertransportation volumes, gains on crude oil inventory sales, a settlement with aformer owner of Seaway’s crude oil assets regarding inventory imbalances thatwere not acquired by us and lower operating, general and administrativeexpenses.

 

**MidstreamSegment**

 

The following table providesfinancial information for the Midstream Segment for the years ended December31, 2005, 2004 and 2003 (in thousands):

 
| ** **                             | ** ** | **Years Ended**** ****December**** ****31,** | ** ** | **Increase (Decrease)** | ** ** |
|----------------------------------------|------------|--------------------------------------------------------|------------|-------------------------|------------|
| ** **                             | ** ** | **2005**                                               | ** ** | **2004**                | ** ** | **2003** | ** ** | **2005-2004** | ** ** | **2004-2003** | ** ** |
| Sales of  petroleum products           |       | $                                                      | 10,479     |                    | $          | 7,295 |   | $ | — |   | $ | 3,184 |   | $ | 7,295 |   |
| Gathering –  Natural gas          |       | 152,797                                                |       | 140,122                 |       | 135,144 |   | 12,675 |   | 4,978 |   |
| Transportation  – NGLs            |       | 43,915                                                 |       | 41,204                  |       | 39,837 |   | 2,711 |   | 1,367 |   |
| Other                                  |       | 17,434                                                 |       | 17,383                  |       | 10,124 |   | 51 |   | 7,259 |   |
| Total operating revenues               |       | 224,625                                                |       | 206,004                 |       | 185,105 |   | 18,621 |   | 20,899 |   |
|                                   |       |                                                   |       |                    |       |   |   |   |   |   |   |
| Purchases of  petroleum products       |       | 8,995                                                  |       | 5,944                   |       | — |   | 3,051 |   | 5,944 |   |
| Operating,  general and administrative |       | 43,738                                                 |       | 44,318                  |       | 34,618 |   | (580 | ) | 9,700 |   |
| Operating  fuel and power              |       | 11,350                                                 |       | 10,943                  |       | 8,884 |   | 407 |   | 2,059 |   |
| Depreciation  and amortization         |       | 54,777                                                 |       | 56,629                  |       | 57,797 |   | (1,852 | ) | (1,168 | ) |
| Taxes –  other than income taxes  |       | 4,310                                                  |       | 4,565                   |       | 3,518 |   | (255 | ) | 1,047 |   |
| Gains on  sales of assets              |       | (411                                                   | )          | —                  |       | — |   | (411 | ) | — |   |
| Total costs and expenses               |       | 122,759                                                |       | 122,399                 |       | 104,817 |   | 360 |   | 17,582 |   |
| Operating  income                      |       | 101,866                                                |       | 83,605                  |       | 80,288 |   | 18,261 |   | 3,317 |   |
| Other income  – net               |       | 224                                                    |       | 127                     |       | 289 |   | 97 |   | (162 | ) |
| Earnings  before interest              |       | $                                                      | 102,090    |                    | $          | 83,732 |   | $ | 80,577 |   | $ | 18,358 |   | $ | 3,155 |   |

 

Thefollowing table presents volume and average rate information for the yearsended December 31, 2005, 2004 and 2003 (in thousands, except average fee andaverage rate amounts):

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

 

49

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Information presented in the following discussion includes the marginof the Midstream Segment, which may be viewed as a non-GAAP financial measureunder the rules of the SEC.  We calculatethe margin of the Midstream Segment as revenues generated from the processingarrangements at the Jonah Pioneer plant, less purchases of gas.   Pioneer’s processing agreements allow Jonahto retain and sell the NGLs extracted during the process and deliver toproducers the residue gas equivalent in energy to the natural gas received fromthe producers.  Jonah sells the NGLs itretains and purchases gas to replace the equivalent energy removed in theliquids.  We believe that margin is amore meaningful measure of financial performance than sales and purchases ofpetroleum products due to the significant fluctuations in sales and purchasescaused by variations in the level of volumes marketed and prices for productsmarketed.  Additionally, we use margininternally to evaluate the financial performance of the Midstream Segment’sprocessing activities as we believe margin is a better indicator of performancethan operating income as operating, general and administrative expenses,operating fuel and power and depreciation expense are not directly related tothe margin activities.  The followingtable reconciles the Midstream 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 in the Notes to the Consolidated Financial Statements (inthousands):

 
| ** **                             | ** ** | **Years Ended**** ****December**** ****31,** | ** ** |
|----------------------------------------|------------|--------------------------------------------------------|------------|
| ** **                             | ** ** | **2005**                                               | ** ** | **2004** | ** ** | **2003** | ** ** |
| Sales of  petroleum products           |       | $                                                      | 10,479     |   | $ | 7,295 |   | $ | — |   |
| Less:  Purchases of petroleum products |       | (8,995                                                 | )          | (5,944 | ) | — |   |
| Total margin                           |       | 1,484                                                  |       | 1,351 |   | — |   |
| Gathering –  Natural Gas          |       | 152,797                                                |       | 140,122 |   | 135,144 |   |
| Transportation  – NGLs            |       | 43,915                                                 |       | 41,204 |   | 39,837 |   |
| Other  operating revenues              |       | 17,434                                                 |       | 17,383 |   | 10,124 |   |
| Total operating revenues               |       | 215,630                                                |       | 200,060 |   | 185,105 |   |
| Operating,  general and administrative |       | 43,738                                                 |       | 44,318 |   | 34,618 |   |
| Operating  fuel and power              |       | 11,350                                                 |       | 10,943 |   | 8,884 |   |
| Depreciation  and amortization         |       | 54,777                                                 |       | 56,629 |   | 57,797 |   |
| Taxes –  other than income taxes  |       | 4,310                                                  |       | 4,565 |   | 3,518 |   |
| Gains on  sales of assets              |       | (411                                                   | )          | — |   | — |   |
| Operating income                       |       | $                                                      | 101,866    |   | $ | 83,605 |   | $ | 80,288 |   |

 

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

 

Revenues from the gathering of natural gas increased $12.7 million forthe year ended December 31, 2005, compared with the year ended December 31,2004.  Natural gas gathering revenuesfrom the Jonah system increased $10.2 million and volumes gathered increased60.6 Bcf for the year ended December 31, 2005, primarily due to the expansionof the Jonah system in 2004. Installation of additional capacity of 100 million cubic feet per daywas completed during the fourth quarter of 2004.  Jonah’s average natural gas gathering rateper MMcf decreased due to higher system wellhead pressures.  Natural gas gathering revenues from the ValVerde system increased $2.5 million and volumes gathered increased 36.7 Bcf forthe year ended December 31, 2005, primarily due to increased volumes from twonew connections made to the Val Verde system in May and December 2004,partially offset by the natural decline of CBM production.  Val Verde’s average natural gas 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.

 

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

 

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

 

Revenuesfrom the transportation of NGLs increased $2.7 million for the year endedDecember 31, 2005, compared with the year ended December 31, 2004, primarilydue to increased volumes transported on the Chaparral, Panola and DeanPipelines, partially offset by decreased volumes transported on the WilcoxPipeline.  The increase in the NGLtransportation average rate per barrel resulted from a higher average rate perbarrel on volumes transported on the Panola Pipeline offset by a lower averagerate per barrel on the Chaparral Pipeline.

 

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

 

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

 

Operating,general and administrative expenses decreased $0.6 million from the prior yearperiod as a result a $6.0 million decrease in gas settlement expenses, a $1.2million decrease in a operating expenses primarily related to Val Verde and a$0.5 million decrease in inspection and repair costs associated with ourintegrity management program.  Thesedecreases were partially offset by a $2.1 million increase in labor andbenefits expense primarily associated with vesting provisions in certain of ourcompensation plans and with certain DEFS employees becoming employees of EPCO,a $1.9 million increase in transition expenses as a result of changes inownership of our General Partner, a $1.5 million increase in insurance expenseand increases in various general and administrative supplies and expenses.  Taxes – other than income taxes decreased$0.3 million as a result of adjustments to property tax accruals.  Operating fuel and power increased $0.4million compared to the prior year due to adjustments to the fuel and poweraccrual in the prior year period, partially offset by increased expenses in2005 related to higher transportation volumes. A net gain of $0.4 million was recognized on the sale of equipment inthe current period.

 

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

 

Revenues from the gathering of natural gas increased $5.0 million forthe year ended December 31, 2004, compared with the year ended December 31,2003.  Natural gas gathering revenuesfrom the Jonah system increased $11.3 million and volumes gathered increased51.6 Bcf for the year ended December 31, 2004, due to the expansion of theJonah system during 2003.  The Phase IIIexpansion was substantially completed during the fourth quarter of 2003 andincreased system capacity from 880 MMcf/day to 1,180 MMcf/day.  The increase in Jonah’s revenues was alsopartially due to higher gathering rates realized due to lower system pressuresresulting from the increased

 

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capacity provided by the PhaseIII expansion.  Natural gas gatheringrevenues from the Val Verde system decreased $6.3 million and volumes gathereddecreased 13.7 Bcf for the year ended December 31, 2004, primarily due to thenatural decline of CBM production and slower than anticipated completion andconnection of infill wells, partially offset by increased volumes from two newconnections made to the 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.

 

Forthe year ended 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 endedDecember 31, 2004, compared with the year ended December 31, 2003, primarilydue to increased volumes transported on the Chaparral and Panola Pipelines,partially offset by decreased volumes on the Dean and Wilcox Pipelines.  Higher average rates per barrel on 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 million as a result of Jonah’sPioneer processing plant, which was constructed as part of the Phase III expansionand placed in service in January 2004. Jonah’s other operating revenues also increased $0.9 million primarilydue to higher condensate sales.  Otheroperating revenues on Chaparral increased $1.9 million due to the recognitionof deferred revenue related to an inventory settlement.  Val Verde’s operating revenues increased $1.6million due to revenues generated as a result of contractual producer minimumfuel levels exceeding actual operating fuel usage during the year endedDecember 31, 2004.

 

Costsand expenses (excluding purchases of petroleum products) increased $11.7million for the year ended December 31, 2004, compared with the year endedDecember 31, 2003, due to increases in operating, general and administrativeexpense, operating fuel and power and taxes – other than income taxes,partially offset by 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 millionincrease in 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. These increases were partially offset by a $0.6 million decrease inexpense related to the sale of our Enron Corp. receivable, which had been fullyreserved in 2001, and a $0.4 million decrease in maintenance expenditures atVal Verde.  Operating fuel and powerincreased $2.1 million, primarily due to higher variable power rates andincreased NGL volumes transported during times of peak variable powerrates.  Depreciation expense increased$3.5 million, primarily as a result of assets placed in service in 2003 relatedto the expansion of the Jonah system and additional well connections on the ValVerde system in 2004.  Taxes – other thanincome taxes increased $1.0 million as a result of higher propertybalances.  Amortization expense decreased$4.7 million primarily due to revisions to the estimated life of Jonah’sintangible assets under the units-of-production method, partially offset by a$1.7 million increase as a result of higher volumes in the 2004 period.  In second quarter 2003, Jonah’s 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 Jonah system.  This increase in the estimate of futurethroughput extended the amortization period of Jonah’s natural gas gatheringcontracts (see Note 3 in the Notes to the Consolidated FinancialStatements).  Amortization expense on theVal Verde system decreased $2.1 million primarily due to lower volumes in the2004 period, resulting from the natural decline 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 interest incomeearned on cash investments.

 

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**InterestExpense and Capitalized Interest**

 

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

 

Interestexpense increased $12.3 million for the year ended December 31, 2005, comparedwith the year ended December 31, 2004, primarily due to higher outstandingborrowings and higher short term floating interest rates on our revolvingcredit facility and $2.0 million of expense related to the termination of atreasury lock (see Note 4 in the Notes to the Consolidated FinancialStatements).  These increases werepartially offset by a higher percentage of fixed interest rate debt during theyear ended December 31, 2004, that carried a higher rate of interest ascompared with floating interest rate debt. The higher percentage of fixed interest rate debt resulted from aninterest rate swap that expired in April 2004 (see Note 4 in the Notes to theConsolidated Financial Statements).

 

Capitalizedinterest increased $2.5 million for the year ended December 31, 2005, comparedwith the year ended December 31, 2004, due to interest capitalized on higherconstruction work-in-progress balances in 2005.

 

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

 

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

 

Capitalizedinterest decreased $1.1 million for the year ended December 31, 2004, comparedwith the year ended December 31, 2003, due to interest capitalized on higherconstruction work-in-progress balances in 2003.

 

**FinancialCondition and Liquidity**

 

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

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

 

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*Operating Activities*

 

Net cash from operatingactivities for the years ended December 31, 2005, 2004 and 2003, was comprisedof the following (in millions):

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

 

Fora discussion of changes in earnings before interest, depreciation andamortization, equity earnings, gain on sales of assets by segment andconsolidated interest expense – net, see “Results of Operations.”  Cash distributions from equity investmentsdecreased $10.1 million primarily due to Seaway funding its construction ofadditional storage tanks from its operating cash flows.  Cash used for working capital purposesincreased $29.5 million for the year ended December 31, 2005, primarily due tothe timing of cash disbursements and cash receipts for crude oil inventory.  Cash distributions from our equity investmentsincreased $19.2 million for the year ended December 31, 2004, compared with theyear ended December 31, 2003, due to an improved operating performance inSeaway and MB Storage during the year ended December 31, 2004.  Cash used for working capital purposes andother operating activities increased $11.7 million for the year ended December31, 2004, primarily due to the timing of cash disbursements and cash receiptsfor working capital components.

 

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

 

*Investing Activities*

 

 Cash flows used in investing activities totaled$350.9 million for the year ended December 31, 2005, and were comprised of$220.6 million of capital expenditures, $69.0 million for the acquisition ofDownstream Segment assets, $43.2 million for the acquisition of UpstreamSegment assets, $14.4 million of cash paid for linefill on assets owned and$4.2 million of cash contributions for TE Products’ ownership interest in MBStorage for capital expenditures, partially offset by $0.5 million in net cashproceeds from an asset sale in our Midstream Segment. Cash flows used ininvesting activities totaled $190.2 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 in Centennialto cover operating needs and capital expenditures, $21.4 million of cashcontributions for TE Products’ ownership interest in MB Storage of which $16.5million was used to acquire storage assets, $3.4 million for the acquisition ofassets during the year ended December 31, 2004 and $1.0 million of cash paidfor linefill on assets owned, partially offset by $1.2 million in net cashproceeds from the sales of various assets in our Upstream and DownstreamSegments.  Cash flows used in investingactivities totaled $188.3 million for the year ended December 31, 2003, andwere comprised of $140.5 million of capital expenditures, $22.0 million for theacquisition of assets, $20.0 million for TE Products’ acquisition of anadditional 16.7% interest in Centennial, $4.0 million of cash contributions forTE Products’ ownership interest in Centennial to cover operating needs andcapital expenditures, $2.5 million of cash contributions for TE Products’ownership interest in MB Storage for capital expenditures and $3.1 million ofcash paid for linefill on assets owned. These uses of cash were partially offset by $3.0 million in net cashproceeds from the Rancho Pipeline transactions and $0.8 million received onmatured cash investments.

 

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*Financing Activities*

 

Cash flows provided byfinancing activities totaled $80.1 million for the year ended December 31,2005, and were comprised of $278.8 million of net proceeds received from theissuance of 7.0 million Units in May and June 2005 and $52.9 million inborrowings, net of repayments, on our revolving credit facility, partiallyoffset by $251.1 million of distributions paid to unitholders and $0.5 millionof debt issuance costs related to an amendment of our revolving credit facility.  Cash flows used in financing activitiestotaled $90.1 million for the year ended December 31, 2004, and were comprisedof $233.1 million of distributions paid to unitholders, partially offset by$143.0 million in borrowings, net of repayments, from our revolving creditfacility.  Cash flows used in financingactivities totaled $55.6 million for the year ended December 31, 2003, and werecomprised of $382.0 million in proceeds from revolving credit facilities; $198.6million 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 millionfrom the issuance of 9.2 million Units in April and August 2003.  These sources of cash for the year endedDecember 31, 2003, were partially offset by $604.0 million of repayments on ourrevolving credit facilities, $113.8 million to repurchase and retire all of the3.9 million outstanding Class B Units, and $202.5 million of distributions paidto unitholders.

 

We paid cash distributionsto our limited partners and general partner, including general partnerincentive distributions, of $251.1 million ($2.675 per Unit), $233.1 million($2.6375 per Unit), and $202.5 million ($2.50 per Unit) during each of theyears ended December 31, 2005, 2004 and 2003, respectively.  Additionally, on January 13, 2006, wedeclared a cash distribution of $0.675 per Unit for the quarter ended December31, 2005.  The distribution of $66.9million was paid on February 7, 2006, to unitholders of record on January 31,2006 (see Note 11 in the Notes to the Consolidated Financial Statements).

** **

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

** **

**OtherConsiderations**

 

*Universal Shelf*

 

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

 

*Credit Facilities*

 

Wehave in place an unsecured revolving credit facility for up to $700.0 million (“RevolvingCredit Facility”), which may be increased up to a maximum of $850.0 millionupon our request, subject to lender approval and the satisfaction of certain otherconditions.  The Revolving CreditFacility expires on December 13, 2010. Interest is payable at an applicable margin above either the lender’sbase rate or LIBOR.  At December 31,2005, $405.9 million was outstanding under the facility, and we had $274.6million of availability under the most restrictive financial covenant.  Restrictive covenants in the credit agreementlimit our ability to, among other things, incur additional indebtedness, makedistributions in excess of Available Cash (see Note 11 in the Notes to theConsolidated Financial Statements), and complete mergers, acquisitions andsales of assets.  In addition, the creditagreement requires us to maintain certain financial ratios, which we were in compliancewith at December 31, 2005.

 

*Future Capital Needs and Commitments*

 

We estimate that capitalexpenditures, excluding acquisitions, for 2006 will be approximately $209.7million (including $6.0 million of capitalized interest).  We expect to spend approximately $147.4million for revenue generating projects. Capital spending on revenue generating projects and facilityimprovements will include approximately $70.9 million for the expansion of ourDownstream Segment facilities.  We expectto spend

 

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$16.3 million to expand ourUpstream Segment pipelines and facilities in West Texas and Oklahoma andapproximately $60.2 million to expand our Midstream Segment assets, withfurther expansions on our Jonah system. We expect to spend approximately $37.8 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 spend approximately$18.5 million to improve operational efficiencies and reduce costs among all ofour business segments.  During 2006, TEProducts may be required to contribute cash to Centennial to cover capitalexpenditures, acquisitions or other operating needs and to MB Storage to coversignificant capital expenditures or additional acquisitions.  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.

 

Theconstruction of the Jonah Expansion is expected to be completed through aproposed Joint Venture between us and Enterprise, relating to the constructionand financing of the Jonah Expansion. Enterprise will be responsible for all activities relating to theconstruction of the Jonah Expansion and will advance all amounts necessary toplan, engineer, construct or complete the Jonah Expansion (anticipated to beapproximately $200.0 million).  Suchadvance will constitute a Subscription for an equity interest in the proposedJoint Venture.  We expect the JonahExpansion to be put into service in late 2006. We have the option to return to Enterprise up to 100% of the amount ofthe Subscription.  If we return a portionof the Subscription to Enterprise, our relative interests in the proposed JointVenture will be adjusted accordingly. The proposed Joint Venture will terminate without liability to eitherparty if we return 100% of the Subscription.

 

*Liquidity Outlook*

 

Webelieve that we will continue to have adequate liquidity to fund futurerecurring operating and investing activities. Our primary cash requirements consist of normal operating expenses,capital expenditures to sustain existing operations and to complete the JonahExpansion, revenue generating expenditures, interest payments on our SeniorNotes and Revolving Credit Facility, distributions to our General Partner andunitholders and acquisitions of new assets or businesses.  Our cash requirements for 2006 are expectedto be funded through operating cash flows and our arrangement with Enterpriseunder the pending Joint Venture agreement related to the Jonah Expansion.   Long-term cash requirements for expansionprojects, acquisitions and debt repayments are expected to be funded by severalsources, including cash flows from operating activities, borrowings undercredit facilities, joint ventures and possibly 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, our financial condition and our credit rating atthe time.

* *

*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 the limitedguarantee of Centennial catastrophic events as discussed below.  In addition, we have entered into variousleases covering assets utilized in several areas of our operations.

 

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

 

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

 

One of our subsidiaries,TCO, has entered into master equipment lease agreements with finance companiesfor the use of various equipment.  Wehave guaranteed the full and timely payment and performance of TCO’sobligations under the agreements. Generally, events of default would trigger our performance under theguarantee.  The maximum potential amountof future payments under the guarantee is not estimable, but would include baserental payments for both current and future equipment, stipulated loss paymentsin the event any equipment is stolen, damaged, or destroyed and any futureindemnity payments.  We carry insurancecoverage that may offset any payments required under the guarantees.

 

*Contractual Obligations*

 

The following tablesummarizes our debt repayment obligations and material contractual commitmentsas of December 31, 2005 (in millions):  

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

 

----

(1)          Obligations of TE Products.

 

(2)          Our TE Products subsidiary entered into aninterest rate swap agreement to hedge its exposure to changes in the fair valueof its 7.51% Senior Notes due 2028.  AtDecember 31, 2005, the 7.51% Senior Notes include an adjustment to decrease thefair value of the debt by $0.9 million related to this interest rate swapagreement.  We also entered into interestrate swap agreements to hedge our exposure to changes in the fair value of our7.625% Senior Notes due 2012.  AtDecember 31, 2005, the 7.625% Senior Notes include a deferred gain, net ofamortization, from previous interest rate swap terminations of $32.4million.  At December 31, 2005, our 6.45%Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $2.4million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and theunamortized debt discounts are excluded from this table.

 

(3)          Includes interest payments due on our SeniorNotes and interest payments and commitment fees due on our Revolving CreditFacility. The interest amount calculated on the Revolving Credit Facility isbased on the assumption that the amount outstanding and the interest ratecharged both remain at their current levels.

 

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

 

57

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(5)          Includes accruals for costs incurred but notyet paid relating to capital projects.

 

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

 

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

 

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 items inthe 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 we make for the purchase ofcrude oil range in term from a thirty-day evergreen to one year.  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 December31, 2005, crude oil purchases averaged approximately $665.8 million per month.

 

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

 

## **Recent AccountingPronouncements**

 

Seediscussion of new accounting pronouncements in Note 2 in the Notes to theConsolidated Financial Statements.

 

**Item 7A*.   Quantitative and QualitativeDisclosures About Market Risk***

 

*Commodity Risk*

 

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

 

We seek to maintain a positionthat is substantially balanced between crude oil purchases and sales and futuredelivery obligations.  On the majority ofour crude oil derivative contracts, we take the normal purchase and normal saleexclusion in accordance with SFAS No. 133, *Accountingfor Derivative Instruments and Hedging Activities*, and SFAS No. 138,*Accounting for Certain DerivativeInstruments and Certain Hedging Activities, an amendment of FASB Statement No.133*.

 

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

 

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significant market risk.  For derivatives where hedge accounting iselected, the effective portion of changes in fair value are recorded in othercomprehensive income and reclassified into earnings as such transactions aresettled.  For derivatives where hedgeaccounting is not elected, we mark these transactions to market and the changesin the fair value are recognized in current earnings.  This results in some financial statementvariability during quarterly periods; however, any unrealized gains and lossesreflected in the financial statements related to marking these transactions tomarket are offset by realized gains and losses in different quarterly periodswhen the transactions are settled.

 

At December 31, 2005, we hada limited number of commodity derivatives that were accounted for as cash flowhedges.  Gains and losses on thesederivatives are offset against corresponding gains or losses of the hedged itemand are deferred through other comprehensive income, thus minimizing exposureto cash flow risk.  The fair value of theopen positions at December 31, 2005 was $0.1 million.  Assuming a hypothetical across-the-board 10%price decrease in the forward curve, the change in fair value of the hedginginstrument would have been $0.7 million. At December 31, 2004, we had a limited number of commodity derivativeswhere the transactions were marked to market because hedge accounting was notelected.  The fair value of the openpositions at December 31, 2004 was $0.3 million.  The fair value of the open positions wasbased upon both quoted market prices obtained from NYMEX and were estimatedbased on quoted prices from various sources such as independent reportingservices, industry publications, brokers and marketers.  The fair values were determined based uponthe differences by month between the fixed contract price and the relevantforward price curve, the volumes for the applicable month and a discount rateof 6%.

* *

*Interest Rate Risk*

 

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

 

The following tablesummarizes the estimated fair values of the Senior Notes as of December 31,2005 and 2004 (in millions):
| ** **                                        | ** ** | ** ** | ** ** | **Fair Value**   | ** ** |
|---------------------------------------------------|------------|------------|------------|------------------|------------|
| ** **                                        | ** ** | **Face**   | ** ** | **December 31,** | ** ** |
| ** **                                        | ** ** | **Value**  | ** ** | **2005**         | ** ** | **2004** | ** ** |
| 6.45% TE  Products Senior Notes, due January 2008 |       | $          | 180.0      |             | $          | 183.7 |   | $ | 187.1 |   |
| 7.625%  Senior Notes, due February 2012           |       | 500.0      |       | 552.0            |       | 569.6 |   |
| 6.125%  Senior Notes, due February 2013           |       | 200.0      |       | 205.6            |       | 210.2 |   |
| 7.51% TE  Products Senior Notes, due January 2028 |       | 210.0      |       | 224.1            |       | 225.6 |   |
|                                                   |            |            |            |                  |            |  |  |  |  |  |

 

We have utilized and expectto continue to utilize interest rate swap agreements to hedge a portion of ourcash flow and fair value risks.  Interestrate swap agreements are used to manage the fixed and floating interest ratemix of our total debt portfolio and overall cost of borrowing.  Interest rate swaps that manage our cash flowrisk reduce our exposure to increases in the benchmark interest ratesunderlying variable rate debt.  Interestrate swaps that manage our fair value risks are intended to reduce our exposureto 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 July 2000, we enteredinto an interest rate swap agreement to hedge our exposure to increases in thebenchmark interest rate underlying our variable rate revolving creditfacility.  This interest rate swapmatured in April 2004.  We designatedthis swap agreement, which hedged exposure to variability in expected futurecash flows attributed to changes in interest rates, as a cash flow hedge.  The swap agreement was based on a notionalamount of $250.0 million.  Under the swapagreement, we paid a fixed rate of interest of 6.955% and received a floating ratebased on a three-month U.S. Dollar LIBOR rate. Because this swap was designated as a cash flow hedge, the changes infair value, to the extent the swap was effective, were recognized in othercomprehensive income until the hedged interest costs were recognized inearnings.  During the years endedDecember 31, 2004 and 2003, we

 

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

 

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

 

During2002, we entered into interest rate swap agreements, designated as fair valuehedges, to hedge our exposure to changes in the fair value of our fixed rate7.625% 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%. These swap agreements were later terminated in 2002 resulting in gainsof $44.9 million.  The gains realizedfrom the swap terminations have been deferred as adjustments to the carryingvalue of the Senior Notes and are being amortized using the effective interestmethod as reductions to future interest expense over the remaining term of theSenior Notes.  At December 31, 2005, theunamortized balance of the deferred gains was $32.4 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.

 

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

 

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

 

**Item 8.      * Financial Statementsand Supplementary Data***

 

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

 

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

 

None.

 

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

 

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

 

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

 

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

 

*Management’s Annual Report on Internal Control overFinancial Reporting*

 

The management 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, as amended. The Partnership’s internal control over financial reporting is designedto provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles.  The Partnership’s internal control overfinancial reporting includes those policies and procedures that:

 

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

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

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

 

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

 

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

 

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

 

The Partnership’s registered public accounting firm has issued anattestation report on management’s assessment of the Partnership’s internalcontrol over financial reporting.  Thatreport appears below.

 

 
| /s/ LEE W. MARSHALL, SR.                                       |   |
|----------------------------------------------------------------|--------|
| Lee W. Marshall, Sr.                                           |
| Acting Chief Executive  Officer and Chairman of the Board      |
| Texas Eastern Products  Pipeline Company, LLC, General Partner |

 

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| /s/ WILLIAM G. MANIAS                                          |   |
|----------------------------------------------------------------|--------|
| William G. Manias                                              |
| Vice President and Chief  Financial Officer                    |
| Texas Eastern Products  Pipeline Company, LLC, General Partner |

 

 

*Report of Independent Registered Public Accounting Firm*

 

Tothe Partners of

TEPPCOPartners, L.P.:

 

We have audited management’s assessment, included in the accompanyingreport titled Management’s Annual Report on Internal Control over FinancialReporting included in Item 9A, that TEPPCO Partners, L.P. maintained effectiveinternal control over financial reporting as of December 31, 2005, 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 to expressan opinion on management’s assessment and an opinion on the effectiveness ofTEPPCO Partners, L.P.’s internal control over financial reporting based on ouraudit.

 

We conducted our audit in accordance with the standards of the PublicCompany Accounting Oversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects.  Our audit included obtainingan understanding of internal control over financial reporting, evaluatingmanagement’s assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a processdesigned to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles.  A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2)provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of thecompany are being made only in accordance with authorizations of management anddirectors of the company; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the company’s assets that could have a material effect on the financialstatements.

 

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

 

In our opinion, management’s assessment that TEPPCO Partners, L.P.maintained effective internal control over financial reporting as of December31, 2005, is fairly stated, in all material respects, based on criteriaestablished in *Internal Control – IntegratedFramework*issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO).  Also, in ouropinion, TEPPCO Partners, L.P. maintained, in all material respects, effectiveinternal control over financial reporting as of December 31, 2005, based oncriteria established in *Internal Control –Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO).

 

We also have audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), the consolidated balancesheets of TEPPCO Partners, L.P. as of December 31, 2005 and 2004, and therelated consolidated statements of income, partners’ capital and comprehensiveincome, and cash

 

62

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

 
|              |   | KPMG LLP |
|-------------------|--------|----------|
|              |   |     |
| Houston, Texas    |   |     |
| February 28, 2006 |   |     |

 

*Changes in Internal Control over Financial Reporting*

 

Therehas been no change in our internal control over financial reporting during thefourth quarter of 2005 that has materially affected, or is reasonably likely tomaterially affect, our internal control over financial reporting.

 

**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 were elected annually by DEFSthrough February 24, 2005.  From February24, 2005, all directors of the General Partner are elected annually byEPCO.  All officers serve at thediscretion of the directors.  None of theofficers of the General Partner, with the exception of William Ordemann, serveas officers or employees of EPCO or any other parent-affiliated company.  Mr. Ordemann serves as Senior Vice Presidentof Enterprise Products GP, LLC (“Enterprise Products GP”), the general partnerof Enterprise and as Senior Vice President of the 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 (the “Board”).

 

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

 

63

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**Committeesof the Board of Directors**

 

*Audit andConflicts Committee*

 

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

 

The Audit and ConflictsCommittee provides independent oversight with respect to our internal controls,disclosure controls, accounting policies, financial reporting, the integrity ofthe financial statements, internal audit function, the independent auditors andcompliance with legal and regulatory requirements.  The Audit and Conflicts Committee alsoreviews the scope and quality, including the independence and objectivity ofthe independent and internal auditors. The Audit and Conflicts Committee has sole authority as to theretention, evaluation, compensation and oversight of the work of theindependent auditors.  The independentauditors report directly to the Audit and Conflicts Committee.  The Audit and Conflicts Committee also hassole authority to approve all audit and non-audit services provided by theindependent auditors and shall ensure that the independent auditors are notengaged to perform specific non-audit services prohibited by law or regulation.

 

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

 

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

 

Wehave adopted a Code of Ethics applicable to all employees, including theprincipal executive officer, principal financial officer and directors of theGeneral Partner.  A copy of the Code ofEthics is available on our website at www.teppco.com under CorporateGovernance.  We intend to post on ourwebsite any amendments to, or waivers from, our Code of Ethics applicable toour senior officers.

 

OurCorporate Governance Guidelines address director qualification standards;director responsibilities; director access to management, and as necessary andappropriate, independent advisors; director compensation; director orientationand continuing education; management succession and annual performance evaluationof the Board.  The Charter of our AuditCommittee and our Corporate Governance Guidelines are currently available onour website at www.teppco.com under Corporate Governance.  Additionally, the Code of Ethics, ourCorporate Governance Guidelines and the Charter of the Audit and ConflictsCommittee are available in print to any person who requests theinformation.  Persons wishing to obtainthis printed material should submit a request in care of Secretary, TEPPCO Partners,L.P., 2929 Allen Parkway, P.O. Box 2521, Houston, Texas 77252-2521.

 

64

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**NYSECorporate Governance Listing Standards**

* *

*Annual CEO Certification*

 

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

 

**ExecutiveSessions of Non-Management Directors**

 

Forthe period from January 1, 2005 through March 22, 2005, Mark A. Borer, MichaelJ. Bradley, Milton Carroll, Derrill Cody, John P. DesBarres, William H. EasterIII, Paul F. Ferguson, Jr. and Jim W. Mogg, were non-management directors ofour General Partner.  They met atregularly scheduled executive sessions without management.  Mr. Mogg served as the presiding director atthose executive sessions.  For the periodfrom January 1, 2005 through March 22, 2005, Milton Carroll, John P. DesBarresand Paul F. Ferguson, Jr., were independent directors of our GeneralPartner.  They met once during thisperiod in executive session without management and the other directors.

 

Forthe period from March 22, 2005 through December 31, 2005, Michael B. Bracy,Murray H. Hutchison and Lee W. Marshall, Sr., were independent directors of ourGeneral Partner, except that effective December 31, 2005, Lee W. Marshall, Sr.was appointed acting chief executive officer and was no longer determined to beindependent.  They met at regularlyscheduled executive sessions without management.  On January 6, 2006, Richard S. Snell waselected a director of the General Partner and became an independentdirector.  The chair of the Audit andConflicts Committee, Michael B. Bracy, is the chair of the independentdirectors.  Persons wishing tocommunicate with the Company’s independent directors may do so by calling1-877-888-0002.

 

**Directorsand Executive Officers**

 

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

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

 

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* Chairman of committee

+ See Executive Employment Contracts andTermination of Employment Arrangements

** Effective March 1, 2006.

 

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*Lee W. Marshall, Sr.* was elected Acting Chief Executive Officereffective December 31, 2005 upon the retirement of Barry R. Pearl, and Chairmanof the Board in November 2005, upon the resignation of Dr. Ralph S.Cunningham.  He served as a member of theAudit and Conflicts Committee from March 2005 to December 2005.  Prior to being elected to the Board in March2005 upon the change in ownership of the General Partner, Mr. Marshall servedas a director of Enterprise Products GP, the general partner of Enterprise from1998 until his resignation on March 22, 2005. Mr. Marshall has been the managing partner and principal owner of BisonResources, LLC, a privately held oil and gas production company, since1993.  Previously, he held senior managementpositions with Union Pacific Resources as senior vice president, refining,manufacturing and marketing; with Wolverine Exploration Company as executivevice president and chief financial officer; and with Tenneco Oil Company assenior vice president, marketing.

 

*Michael B. Bracy* was elected a director of the General Partner in March 2005, upon thechange in ownership of the General Partner. He also serves as Chairman of the Audit and Conflicts Committee.  Prior to being elected to the Board in March2005, Mr. Bracy served as a director of the general partner of GulfTerra EnergyPartners, L.P. (“GulfTerra”) from October 1998 until September 30, 2004, whenit merged with Enterprise.  He was alsoan audit committee financial expert as determined under the SEC rules whileserving on the board of GulfTerra’s general partner.  Mr. Bracy also serves as an audit committeefinancial expert on the Board of the General Partner.  From 1993 to 1997, Mr. Bracy served asdirector, executive vice president and chief financial officer of NorAm EnergyCorp.  For nine years prior, he served invarious executive capacities with NorAm Energy Corp.  Mr. Bracy is a member of the board of directorsof Itron, Inc.

 

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

 

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

 

*Michael A. Creel* was elected a director of the General Partner in February 2006.  Mr. Creel is currently executive vicepresident of Enterprise Products GP and EPCO, having been elected in January2001, after serving as a senior vice president of Enterprise Products GP andEPCO from November 1999 to January 2001. Mr. Creel, a certified public accountant, served as chief financialofficer of EPCO from June 2000 through April 2005 and was named chief operatingofficer of EPCO in April 2005.  In June2000, Mr. Creel was also named chief financial officer of Enterprise ProductsGP.  Mr. Creel has served as a directorof Enterprise Products OLPGP, Inc. (a wholly subsidiary of Enterprise) sinceDecember 2003, and has served as president, chief executive officer and adirector of EPE Holdings, LLC since August 2005.  Mr. Creel was elected a director of EdgePetroleum Corporation (a publicly traded oil and natural gas exploration andproduction company) in October 2005 and a director of Enterprise Products GP inFebruary 2006.

 

*Richard H. Bachmann* was elected a director of the General Partner in February 2006.  Mr. Bachmann is currently executive vicepresident, chief legal officer and secretary of Enterprise Products GP andEPCO, having been elected in January 1999. Mr. Bachmann previously served as a director of Enterprise Products GPfrom June 2000 to January 2004.  Mr.Bachmann has served as a director of Enterprise Products OLPGP, Inc. sinceDecember 2003, and has served as executive vice president, chief legal officerand secretary of EPE Holdings, LLC since August 2005.  Mr. Bachmann was elected a director of EPCOin January 1999 and EPE Holdings, LLC and Enterprise Products GP in February2006.  Mr. Bachmann was a partner in thelaw firms of Snell & Smith, P.C. from 1993 to 1998 and Butler & Binionfrom 1988 to 1993.

 

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*W. Randall Fowler* was elected a director of the GeneralPartner in February 2006.  Mr. Fowler iscurrently senior vice president and treasurer of Enterprise Products GP, havingbeen elected in February 2005, and is chief financial officer of EPCO, having beenelected in April 2005.  Mr. Fowler, acertified public accountant (inactive), joined Enterprise Products PartnersL.P. as director of investor relations in January 1999 and served as treasurerand a vice president of Enterprise Products GP and EPCO from August 2000 toFebruary 2005.  Mr. Fowler has served as seniorvice president and chief financial officer of EPE Holdings, LLC since August2005.  Mr. Fowler was elected a directorof EPE Holdings, LLC and Enterprise Products GP in February 2006.

 

*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.

 

*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* was 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. Effective February 28, 2006, Mr. Ruth retired from the Company.

 

*WilliamOrdemann* is SeniorVice President, responsible for the commercial development of the Jonah system,of the General Partner, having been elected in July 2005.  Mr. Ordemann has served as senior vice presidentof Enterprise Products GP, the general partner of Enterprise, since September2001.  He was previously vice presidentof Enterprise Products GP from October 1999 to September 2001.  Prior to joining Enterprise Products GP, Mr.Ordemann served as vice president of Tejas Natural Gas Liquids, LLC fromFebruary 1998 to September 1999, and vice president of Shell MidstreamEnterprises, LLC from January 1997 to February 1998.

 

*WilliamG. Manias* is Chief Financial Officer of the Company, havingbeen elected effective January 13, 2006. Mr. Manias was vice president of corporate development of EnterpriseProducts GP from October 2004 until January 2006.  He served as vice president and chief financialofficer of Gulfterra Energy Partners, L.P. from February 2004 until October2004.  Mr. Manias was previously vice presidentof business development and strategic planning at El Paso Energy Partners, L.P.from October 2001 to February 2004. Prior to his joining El Paso Energy Partners, L.P. in October 2001, Mr.Manias served as vice president of investment banking for J.P. MorganSecurities Inc. (formerly Chase Securities Inc.) from January 1996 to August2001.  Mr. Manias serves as principalfinancial and accounting officer of the Company.

 

*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 procurement servicesmanager, materials and service manager and Baytown area public affairs manageruntil she joined the Company in February 2002. Prior to ExxonMobil, Ms. Carroll was general manager, corporate environmentalprotection and compliance with Panhandle Eastern Corporation.

 

*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 and marketing.

 

*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 until

 

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September 2000, and Technical OperationsSuperintendent of the Southwest Region from 1994 until 1999.  Mr. Russell joined the Company in 1988 asProject Manager in Engineering.

* *

*C. Bruce Shaffer*is Vice President, Human Resources and Ethics and ComplianceOfficer of the General Partner, having been elected in February 2005.  Mr. Shaffer joined the Company in August 2004supporting Human Resources.  He waspreviously vice president of human resources services for Duke Energy GasTransmission and Duke Energy Americas from January 2004 until July 2004 and vicepresident of human resources for Duke Energy North America from June 2003 untilJuly 2004.  Mr. Shaffer joined DukeEnergy in January 2000 as managing director of human resources for Duke EnergyNorth America and Duke Energy International.

 

*StephenO. McNair* is Vice President, Natural Gas Services of theGeneral Partner, having been elected in July 2005.  Mr. McNair joined our General Partner in June2005.  He was previously Rockies Regionvice president for DEFS.  He joined DEFSas general manager of operations, West Permian Region in 2000.  Prior to his employment with DEFS, Mr. McNairheld various engineering, commercial and operations management positions withConoco Inc. and GPM Gas Corporation.

 

*Samuel N. Brown* is Vice President, Commercial Downstream ofthe General Partner, having been elected in June 2005.  He was previously Vice President, PipelineMarketing and Business Development in our Upstream Segment from September 2000to June 2005.  Mr. Brown joined theCompany in 1998 as Vice President of Pipeline Marketing and BusinessDevelopment.  Prior to joining theCompany in 1998, he was vice president of commercial operations at DETTCO from1996 until 1998.

 

*Patricia A. Totten* has been elected VicePresident, General Counsel and Secretary of the General Partner, effectiveMarch 1, 2006.  She was previouslyassociate general counsel and deputy general counsel for Enterprise Products GPfrom December 2002 to January 2006. Prior to joining Enterprise Products GP in August 2002, Ms. Tottenserved as general counsel of Solid Systems Inc. from March 2001 to August 2002,and as assistant general counsel and vice president of marketing for a smallwireless company from 1995 to December 2000 that was merged into VerizonWireless in 2000.

 

In addition to ourExecutive Officers, Mark G. Stockard serves as Treasurer since 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.  Tracy E. Ohmart serves asController since May 2002.  Mr. Ohmartserved as acting Chief Financial Officer of the General Partner from July 2005until January 2006.  Mr. Ohmart joinedthe General Partner in January 2001 and held various positions with the Companyuntil he became Assistant Controller in May 2001.  Prior to his employment with the GeneralPartner, Mr. Ohmart spent 12 years in various positions at ARCO Pipe LineCompany, most recently serving as supervisor of general accounting and policy.

 

**Section 16(a) Beneficial Ownership ReportingCompliance**

 

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 31,2005, except for a report covering a transaction that was filed late by Mr. McNairand four reports covering four transactions totaling $640 that were filed lateby Mr. Mallett.

 

***Item 11. *Executive Compensation**

 

**Summary Compensation Table**

 

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

 

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reflects information regarding compensation paid oraccrued by the General Partner for the years ended December 31, 2005, 2004 and2003, with respect to each person who served as Chief Executive Officer during2005, the four other most highly compensated executive officers serving atDecember 31, 2005, and one former executive officer for whom disclosure wouldhave been required but for the fact that he was not serving at December 31,2005 (collectively, the “Named Executive Officers”).

** **

**SUMMARY COMPENSATION TABLE**

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

 

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(1)          Amounts represent bonuses accrued during the year underthe Management Incentive Compensation Plan (“MICP”). Payments under the MICPare made in the subsequent year.  Annualcompensation does not include awards under long-term incentive plans, which aredescribed in the 2000 LTIP awards table under “Compensation Pursuant to GeneralPartner Plans”.

 

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

 

(3)          Amounts represent payouts under the 2000 LTIP.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

## ** **

## **Compensation Committee Interlocks and InsiderParticipation**

 

 From January 1, 2005 throughMarch 22, 2005, Jim W. Mogg, a director of the General Partner and group vicepresident and chief development officer of Duke Energy, was Chairman of theCompensation Committee of the General Partner and participated in deliberationsconcerning the General Partner’s executive officer compensation.  The other four members of the CompensationCommittee of the General Partner at that time, Milton Carroll, Derrill Cody,John P. DesBarres and Paul F. Ferguson, Jr., were non-employee directors of theGeneral Partner and were not officers or directors of DEFS or its parentcompanies, ConocoPhillips or Duke Energy.

 

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

## **** ****

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

* *

*ManagementIncentive Compensation Plan. (“MICP”)*

* *

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

 

*1994 Long Term Incentive Plan*

 

During 1994, the Company adopted the Texas Eastern Products PipelineCompany 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 Units may begranted.  No awards have been made underthe 1994 LTIP since 1999, and none are expected to be made in the future.

 

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

* *

*2000Long Term Incentive Plan*

* *

Effective January 1, 2000, the General Partner established the TexasEastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000LTIP”) to provide key employees incentives to achieve improvements in ourfinancial performance.  Generally, uponthe close of a three-year performance period, if the participant is then stillan employee of the General Partner, the participant will receive a cash paymentin an amount equal to (1) the applicable performance percentage specified inthe award multiplied by (2) the number of phantom units granted under the awardmultiplied by (3) the average of the closing prices of a Unit over the tenconsecutive trading days immediately preceding the last day of the performanceperiod.  Generally, a participant’sperformance percentage is based upon the improvement of our Economic ValueAdded (as defined below) during a three-year performance period over the EconomicValue Added during the three-year period immediately preceding the performanceperiod.  If a participant incurs aseparation from service during the performance period due to death, disabilityor retirement (as such terms are defined in the 2000 LTIP), the participantwill be entitled to receive a cash payment in an amount equal to the amountcomputed as described above multiplied by a fraction, the numerator of which isthe number of days that have elapsed during the performance period prior to theparticipant’s separation from service and the denominator of which is thenumber of days in the performance period.

 

The performance period applicable to awards granted in 2005 is thethree-year period that commenced on January 1, 2005, and ends on December 31,2007.  Each participant’s performancepercentage is the result of 100% +/- [(A) minus (C)] divided by [(C) minus (B)]where (A) is the actual Economic Value Added for the performance period, (B) is$73.0 million (which represents the actual Economic Value Added for thethree-year period immediately preceding the performance period) and (C) is $97.7million (which represents the Target Economic Value Added during the three-yearperformance period).  No amounts will bepayable under the awards granted in 2005 for the 2000 LTIP unless EconomicValue Added for the three year performance period exceeds $73.0 million.  The performance percentage may not exceed150%.

 

Economic Value Added means our average annual EBITDA for theperformance period minus the product of our average asset base and our cost ofcapital for the performance period.  Forpurposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earningsbefore net interest expense, depreciation and amortization and our proportionalinterest in EBITDA of our joint ventures as presented in our consolidated financialstatements prepared in accordance with generally accepted accountingprinciples, except that at his discretion the CEO of the partnership mayexclude gains or losses from extraordinary, unusual or non-recurringitems.  For the years ended December 31, 2005,2004 and 2003, EBITDA means, in addition to the above, earnings before otherincome — net.  Average asset base meansthe quarterly average, during the performance period, of our gross value of property,plant and equipment, *plus* products andcrude oil operating oil supply and the gross value of intangibles and equityinvestments.  Our cost of capital is approvedby the CEO at the date of award grant.

 

In addition to the payment described above, during the performanceperiod, the General Partner will pay to the participant the amount of cashdistributions that we would have paid to our unitholders had the participantbeen the owner of the number of Units equal to the number of phantom unitsgranted to the participant under this award.

 

The following table provides information concerning awards under the2000 LTIP to each of the Named Executive Officers during 2005.

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

 

72

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----

(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 2005 unless Economic Value Added for the three year performanceperiod exceeds $73.0 million.

 

(3)          In number of phantomunits.  Pursuant to Instruction 5 toRegulation S-K, Item 402(e) promulgated by the Securities and ExchangeCommission, these amounts assume that the 11% increase in Economic Value Addedfor 2005 as compared with 2004 is maintained for each of the three years in theperformance period.  There can be noassurance that any specific amount of Economic Value Added will be attained forsuch period.

 

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

 

(5)          Mr. Harper retired from the Companyeffective February 3, 2006.  However, heremains an EPCO employee.  As he remainsemployed by an affiliate of the Partnership, he is entitled to a portion of hisawarded units following the 2005-2007 performance period.

## ** **

## **Pension Plan**

 

Prior to the transfer of the General Partner interest from Duke Energyto DEFS on April 1, 2000, the Company’s employees participated in the DukeEnergy 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 cash balance formula, a planparticipant accumulated a retirement benefit based upon pay credits and currentinterest credits. The pay credits were based on a participant’s salary, age,and service.  In addition, the NamedExecutive Officers participated in the Duke Energy Executive Cash Balance Plan,which is a noncontributory, nonqualified, defined benefit retirement plan.  The Duke Energy Executive Cash Balance Planwas established to restore benefit reductions caused by the maximum benefitlimitations that apply to qualified plans.

 

Benefits under the Duke Energy Retirement Cash Balance Plan and theDuke Energy Executive Cash Balance Plan were based on eligible pay, generally consistingof base pay, short term incentive pay and lump-sum merit increases.  The Duke Energy Retirement Cash Balance Planexcludes deferred compensation, other than deferrals pursuant to Sections401(k) and 125 of the Internal Revenue Code. All benefits owed to the Named Executive Officers under the Duke EnergyRetirement Cash Balance Plan have been paid. As part of the change in ownership on March 31, 2000, the Company is nolonger responsible for the funding of the liabilities associated with the DukeEnergy Executive Cash Balance Plan.

 

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

 

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

 

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

 

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

 

73

----

 

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

 

On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended.  Effective May 31, 2005, participation in theTEPPCO RCBP was frozen, and no new participants were eligible to be covered bythe plan after that date.  EffectiveDecember 31, 2005, all plan benefits accrued were frozen, participants will notreceive additional pay credits after that date, and all plan participants willbe 100% vested regardless of their years of service.  The TEPPCO RCBP plan was terminated effectiveDecember 31, 2005, subject to IRS approval of plan termination, and planparticipants will have the option to receive their benefits either through alump sum payment in 2006 or through an annuity. For those plan participants who elect to receive an annuity, we willpurchase an annuity contract from an insurance company in which the planparticipant owns the annuity, absolving us of any future obligation to theparticipant.  Participants in the TEPPCOSBP received pay credits through November 30, 2005, and received lump sumbenefit payments in December 2005.

 

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

** **

**Compensation of Directors**

 

Effective January 1, 2005, for the period from January 1, 2005 throughMarch 22, 2005, directors of the General Partner who were neither officers noremployees of either the Company or DEFS received a retainer of $35,000 perannum, $1,000 for attendance at each meeting of the Board, $1,000 forattendance at each meeting of a committee of the Board, except for attendanceof the Audit Committee, for which the amount was $2,000 for each meeting, andreimbursement of expenses incurred in connection with attendance at a meetingof the Board or a committee of the Board. Each non-employee director who served as Chairman of a committee of theBoard received an additional retainer of $8,000 per annum, except for the Chairmanof the Audit Committee, who received an additional retainer of $20,000 perannum.  Effective September 1, 1999,non-employee directors could elect to defer payment of retainer and attendancefees until termination of service on the Board. Upon termination, the director could elect to receive payment either ina lump sum or in equal installments over five years.  Such deferral could either be 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 our Units.  Effective with the change in ownership of theGeneral Partner on February 24, 2005, deferrals of Board compensation wasdiscontinued.

 

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

 

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

 

74

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***Item 12. *Security Ownership of CertainBeneficial Owners and Management**

 

*EquityCompensation Plan Information*

* *

At December 31, 2005, we had no Equity Compensation Plans approved or unapprovedby security holders as none of our compensation plans require the issuance ofsecurities or options.  During the yearended December 31, 2003, all of the remaining outstanding Unit options underthe 1994 LTIP were exercised (see Compensation Pursuant to General PartnerPlans).  We have no other compensationplans that would result in the issuance of Units.

* *

*SecurityOwnership of Certain Beneficial Owners*

* *

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

 

* Security Ownership of Management*

* *

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

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

 

----

(1)     Unless otherwise indicated, thepersons 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)     These Units are held by an estate for which Mr. Snell is theco-executor. Mr. Snell disclaims beneficial ownership of these Units.

 

***Item 13. *Certain Relationships andRelated Transactions**

 

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

 

The Partnership does not have any employees.  We are managed by the Company, which for allperiods prior to February 23, 2005, was an indirect wholly owned subsidiary ofDEFS.  According to the PartnershipAgreement, the Company was entitled to reimbursement of all direct and indirectexpenses related to our business activities. As a result of the change in ownership of the General Partner onFebruary 24, 2005, all of our management, administrative and operatingfunctions are performed by employees of EPCO, pursuant to an administrative servicesagreement.  We reimburse EPCO for thecosts of its employees who perform operating functions for us and for costsrelated to its other management and administrative employees (see Note 1 in theNotes to the Consolidated Financial Statements).

 

75

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

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

 

----

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

 

76

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| (14)   |   | Effective with the purchase of the fractionation  facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into an  Operation and Maintenance Agreement, whereby DEFS operates and maintains the  fractionation facilities for TEPPCO Colorado. For these services, TEPPCO  Colorado pays DEFS a set volumetric rate for all fractionated volumes  delivered to DEFS. |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| (15)   |   | Includes TCO purchases of condensate.                                                                                                                                                                                                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| (16)   |   | Includes Jonah purchases of natural gas in connection  with Jonah’s Pioneer processing plant operations.                                                                                                                                                                                                                                                               |

 

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

 

At December 31, 2004, we had a receivable from DEFS and affiliates of$10.5 million related to sales and transportation services provided to DEFS andaffiliates.  Included in this receivablebalance from DEFS and affiliates at December 31, 2004, is a gas imbalancereceivable of $0.9 million.  At December31, 2004, we had a payable to DEFS and affiliates of $22.4 million related todirect payroll, payroll related costs, management fees, and other operationalrelated charges, including those for Jonah, Chaparral and Val Verde asdescribed above.  Included in thispayable balance at December 31, 2004, is a gas imbalance payable to DEFS andaffiliates of $3.2 million.

 

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

 

Through February 23, 2005, we contracted with Bison Insurance CompanyLimited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority ofour insurance coverage, including property, liability, auto and directors andofficers’ liability insurance.  Through February23, 2005 and for the years ended December 31, 2004 and 2003, we incurredinsurance expense related to premiums paid to Bison of $1.2 million, $6.5million and $5.9 million, respectively. At December 31, 2004, we had insurance reimbursement receivables duefrom Bison of $5.2 million.

 

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

** **

**Interest of the General Partner in the Partnership**

 

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

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

 

During the year ended December 31, 2005, distributionspaid to the General Partner totaled $73.2 million, including incentivedistributions of $69.5 million.

 

77

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## **Interests of DFI in the Partnership**

 

At formation in 1990, we completed an initial public offering of26,500,000 Units representing Limited Partner Interests.  In connection with our formation, the Companyreceived 2,500,000 DPIs.  Effective April1, 1994, the DPIs were converted to Units, but they have not been listed fortrading on the New York Stock Exchange.  These Units were assigned to Duke Energy whenownership of the Company was transferred from Duke Energy to DEFS in 2000.  On February 24, 2005, DFI entered into an LPUnit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000Units for $104.0 million.  At December31, 2005, we had outstanding 69,963,554 Units, including 2,500,000 Units heldby DFI.

 

***Item 14. *Principal Accounting Fees andServices**

 

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

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

 

----

(1)          Audit fees include fees for the audits of theconsolidated financial statements as well as for the audit of internal controlover financial reporting.

 

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

 

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

 

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

## ** **

Pursuant to its charter, the Audit and Conflicts Committee of our Boardis responsible for reviewing and approving, in advance, any audit and anypermissible non-audit engagement or relationship between us and our independentregistered public accountants.  KPMG’sengagement and all related fees to conduct our audit were pre-approved by theAudit and Conflicts Committee on April 25, 2005.  Additionally, all permissible non-auditengagements with KPMG have been reviewed and approved by the Audit andConflicts Committee, pursuant to pre-approval policies and proceduresestablished by the Audit and Conflicts Committee.

** **

**PART IV**

*** ***

***Item 15. *Exhibits, Financial StatementSchedules.**

 

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

 

(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.

 

78

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

 

79

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

 

80

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

 

81

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

 

82

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

 

83

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

 

----

*  Filedherewith.

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

+  A managementcontract or compensation plan or arrangement.

 

**SIGNATURES**

 

Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this Report to be signed on its behalf bythe undersigned, thereunto duly authorized.

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

 

84

----

 

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

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

 

* Signed on behalf of the Registrantand each of these persons:

 

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

 

85

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**CONSOLIDATED FINANCIAL STATEMENTS**

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

 

**INDEX TO CONSOLIDATED FINANCIALSTATEMENTS**

 

 
|                                                                                                                                      |   |
|-------------------------------------------------------------------------------------------------------------------------------------------|--------|
| Consolidated Financial Statements:                                                                                                        |   |
|                                                                                                                                      |   |
| Report of Independent  Registered Public Accounting Firm                                                                                  |   |
|                                                                                                                                      |   |
| Consolidated Balance Sheets as of  December 31, 2005 and 2004 (as restated)                                                          |   |
|                                                                                                                                      |   |
| Consolidated Statements of  Income for the years ended December 31, 2005, 2004 (as restated) and  2003 (as restated)                 |   |
|                                                                                                                                      |   |
| Consolidated Statements of  Cash Flows for the years ended December 31, 2005, 2004 (as restated) and  2003 (as restated)             |   |
|                                                                                                                                      |   |
| Consolidated Statements of  Partners’ Capital for the years ended December 31, 2005, 2004 (as  restated) and 2003 (as restated) |   |
|                                                                                                                                      |   |
| Consolidated Statements of  Comprehensive Income for the years ended December 31, 2005, 2004 (as  restated) and 2003 (as restated)   |   |
|                                                                                                                                      |   |
| Notes to Consolidated  Financial Statements                                                                                               |   |

 

F-1

----

 

**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

To the Partners of

TEPPCO Partners, L.P.:

 

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

 

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

 

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

 

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

 

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

 
|                    | KPMG  LLP |
|-------------------------|-----------|
|                    |      |
| Houston,  Texas         |      |
| February 28,  2006 |      |

 

F-2

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATED BALANCE SHEETS**

**(in thousands)**

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

 

See accompanying Notes to Consolidated FinancialStatements.

 

F-3

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATEDSTATEMENTS OF INCOME**

**(in thousands, except per Unitamounts**)

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

 

See accompanying Notes to Consolidated FinancialStatements.

 

F-4

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**

**(in thousands)**

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

 

See accompanying Notes to Consolidated Financial Statements.

 

F-5

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATEDSTATEMENTS OF PARTNERS’ CAPITAL**

**(in thousands, except Unitamounts)**

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

 

See accompanying Notes to Consolidated FinancialStatements.

 

F-6

----

 

**TEPPCO PARTNERS, L.P.**

 

**CONSOLIDATEDSTATEMENTS OF COMPREHENSIVE INCOME**

**(in thousands)**

 

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

 

See accompanying Notes to Consolidated FinancialStatements.

 

F-7

----

 

**TEPPCO PARTNERS, L.P.**

 

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**NOTE 1.        PARTNERSHIPORGANIZATION**

** **

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.

 

On July 26, 2001,the Company restructured its general partner ownership of the OperatingPartnerships to cause them to be indirectly wholly owned by us.  TEPPCO GP, Inc. (“TEPPCO GP”), oursubsidiary, succeeded the Company as general partner of the OperatingPartnerships. All remaining partner interests in the Operating Partnerships notalready owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our generalpartner was increased to 2%.  Theincreased percentage is the economic equivalent of the aggregate interest thatthe Company had prior to the restructuring through its combined interests in usand the Operating Partnerships.  As aresult, we hold a 99.999% limited partner interest in the OperatingPartnerships and TEPPCO GP holds a 0.001% general partner interest.  This reorganization was undertaken tosimplify required financial reporting by the Operating Partnerships when theOperating Partnerships issue guarantees of our debt.

 

Through February 23,2005, the General Partner was an indirect wholly owned subsidiary of DukeEnergy Field Services, LLC (“DEFS”), a joint venture between Duke EnergyCorporation (“Duke Energy”) and ConocoPhillips. Duke Energy held an interest of approximately 70% in DEFS, andConocoPhillips held the remaining interest of approximately 30%.  On February 24, 2005, the GeneralPartner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP HoldingsL.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately heldcompany controlled by Dan L. Duncan, for approximately $1.1 billion.  As a result of the transaction, DFI owns andcontrols the 2% general partner interest in us and has the right to receive theincentive distribution rights associated with the general partnerinterest.  In conjunction with an amendedand restated administrative services agreement, EPCO performs all management,administrative and operating functions required for us, and we reimburse EPCOfor all direct and indirect expenses that have been incurred in managingus.  As a result of the sale of ourGeneral Partner, DEFS and Duke Energy continued to provide some administrativeservices for us for a period of up to one year after the sale, at which time,we assumed these services.  In connectionwith us assuming the operations of certain of the TEPPCO Midstream assets fromDEFS, certain DEFS employees became employees of EPCO effective June 1,2005.

 

At formation in 1990, wecompleted an initial public offering of 26,500,000 units representing LimitedPartner Interests (“Limited Partner Units”) at $10.00 per Limited PartnerUnit.  In connection with our formation,the Company received 2,500,000 Deferred Participation Interests (“DPIs”).  Effective April 1, 1994, the DPIs wereconverted to Limited Partner Units, but they have not been listed for tradingon the New York Stock Exchange.  TheseLimited Partner Units were assigned to Duke Energy when ownership of theCompany was transferred from Duke Energy to DEFS in 2000.  On February 24, 2005, DFI entered intoan LP Unit Purchase and Sale Agreement with Duke Energy and purchased these2,500,000 Limited Partner Units for $104.0 million.  As of December 31, 2005, none of theseLimited Partner Units had been sold by DFI.

 

At December 31,2005, 2004 and 2003, we had outstanding 69,963,554, 62,998,554 and 62,998,554Limited Partner Units, respectively.  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.  On April 2, 2003, we repurchased andretired all of the 3,916,547 previously outstanding Class B Units withproceeds from the issuance of additional Limited Partner Units (see Note11).  Collectively, the Limited PartnerUnits and Class B Units are referred to as “Units”.

 

F-8

----

 

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

 

We restated ourconsolidated financial statements and related financial information for theyears ended December 31, 2004 and 2003, for an accounting correction.  In addition, the restatement adjustmentimpacted quarterly periods with the fiscal years ended December 31, 2005,2004 and 2003.  See Note 20 for adiscussion of the restatement adjustment and the impact on previously issuedfinancial statements.

 

**NOTE 2.        SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES**

** **

We adhere to thefollowing significant accounting policies in the preparation of ourconsolidated financial statements.

 

## **Basis of Presentation andPrinciples of Consolidation**

## ** **

Throughout theconsolidated financial statements and accompanying notes, all referencedamounts related to prior periods reflect the balances and amounts on a restatedbasis.  The financial statements includeour accounts on a consolidated basis.  Wehave eliminated all significant intercompany items in consolidation.  We have reclassified certain amounts fromprior periods to conform to the current presentation.

 

## **Use of Estimates**

## ** **

The preparation offinancial statements in conformity with generally accepted accountingprinciples in the United States requires our management to make estimates andassumptions that affect the reported amounts of assets and liabilities anddisclosure of contingent assets and liabilities at the date of the financialstatements and the reported amounts of revenues and expenses during thereporting periods.  Although we believethese estimates are reasonable, actual results could differ from thoseestimates.

 

## **Business Segments**

## ** **

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

 

## **Revenue Recognition**

## ** **

Our Downstream Segmentrevenues are earned from transportation and storage of refined products andLPGs, intrastate transportation of petrochemicals, sale of product inventoryand other ancillary services. Transportation revenues are recognized as products are delivered tocustomers.  Storage revenues arerecognized upon receipt of products into storage and upon performance ofstorage services. Terminaling revenues are recognized as products areout-loaded.  Revenues from the sale ofproduct inventory are recognized when the products are sold.

 

F-9

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Our Upstream Segmentrevenues are earned from gathering, transportation, marketing and storage ofcrude oil, and distribution of lubrication oils and specialty chemicalsprincipally in Oklahoma, Texas, New Mexico and the Rocky Mountain region.  Revenues are also generated from tradedocumentation and pumpover services, primarily at Cushing, Oklahoma, andMidland, Texas.  Revenues are accrued atthe time title to the product sold transfers to the purchaser, which typicallyoccurs upon receipt of the product by the purchaser, and purchases are accruedat the time title to the product purchased transfers to our crude oil marketingcompany, TEPPCO Crude Oil, L.P. (“TCO”), which typically occurs upon ourreceipt of the product.  Revenues relatedto trade documentation and pumpover fees are recognized as services arecompleted.

 

Except for crude oilpurchased from time to time as inventory, our policy is to purchase only crudeoil for which we have a market to sell and to structure sales contracts so thatcrude oil price fluctuations do not materially affect the margin received.  As we purchase crude oil, we establish amargin by selling crude oil for physical delivery to third party users or byentering into a future delivery obligation. Through these transactions, we seek to maintain a position that isbalanced between crude oil purchases and sales and future deliveryobligations.  However, certain basisrisks (the risk that price relationships between delivery points, classes ofproducts or delivery periods will change) cannot be completely hedged.

 

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

 

## **Cash and Cash Equivalents**

## ** **

Cash equivalents aredefined as all highly marketable securities with maturities of three months orless when purchased.  The carrying valueof cash and cash equivalents approximate fair value because of the short termnature of these investments.

 

**Allowancefor Doubtful Accounts**

 

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

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

 

## **Inventories**

## ** **

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

 

F-10

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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 andexpansions, are carried at the lower of fair value or cost.

 

## **Property, Plant andEquipment**

## ** **

We record property, plantand equipment at its acquisition cost. Additions to property, plant and equipment, including major replacementsor betterments, are recorded at cost.  Wecharge replacements and renewals of minor items of property that do notmaterially increase values or extend useful lives to maintenance 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 oflong-lived assets in accordance with Statement of Financial AccountingStandards (“SFAS”) No. 144, *Accounting for theImpairment 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 estimatedfuture net cash flows expected to be generated by the asset.  If such assets are considered to be impaired,the impairment to be recognized is measured by the amount by which the carryingamount of the assets exceeds the estimated fair value of the assets.  Assets to be disposed of are reported at thelower of the carrying amount or estimated fair value less costs to sell.

 

## **Asset RetirementObligations**

## ** **

In June 2001,the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, *Accounting for Asset Retirement Obligations*.  SFAS 143 requires us to record the fair valueof an asset retirement obligation as a liability in the period in which weincur a legal obligation for 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.

 

TheDownstream Segment assets consist primarily of an interstate trunk pipelinesystem and a series of storage facilities that originate along the upper TexasGulf Coast and extend through the Midwest and northeastern United States.  We transport refined products, LPGs andpetrochemicals through the pipeline system. These products are primarily received in the south end of the system andstored and/or transported to various points along the system per customernominations.  The Upstream Segment’soperations include purchasing crude oil from producers at the wellhead andproviding delivery, storage and other services to its customers.  The properties in the Upstream Segmentconsist of interstate trunk pipelines, pump stations, trucking facilities,storage tanks and various gathering systems primarily in Texas and Oklahoma.  The Midstream Segment gathers natural gasfrom wells owned by producers and delivers natural gas and NGLs on its pipelinesystems, primarily in Texas, Wyoming, New Mexico and Colorado.  The Midstream Segment also owns and operatestwo NGL fractionator facilities in Colorado.

 

We havecompleted our assessment of SFAS 143, and we have determined that we areobligated by contractual or regulatory requirements to remove certainfacilities or perform other remediation upon retirement of our assets.  However, we are not able to reasonablydetermine the fair value of the asset retirement obligations for our trunk,interstate and gathering pipelines and our surface facilities, since futuredismantlement and removal dates are indeterminate.

 

In orderto determine a removal date for our gathering lines and related surface assets,reserve information regarding the production life of the specific field isrequired.  As a transporter and gathererof crude oil and natural

 

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gas, we are not a producer ofthe field reserves, and we therefore do not have access to adequate forecaststhat predict the timing of expected production for existing reserves on thosefields 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.

 

We will record such assetretirement obligations in the period in which more information becomesavailable for us to reasonably estimate the settlement dates of the retirementobligations.  The adoption of SFAS 143did not have an effect on our financial position, results of operations or cashflows.

 

## **Capitalization ofInterest**

## ** **

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

 

**IntangibleAssets**

 

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

 

In connection with theacquisitions of Jonah and Val Verde, we assumed contracts that dedicate futureproduction from natural gas wells in the Green River Basin in Wyoming, and weassumed fixed-term contracts with customers that gather coal bed methane (“CBM”)from the San Juan Basin in New Mexico and Colorado, respectively.  The value assigned to these intangible assetsrelates to contracts with customers that are for either a fixed term or whichdedicate total future lease production to the gathering system.  These intangible assets are amortized on aunit-of-production basis, based upon the actual throughput of the system overthe 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).

 

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

 

In connection with theacquisition of crude supply and transportation assets in November 2003, weacquired intangible customer contracts for $8.7 million, which are amortized ona unit-of-production basis (see Note 5).

 

Inconnection with the formation of Centennial, we recorded excess investment, themajority of which is amortized on a unit-of-production basis over a period of10 years.  In connection with theacquisition of our interest in Seaway, we recorded excess investment, which isamortized on a straight-line basis over a period of 39 years (see Note 3).

 

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**Goodwill**

 

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

## ** **

## **EnvironmentalExpenditures**

## ** **

We accrue forenvironmental costs that relate to existing conditions caused by pastoperations.  Environmental costs includeinitial site surveys and environmental studies of potentially contaminatedsites, costs for remediation and restoration of sites determined to becontaminated and ongoing monitoring costs, as well as damages and other costs,when estimable.  We monitor the balanceof accrued undiscounted environmental liabilities on a regular basis.  We record liabilities for environmental costsat a specific site when our liability for such costs is probable and a reasonableestimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, toreflect changing circumstances and estimates based upon additional informationdeveloped in subsequent periods. Estimates of our ultimate liabilities associated with environmentalcosts are particularly difficult to make with certainty due to the number ofvariables involved, including the early stage of investigation at certainsites, the lengthy time frames required to complete remediation alternativesavailable and the evolving nature of environmental laws and regulations.

 

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

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

## ** **

## **Natural Gas Imbalances**

## ** **

Gas imbalances occur whengas producers (customers) deliver more or less actual natural gas gatheringvolumes to our gathering systems than they originally nominated.  Actual deliveries are different fromnominated volumes due to fluctuations in gas production at the wellhead.  If the customers supply more natural gasgathering volumes than they nominated, Val Verde and Jonah record a payable forthe amount due to customers and also record a receivable for the same amountdue from connecting pipeline transporters or shippers.  To the extent that these amounts are notcashed out monthly on Val Verde, if the customers supply less natural gasgathering volumes than they nominated, Val Verde and Jonah record a receivablereflecting the amount due from customers and a payable for the same amount dueto connecting pipeline transporters or shippers.  We record natural gas imbalances using amark-to-market approach.

 

## **Income Taxes**

## ** **

We are a limitedpartnership.  As such, we are not ataxable entity for federal and state income tax purposes and do not directlypay federal and state income tax.  Ourtaxable income or loss, which may vary substantially from

 

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

 

## **Use of Derivatives**

## ** **

We account for derivativefinancial instruments in accordance with SFAS No. 133, *Accounting for Derivative Instruments and Hedging Activities,*andSFAS No. 138, *Accounting for CertainDerivative Instruments and Certain Hedging Activities, an amendment of FASBStatement No. 133. *Thesestatements establish accounting and reporting standards requiring thatderivative instruments (including certain derivative instruments embedded inother contracts) be recorded on the balance sheet at fair value as eitherassets or liabilities.  The accountingfor changes in the fair value of a derivative instrument depends on theintended use of the derivative and the resulting designation, which isestablished at the inception of a derivative.

 

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

 

For all hedgingrelationships, we formally document at inception the hedging relationship andits risk-management objective and strategy for undertaking the hedge, thehedging instrument, the item, the nature of the risk being hedged, how thehedging instrument’s effectiveness in offsetting the hedged risk will beassessed and a description of the method of measuring ineffectiveness.  This process includes linking all derivativesthat are designated as fair value or cash flow to specific assets andliabilities on the balance sheet or to specific firm commitments or forecastedtransactions.  We also formally assess,both at the hedge’s inception and on an ongoing basis, whether the derivativesthat are used in hedging transactions are highly effective in offsettingchanges 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 derivativeinstruments designated as fair value hedges, gains and losses on the derivativeinstrument are offset against related results on the hedged item in thestatement of income.  Changes in the fairvalue of a derivative that is highly effective and that is designated andqualifies as a fair value hedge, along with the loss or gain on the hedgedasset or liability or unrecognized firm commitment of the hedged item that isattributable to the hedged risk, are recorded in earnings.  Changes in the fair value of a derivativethat is highly effective and that is designated and qualifies as a cash flowhedge are recorded in other comprehensive income to the extent that thederivative is effective as a hedge, until earnings are affected by thevariability in cash flows of the designated hedged item. Hedge effectiveness ismeasured at least quarterly based on the relative cumulative changes in fairvalue between the derivative contract and the hedged item over time.  The ineffective portion of the change in fairvalue of a derivative instrument that qualifies as either a fair value hedge ora cash flow hedge is reported immediately in earnings.

 

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

 

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meets the definition of a firmcommitment, or management determines that designation of the derivative as ahedging instrument is no longer appropriate.

 

When hedge accounting isdiscontinued because it is determined that the derivative no longer qualifiesas an effective fair value hedge, we continue to carry the derivative on thebalance sheet at its fair value and no longer adjust the hedged asset orliability for changes in fair value.  Theadjustment of the carrying amount of the hedged asset or liability is accountedfor in the same manner as other components of the carrying amount of that assetor liability.  When hedge accounting isdiscontinued because the hedged item no longer meets the definition of a firm commitment,we continue to carry the derivative on the balance sheet at its fair value,remove any asset or liability that was recorded pursuant to recognition of thefirm commitment 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.

 

**FairValue of Financial Instruments**

 

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

 

**NetIncome Per Unit**

 

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

 

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

 

## **Unit Option Plan**

## ** **

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

 

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

 

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methods of transition for avoluntary change to the fair value based method of accounting for stock-basedemployee compensation.  In addition, SFAS148 amends the disclosure requirements of SFAS 123 to require prominentdisclosure in both annual and interim financial statements about the method ofaccounting for stock-based employee compensation and the effect of the methodused on reported results.  Certain of thedisclosure modifications are required for fiscal years ending after December 15,2002, and are included in Note 13.

 

Assuming we had used thefair value method of accounting for our Unit option plan, pro forma net incomewould equal reported net income for the years ended December 31, 2005,2004 and 2003.  Pro forma net income perUnit would equal reported 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 AccountingPronouncements**

## ** **

**In December 2004,the FASB issued SFAS No. 123(R), *Share-BasedPayment*.  SFAS 123(R) requirescompensation costs related to share-based payment transactions to be recognizedin the financial statements.  Withlimited exceptions, the amount of the compensation cost is to be measured basedon the grant-date fair value of the equity or liability instrumentsissued.  In addition, liability awardsare to be re-measured each reporting period. Compensation cost will be recognized over the period that an employeeprovides service in exchange for the award. SFAS 123(R) is a revision of SFAS No. 123,*Accounting for Stock-Based Compensation*,as amended by SFAS No. 148,*Accountingfor Stock-Based Compensation – Transition and Disclosure* andsupersedes Accounting Principles Board (“APB”) Opinion No. 25, *Accounting for Stock Issued to Employees*.  SFAS 123(R) is effective for public companiesas of the first interim or annual reporting period of the first fiscal yearbeginning after June 15, 2005.  TheSecurities and Exchange Commission amended the implementation date of SFAS123(R) to begin with the first interim or annual reporting period of thecompany’s first fiscal year beginning on or after June 15, 1005.  As such, we will adopt SFAS 123(R) in thefirst quarter of 2006.  Companies arepermitted to adopt SFAS 123(R) prior to the extended date.  All public companies that adopted thefair-value-based method of accounting must use the modified prospectivetransition method and may elect to use the modified retrospective transitionmethod.  We do not believe that the adoptionof SFAS 123(R) will have a material effect on our financial position, resultsof operations or cash flows.**

** **

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

** **

**In March 2005,the FASB issued FASB Interpretation No. 47, *Accounting for Conditional Asset Retirement Obligations, aninterpretation of FASB Statement No. 143* (“FIN 47”).  FIN 47 clarifies that the term, conditionalasset retirement obligation as used in SFAS No. 143, *Accountingfor Asset Retirement Obligations*, refers to a legal obligation toperform an asset retirement activity in which the timing and/or method ofsettlement are conditional upon a future event that may or may not be withinthe control of the entity.  Even thoughuncertainty about the timing and/or method of settlement exists and may beconditional upon a future event, the obligation to perform the asset retirementactivity is unconditional.  Accordingly,an entity is required to recognize a liability for the fair value of aconditional asset retirement obligation if the fair value of the liability canbe reasonably estimated.  Uncertaintyabout the timing and/or method of settlement of a conditional asset retirementobligation should be factored into the measurement of the liability whensufficient information exists.  The fairvalue of a liability for the conditional asset**

 

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

** **

In June 2005, the EITF reached consensus in EITF 04-5, *Determining Whether a General Partner, or the GeneralPartners as a Group, Controls a Limited Partnership or Similar Entity When theLimited Partners Have Certain Rights*, to provide guidance on howgeneral partners in a limited partnership should determine whether they controla limited partnership and therefore should consolidate it.  The EITF agreed that the presumption ofgeneral partner control would be overcome only when the limited partners haveeither of two types of rights. The first type, referred to as kick-out rights,is the right to dissolve or liquidate the partnership or otherwise remove thegeneral partner without cause.  Thesecond type, referred to as participating rights, is the right to effectivelyparticipate in significant decisions made in the ordinary course of thepartnership’s business. The kick-out rights and the participating rights mustbe substantive in order to overcome the presumption of general partner control.The consensus is effective for general partners of all new limited partnershipsformed and for existing limited partnerships for which the partnershipagreements are modified subsequent to the date of FASB ratification (June 29,2005).  For existing limited partnershipsthat have not been modified, the guidance in EITF 04-5 is effective no laterthan the beginning of the first reporting period in fiscal years beginningafter December 15, 2005.  We do notbelieve that the adoption of EITF 04-5 will have a material effect on ourfinancial position, results of operations or cash flows.

 

In December 2004, the FASB issued SFAS No. 153, *Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29*.   SFAS 153 amends APB Opinion No. 29, *Accounting for Nonmonetary Exchanges,*to eliminate theexception for nonmonetary exchanges of similar productive assets and replacesit with a general exception for exchanges of nonmonetary assets that do nothave commercial substance.  A nonmonetaryexchange has commercial substance if the future cash flows of the entity areexpected to change significantly as a result of the exchange.  SFAS 153 is effective for nonmonetary assetexchanges occurring in fiscal periods beginning after June 15, 2005.  We adopted SFAS 153 during the second quarterof 2005.  The adoption of SFAS 153 didnot have a material effect on our financial position, results of operations orcash flows.

 

In May 2005, the FASB issued SFAS No. 154, *Accounting Changes and Error Corrections*.  SFAS 154 establishes new standards onaccounting for changes in accounting principles.  All such changes must be accounted for byretrospective application to the financial statements of prior periods unlessit is impracticable to do so.  SFAS 154completely replaces APB Opinion No. 20, *AccountingChanges,*and SFAS No. 3, *ReportingAccounting Changes in Interim Periods*.  However, it carries forward the guidance inthose pronouncements with respect to accounting for changes in estimates,changes in the reporting entity, and the correction of errors.  SFAS 154 is effective for accounting changesand error corrections made in fiscal years beginning after December 15,2005, with early adoption permitted for changes and corrections made in yearsbeginning after June 1, 2005. The application of SFAS 154 does not affectthe transition provisions of any existing pronouncements, including those thatare in the transition phase as of the effective date of SFAS 154.  We do not believe that the adoption of SFAS154 will have a material effect on our financial position, results ofoperations or cash flows.

 

**In September 2005,the EITF reached consensus in EITF 04-13, *Accounting for Purchasesand Sales of Inventory with the Same Counterparty*, to define when apurchase and a sale of inventory with the same party that operates in the sameline of business should be considered a single nonmonetary transaction subjectto APB Opinion No. 29, *Accounting for NonmonetaryTransactions*.  Two or moreinventory transactions with the same party should be combined if they areentered into in contemplation of one another. The EITF also requires entities to account for**

 

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

** **

**NOTE 3.        GOODWILLAND OTHER INTANGIBLE ASSETS**

** **

**Goodwill**

** **

Goodwill represents theexcess of purchase price over fair value of net assets acquired and ispresented on the consolidated balance sheets net of accumulatedamortization.  We account for goodwillunder SFAS No. 142, *Goodwill and OtherIntangible Assets,*which was issued by the FASB in July 2001.  SFAS 142 prohibits amortization of goodwilland intangible assets with indefinite useful lives, but instead requirestesting for impairment at least annually. We test goodwill and intangibleassets for impairment annually at December 31.

 

To perform an impairmenttest of goodwill, we have identified our reporting units and have determinedthe carrying value of each reporting unit by assigning the assets andliabilities, including the existing goodwill and intangible assets, to thosereporting units.  We then determine thefair value of each reporting unit and compare it to the carrying value of thereporting unit.  We will continue to comparethe fair value of each reporting unit to its carrying value on an annual basisto determine if an impairment loss has occurred.   There have been no goodwill impairmentlosses recorded since the adoption of SFAS 142.

 

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

 

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

 

**Other Intangible Assets**

 

Thefollowing table reflects the components of intangible assets, including excessinvestments, being amortized at December 31, 2005 and 2004 (in thousands):

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

 

F-18

----

 

 

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

 

Thevalues assigned to our intangible assets for natural gas gathering contracts onthe Jonah and the Val Verde systems are amortized on a unit-of-productionbasis, based upon the actual throughput of the systems compared to the expectedtotal throughput for the lives of the contracts.  On a quarterly basis, we may obtain limitedproduction forecasts and updated throughput estimates from some of theproducers on the systems, and as a result, we evaluate the remaining expecteduseful lives of the contract assets based on the best available information.  During the fourth quarter of 2004 and thefirst and second quarters of 2005, certain limited production forecasts wereobtained from some of the producers on the Jonah system related to futureexpansions of the system, and as a result, we increased our best estimate of futurethroughput on the system, which resulted in extensions in the remaining livesof the intangible assets.  During thefourth quarter of 2004 and the third quarter of 2005, certain limited coal bedmethane production forecasts were obtained from some of the producers on theVal Verde system whose contracts are included in the intangible assets.  These forecasts indicated lower coal bedmethane production estimates over the contract periods, and as a result, wedecreased our best estimate of future throughput on the Val Verde system, whichresulted in increases to amortization expense on the intangible assets.  Further revisions to these estimates mayoccur as additional production information is made available to us.

 

Thevalues assigned to our fractionation agreement and other intangible assets aregenerally amortized on a straight-line basis. Our fractionation agreement is being amortized over its contract periodof 20 years.  The amortization periodsfor our other intangible assets, which include non-compete and otheragreements, range from 3 years to 15 years. The value of $8.7 million assigned to our crude supply andtransportation intangible customer contracts is being amortized on aunit-of-production basis (see Note 5).

 

The valueassigned to our excess investment in Centennial was created upon itsformation.  Approximately $30.0 millionis related to a contract and is being amortized on a unit-of-production basisbased upon the volumes transported under the contract compared to theguaranteed total throughput of the contract over a 10-year life.  The remaining $3.4 million is related to apipeline and is being amortized on a straight-line basis over the life of thepipeline, which is 35 years.  The valueassigned to our excess investment in Seaway was created upon acquisition of our50% ownership interest in 2000.  We areamortizing the $27.1 million excess investment in Seaway on a straight-linebasis over a 39-year life related primarily to the life of the pipeline.

 

Thefollowing table sets forth the estimated amortization expense of intangibleassets and the estimated amortization expense allocated to equity earnings forthe years ending December 31 (in thousands):

 

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

 

F-19

----

 

**NOTE 4.        INTERESTRATE SWAPS**

** **

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 swapmatured in April 2004.  Wedesignated this swap agreement, which hedged exposure to variability inexpected future cash flows attributed to changes in interest rates, as a cashflow 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.  During theyears ended December 31, 2004 and 2003, we recognized an increase ininterest expense of $2.9 million and $14.4 million, respectively, related tothe difference between the fixed rate and the floating rate of interest on theinterest rate swap.

 

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, 2005, 2004 and 2003, we recognized reductionsin interest expense of $5.6 million, $9.6 million and $10.0 million,respectively, related to the difference between the fixed rate and the floatingrate of interest on the interest rate swap. During the years ended December 31,2005, 2004 and 2003, we measured the hedge effectiveness of this interest rateswap and noted that no gain or loss from ineffectiveness was required to be recognized.  The fair value of this interest rate swap wasa loss of approximately $0.9 million at December 31, 2005, and a gain ofapproximately $3.4 million at December 31, 2004.

 

**During 2002, weentered into interest rate swap agreements, designated as fair value hedges, tohedge our exposure to changes in the fair value of our fixed rate 7.625% SeniorNotes due 2012.  The swap agreements hada combined notional amount of $500.0 million and matured in 2012 to match theprincipal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based ona U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interestof 7.625%.  These swap agreements werelater terminated in 2002 resulting in gains of $44.9 million.  The gains realized from the swap terminationshave been deferred as adjustments to the carrying value of the Senior Notes andare being amortized using the effective interest method as reductions to futureinterest expense over the remaining term of the Senior Notes.  At December 31, 2005, the unamortizedbalance of the deferred gains was $32.4 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.**

** **

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

 

**NOTE 5.        ACQUISITIONSAND DISPOSITIONS**

** **

**Rancho Pipeline**

 

Inconnection with our acquisition of crude oil assets 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, Texas.  In March 2003, the Rancho Pipelineceased operations, and segments of the pipeline were sold to certain of

 

F-20

----

 

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

 

**Genesis Pipeline**

 

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 Note11).  We allocated the purchase price,net of liabilities assumed, primarily to property, plant and equipment andintangible assets.  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.

 

Thefollowing table allocates the estimated fair value of the Genesis assetsacquired 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 |   |

 

**MexiaPipeline**

 

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

 

**Crude OilStorage and Terminaling Assets**

 

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

 

F-21

----

 

**RefinedProducts Terminal and Truck Rack**

 

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

 

**Genco Assets**

 

On July 15,2005, we acquired from Texas Genco, LLC (“Genco”) all of its interests incertain companies that own a 90-mile pipeline system and 5.5 million barrels ofstorage capacity for $62.1 million.  Wefunded the purchase through borrowings under our revolving creditfacility.  We allocated the purchaseprice to property, plant and equipment, and we accounted for the acquisition ofthese assets under the purchase method of accounting.  The assets of the purchased companies will beintegrated into our Downstream Segment origin infrastructure in Texas City andBaytown, Texas.  As a result of thisacquisition, we initiated the expansion of refined products origin capabilitiesin the Houston and Texas City, Texas, areas. The integration and other system enhancements should be in service bythe fourth quarter of 2006, at an estimated cost of $45.0 million.  The strategic location of these assets, withrefined products interconnections to major exchange terminals in the Houstonarea, will provide significant long-term value to our customers and our TexasGulf Coast refining and logistics system.

 

**NOTE 6.        EQUITYINVESTMENTS**

** **

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

 

In August 2000,TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”),a former subsidiary of CMS Energy Corporation, and Marathon Petroleum CompanyLLC (“Marathon”) to form Centennial. Centennial owns an interstate refined petroleum products pipelineextending from the upper Texas Gulf Coast to central Illinois.  Through February 9, 2003, eachparticipant owned a one-third interest in Centennial.  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 ownership percentages in Centennial to 50%each.  During the year ended December 31,2005, TE Products did not make any additional investments in Centennial. TEProducts invested an additional $1.5 million and $24.0 million, respectively,in Centennial, in 2004 and 2003, which is included in the equity investmentbalance at December 31, 2005.  The2003 amount includes the $20.0 million paid for the acquisition of theadditional ownership interest in Centennial. TE Products has not received any distributions from Centennial since itsformation.

 

On January 1, 2003,TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formedMont Belvieu Storage Partners, L.P. (“MB Storage”).  TE Products and Louis Dreyfus each own a 50%ownership interest in MB Storage. MB Storage owns storage capacity at the MontBelvieu fractionation and storage complex and a short haul transportationshuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coastenergy marketplace. MB Storage is a service-oriented, fee-based venture servingthe fractionation, refining and petrochemical industries with substantialcapacity and flexibility for the transportation, terminaling and storage of

 

F-22

----

 

NGLs, LPGs and refinedproducts.  MB Storage has no commoditytrading activity.  TE Products operatesthe facilities for MB Storage.  EffectiveJanuary 1, 2003, TE Products contributed property and equipment with a netbook value of $67.1 million to MB Storage. Additionally, as of the contribution date, Louis Dreyfus had invested$6.1 million for expansion projects for MB Storage that TE Products wasrequired to reimburse if the original joint development and marketing agreementwas terminated by either party.  Thisdeferred liability was also contributed and credited to the capital account ofLouis Dreyfus in MB Storage.

 

For the year ended December 31,2005, TE Products received the first $1.7 million per quarter (or $6.78 millionon an annual basis) of MB Storage’s income before depreciation expense, asdefined in the operating agreement.  Forthe year ended December 31, 2004, TE Products received the first $1.8million per quarter (or $7.15 million on an annual basis) of MB Storage’sincome before depreciation expense.  TEProducts’ share of MB Storage’s earnings is adjusted annually by the partnersof MB Storage.  Any amount of MB Storage’sannual income before depreciation expense in excess of $6.78 million for 2005and $7.15 million for 2004 was allocated evenly between TE Products and LouisDreyfus.  Depreciation expense on assetseach party originally contributed to MB Storage is allocated between TEProducts and Louis Dreyfus based on the net book value of the assetscontributed.  Depreciation expense onassets constructed or acquired by MB Storage subsequent to formation isallocated evenly between TE Products and Louis Dreyfus. For the years ended December 31,2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storagewas 64.2%, 69.4% and 70.4%, respectively. During the years ended December 31, 2005, 2004 and 2003, TEProducts received distributions of $12.4 million, $10.3 million and $5.3million, respectively, from MB Storage. During the years ended December 31, 2005, 2004 and 2003, TEProducts contributed $5.6 million, $21.4 million and $2.5 million,respectively, to MB Storage. The 2005 contribution includes a combination ofnon-cash asset transfers of $1.4 million and cash contributions of $4.2million. The 2004 contribution includes $16.5 million for the acquisition ofstorage and pipeline assets in April 2004. The remaining contributionshave been for capital expenditures.

 

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

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

 

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

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

 

F-23

----

 

**NOTE 7.        RELATEDPARTY TRANSACTIONS**

** **

## **EPCO and Affiliates andDuke Energy, DEFS and Affiliates**

## ** **

The Partnership does nothave any employees.  We are managed bythe Company, which, for all periods prior to February 23, 2005, was anindirect wholly owned subsidiary of DEFS. According to the Partnership Agreement, the Company was entitled toreimbursement of all direct and indirect expenses related to our businessactivities.  As a result of the change inownership of the General Partner on February 24, 2005, all of ourmanagement, administrative and operating functions are performed by employeesof EPCO, pursuant to an administrative services agreement.  We reimburse EPCO for the costs of itsemployees who perform operating functions for us and for costs related to its othermanagement and administrative employees (see Note 1).

 

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

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

 

----

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

 

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

 

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

 

(4)          Includes other operating revenues on TE Products.

 

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

 

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

 

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

 

(8)          Includes LSI sales of lubrication oils and specialty chemicalsand Jonah NGL sales in connection with Jonah’s Pioneer processing plant operations,which was constructed during the Phase III expansion and began operating in2004.

 

F-24

----

 

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

 

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

 

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

 

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

 

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

 

(14)          Effective with the purchase of the fractionation facilities onMarch 31, 1998, TEPPCO Colorado and DEFS entered into an Operation andMaintenance Agreement, whereby DEFS operates and maintains the fractionationfacilities for TEPPCO Colorado.  Forthese services, TEPPCO Colorado pays DEFS a set volumetric rate for allfractionated volumes delivered to DEFS.

 

(15)          Includes TCO purchases of condensate.

 

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

 

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

 

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

 

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

 

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

 

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

 

F-25

----

 

## **Seaway**

## ** **

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

 

## **Centennial**

## ** **

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

 

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

 

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

 

## **MB Storage**

## ** **

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

 

F-26

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**NOTE 8.        INVENTORIES**

** **

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

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

 

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

** **

Major categories ofproperty, plant and equipment for the years ended December 31, 2005 and2004, were as follows (in thousands):

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

 

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

 

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

 

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

 

F-27

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

 

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

 

**NOTE 10.      DEBT**

** **

## **Senior Notes**

## ** **

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

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

 

and thereafter at100% of the principal amount, together in each case with accrued interest atthe redemption date.

 

The TE Products SeniorNotes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually inarrears on January 15 and July 15 of each year.  The TE Products Senior Notes are unsecuredobligations of TE Products and rank pari passu with all other unsecured andunsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants,including, but not limited to, covenants limiting the creation of lienssecuring indebtedness and sale and leaseback transactions.  However, the indenture does not limit ourability to incur additional indebtedness. As of December 31, 2005, TE Products was in compliance with thecovenants 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% SeniorNotes were issued at a discount of $2.2 million and are being accreted to theirface value over the term of the notes. 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

 

F-28

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maturity plus 35 basispoints.  The indenture governing our7.625% Senior Notes contains covenants, including, but not limited to,covenants limiting the creation of liens securing indebtedness and sale andleaseback transactions.  However, theindenture does not limit our ability to incur additional indebtedness.  As of December 31, 2005, 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% SeniorNotes due 2013.  The 6.125% Senior Noteswere issued at a discount of $1.4 million and are being accreted to their facevalue over the term of the notes.  TheSenior Notes may be redeemed at any time at our option with the payment ofaccrued interest and a make-whole premium determined by discounting remaininginterest and principal payments using a discount rate equal to the rate of theUnited States Treasury securities of comparable remaining maturity plus 35basis points.  The indenture governingour 6.125% Senior Notes contains covenants, including, but not limited to,covenants limiting the creation of liens securing indebtedness and sale andleaseback transactions.  However, theindenture does not limit our ability to incur additional indebtedness.  As of December 31, 2005, we were incompliance with the covenants of these Senior Notes.

 

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

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

 

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

 

## **Revolving Credit Facility**

## ** **

On April 6, 2001, weentered into a $500.0 million revolving credit facility including the issuanceof 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 certainrestrictive financial covenant ratios. During the first quarter of 2003, we repaid $182.0 million of theoutstanding balance of the Three Year Facility with proceeds from the issuanceof our 6.125% Senior Notes on January 30, 2003.  On June 27, 2003, we repaid theoutstanding balance under the Three Year Facility with borrowings under a newcredit facility, and canceled the Three Year Facility.

 

On June 27, 2003, weentered into a $550.0 million unsecured 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.  Restrictive covenants in the Revolving CreditFacility limit our ability to, among other things, incur additionalindebtedness, make distributions in excess of Available Cash (see Note 11) andcomplete mergers, acquisitions and sales of assets.  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 theLIBOR rate spread charged at the time of each borrowing.  On February 23, 2005, we amended ourRevolving Credit Facility to remove the requirement that DEFS must at all timesown, directly or indirectly, 100% of our General Partner, to allow for itsacquisition by DFI (see Note 1).  Duringthe second quarter of 2005, we used

 

F-29

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

 

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

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

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

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

 

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

 

The following tablesummarizes the principal amounts outstanding under all of our credit facilitiesas of December 31, 2005 and 2004 (in thousands):

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

 

**Letter of Credit**

 

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

 

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

** **

## **Equity Offerings**

## ** **

On April 2,2003, we sold in an underwritten public offering 3.9 million Units at $30.35per 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 of the3.9 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,

 

F-30

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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$53.0 million of the proceeds were used to repay indebtedness under ourrevolving credit facility and $21.0 million was used to fund the acquisition ofthe Genesis assets (see Note 5).  Theremaining amount was used primarily to fund revenue-generating and systemupgrade capital expenditures and for general partnership purposes.

 

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

 

## **Quarterly Distributionsof Available Cash**

## ** **

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

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

 

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

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

 

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

 

**General Partner Interest**

 

As of December 31, 2005 and2004, we had deficit balances of $61.5 million and $35.9 million, respectively,in our General Partner’s equity account. These negative balances do notrepresent an asset to us and do not represent an obligation of the GeneralPartner to contribute cash or other property to us. The General Partner’sequity account generally consists of its cumulative share of our net incomeless cash distributions made to it plus capital contributions that it has madeto us (see our Consolidated Statements of Partners’ Capital for a detail of the

 

F-31

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

 

Capital Accounts, as definedunder our Partnership Agreement, are maintained for our General Partner and ourlimited partners.  The Capital Accountprovisions of our Partnership Agreement incorporate principles established forU.S. federal income tax purposes and are not comparable to the equity accountsreflected under accounting principles generally accepted in the United Statesin our financial statements.  Under ourPartnership Agreement, the General Partner is required to make additionalcapital contributions to us upon the issuance of any additional Units ifnecessary to maintain a Capital Account balance equal to 1.999999% of the totalCapital Accounts of all partners.  At December 31,2005 and 2004, the General Partner’s Capital Account balance substantiallyexceeded this requirement.

 

Net income is allocated betweenthe 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 isgenerally consistent with the manner of allocating net income under ourPartnership Agreement.  Net incomedetermined under our Partnership Agreement, however, incorporates principlesestablished for U.S. federal income tax purposes and is not comparable to netincome reflected under accounting principles generally accepted in the UnitedStates in our financial statements.

 

Cash distributions that we makeduring 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.  Cashdistributions in excess of net income allocations and capital contributionsduring the years ended December 31, 2005 and 2004, resulted in a deficitin the General Partner’s equity account at December 31, 2005 and2004.  Future cash distributions thatexceed net income will result in an increase in the deficit balance in theGeneral Partner’s equity account.

 

According to the PartnershipAgreement, in the event of our dissolution, after satisfying our liabilities,our remaining assets would be divided among our limited partners and theGeneral 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.

 

**NOTE 12.      CONCENTRATIONSOF CREDIT RISK**

** **

Our primary market areasare located in the Northeast, Midwest and Southwest regions of the UnitedStates.  We have a concentration of tradereceivable balances due from major integrated oil companies, independent oilcompanies and other pipelines and wholesalers. These concentrations ofcustomers may affect our overall credit risk in that the customers may besimilarly affected by changes in economic, regulatory or other factors.  We thoroughly analyze our customers’historical and future credit positions prior to extending credit.  We manage our exposure to credit risk throughcredit analysis, credit approvals, credit limits and monitoring procedures, andfor certain transactions may utilize letters of credit, prepayments andguarantees.

 

For each of the yearsended December 31, 2005, 2004 and 2003, Valero Energy Corp. accounted for14%, 16% and 16% of our total consolidated revenues, respectively.  No other single customer accounted for 10% ormore of our total consolidated revenues for the years ended December 31,2005, 2004 and 2003.

 

F-32

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

 

**NOTE 13.      UNIT-BASEDCOMPENSATION**

** **

## **1994 Long Term IncentivePlan**

## ** **

During 1994, the Companyadopted the Texas Eastern Products Pipeline Company 1994 Long Term IncentivePlan (“1994 LTIP”). The 1994 LTIP provides certain key employees with anincentive 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 Units may be granted.

 

When our calendar yearearnings per unit (exclusive of certain special items) exceeds a statedthreshold, each participant receives a credit to their respective PerformanceUnit account equal to the earnings per unit excess multiplied by the number ofPerformance Units awarded.  The balancein the Performance Unit account may be used to offset the cost of exercisingUnit options granted in connection with the Performance Units or may bewithdrawn two years after the underlying options expire, usually 10 years fromthe date of grant.  Any unused balancepreviously credited is forfeited upon termination.  We accrue compensation expense for thePerformance Units awarded annually based upon the terms of the plan discussedabove.

 

Under the agreement forsuch Unit options, the options become exercisable in equal installments overperiods of one, two, and three years from the date of the grant.  At December 31, 2005, all options havebeen fully exercised. The Performance Unit account has a minimal liabilitybalance which may be withdrawn by the participants after December 31,2006.

 

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

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

 

We have not grantedoptions for any periods presented. During the year ended December 31, 2003, all remaining outstandingUnit options were exercised.  For optionspreviously outstanding, we followed the intrinsic value method for recognizingstock-based compensation expense.  Theexercise price of all options awarded under the 1994 LTIP equaled the marketprice of our Units on the date of grant. Accordingly, we recognized no compensation expense at the date ofgrant.  Had compensation expense beendetermined consistent with SFAS No. 123, *Accountingfor Stock-Based Compensation*, no compensation expense would havebeen recognized for the years ended December 31, 2005, 2004 and 2003.

 

## **1999 and 2002 PhantomUnit Plans**

## ** **

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

 

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the 2002 PURP provide keyemployees with incentive awards whereby a participant is granted phantomunits.  These phantom units areautomatically redeemed for cash based on the vested portion of the fair marketvalue of the phantom units at stated redemption dates.  The fair market value of each phantom unit isequal to the closing price of a Unit as reported on the New York Stock Exchangeon the redemption date.

 

Under the agreement forthe phantom units, each participant will vest 10% of the number of phantomunits initially granted under his or her award at the end of each of the firstfour years and will vest the final 60% at the end of the fifth year.  Each participant is required to redeem theirphantom units as they vest.   They arealso entitled to quarterly cash distributions equal to the product of thenumber of phantom units outstanding for the participant and the amount of thecash distribution that we paid per Unit to unitholders.  We accrued compensation expense annuallybased upon the terms of the 1999 PURP and 2002 PURP discussed above.  At December 31, 2004, we had an accruedliability balance of $1.6 million for compensation related to the 1999 PURP and2002 PURP.  Due to a change of ownershipas a result of the sale of our General Partner on February 24, 2005 (seeNote 1), all outstanding units under both the 1999 PURP and the 2002 PURP fullyvested and were redeemed by participants. As such, there were no outstanding units at December 31, 2005 undereither the 1999 PURP or the 2002 PURP.

 

## **2000 Long Term IncentivePlan**

## ** **

Effective January 1,2000, the General Partner established the Texas Eastern Products PipelineCompany, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide keyemployees incentives to achieve improvements in our financial performance.  Generally, upon the close of a three-yearperformance period, if the participant is then still an employee of the GeneralPartner, the participant will receive a cash payment in an amount equal to (1) theapplicable performance percentage specified in the award multiplied by (2) thenumber of phantom units granted under the award multiplied by (3) theaverage of the closing prices of a Unit over the ten consecutive trading daysimmediately preceding 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 ValueAdded during the three-year period immediately preceding the performanceperiod.  If a participant incurs aseparation from service during the performance period due to death, disabilityor retirement (as such terms are defined in the 2000 LTIP), the participantwill be entitled to receive a cash payment in an amount equal to the amountcomputed as described above multiplied by a fraction, the numerator of which isthe number of days that have elapsed during the performance period prior to theparticipant’s separation from service and the denominator of which is thenumber of days in the performance period. Due to a change of ownership as a result of the sale of our GeneralPartner on February 24, 2005, all outstanding units under the 2000 LTIPfor plan years 2003 and 2004 were fully vested and redeemed by participants.  As such, there were no outstanding units at December 31,2005, for awards granted for the plan years ended December 31, 2004 and2003.  At December 31, 2005, phantomunits outstanding for awards granted for the plan year ended December 31,2005, were 23,400.

 

Economic Value Addedmeans our average annual EBITDA for the performance period minus the product ofour average asset base and our cost of capital for the performance period.  For purposes of the 2000 LTIP for plan years2000 through 2002, EBITDA means our earnings before net interest expense,depreciation and amortization and our proportional interest in EBITDA of ourjoint ventures as presented in our consolidated financial statements preparedin accordance with generally accepted accounting principles, except that at hisdiscretion the Chief Executive Officer (“CEO”) of the Company may exclude gainsor losses from extraordinary, unusual or non-recurring items.  For the years ended December 31, 2005,2004 and 2003, EBITDA means, in addition to the above definition of EBITDA,earnings before other income – net. Average asset base means the quarterly average, during the performanceperiod, of our gross value of property, plant and equipment, *plus* products and crude oil operating oil supply and thegross value of intangibles and equity investments.  Our cost of capital is approved by our CEO atthe date of award grant.

 

In addition to thepayment described above, during the performance period, the General Partnerwill pay to the participant the amount of cash distributions that we would havepaid to our unitholders had the participant been

 

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the owner of the number ofUnits equal to the number of phantom units granted to the participant under thisaward.  We accrue compensation expenseannually based upon the terms of the 2000 LTIP discussed above.  At December 31, 2005 and 2004, we had anaccrued liability balance of $0.7 million and $2.4 million, respectively, forcompensation related to the 2000 LTIP.

 

## **2005 Phantom Unit Plan**

## ** **

Effective January 1,2005, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2005Phantom Unit Plan (“2005 PURP”) 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 grantee’s vestedpercentage multiplied by (2) the number of phantom units granted under theaward multiplied by (3) the average of the closing prices of a Unit overthe ten consecutive trading days immediately preceding the last day of theperformance period.  Generally, aparticipant’s vested percentage is based upon the improvement of our EBITDA (asdefined below) during a three-year performance period over the target EBITDA asdefined at the beginning of each year during the three-year performanceperiod.  EBITDA means our earnings beforeminority interest, net interest expense, other income – net, income taxes,depreciation and amortization and our proportional interest in EBITDA of ourjoint ventures as presented in our consolidated financial statements preparedin accordance with generally accepted accounting principles, except that at hisdiscretion, our CEO may exclude gains or losses from extraordinary, unusual ornon-recurring items.  At December 31,2005, phantom units outstanding for awards granted for the plan year ended December 31,2005, were 53,600.

 

In addition to thepayment described above, during the performance period, the General Partnerwill pay to the participant the amount of cash distributions that we would havepaid to our unitholders had the participant been the owner of the number ofUnits equal to the number of phantom units granted to the participant underthis award.  We accrue compensationexpense annually based upon the terms of the 2005 PURP discussed above.  At December 31, 2005, we had an accruedliability balance of $0.7 million for compensation related to the 2005 PURP.

 

**NOTE 14.              OPERATING LEASES**

** **

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

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

 

**NOTE 15.      EMPLOYEEBENEFITS**

** **

## **Retirement Plans**

## ** **

The TEPPCO RetirementCash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administeredpension plan.  In addition, the TEPPCOSupplemental Benefit Plan (“TEPPCO SBP”) was a non-contributory, nonqualified,defined benefit retirement plan, in which certain executive officersparticipated.  The

 

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TEPPCO SBP was established torestore benefit reductions caused by the maximum benefit limitations that applyto qualified plans.  The benefit formulafor all eligible employees was a cash balance formula.  Under a cash balance formula, a planparticipant accumulated a retirement benefit based upon pay credits and currentinterest credits.  The pay credits werebased on a participant’s salary, age and service.  We used a December 31 measurement datefor these plans.

 

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

 

In June 2005, werecorded a curtailment charge of $0.1 million in accordance with SFAS No. 88,*Employers’ Accounting for Settlements andCurtailments of Defined Benefit Pension Plans and for Termination Benefits*,as a result of the TEPPCO RCBP and TEPPCO SBP amendments.  As of May 31, 2005, the followingassumptions were changed for purposes of determining the net periodic benefitcosts for the remainder of 2005: the discount rate, the long-term rate ofreturn on plan assets, and the assumed mortality table.  The discount rate was decreased from 5.75% to5.00% to reflect rates of returns on bonds currently available to settle theliability.   The expected long-term rateof return on plan assets was changed from 8% to 2% due to the movement of planfunds from equity investments into short-term money market funds.  The mortality table was changed to reflectoverall improvements in mortality experienced by the general population.  The curtailment charge arose due to theaccelerated recognition of the unrecognized prior service costs.  We recorded additional settlement charges ofapproximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCOSBP.  We expect to record additionalsettlement charges of approximately $4.0 million in 2006 relating to the TEPPCORCBP for any existing unrecognized losses upon the plan termination and finaldistribution of the assets to the plan participants.

 

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

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

 

## **Other PostretirementBenefits**

## ** **

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

 

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

 

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

 

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

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

 

Effective June 1,2005, the payroll functions performed by DEFS for our General Partner weretransferred from DEFS to EPCO.  For thoseemployees who were receiving certain other postretirement benefits at the timeof the acquisition of our General Partner by DFI, DEFS will continue to providethese benefits to those employees. Effective June 1, 2005, EPCO began providing certain otherpostretirement benefits to those employees who became eligible for the benefitsafter June 1, 2005, and will charge those benefit related costs tous.  As a result of these changes, werecorded a $1.2 million reduction in our other postretirement obligation in June 2005.

 

We employed a buildingblock approach in determining the long-term rate of return for planassets.  Historical markets were studiedand long-term historical relationships between equities and fixed-income werepreserved consistent with a widely accepted capital market principle thatassets with higher volatility generate a greater return over the long run.  Current market factors such as inflation andinterest rates were evaluated before long-term capital market assumptions weredetermined.  The long-term portfolioreturn was established via a building block approach with proper considerationof diversification and rebalancing.  Peerdata and historical returns were reviewed to check for reasonability andappropriateness.

 

The weighted averageassumptions used to determine benefit obligations for the retirement plans andother postretirement benefit plans at December 31, 2005 and 2004, were asfollows:

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

 

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

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

 

----

(1)          Expense was remeasured on May 31, 2005, as a result of TEPPCO RCBPand TEPPCO SBP amendments.  The discountrate was decreased from 5.75% to 5% effective June 1, 2005, to reflectrates of returns on bonds currently available to settle the liability.

 

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

 

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

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

 

F-38

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

 
| ** ** | ** ** | **Pension  Benefits** | ** ** | **Other  Postretirement  Benefits** | ** ** |
|------------|------------|-----------------------|------------|-------------------------------------|------------|
|       |       |                  |       |                                |       |
| 2006       |       | $                     | 22,360     |                                | $          | — |   |
|            |            |                       |            |                                     |            |  |  |

## ** **

## **Plan Assets**

 

We employed a total return investmentapproach whereby a mix of equities and fixed income investments were used tomaximize the long-term return of plan assets for a prudent level of risk.  Risk tolerance was established throughcareful consideration of plan liabilities, plan funded status and corporatefinancial condition.  The investmentportfolio contained a diversified blend of equity and fixed-incomeinvestments.  Furthermore, equityinvestments were diversified across U.S. and non-U.S. stocks, both growth andvalue equity style, and small, mid and large capitalizations.  Investment risk and return parameters werereviewed and evaluated periodically to ensure compliance with stated investmentobjectives and guidelines.  Thiscomprehensive review incorporated investment portfolio performance, annualliability measurements and periodic asset/liability studies.

 

The following table sets forth the weightedaverage asset allocations for the retirement plans and other postretirementbenefit plans as of December 31, 2005 and 2004, by asset category (inthousands):

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

 

We do not expect to makefurther contributions to our retirement plans and other postretirement benefitplans in 2006.

 

## **Other Plans**

## ** **

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

 

**NOTE 16.      COMMITMENTSAND CONTINGENCIES**

** **

**Litigation**

** **

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

 

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their complaints, theplaintiffs allege strict liability for both personal injury and property damagetogether with gross negligence, continuing nuisance, trespass, criminalmischief and loss of consortium. The plaintiffs are seeking compensatory,punitive and treble damages.  On January 27,2005, we entered into Release and Settlement Agreements with the McCleeryplaintiffs and the Richards plaintiffs dismissing all of these plaintiffs’claims on terms that did not have a material adverse effect on our financialposition, results of operations or cash flows. Although we did not settle with all plaintiffs and we therefore remainnamed 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 these remaining claims will have a materialadverse effect on our financial position, results of operations or cash flows.

 

On December 21,2001, TE Products was named as a defendant in a lawsuit in the 10th 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.

 

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.  Basedupon current information, 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 beenhandling this matter for Centennial under its operating agreement withCentennial.  TE Products has a 50%ownership interest in Centennial.  On November 30,2004, the court approved a class settlement. The time period for parties to appeal this settlement expired in March 2005,and the class settlement became final. The terms of the settlement did not have a material adverse effect onour financial position, results of operations or cash flows.

 

In May 2003, theGeneral Partner was named as a defendant in a lawsuit styled *John R. James, et al. v. J Graves Insulation Company, et al.*as filed in the first Judicial District Court, Caddo Parish, Louisiana.  There are numerous plaintiffs identified inthe action that are alleged to have suffered damages as a 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 is planned, and the General Partner intends todefend itself 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.

 

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

 

In 1991, we were named asa defendant in a matter styled *Jimmy R. Green, et al. v.Cities Service Refinery, et al.*as filed in the 26thJudicial District Court of Bossier Parish, Louisiana.  The plaintiffs in this matter reside orformerly resided on land that was once the site of a refinery owned by one ofour co-defendants.  The former refineryis located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arisingfrom alleged contamination of the refinery property.  The plaintiffs have recently pursuedcertification as a class and have significantly increased their demand toapproximately $175.0 million.  Thisrevised demand includes amounts for environmental restoration not previouslyclaimed by the plaintiffs.  We have neverowned any interest in the refinery property made the basis of this action, andwe do not believe that we contributed to any alleged contamination of thisproperty.  While we cannot predict theultimate outcome, we do not believe that the outcome of this lawsuit will havea material adverse effect on our financial position, results of operations orcash 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 insurance. We believe that theoutcome of these lawsuits and other proceedings will not individually or in theaggregate have a future material adverse effect on our consolidated financialposition, results of operations or cash flows.

 

**RegulatoryMatters**

 

Our operations aresubject to federal, state and local laws and regulations governing thedischarge of materials into the environment and various safety matters. Failureto comply with these laws and regulations may result in the assessment ofadministrative, civil and criminal penalties, imposition of injunctionsdelaying or prohibiting certain activities and the need to performinvestigatory and remedial activities. We believe our operations have been and are in material compliance withapplicable environmental and safety laws and regulations, and that compliancewith existing environmental laws and regulations are not expected to have amaterial adverse effect on our competitive position, financial positions,results of operations or cash flows. However, risks of significant costs and liabilities are inherent inpipeline operations, and we cannot assure that significant costs andliabilities will not be incurred. Moreover, it is possible that otherdevelopments, such as increasingly strict environmental and safety 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.  At December 31,2005 and 2004, we have an accrued liability of $2.4 million and $5.0 million,respectively, related to sites requiring environmental remediation activities.

 

On March 26, 2004, adecision in *ARCO Products Co., et al. v. SFPP*,Docket OR96-2-000, was issued by the FERC, which made several significantdeterminations with respect to finding “changed circumstances” under the EnergyPolicy Act of 1992 (“EP Act”).  Thedecision largely clarifies, but does not fully quantify, the standard requiredfor a complainant to demonstrate that an oil pipeline’s rates are no longersubject to the rate protection of the EP Act by demonstrating that asubstantial change in circumstances has occurred since 1992 with respect to thebasis of the rates being challenged.  Inthe decision, the FERC found that a limited number of rate elements willsignificantly affect the economic basis for a pipeline company’s rates.  The elements identified in the decision are

 

 

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volume changes, allowedtotal return and total cost-of-service (including major cost elements such asrate base, tax rates and tax allowances, among others).  The FERC did reject, however, the use ofchanges in tax rates and income tax allowances as stand-alone factors.  Judicial review of that decision, which hasbeen sought by a number of parties to the case, is currently pending before theU.S. Court of Appeals for the District of Columbia Circuit.  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 District of Columbia Circuit issued an opinion in *BP WestCoast Products 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 income attributable to partnership interests ownedby corporate partners.  Under the FERC’sinitial ruling, SFPP, L.P. was permitted an income tax allowance on itscost-of-service filing for the percentage of its net operating (pre-tax) incomeattributable to partnership units held by corporations, and was denied anincome tax allowance equal to the percentage attributable to partnership unitsheld by non-corporate partners.  Thecourt remanded the case back to the FERC for further review.  As a result of the court’s remand, on May 4,2005, the FERC issued its Policy Statement on Income Tax Allowances, whichpermits regulated partnerships, limited liability companies and otherpass-through entities an income tax allowance on their income attributable toany owner that has an actual or potential income tax liability on that income,regardless whether the owner is an individual or corporation.  If there is more than one level ofpass-through entities, the regulated company income must be traced to where theultimate tax liability lies.  The PolicyStatement is to be applied in individual cases, and the regulated entity bearsthe burden of proof to establish the tax status of its owners.  On December 16, 2005, the FERC issuedthe first of those decisions, in an order involving SFPP (the “SFPP Order”).  The SFPP Order confirmed that an MLP isentitled to a tax allowance with respect to partnership income for which thereis an “actual or potential income tax liability” and determined that aunitholder that is required to file a Form 1040 or Form 1120 taxreturn that includes partnership income or loss is presumed to have an actualor potential income tax liability sufficient to support a tax allowance on thatpartnership income.  The FERC alsoestablished certain other presumptions, including that corporate unitholdersare presumed to be taxed at the maximum corporate tax rate of 35% whileindividual unitholders (and certain other types of unitholders taxed likeindividuals) are presumed to be taxed at a 28% tax rate.  The SFPP Order remains subject to further administrativeproceedings (including compliance filings by SFPP and possible rehearingrequests), as well as potential judicial review.  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 touse cost-of-service to support our rates, or (ii) be required to use suchmethodology to defend our indexed rates.

 

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 adjacentterminals were directed by the Remediation Services Division of the LDEQ topursue remediation of this contamination. Effective March 2004, we executed an access agreement with anadjacent industrial landowner who is located upgradient of the Arcadiafacility.  This agreement enables thelandowner to proceed with remediation activities at our Arcadia facility forwhich it has accepted shared responsibility. At December 31, 2005, we have an accrued liability of $0.2 millionfor remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposedto the LDEQ will have a future material adverse effect on our financialposition, 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.  On August 30,2005, a final settlement was reached with the State of Illinois.  The settlement included the payment ofa civil penalty of $0.1 million and the requirement that we make

 

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certainmodifications to the equipment of the facility, none of which are expected to havea material adverse effect on our financial position, results of operations orcash 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 effect on ourfinancial 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 Environmental ProtectionAgency, is seeking a civil penalty against us for alleged violations of theClean Water Act (“CWA”) arising out of this release.  We are in discussions with the DOJ regardingthis matter and have responded to its request for additional information.  The maximum statutory penalty proposed by theDOJ for this alleged violation of the CWA is $2.1 million.  We do not expect any civil penalty to have amaterial adverse effect on our financial position, results of operations orcash flows.

 

On September 18, 2005, a propane release and fire occurredat our Todhunter facility, near Middletown, Ohio.  The incident resulted in the death of one ofour employees. There were no other injuries. On or about February 22, 2006, wereceived verbal notification from a representative of the Occupational Safetyand Health Administration that they intend to serve us with a citation arisingout of this incident.  At this time, wehave not received any citation, and we cannot predict with certainty the amountof any fine or penalty associated with any such citation; however, we do not expectany fine or penalty to have a material adverse effect on our financialposition, results of operations or cash flows. 

 

Rates of interstatepetroleum products and crude oil pipeline companies, like us, are currentlyregulated by the FERC primarily through an index methodology, which allows apipeline to change its rates based on the change from year to year in theProducer Price Index for finished goods (“PPI Index”).  Effective as of February 24, 2003, FERCOrder on Remand modified the PPI Index from PPI – 1% to PPI.  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 a review of whether the FERC’s adoption of the PPI Index was reasonableand supported 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 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.

 

**Other**

 

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

 

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and conversioncosts of its pipeline system.  Prior tothe expiration of the long-term credit agreement, TE Products could berelinquished from responsibility under the guarantee should Centennial meetcertain financial tests.  If Centennialdefaults on its outstanding balance, the estimated maximum potential amount offuture payments for TE Products and Marathon is $75.0 million each at December 31,2005.

 

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

 

One of our subsidiaries,TCO, has entered into master equipment lease agreements with finance companiesfor the use of various equipment.  Wehave guaranteed the full and timely payment and performance of TCO’sobligations under the agreements. Generally, events of default would trigger our performance under theguarantee.  The maximum potential amountof future payments under the guarantee is not estimable, but would include baserental payments for both current and future equipment, stipulated loss paymentsin the event any equipment is stolen, damaged, or destroyed and any futureindemnity payments.  We carry insurancecoverage that may offset any payments required under the guarantees.

 

On February 24,2005, the General Partner was acquired from DEFS by DFI.  The General Partner owns a 2% general partnerinterest in us and is the general partner of the Partnership.  On March 11, 2005, the Bureau ofCompetition of the Federal Trade Commission (“FTC”) delivered written notice toDFI’s legal advisor that it was conducting a non-public investigation todetermine whether DFI’s acquisition of the General Partner may substantiallylessen competition.  The General Partneris cooperating fully with this investigation.

 

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

 

We carry insurancecoverage consistent with the exposures associated with the nature and scope ofour operations.  Our current insurancecoverage includes (1) commercial general liability insurance forliabilities to third parties for bodily injury and property damage resultingfrom our operations; (2) workers’ compensation coverage to requiredstatutory limits;  (3) automobileliability insurance for all owned, non-owned and hired vehicles coveringliabilities to third parties for bodily injury and property damage, and (4) propertyinsurance covering the replacement value of all real and personal propertydamage, including damages arising from earthquake, flood damage and businessinterruption/extra expense.  For selectassets, we also carry pollution liability insurance that provides coverage forhistorical and gradual pollution events. All coverages are subject to certain deductibles, limits or sub-limitsand policy terms and conditions.

 

We also maintain excessliability insurance coverage above the established primary limits forcommercial general liability and automobile liability insurance.  Limits, terms, conditions and deductibles arecommensurate with the nature and scope of our operations.  The cost of our general insurance coverageshas increased over the past year reflecting the changing conditions of theinsurance markets.  These insurancepolicies, except for the pollution liability policies, are through EPCO (seeNote 7).

 

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**NOTE 17.**                                          SEGMENT INFORMATION

** **

We have three reportingsegments:

 

•                  Our DownstreamSegment, which is engaged in the transportation and storage of refinedproducts, LPGs and petrochemicals;

 

•                  Our UpstreamSegment, which is engaged in the gathering, transportation, marketing andstorage of crude oil and distribution of lubrication oils and specialtychemicals; and

 

•                  Our MidstreamSegment, which is engaged in the gathering of natural gas, fractionation ofNGLs and transportation of NGLs.

 

The amounts indicated belowas “Partnership and Other” relate primarily to intersegment eliminations andassets that we hold that have not been allocated to any of our reportingsegments.

 

Our Downstream Segmentrevenues are earned from transportation and storage of refined products andLPGs, intrastate transportation of petrochemicals, sale of product inventoryand other ancillary services. The two largest operating expense items of theDownstream Segment are labor and electric power.  We generally realize higher revenues duringthe first and fourth quarters of each year since our operations are somewhatseasonal. Refined products volumes are generally higher during the second andthird quarters because of greater demand for gasolines during the spring andsummer driving seasons. LPGs volumes are generally higher from November throughMarch due to higher demand 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, refinery grade propylene from Mont Belvieu to Point Comfort,Texas.  Our Downstream Segment alsoincludes our equity investments in Centennial and MB Storage (see Note 6).

 

Our Upstream Segmentrevenues are earned from gathering, transportation, marketing and storage ofcrude oil and distribution of lubrication oils and specialty chemicals,principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region.  Marketing operations consist primarily ofaggregating purchased crude oil along our pipeline systems, or from third partypipeline systems, and arranging the necessary transportation logistics for theultimate sale of the crude oil to local refineries, marketers or other endusers.  Our Upstream Segment alsoincludes our equity investment in Seaway. Seaway consists of large diameter pipelines that transport crude oilfrom Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, acrude oil distribution point for the central United States, and to refineriesin 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 ofCBM and conventional natural gas in the San Juan Basin in New Mexico andColorado, through Val Verde.

 

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Thetables below include financial information by reporting segment for the yearsended December 31, 2005, 2004 and 2003 (in thousands):

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

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

 

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

 

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

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

 

The following tablereconciles the segments total earnings before interest to consolidated netincome for the three years ended December 31, 2005, 2004 and 2003 (inthousands):

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

** **

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**NOTE 18.**                                          COMPREHENSIVE INCOME

** **

SFAS No. 130, *Reporting Comprehensive Income* requires certain items suchas foreign currency translation adjustments, minimum pension liabilityadjustments and unrealized gains and losses on certain investments to be reportedin a financial statement.  As of and forthe year ended December 31, 2005, the components of comprehensive income weredue to crude oil hedges.  The crude oilhedges mature in December 2006. While the crude oil hedges are in effect, changes in the fair values ofthe crude oil hedges, to the extent the hedges are effective, are recognized inother comprehensive income until they are recognized in net income in futureperiods.  As of and for the year ended December 31,2004, the components of comprehensive income were due to the interest rate swaprelated to our variable rate revolving credit facility, which was designated asa cash flow hedge.  The interest rateswap matured in April 2004.  Whilethe interest rate swap was in effect, changes in the fair value of the cashflow hedge, to the extent the hedge was effective, were recognized in othercomprehensive income until the hedge interest costs were recognized in netincome.

 

The accumulated balanceof other comprehensive income related to our cash flow hedges is as follows (inthousands):

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

 

**NOTE 19.**                                          SUPPLEMENTAL CONDENSEDCONSOLIDATING FINANCIAL INFORMATION

** **

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

 

The followingsupplemental condensed consolidating financial information reflects ourseparate accounts, the combined accounts of the Guarantor Subsidiaries, thecombined accounts of our other non-guarantor subsidiaries, the combinedconsolidating adjustments and eliminations and our consolidated accounts forthe dates and periods indicated.  For purposesof the following consolidating information, our investments in our subsidiariesand the Guarantor Subsidiaries’ investments in their subsidiaries are accountedfor under the equity method of accounting.                        

 

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

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

 

F-49

----

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

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

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

 

F-50

----

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

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

 

F-51

----

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

** **

**NOTE 20.**                                          RESTATEMENT OF CONSOLIDATEDFINANCIAL STATEMENTS

** **

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

 

Whilewe believe the impacts of these non-cash adjustments are not material to anypreviously issued financial statements, we determined that the cumulativeadjustment for these non-cash items was too material to record in the fourthquarter of 2005, and therefore it was most appropriate to restate prior periods’results.  These non-cash adjustments hadno effect on our operating income, compensation expense, debt balances orability to meet all requirements related to our debt facilities.  The restatement had no impact on total cashflows from operating activities, investing activities or financingactivities.  All amounts in theaccompanying consolidated financial statements have been adjusted for this restatement.

 

F-52

----

 

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

 

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

 

**Balance Sheet Amounts;**

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

 

**Income Statement Amounts:**

 
| ** **                                                                                     | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                     | ** ** | **2004**                          | ** ** | **2003** | ** ** |
|                                                                                           |       |                              |       |   |   |
| Equity earnings as previously reported                                                         |       | $                                 | 25,981     |   | $ | 16,863 |   |
| Adjustment for amortization of excess investments                                              |       | (3,833                            | )          | (3,989 | ) |
| Equity earnings as restated                                                                    |       | $                                 | 22,148     |   | $ | 12,874 |   |
|                                                                                           |       |                              |       |   |   |
| Net income as previously reported                                                              |       | $                                 | 142,381    |   | $ | 125,769 |   |
| Adjustment for amortization of excess investments                                              |       | (3,833                            | )          | (3,989 | ) |
| Net income as restated                                                                         |       | $                                 | 138,548    |   | $ | 121,780 |   |
|                                                                                           |       |                              |       |   |   |
| Net Income Allocation as previously reported:                                                  |       |                              |       |   |   |
| Limited Partner Unitholders                                                                    |       | $                                 | 101,307    |   | $ | 89,191 |   |
| Class B Unitholder                                                                        |       | —                            |       | 1,806 |   |
| General Partner                                                                                |       | 41,074                            |       | 34,772 |   |
| Total net income allocated                                                                     |       | $                                 | 142,381    |   | $ | 125,769 |   |
|                                                                                           |       |                              |       |   |   |
| Basic and diluted net income per Limited Partner and  Class B Unit as previously reported |       | $                                 | 1.61       |   | $ | 1.52 |   |
|                                                                                           |       |                              |       |   |   |
| Net Income Allocation as restated:                                                             |       |                              |       |   |   |
| Limited Partner Unitholders                                                                    |       | $                                 | 98,580     |   | $ | 86,357 |   |
| Class B Unitholder                                                                        |       | —                            |       | 1,754 |   |
| General Partner                                                                                |       | 39,968                            |       | 33,669 |   |
| Total net income allocated as restated                                                         |       | $                                 | 138,548    |   | $ | 121,780 |   |
|                                                                                           |       |                              |       |   |   |
| Basic and diluted net income per Limited Partner and  Class B Unit as restated            |       | $                                 | 1.56       |   | $ | 1.47 |   |

 

F-53

----

 

**Cash Flow Amounts;**

 
| ** **                                           | ** ** | **Year Ended December 31,  2004** | ** ** |
|------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                           | ** ** | **As Previously  Reported**            | ** ** | **Adjustment** | ** ** | **As Restated** | ** ** |
|                                                 |       |                                   |       |   |   |   |   |
| Cash flows from operating activities:                |       |                                   |       |   |   |   |   |
| Net income                                           |       | $                                      | 142,381    |   | $ | (3,833 | ) | $ | 138,548 |   |
| Earnings in equity investments, net of distributions |       | 21,232                                 |       | 3,833 |   | 25,065 |   |
|                                                      |            |                                        |            |  |  |  |  |  |  |  |

 
| ** **                                           | ** ** | **Year Ended December 31,  2003** | ** ** |
|------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                           | ** ** | **As Previously  Reported**            | ** ** | **Adjustment** | ** ** | **As Restated** | ** ** |
|                                                 |       |                                   |       |   |   |   |   |
| Cash flows from operating activities:                |       |                                   |       |   |   |   |   |
| Net income                                           |       | $                                      | 125,769    |   | $ | (3,989 | ) | $ | 121,780 |   |
| Earnings in equity investments, net of distributions |       | 11,140                                 |       | 3,989 |   | 15,129 |   |
|                                                 |       |                                   |       |   |   |   |   |
|                                                      |            |                                        |            |  |  |  |  |  |  |  |

 

**Partners’ Capital Amounts:**

 
| ** **                                                                | ** ** | **Outstanding  Limited  Partner  Units** | ** ** | **General  Partner’s  Interest** | ** ** | **Limited  Partners’  Interests** | ** ** | **Accumulated  Other  Comprehensive  Loss** | ** ** | **Total** | ** ** |
|---------------------------------------------------------------------------|------------|------------------------------------------|------------|---------------------------------------|------------|----------------------------------------|------------|---------------------------------------------|------------|-----------|------------|
| **2002:**                                                                 |       |                                     |       |                                  |       |                                   |       |                                        |       |      |       |
| Partners’ capital at December 31, 2002 as  previously reported  |       | 53,809,597                               |       | $                                     | 12,770     |                                   | $          | 899,127                                     |       | $         | (20,055    | ) | $ | 891,842 |   |
| Restatement adjustment                                                    |       | —                                   |       | (666                                  | )          | (1,727                                 | )          | —                                      |       | (2,393    | )          |
| Partners’ capital at December 31, 2002 as  restated (unaudited) |       | 53,809,597                               |       | $                                     | 12,104     |                                   | $          | 897,400                                     |       | $         | (20,055    | ) | $ | 889,449 |   |
| **2003:**                                                                 |       |                                     |       |                                  |       |                                   |       |                                        |       |      |       |
| Partners’ capital at December 31, 2003 as  previously reported  |       | 62,998,554                               |       | $                                     | (7,181     | )                                      | $          | 1,119,404                                   |       | $         | (2,902     | ) | $ | 1,109,321 |   |
| Restatement adjustment                                                    |       | —                                   |       | (1,769                                | )          | (4,743                                 | )          | —                                      |       | (6,512    | )          |
| Partners’ capital at December 31, 2003 as  restated             |       | 62,998,554                               |       | $                                     | (8,950     | )                                      | $          | 1,114,661                                   |       | $         | (2,902     | ) | $ | 1,102,809 |   |
| **2004:**                                                                 |       |                                     |       |                                  |       |                                   |       |                                        |       |      |       |
| Partners’ capital at December 31, 2004 as  previously reported  |       | 62,998,554                               |       | $                                     | (33,006    | )                                      | $          | 1,054,454                                   |       | $         | —     |   | $ | 1,021,448 |   |
| Restatement adjustment                                                    |       | —                                   |       | (2,875                                | )          | (7,470                                 | )          | —                                      |       | (10,345   | )          |
| Partners’ capital at December 31, 2004 as  restated             |       | 69,963,554                               |       | $                                     | (35,881    | )                                      | $          | 1,046,984                                   |       | $         | —     |   | $ | 1,011,103 |   |

 

 

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**NOTE 21.**                                          QUARTERLY FINANCIALINFORMATION (UNAUDITED)

** **
|  

** **                                                               | ** ** | **First  Quarter**                          | ** ** | **Second  Quarter** | ** ** | **Third  Quarter** | ** ** | **Fourth  Quarter** | ** ** |
|----------------------------------------------------------------------------------|------------|---------------------------------------------|------------|---------------------|------------|--------------------|------------|---------------------|------------|
|                                                                             |       | **(as restated)**                           | ** ** | **(as restated)**   | ** ** | **(as restated)**  | ** ** | **(as restated)**   |       |
|                                                                             |       | **(in thousands, except per Unit amounts)** |       |
| **2005**                                                                         |       |                                        |       |                |       |               |       |                |       |
| Operating revenues                                                               |       | $                                           | 1,526,605  |                | $          | 2,090,380          |       | $                   | 2,503,796  |   | $ | 2,497,707 |   |
| Operating income                                                                 |       | 62,356                                      |       | 54,663              |       | 44,070             |       | 62,094              |       |
|                                                                             |       |                                        |       |                |       |               |       |                |       |
| Net income as previously reported                                                |       | $                                           | 48,581     |                | $          | 42,233             |       | $                   | 30,923     |   | $ | 44,625 |   |
| Restatement adjustment                                                           |       | (1,152                                      | )          | (1,311              | )          | (1,348             | )          | —              |       |
| Net income as restated (1)                                                       |       | $                                           | 47,429     |                | $          | 40,922             |       | $                   | 29,575     |   | $ | 44,625 |   |
|                                                                             |       |                                        |       |                |       |               |       |                |       |
| Basic and diluted income per Limited Partner Unit as  previously reported (2)(3) |       | $                                           | 0.55       |                | $          | 0.45               |       | $                   | 0.31       |   | $ | 0.45 |   |
| Restatement adjustment                                                           |       | (0.01                                       | )          | (0.02               | )          | (0.01              | )          | —              |       |
| Basic and diluted income per Limited Partner Unit as  restated (1)(2)(3)         |       | $                                           | 0.54       |                | $          | 0.43               |       | $                   | 0.30       |   | $ | 0.45 |   |
|                                                                             |       |                                        |       |                |       |               |       |                |       |
| **2004**                                                                         |       |                                        |       |                |       |               |       |                |       |
| Operating revenues                                                               |       | $                                           | 1,318,061  |                | $          | 1,354,564          |       | $                   | 1,490,010  |   | $ | 1,795,557 |   |
| Operating income                                                                 |       | 53,901                                      |       | 42,401              |       | 37,081             |       | 53,750              |       |
|                                                                             |       |                                        |       |                |       |               |       |                |       |
| Net income as previously reported                                                |       | $                                           | 40,433     |                | $          | 37,759             |       | $                   | 25,855     |   | $ | 38,334 |   |
| Restatement adjustment                                                           |       | (713                                        | )          | (1,129              | )          | (1,085             | )          | (906                | )          |
| Net income as restated (1)                                                       |       | $                                           | 39,720     |                | $          | 36,630             |       | $                   | 24,770     |   | $ | 37,428 |   |
|                                                                             |       |                                        |       |                |       |               |       |                |       |
| Basic and diluted income per Limited Partner Unit as  previously reported        |       | $                                           | 0.46       |                | $          | 0.43               |       | $                   | 0.29       |   | $ | 0.43 |   |
| Restatement adjustment                                                           |       | (0.01                                       | )          | (0.02               | )          | (0.01              | )          | (0.01               | )          |
| Basic and diluted income per Limited Partner Unit as  restated (1)               |       | $                                           | 0.45       |                | $          | 0.41               |       | $                   | 0.28       |   | $ | 0.42 |   |

 

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(1)          The quarterly financial informationfor 2004 and the first three quarters of 2005 reflect the impact of therestatement.

 

(2)          The sum of the four quarters does notequal the total year due to rounding.

 

(3)          Per Unit calculation includes6,965,000 Units issued in May and June 2005.

 

**NOTE 22.**                                          SUBSEQUENT EVENTS

** **

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

 

On January 26, 2006, weannounced the execution of a letter of intent to sell our ownership interest inthe Pioneer silica gel natural gas processing plant located in Opal, Wyoming,to an affiliate of Enterprise Products Partners L.P., including all of Jonah’srights to process natural gas originating from the Jonah and Pinedalefields.  The proposed sale of the Pioneerplant is subject to the execution of definitive agreements and to regulatoryapprovals.  The proposed sale is expectedto be completed by the middle of 2006. The Pioneer plant is not an integral part of our Midstream Segmentoperations, and natural gas processing is not a core business.  The anticipated sales proceeds would be usedto fund organic growth projects, retire debt, or for other general partnershippurposes.  The carrying value of thePioneer plant at December 31, 2005, was $19.8 million.

 

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On February 13, 2006, weand an affiliate of Enterprise Products Partners L.P. (“Enterprise”) enteredinto a letter agreement related to an additional expansion (the “JonahExpansion”) of the Jonah system (the “Letter Agreement”).  The Jonah Expansion will consist of theinstallation of approximately 90,000 horsepower of gas turbine compression at anew compression station, related new piping and certain related facilities,which is expected to increase capacity of the Jonah system from 1.5 billioncubic feet per day to 2.0 billion cubic feet per day.  We expect to enter into a joint venture (“JointVenture”) agreement with Enterprise relating to the construction and financingof the Jonah Expansion.  Enterprise willbe responsible for all activities relating to the construction of the JonahExpansion and will advance all amounts necessary to plan, engineer, constructor complete the Jonah Expansion (anticipated to be approximately $200.0million).  Such advance will constitute asubscription for an equity interest in the proposed Joint Venture (the“Subscription”).  We expect the JonahExpansion to be put into service in late 2006. We have the option to return to Enterprise up to 100% of the amount ofthe Subscription.  If we return a portionof the Subscription to Enterprise, our relative interests in the proposed JointVenture will be adjusted accordingly. The proposed Joint Venture will terminate without liability to eitherparty if we return 100% of the Subscription.

 

 

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