UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K
(Mark One)

[X]  ANNUAL REPORT  PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES  EXCHANGE
     ACT OF 1934

                   For the fiscal year ended December 31, 2004

                                       OR

[ ]  TRANSITION  REPORT  PURSUANT  TO SECTION  13 OR 15(d) OF THE  SECURITIES
     EXCHANGE ACT OF 1934

                        Commission file number 333-44634

                   KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.

             (Exact name of Registrant as specified in its Charter)

            Delaware                                             75-2287683
(State or other jurisdiction of                                (IRS Employer
  incorporation or organization)                             Identification No.)

2435 North Central Expressway
      Richardson, Texas                                         75080
---------------------------------------              --------------------------
(Address of principal executive offices)                     (zip code)

       Registrant's telephone number, including area code: (972) 699-4062


                              Title of each class
                      7.75% Senior Unsecured Notes due 2012
                     5.875% Senior Unsecured Notes due 2013

        Securities registered pursuant to Section 12(b) of the Act: None

        Securities registered pursuant to Section 12(g) of the Act: None


     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days. Yes    X      No
                                              -------      ------

     Indicate by check mark if disclosure of delinquent  filers pursuant to Item
405 of  Regulation  S-K  (Subsection  229.405 of this  chapter) is not contained
herein,  and will not be contained,  to the best of registrant's  knowledge,  in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K.    N/A
                                                        -----

     Indicate by check mark whether the registrant is an  accelerated  filer (as
defined in Exchange Act Rule 12b-2).

                                Yes         No    X
                                   -------     -------

<PAGE>
                                     PART I


Item 1. Business


GENERAL

     Kaneb Pipe Line Operating Partnership, L.P., a Delaware limited partnership
(the "Partnership"),  is engaged in the refined petroleum products and anhydrous
ammonia  pipeline  business  and  the  terminaling  of  petroleum  products  and
specialty liquids. Kaneb Pipe Line Partners,  L.P. ("KPP") (NYSE: KPP), a master
limited  partnership,  holds  a  99%  interest  as  a  limited  partner  in  the
Partnership.  Kaneb Pipe Line Company LLC, a Delaware limited  liability company
("KPL"),  a wholly-owned  subsidiary of Kaneb  Services LLC, a Delaware  limited
liability company ("KSL") (NYSE: KSL), holds a 1% interest as general partner of
the  Partnership  and a 1% interest as general  partner of KPP. The  terminaling
business of the  Partnership is conducted  through Support  Terminals  Operating
Partnership,  L.P.  ("STOP"),  and its  affiliated  partnerships  and  corporate
entities,  which operate  under the trade names "ST  Services" and  "StanTrans,"
among  others;  and Statia  Terminals  Holdings  Company LLC and its  subsidiary
entities ("Statia").

     On  October  31,  2004,  Valero  L.P.  and KPP  entered  into a  definitive
agreement to merge (the "KPP  Merger")  Valero L.P. and KPP.  Under the terms of
the agreement, each holder of units of limited partnership interests in KPP will
receive a number of Valero L.P.  common  units  based on an exchange  ratio that
fluctuates  within a fixed range to provide $61.50 in value of Valero L.P. units
for each unit of KPP. The actual  exchange  ratio will be determined at the time
of the closing of the proposed  merger and is subject to a fixed value collar of
plus or minus  five  percent  of Valero  L.P.'s  per unit  price of $57.25 as of
October 7, 2004. Should Valero L.P.'s per unit price fall below $54.39 per unit,
the exchange  ratio will remain fixed at 1.1307 Valero L.P.  units for each unit
of KPP. Likewise,  should Valero L.P.'s per unit price exceed $60.11 per unit of
KPP, the exchange  ratio will remain fixed at 1.0231 Valero L.P.  units for each
unit of KPP.

     In a separate definitive agreement, on October 31, 2004, Valero L.P. agreed
to acquire by merger (the "KSL Merger") all of the outstanding  common shares of
KSL for cash.  Under the terms of that  agreement,  Valero  L.P.  is offering to
purchase all of the outstanding shares of KSL at $43.31 per share.

     The  completion  of the KPP Merger is subject to the  customary  regulatory
approvals  including those under the  Hart-Scott-Rodino  Antitrust  Improvements
Act. The  completion  of the KPP Merger is also subject to completion of the KSL
Merger.  All required  unitholder and shareholder  approvals have been obtained.
Upon completion of the mergers,  the general partner of the combined partnership
will be owned by affiliates of Valero  Energy  Corporation  and KPP and KSL will
become wholly owned subsidiaries of Valero L.P.


PIPELINE BUSINESS

Introduction

     The   Partnership's   pipeline   business   consists   primarily   of   the
transportation  of refined  petroleum  products  as a common  carrier in Kansas,
Nebraska, Iowa, South Dakota, North Dakota, Colorado,  Wyoming and Minnesota. On
December 24, 2002,  the  Partnership  acquired the Northern Great Plains Product
System  from Tesoro  Refining  and  Marketing  Company  for  approximately  $100
million.  This product  pipeline system is now referred to as the  Partnership's
North  Pipeline.  On November  1, 2002,  the  Partnership  acquired a 2,000 mile
anhydrous  ammonia pipeline from Koch Pipeline  Company,  LP and Koch Fertilizer
Storage and Terminal Company for approximately  $139 million.  The Partnership's
three refined  petroleum  products  pipelines and the anhydrous ammonia pipeline
are described below.

East Pipeline

     Construction  of the  East  Pipeline  commenced  in 1953  with a line  from
southern Kansas to Geneva, Nebraska.  During subsequent years, the East Pipeline
was extended northward to its present terminus at Jamestown,  North Dakota, west
to North Platte,  Nebraska and east into the State of Iowa.  The East  Pipeline,
which moves refined products from south to north, now consists of 2,090 miles of
pipeline ranging in size from 6 inches to 16 inches.

     The East  Pipeline  system also  includes 17 product  terminals  in Kansas,
Nebraska,  Iowa,  South Dakota and North Dakota with total  storage  capacity of
approximately  3.5 million barrels and an additional 23 product tanks with total
storage   capacity  of  approximately   1,082,555   barrels  at  its  tank  farm
installations at McPherson and El Dorado, Kansas. The system also has six origin
pump  stations in Kansas and 38 booster  pump  stations  throughout  the system.
Additionally,  the system maintains various office and warehouse facilities, and
an extensive quality control laboratory.

     The East Pipeline transports refined petroleum products, including propane,
received from refineries in southeast Kansas and other  connecting  pipelines to
its terminals along the system and to receiving pipeline  connections in Kansas.
Shippers on the East Pipeline obtain refined petroleum  products from refineries
connected to the East Pipeline or through other pipelines  directly connected to
the pipeline system. Five connecting  pipelines can deliver propane for shipment
through  the East  Pipeline  from gas  processing  plants in Texas,  New Mexico,
Oklahoma and Kansas.

     Much of the refined petroleum  products delivered through the East Pipeline
are  ultimately  used as  fuel  for  railroads  or in  agricultural  operations,
including  fuel  for  farm  equipment,   irrigation  systems,  trucks  used  for
transporting  crops and crop drying  facilities.  Demand for  refined  petroleum
products for  agricultural  use, and the relative mix of products  required,  is
affected  by weather  conditions  in the  markets  served by the East  Pipeline.
Government  agricultural  policies and crop prices also affect the  agricultural
sector.  Although  periods  of  drought  suppress  agricultural  demand for some
refined petroleum products,  particularly those used for fueling farm equipment,
the demand for fuel for irrigation systems often increases during such times.

     The mix of refined petroleum  products  delivered varies  seasonally,  with
gasoline  demand  peaking in early  summer,  diesel fuel demand  peaking in late
summer and propane demand higher in the fall. In addition, weather conditions in
the areas served by the East Pipeline  affect both the demand for and the mix of
the refined petroleum  products  delivered  through the East Pipeline,  although
historically  any impact on total volumes shipped has been  short-term.  Tariffs
charged to shippers for  transportation of products do not vary according to the
type of product delivered.

West Pipeline

     The Partnership acquired the West Pipeline in February 1995, increasing the
Partnership's  pipeline  business in South Dakota and  expanding it into Wyoming
and  Colorado.  The West Pipeline  system  includes  approximately  550 miles of
pipeline in Wyoming, Colorado and South Dakota, four truck-loading terminals and
numerous  pump  stations  situated  along the system.  The system's four product
terminals have a total storage capacity of over 1.7 million barrels.

     The West Pipeline  originates  near Casper,  Wyoming,  where it serves as a
connecting  point  with  Sinclair's  Little  America  Refinery  and the  Seminoe
Pipeline which transports  product from Billings,  Montana area  refineries.  At
Douglas,  Wyoming,  a 6 inch  pipeline  branches off to serve the  Partnership's
Rapid City,  South  Dakota  terminal  approximately  190 miles away.  The 6 inch
pipeline also receives product from Wyoming Refining's  pipeline at a connection
located near the Wyoming/South  Dakota border.  From Douglas,  the Partnership's
pipeline continues southward through a delivery point at the Burlington Northern
junction to terminals at Cheyenne,  Wyoming,  the Denver  metropolitan  area and
Fountain, Colorado.

     The West Pipeline system parallels the  Partnership's  East Pipeline to the
west.  The East  Pipeline's  North Platte line  terminates in western  Nebraska,
approximately 200 miles east of the West Pipeline's Cheyenne,  Wyoming terminal.
The West Pipeline serves Denver and other eastern  Colorado markets and supplies
jet fuel to Ellsworth Air Force Base at Rapid City, South Dakota, as compared to
the East Pipeline's largely  agricultural  service area. The West Pipeline has a
relatively small number of shippers who, with few exceptions,  are also shippers
on the Partnership's East Pipeline system.

North Pipeline

     The North  Pipeline,  acquired  in  December  2002,  runs from west to east
approximately  440 miles from its origin at the Tesoro  Refining  and  Marketing
Company's Mandan,  North Dakota refinery to the Minneapolis,  Minnesota area. It
has four product terminals,  one in North Dakota and three in Minnesota,  with a
total tankage  capacity of 1.3 million  barrels.  The North Pipeline crosses the
Partnership's East Pipeline near Jamestown, North Dakota where the two pipelines
are  connected.  The North  Pipeline is currently  supplied  exclusively  by the
Mandan refinery,  however,  it is capable of delivering or receiving products to
or from the East Pipeline.

Ammonia Pipeline

     In November 2002, the Partnership  acquired the anhydrous  ammonia pipeline
(the "Ammonia Pipeline") from two Koch companies. Anhydrous ammonia is primarily
used as agricultural fertilizer through direct application.  Other uses are as a
component of various types of dry  fertilizer as well as use as a cleaning agent
in power plant  scrubbers.  The 2,000 mile pipeline  originates in the Louisiana
delta area  where it has access to three  marine  terminals  on the  Mississippi
River.  It moves north through  Louisiana and Arkansas into  Missouri,  where at
Hermann,  Missouri,  one branch splits going east into Illinois and Indiana, and
the other branch  continues north into Iowa and then turning west into Nebraska.
The Partnership acquired a storage and loading terminal near Hermann, Missouri a
portion  of which is leased  back to Koch  Nitrogen.  The  Ammonia  Pipeline  is
connected to twenty-two  other third party owned  terminals and also has several
industrial facility delivery locations. Product is supplied to the pipeline from
plants in Louisiana  and  foreign-source  product  delivered  through the marine
terminals.

Other Systems

     The  Partnership  also  owns  three  single-use  pipelines,   located  near
Umatilla, Oregon; Rawlins, Wyoming and Pasco, Washington, each of which supplies
diesel fuel to a railroad fueling facility.  The Oregon and Washington lines are
fully  automated,  however  the  Wyoming  line  utilizes a  coordinated  startup
procedure between the refinery and the railroad. For the year ended December 31,
2004, these three systems combined transported a total of 3.8 million barrels of
diesel fuel, representing an aggregate of $1.55 million in revenues.

Pipelines Products and Activities

     The revenues for the East Pipeline, West Pipeline, North Pipeline,  Ammonia
Pipeline and Other  Pipelines  (collectively,  the  "Pipelines")  are based upon
volumes and distances of product shipped. The following table reflects the total
volume,  barrel miles of refined petroleum  products shipped and total operating
revenues earned by the Pipelines for each of the periods indicated, but does not
include any  information  on the  Ammonia  Pipeline.  During 2004 and 2003,  the
Ammonia Pipeline  shipped  1,122,618 tons and 1,156,549 tons,  respectively,  of
ammonia generating $19.6 million and $21.3 million, respectively, of revenue.
<TABLE>
<CAPTION>

                                                              Year Ended December 31,
                               ------------------------------------------------------------------------------------
                                    2004             2003              2002             2001              2000
                               -------------     -------------    --------------    -------------    --------------
<S>                            <C>               <C>              <C>               <C>              <C>
Volume (1)..................         104,344           102,928            89,780           92,116            89,192
Barrel miles (2)............          22,243            21,327            18,275           18,567            17,843
Revenues (3)................        $100,241           $98,329           $78,240          $74,976           $70,685
</TABLE>
(1)  Volumes are expressed in thousands of barrels of refined petroleum product.

(2)  Barrel  miles are shown in  millions.  A barrel mile is the movement of one
     barrel of refined petroleum product one mile.

(3)  Revenues are expressed in thousands of dollars.

     The  following  table sets forth  volumes of propane and  various  types of
other refined petroleum products transported by the Pipelines during each of the
periods indicated:

<TABLE>
<CAPTION>
                                                              Year Ended December 31,
                                                              (thousands of barrels)
                               ------------------------------------------------------------------------------------
                                    2004             2003              2002             2001              2000
                               -------------     -------------    --------------    -------------    --------------
<S>                            <C>               <C>              <C>               <C>              <C>
Gasoline....................          54,745            53,205            45,106           46,268            44,215
Diesel and fuel oil.........          46,223            46,072            40,450           42,354            41,087
Propane.....................           3,376             3,651             4,224            3,494             3,890
                               -------------     -------------    --------------    -------------    --------------
Total.......................         104,344           102,928            89,780           92,116            89,192
                               =============     =============    ==============    =============    ==============
</TABLE>

     Diesel and fuel oil are used in farm machinery and equipment, over-the-road
transportation, railroad fueling and residential fuel oil. Gasoline is primarily
used in  over-the-road  transportation  and  propane  is used for  crop  drying,
residential  heating  and to  power  irrigation  equipment.  The mix of  refined
petroleum products delivered varies seasonally,  with gasoline demand peaking in
early  summer,  diesel  fuel demand  peaking in late  summer and propane  demand
higher in the fall. In addition,  weather  conditions in the areas served by the
East  Pipeline  affect both the demand for and the mix of the refined  petroleum
products delivered through the East Pipeline,  although historically any overall
impact on the total  volumes  shipped has been  short-term.  Tariffs  charged to
shippers  for  transportation  of products do not vary  according to the type of
product  delivered.  Demand  on  the  North  Pipeline  is  mainly  of  the  same
agricultural  nature as that of the East  Pipeline  except  for the  Minneapolis
terminal area which is more metropolitan.

Maintenance and Monitoring

     The  Pipelines  have  been  constructed  and  are  maintained  in a  manner
consistent  with  applicable  federal,  state  and local  laws and  regulations,
standards  prescribed by the American Petroleum  Institute and accepted industry
practice.   Further,  protective  measures  are  taken  and  routine  preventive
maintenance  is  performed  on the  Pipelines  in order to prolong  their useful
lives. Such measures include cathodic  protection to prevent external corrosion,
inhibitors  to  prevent  internal  corrosion  and  periodic  inspection  of  the
Pipelines.  Additionally,  the Pipelines  are patrolled at regular  intervals to
identify equipment or activities by third parties that, if left unchecked, could
result in encroachment upon the Pipelines'  rights-of-way and possible damage to
the Pipelines.

     The  Partnership  uses  Supervisory  Control  and Data  Acquisition  remote
supervisory  control software  programs to continuously  monitor and control the
Pipelines  from  the  Wichita,  Kansas  headquarters  and  from  the  Roseville,
Minnesota  terminal for the North Pipeline.  The system  monitors  quantities of
products  injected in and  delivered  through the  Pipelines  and  automatically
signals  the  Wichita  or  Roseville   personnel  upon  deviations  from  normal
operations that requires attention.

Pipeline Operations

     For pipeline  operations,  integrity management and public safety, the East
Pipeline,  the West Pipeline,  the North  Pipeline and the Ammonia  Pipeline are
subject  to  federal  regulation  by one or more of the  following  governmental
agencies or laws: the Federal Energy Regulatory Commission ("FERC"), the Surface
Transportation  Board  (the  "STB"),  the  Department  of  Transportation,   the
Environmental  Protection Agency,  and the Homeland Security Act.  Additionally,
the  operations  and integrity of the  Pipelines  are subject to the  respective
state jurisdictions along the route of the systems. See "Regulation."

     Except for the three single-use  pipelines and certain ethanol  facilities,
all  of  the  Partnership's   pipeline  operations   constitute  common  carrier
operations  and are  subject  to federal  tariff  regulation.  In May 1998,  the
Partnership  was  authorized  by  the  FERC  to  adopt   market-based  rates  in
approximately  one-half  of its  markets  on the East and West  systems.  Common
carrier activities are those for which transportation  through the Partnership's
Pipelines is available at published  tariffs  filed,  in the case of  interstate
petroleum  product  shipments,  with  the FERC  or,  in the  case of  intrastate
petroleum product shipments in Kansas, Colorado,  Wyoming and North Dakota, with
the relevant state authority,  to any shipper of refined petroleum  products who
requests  such  services and satisfies the  conditions  and  specifications  for
transportation.  The Ammonia  Pipeline is subject to federal  regulation  by the
STB, rather than the FERC.

     In  general,  a  shipper  on  one of the  Partnership's  refined  petroleum
products  pipelines  delivers  products to the pipeline from refineries or third
party pipelines that connect to the Pipelines.  The Pipelines' refined petroleum
products  operations  also  include 25  truck-loading  terminals  through  which
refined  petroleum  products are delivered to storage tanks and then loaded into
petroleum  transport trucks.  Five of the 25 terminals also receive propane into
storage  tanks and then load it into  transport  trucks.  The  Ammonia  Pipeline
receives product from anhydrous  ammonia plants or from the marine terminals for
imported product.  Tariffs for transportation are charged to shippers based upon
transportation  from the  origination  point  on the  pipeline  to the  point of
delivery.  Such  tariffs  also include  charges for  terminaling  and storage of
product at the  Pipeline's  terminals.  Pipelines  are generally the lowest cost
method  for  intermediate  and  long-haul  overland  transportation  of  refined
petroleum products.

     Each shipper  transporting  product on a pipeline is required to supply the
Partnership  with a notice  of  shipment  indicating  sources  of  products  and
destinations.  All shipments are tested or receive  refinery  certifications  to
ensure compliance with the Partnership's specifications.  Petroleum shippers are
generally invoiced by the Partnership  immediately upon the product entering one
of the Petroleum Pipelines.

     The following  table shows the number of tanks owned by the  Partnership at
each refined  petroleum  product  terminal  location at December  31, 2004,  the
storage capacity in barrels and truck capacity of each terminal location.

<TABLE>
<CAPTION>

                Location of                     Number                 Tankage          Truck
                  Terminals                    of Tanks               Capacity       Capacity(a)
              ------------------------         ---------             ----------      -----------
<S>           <C>                              <C>                  <C>             <C>
              Colorado:
                    Dupont                         18                  692,000              6
                    Fountain                       13                  391,000              5
              Iowa:
                    LeMars                          9                  103,000              2
                    Milford(b)                     11                  172,000              2
                    Rock Rapids                    12                  366,000              2
              Kansas:
                    Concordia(c)                    7                   79,000              2
                    Hutchinson                      9                  161,000              2
                    Salina                         10                   98,000              3
              Minnesota
                    Moorhead                       17                  498,000              3
                  Sauk Centre                      11                  114,000              2
                  Roseville                        13                  594,000              5
              Nebraska:
                    Columbus(d)                    12                  191,000              2
                    Geneva                         39                  678,000              6
                    Norfolk                        16                  187,000              4
                    North Platte                   22                  197,000              5
                    Osceola                         8                   79,000              2
              North Dakota:
                    Jamestown(e)                   19                  315,000              4
              South Dakota:
                    Aberdeen                       12                  181,000              2
                    Mitchell                        8                   72,000              2
                    Rapid City                     13                  256,000              3
                    Sioux Falls                     9                  381,000              2
                    Wolsey                         21                  149,000              4
                    Yankton                        25                  246,000              4
              Wyoming:
                    Cheyenne                       15                  345,000              2
                                               ------              -----------
              Totals                              349                6,545,000
                                               ======              ===========
</TABLE>

(a)  Number of trucks that may be simultaneously loaded.

(b)  This  terminal  is situated  on land  leased  through  August 7, 2007 at an
     annual rental of $2,400.  The  Partnership has the right to renew the lease
     upon its expiration  for an additional  term of 20 years at the same annual
     rental rate.

(c)  This terminal is situated on land leased  through the year 2060 for a total
     rental of $2,000.

(d)  Also loads rail tank cars.

(e)  Two terminals.


     The East Pipeline also has intermediate storage facilities consisting of 12
storage tanks at El Dorado,  Kansas and 10 storage  tanks at McPherson,  Kansas,
with  aggregate  capacities  of  approximately   548,555  and  534,000  barrels,
respectively.   During  2004,  approximately  57.3%,  87.6%  and  90.0%  of  the
deliveries of the East,  the West and the North  Pipelines,  respectively,  were
made through their terminals,  and the remainder of the respective deliveries of
such lines were made to other pipelines and customer owned storage tanks.

     Storage of product at  terminals  pending  delivery  is  considered  by the
Partnership to be an integral part of the petroleum  product delivery service of
the pipelines. Shippers generally store refined petroleum products for less than
one week.  Ancillary  services,  including  injection of  shipper-furnished  and
generic additives, are available at each terminal.

     The  Partnership  owns 1,500 tons of ammonia  storage at the terminal  near
Hermann, Missouri. One half of the capacity is leased to Koch Nitrogen.

Demand for and Sources of Refined Petroleum Products

     The  Partnership's  pipeline business depends in large part on the level of
demand for refined petroleum products in the markets served by the pipelines and
the ability and  willingness  of refiners  and  marketers  having  access to the
pipelines to supply such demand by deliveries through the pipelines.

     Much of the refined petroleum  products delivered through the East Pipeline
and the western three terminals on the North Pipeline is ultimately used as fuel
for railroads or in agricultural operations,  including fuel for farm equipment,
irrigation  systems,   trucks  used  for  transporting  crops  and  crop  drying
facilities.  Demand for refined petroleum products for agricultural use, and the
relative  mix of products  required,  is affected by weather  conditions  in the
markets served by the East and North Pipelines.  The agricultural sector is also
affected by government  agricultural policies and crop prices.  Although periods
of drought suppress  agricultural  demand for some refined  petroleum  products,
particularly  those used for  fueling  farm  equipment,  the demand for fuel for
irrigation systems often increases during such times.

     While there is some agricultural  demand for the refined petroleum products
delivered through the West Pipeline,  as well as military jet fuel volumes, most
of the demand is  centered  in the Denver and  Colorado  Springs  area.  Because
demand on the West  Pipeline  and the  Minneapolis  area  terminal  of the North
Pipeline is significantly  weighted toward urban and suburban areas, the product
mix on the West  Pipeline  and that  terminal  includes a  substantially  higher
percentage of gasoline than the product mix on the East Pipeline.

     The Partnership's  refined petroleum  products pipelines are also dependent
upon adequate levels of production of refined  petroleum  products by refineries
connected  to the  Pipelines,  directly  or through  connecting  pipelines.  The
refineries are, in turn,  dependent upon adequate supplies of suitable grades of
crude oil. The refineries  connected  directly to the East Pipeline obtain crude
oil from producing fields located primarily in Kansas,  Oklahoma and Texas, and,
to a much lesser extent,  from other domestic or foreign  sources.  In addition,
refineries in Kansas, Oklahoma and Texas are also connected to the East Pipeline
through other  pipelines.  These  refineries  obtain their supplies of crude oil
from a  variety  of  sources.  The  refineries  connected  directly  to the West
Pipeline  are located in Casper and  Cheyenne,  Wyoming  and  Denver,  Colorado.
Refineries  in Billings and Laurel,  Montana are  connected to the West Pipeline
through other  pipelines.  These  refineries  obtain their supplies of crude oil
primarily from Rocky Mountain  sources.  The North Pipeline is heavily dependent
on the Tesoro Mandan refinery which primarily operates on North Dakota crude oil
although it has the ability to access other crude oils. If operations at any one
refinery were discontinued,  the Partnership believes (assuming unchanged demand
for  refined  petroleum  products  in markets  served by the  refined  petroleum
products  pipelines)  that the effects thereof would be short-term in nature and
the Partnership's  business would not be materially  adversely affected over the
long term  because  such  discontinued  production  could be  replaced  by other
refineries or by other sources.

     The majority of the refined petroleum product  transported through the East
Pipeline in 2004 was produced at three  refineries  located at McPherson  and El
Dorado,  Kansas  and  Ponca  City,  Oklahoma,   and  operated  by  the  National
Cooperative Refining Association ("NCRA"),  Frontier Refining and ConocoPhillips
Company,  respectively.  The NCRA and Frontier Refining refineries are connected
directly to the East Pipeline.  The McPherson,  Kansas refinery operated by NCRA
accounted for  approximately  31.8% of the total amount of product  shipped over
the East  Pipeline in 2004.  The East  Pipeline  also has direct access by third
party  pipelines to four other  refineries in Kansas,  Oklahoma and Texas and to
Gulf Coast  supplies of  products  through  connecting  pipelines  that  receive
products from pipelines originating on the Gulf Coast. Five connecting pipelines
can deliver propane from gas processing  plants in Texas,  New Mexico,  Oklahoma
and Kansas to the East Pipeline for shipment.

     The majority of the refined petroleum products transported through the West
Pipeline is produced at the Frontier Refinery located at Cheyenne,  Wyoming, the
Valero Energy Corporation and Suncor Refineries located at Denver, Colorado, and
Sinclair's Little America Refinery located at Casper,  Wyoming, all of which are
connected  directly to the West  Pipeline.  The West Pipeline also has access to
three Billings, Montana, area refineries through a connecting pipeline.

Demand for and Sources of Anhydrous Ammonia

     The Partnership's Ammonia Pipeline business depends on the overall nitrogen
fertilizer use, management  practice,  level of demand for direct application of
anhydrous ammonia as a fertilizer for crop production  ("Direct  Application" or
"DA"), the weather (DA is not effective if the ground is too wet or too dry) and
the price of natural gas (the primary component of anhydrous ammonia).

     The Ammonia Pipeline is the largest of three anhydrous ammonia pipelines in
the United States and the only one that has the capability of receiving  foreign
production directly into the system and transporting  anhydrous ammonia into the
nation's corn belt. This ability to receive either domestic or foreign anhydrous
ammonia is a competitive  advantage  over the next largest  ammonia system which
originates in Oklahoma and Texas, then extends into Iowa.

     Corn producers have several fertilizer  alternatives such as liquid, dry or
Direct  Application.  Liquid and dry  fertilizers are both upgrades of anhydrous
ammonia  and  therefore  are  generally  more costly but are less  sensitive  to
weather conditions during  application.  DA is the cheapest method of fertilizer
application but cannot be applied if the ground is too wet or extremely dry.

Principal Customers

     The  Partnership  had a total of  approximately  48 shippers  in 2004.  The
principal shippers include integrated oil companies,  refining  companies,  farm
cooperatives and a railroad.  Transportation revenues attributable to the top 10
shippers were $90.4 million,  $86.6 million and $61.5 million,  which  accounted
for 75%, 72% and 74% of total  Pipeline  revenues  shipped for each of the years
2004, 2003 and 2002, respectively.

Competition and Business Considerations

     The East and North Pipelines' major competitor is an independent, regulated
common  carrier  pipeline  system  owned by Magellan  Midstream  Partners,  L.P.
("Magellan"), formerly the Williams Companies, Inc., that operates approximately
100 miles east of and parallel to the East  Pipeline  and in close  proximity to
the North Pipeline. The Magellan system is a substantially more extensive system
than the East and North Pipelines.  Competition with Magellan is based primarily
on  transportation  charges,  quality of customer  service and  proximity to end
users,  although  refined product pricing at either the origin or terminal point
on  a  pipeline  may  outweigh  transportation  costs.  Seventeen  of  the  East
Pipeline's and all four of the North Pipeline's  delivery  terminals are located
within 2 to 145 miles of, and in direct competition with Magellan's terminals.

     The West Pipeline competes with the truck-loading racks of the Cheyenne and
Denver  refineries and the Denver  terminals of the Chase  Terminal  Company and
ConocoPhillips.  Valero L.P. terminals in Denver and Colorado Springs, connected
to a Valero  L.P.  pipeline  from  their  Texas  Panhandle  Refinery,  are major
competitors to the West Pipeline's Denver and Fountain Terminals, respectively.

     Because pipelines are generally the lowest cost method for intermediate and
long-haul  movement  of  refined  petroleum  products,  the  Partnership's  more
significant  competitors are common carrier and proprietary  pipelines owned and
operated by major  integrated  and large  independent  oil  companies  and other
companies  in the areas where the  Partnership  delivers  products.  Competition
between common carrier pipelines is based primarily on  transportation  charges,
quality of customer service and proximity to end users. The Partnership believes
high capital costs, tariff regulation, environmental considerations and problems
in  acquiring  rights-of-way  make it  unlikely  that other  competing  pipeline
systems  comparable in size and scope to its pipelines will be built in the near
future, provided its pipelines have available capacity to satisfy demand and its
tariffs remain at reasonable levels.

     The costs associated with transporting  products from a loading terminal to
end  users  limit  the  geographic  size  of  the  market  that  can  be  served
economically  by any  terminal.  Transportation  to end users  from the  loading
terminals of the Partnership is conducted  principally by trucking operations of
unrelated third parties.  Trucks may  competitively  deliver products in some of
the areas served by the Partnership's pipelines.  However, trucking costs render
that mode of transportation  not competitive for longer hauls or larger volumes.
The  Partnership  does not  believe  that  trucks  are,  or will  be,  effective
competition to its long-haul volumes over the long term.

     Competitors  of the Ammonia  Pipeline  include  another  anhydrous  ammonia
pipeline  which  originates in Oklahoma and Texas,  and  terminates in Iowa. The
competitor  pipeline  has the same DA demand and  weather  issues as the Ammonia
Pipeline but is restricted to domestically  produced anhydrous ammonia.  Midwest
production barges and railroads  represent other forms of direct  competition to
the pipeline under certain market conditions.


LIQUIDS TERMINALING BUSINESS

Introduction

     The  Partnership's  terminaling  business is conducted  through the Support
Terminal  Services  operation  ("ST  Services"  or "ST")  and  Statia  Terminals
International  N.V.  ("Statia").  ST Services is one of the largest  independent
petroleum  products and specialty  liquids  terminaling  companies in the United
States.  Statia,  acquired  on February  28,  2002 for a purchase  price of $178
million (net of cash  acquired),  plus the  assumption  of $107 million of debt,
owns and operates the  Partnership's  two largest terminals and provides related
value-added  services,  including crude oil and petroleum  product  blending and
processing,  berthing of vessels at their marine  facilities,  and emergency and
spill response services. In addition to its terminaling  services,  Statia sells
bunkers,  which is the fuel marine vessels consume,  and bulk petroleum products
to various commercial interests.

     For the  year  ended  December  31,  2004,  the  Partnership's  terminaling
business  accounted for approximately 40% of the Partnership's  revenues.  As of
December 31, 2004, ST operated 41 facilities in 20 states,  with a total storage
capacity of approximately 34.9 million barrels.  ST also owns and operates seven
terminals   located  in  the  United   Kingdom,   having  a  total  capacity  of
approximately  6.0  million  barrels.  In May and  September  2004,  ST acquired
terminals in Philadelphia,  Pennsylvania and Linden, New Jersey from ExxonMobil.
In September 2004, ST acquired a chemical and petroleum terminal in Grangemouth,
Scotland.  In September  2002, ST acquired eight  terminals in Australia and New
Zealand  with  a  total  capacity  of  approximately  1.2  million  barrels  for
approximately  $47 million in cash. ST Services and its predecessors have a long
history in the  terminaling  business  and handle a wide variety of liquids from
petroleum products to specialty chemicals to edible liquids. At the end of 2004,
Statia's  tank  capacity  was 18.8  million  barrels,  including an 11.3 million
barrel storage and  transshipment  facility located on the Netherlands  Antilles
island of St.  Eustatius,  and a 7.5 million  barrel  storage and  transshipment
facility located at Point Tupper, Nova Scotia, Canada.

     The Partnership's terminal facilities provide storage and handling services
on a fee basis for petroleum  products,  specialty  chemicals and other liquids.
The Partnership's  six largest terminal  facilities are located on the Island of
St. Eustatius,  Netherlands Antilles;  in Point Tupper, Nova Scotia,  Canada; in
Piney  Point,  Maryland;  in Linden,  New Jersey (50% owned joint  venture);  in
Crockett, California; and in Martinez, California.


Description of Largest Terminal Facilities

     St. Eustatius, Netherlands Antilles

     Statia  owns and  operates an 11.3  million  barrel  petroleum  terminaling
facility located on the Netherlands  Antilles island of St. Eustatius,  which is
located  at a point of  minimal  deviation  from  major  shipping  routes.  This
facility is capable of handling a wide range of  petroleum  products,  including
crude oil and refined products,  and can accommodate the world's largest tankers
for loading and discharging  crude oil. A two-berth jetty, a two-berth  monopile
with platform and buoy systems, a floating hose station,  and an offshore single
point mooring buoy with loading and unloading  capabilities serve the terminal's
customers' vessels. The St. Eustatius facility has a total of 51 tanks. The fuel
oil  and  petroleum  product   facilities  have  in-tank  and  in-line  blending
capabilities,  while the crude tanks have  tank-to-tank  blending  capability as
well as in-tank mixers.  In addition to the storage and blending services at St.
Eustatius,  the facility has the flexibility to utilize certain storage capacity
for both feedstock and refined products to support its atmospheric  distillation
unit,  which is capable of processing up to 15,000 barrels per day of feedstock,
ranging from condensates to heavy crude oil. Statia owns and operates all of the
berthing  facilities at its St. Eustatius terminal and charges vessels a fee for
their use.  Vessel owners or charterers  may incur  separate fees for associated
services  such as pilotage,  tug  assistance,  line  handling,  launch  service,
emergency response services and other ship services.

     Point Tupper, Nova Scotia, Canada

     Statia owns and operates a 7.5 million barrel terminaling  facility located
at Point  Tupper on the  Strait of Canso,  near Port  Hawkesbury,  Nova  Scotia,
Canada,  which is located  approximately 700 miles from New York City, 850 miles
from  Philadelphia and 2,500 miles from Mongstad,  Norway.  This facility is the
deepest  independent,  ice-free marine  terminal on the North American  Atlantic
coast, with access to the East Coast and Canada as well as the Midwestern United
States via the St. Lawrence  Seaway and the Great Lakes system.  With one of the
premier  jetty  facilities  in North  America,  the Point  Tupper  facility  can
accommodate  substantially  all of the world's  largest,  fully-laden very large
crude carriers and ultra large crude carriers for loading and discharging  crude
oil, petroleum  products,  and  petrochemicals.  The Point Tupper facility has a
total of 37 tanks.  Its butane sphere is one of the largest of its kind in North
America. The facility's tanks were renovated in 1994 to comply with construction
standards  that meet or exceed  American  Petroleum  Institute,  NFPA, and other
material  industry  standards.  Crude oil and petroleum product movements at the
terminal  are fully  automated.  Separate  Statia  fees apply for the use of the
jetty  facility  as  well  as  associated  services,   including  pilotage,  tug
assistance,  line handling,  launch service,  spill response  services and other
ship services. Statia also charters tugs, mooring launches, and other vessels to
assist  with the  movement  of vessels  through the Strait of Canso and the safe
berthing of vessels at Point Tupper and to provide other services to vessels.

     Piney Point, Maryland

     The  largest  domestic  terminal  currently  owned  by  ST  is  located  on
approximately  400 acres on the Potomac River. The facility was acquired as part
of the purchase of the liquids  terminaling  assets of Steuart Petroleum Company
and certain of its  affiliates in December  1995.  The Piney Point  terminal has
approximately  5.4  million  barrels of storage  capacity in 28 tanks and is the
closest  deep-water  facility to  Washington,  D.C. This terminal  competes with
other large petroleum  terminals in the East Coast water-borne  market extending
from New York  Harbor  to  Norfolk,  Virginia.  The  terminal  currently  stores
petroleum products consisting  primarily of fuel oils and asphalt.  The terminal
has a dock with a 36-foot draft for tankers and four berths for barges.  It also
has truck-loading facilities,  product-blending capabilities and is connected to
a pipeline which supplies residual fuel oil to two power generating stations.

     Linden, New Jersey

     In  October  1998,  ST  entered  into a  joint  venture  relationship  with
Northville  Industries Corp.  ("Northville") to acquire a 50% ownership interest
in and the  management of the terminal  facility at Linden,  New Jersey that was
previously owned by Northville. The 44-acre facility provides ST with deep-water
terminaling  capabilities  at New York  Harbor and  primarily  stores  petroleum
products,  including gasoline,  jet fuel and fuel oils. The facility has a total
capacity of approximately  3.9 million barrels in 22 tanks, can receive products
via ship, barge and pipeline and delivers product by ship,  barge,  pipeline and
truck.  The terminal  owns two docks and leases a third with draft limits of 35,
24 and 24 feet,  respectively.  In  September  2004,  ST,  outside  of the joint
venture, acquired an adjacent 375,000 barrel terminal from Exxon-Mobil.

     Crockett, California

     The  Crockett  Terminal was acquired in January 2001 as a part of the Shore
acquisition.  The terminal has approximately 3 million barrels of tankage and is
located in the San Francisco Bay area. The facility  provides  deep-water access
for handling  petroleum  products and gasoline  additives  such as ethanol.  The
terminal offers  pipeline  connections to various  refineries and pipelines.  It
receives  and delivers  product by vessel,  barge,  pipeline  and  truck-loading
facilities. The terminal also has railroad tank car unloading capability.

     Martinez, California

     The Martinez Terminal, also acquired in January 2001 as a part of the Shore
acquisition,  is located  in the  refinery  area of San  Francisco  Bay.  It has
approximately  3.1  million  barrels of tankage and  handles  refined  petroleum
products as well as crude oil.  The  terminal is  connected to a pipeline and to
area refineries by pipelines and can also receive and deliver products by vessel
or barge. It also has a truck rack for product delivery.

     The Partnership's  facilities have been designed with engineered structural
measures to minimize the  possibility  of the occurrence and the level of damage
in the event of a spill or fire.  All loading  areas,  tanks,  pipes and pumping
areas are  "contained"  to collect any  spillage  and insure that only  properly
treated water is discharged from the site.

     Other Terminal Sites

     In addition  to the four major  domestic  facilities  described  above,  ST
Services has 37 other terminal  facilities located throughout the United States,
seven  facilities in the United  Kingdom,  four facilities in Australia and four
facilities in New Zealand.  These other  facilities  primarily  store  petroleum
products for a variety of  customers,  with the  exception of the  facilities in
Texas City, Texas, which handles specialty chemicals;  Columbus,  Georgia, which
handles aviation  gasoline and specialty  chemicals;  Winona,  Minnesota,  which
handles  nitrogen  fertilizer  solutions;   Savannah,   Georgia,  which  handles
chemicals,  lube  oils,  potash  and  caustic  solutions,  as well as  petroleum
products;  Vancouver,   Washington,  which  handles  chemicals  and  fertilizer;
Eastham,  United Kingdom, which handles chemicals and animal fats;  Grangemouth,
United  Kingdom,  which  handles  chemicals  and  molasses as well as  petroleum
products;  and Runcorn,  United Kingdom,  which handles molten sulphur,  and the
Australian and New Zealand  terminals which handle chemicals and animal fats and
oil.  Overall,  these  facilities  provide ST Services with locations  which are
diverse geographically, in products handled and in customers served.

     The  following  table  outlines  the  Partnership's   terminal   locations,
capacities, tanks and primary products handled:
<TABLE>
<CAPTION>

                                    Tankage         No. of               Primary Products
          Facility                  Capacity         Tanks                     Handled
--------------------------------   ------------   ------------   -----------------------------------
<S>                                <C>            <C>            <C>
Major U. S. Terminals:
Piney Point, MD                    5,403,000            28       Petroleum
Linden, NJ(a)                      3,884,000            22       Petroleum
Crockett, CA                       3,048,000            24       Petroleum, ethanol
Martinez, CA                       3,106,000            19       Petroleum
Jacksonville, FL                   2,069,000            30       Petroleum
Texas City, TX                     2,008,000           124       Chemicals, petrochemicals,
                                                                 petroleum

Other U. S. Terminals:
Montgomery, AL(b)                    162,000             7       Petroleum, jet fuel
Moundville, AL                       310,000             6       Jet Fuel
Tucson, AZ(a)                        174,000             7       Petroleum
Los Angeles, CA                      597,000            20       Petroleum
Richmond, CA                         617,000            25       Petroleum, ethanol
Stockton, CA                         706,000            32       Petroleum, ethanol, fertilizer,
                                                                 caustic
Bremen, GA                           182,000             9       Petroleum, jet fuel
Brunswick, GA                        302,000             3       Fertilizer, pulp liquor
Columbus, GA                         175,000            24       Petroleum, chemicals, fertilizers
Macon, GA(b)                         307,000            10       Petroleum, jet fuel
Savannah, GA                         903,000            28       Petroleum, chemicals
Blue Island, IL                      752,000            19       Petroleum, ethanol
Chillicothe, IL(a)                   270,000             6       Petroleum
Peru, IL                             221,000             8       Fertilizer
Indianapolis, IN                     410,000            18       Petroleum
Westwego, LA                         849,000            53       Molasses, fertilizer, caustic,
                                                                 chemicals, lube oil
Andrews AFB Pipeline, MD(b)           72,000             3       Jet fuel
Baltimore, MD                        832,000            50       Chemicals, asphalt, jet fuel
Salisbury, MD                        177,000            14       Petroleum
Winona, MN                           267,000             8       Fertilizer
Reno, NV                             107,000             7       Petroleum
Linden, NJ                           375,000            11       Petroleum
Paulsboro, NJ                      1,580,000            18       Petroleum
Alamogordo, NM(b)                    120,000             5       Jet Fuel
Drumright, OK                        315,000             4       Petroleum
Portland, OR                       1,119,000            31       Petroleum
Philadelphia, PA                     894,000            11       Petroleum
Philadelphia, PA                     665,000            11       Petroleum
Texas City, TX                       153,000            12       Chemicals, petrochemicals,
                                                                 petroleum
Dumfries, VA                         554,000            16       Petroleum, asphalt
Virginia Beach, VA(b)                 40,000             2       Jet fuel
Tacoma, WA                           377,000            15       Petroleum
Vancouver, WA                        227,000            49       Chemicals, fertilizer, petroleum
Vancouver, WA                        316,000             6       Petroleum, chemicals, fertilizer
Milwaukee, WI                        308,000             7       Petroleum, ethanol

Foreign Terminals:
St. Eustatius, Netherlands
Antilles.                         11,350,000            60       Petroleum, crude oil
Point Tupper, Canada               7,514,000            40       Petroleum, crude oil
Sydney, Australia                    330,000            65       Chemicals, fats and oils
Melbourne, Australia                 468,000           118       Specialty chemicals
Geelong, Australia                   145,000            14       Specialty chemicals, petroleum
Adelaide, Australia                   90,000            24       Chemicals, tallow, petroleum
Auckland, New Zealand (a)             74,000            44       Fats, oils and chemicals
New Plymouth, New Zealand             35,000            10       Fats, oils and chemicals
Mt. Maunganui, New Zealand            83,000            24       Fats, oils and chemicals
Wellington, New Zealand               50,000            13       Fats, oils and chemicals
Grays, England                     1,945,000            53       Petroleum
Eastham, England                   2,185,000           162       Chemicals, petroleum, animal fats
Runcorn, England                     146,000             4       Molten sulfur
Grangemouth, Scotland                530,000            46       Petroleum, chemicals and molasses
Glasgow, Scotland                    344,000            16       Petroleum
Leith, Scotland                      459,000            34       Petroleum, chemicals
Belfast, Northern Ireland            407,000            41       Petroleum
                                 ---------------  --------------
                                  61,108,000         1,570
                                 ===============  ==============
</TABLE>

(a)  The terminal is 50% owned by ST.

(b)  Facility  also  includes  pipelines  to  U.S.   government   military  base
     locations.

Customers

     Statia provides  terminaling  services for crude oil and refined  petroleum
products to many of the world's largest  producers of crude oil,  integrated oil
companies, oil traders and refiners.  Statia's crude oil transshipment customers
include an oil producer that leases and utilizes 5.0 million  barrels of storage
at St. Eustatius and a major international oil company which leases and utilizes
3.6 million  barrels of storage at Point  Tupper,  both of which have  long-term
contracts with Statia.  In addition,  two different  international oil companies
each lease and  utilize  1.0 million  barrels of clean  products  storage at St.
Eustatius  and  Point  Tupper,  respectively.   Also  in  Canada,  a  consortium
consisting  of major oil  companies  sends  natural gas liquids via  pipeline to
certain  processing  facilities  on land leased from Statia.  After  processing,
certain  products  are stored at the Point  Tupper  facility  under a  long-term
contract.  In addition,  Statia's blending capabilities have attracted customers
who  have  leased  capacity   primarily  for  blending  purposes  and  who  have
contributed to Statia's bunker fuel and bulk product sales.

     The storage and transport of jet fuel for the U.S. Department of Defense is
an important part of ST's  business.  Eleven of ST's terminal sites are involved
in the terminaling or transport (via pipeline) of jet fuel for the Department of
Defense and four of the eleven  locations have been utilized  solely by the U.S.
Government.  Of the eleven  locations,  five include pipelines which deliver jet
fuel directly to nearby military bases.

 Competition and Business Considerations

     In addition to the terminals owned by independent terminal operators,  such
as the  Partnership,  many major energy and  chemical  companies  own  extensive
terminal  storage  facilities.  Although  such  terminals  often  have  the same
capabilities as terminals owned by independent operators,  they generally do not
provide terminaling  services to third parties. In many instances,  major energy
and chemical  companies  that own storage and  terminaling  facilities  are also
significant   customers  of  independent   terminal   operators,   such  as  the
Partnership.  Such companies typically have strong demand for terminals owned by
independent  operators  when  independent  terminals  have more  cost  effective
locations near key transportation  links, such as deep-water ports. Major energy
and chemical  companies also need independent  terminal storage when their owned
storage  facilities  are  inadequate,  either because of size  constraints,  the
nature of the stored material or specialized handling requirements.

     Independent  terminal owners generally compete on the basis of the location
and versatility of terminals,  service and price. A favorably  located  terminal
will have access to various cost effective transportation modes both to and from
the terminal.  Transportation  modes  typically  include  waterways,  railroads,
roadways and pipelines.  Terminals  located near  deep-water port facilities are
referred to as "deep-water  terminals" and terminals without such facilities are
referred to as "inland terminals"; although some inland facilities located on or
near navigable rivers are served by barges.

     Terminal  versatility  is a  function  of the  operator's  ability to offer
handling for diverse  products with complex handling  requirements.  The service
function typically  provided by the terminal  includes,  among other things, the
safe  storage  of the  product  at  specified  temperature,  moisture  and other
conditions,  as well as receipt at and delivery from the terminal,  all of which
must be in compliance  with  applicable  environmental  regulations.  A terminal
operator's  ability  to obtain  attractive  pricing  is often  dependent  on the
quality,  versatility  and reputation of the  facilities  owned by the operator.
Although many products  require  modest  terminal  modification,  operators with
versatile storage  capabilities  typically  require less  modification  prior to
usage, ultimately making the storage cost to the customer more attractive.

     A few companies offering liquid  terminaling  facilities have significantly
more capacity than the Partnership.  However,  much of the Partnership's tankage
can be described  as "niche"  facilities  that are  equipped to properly  handle
"specialty"  liquids or provide facilities or services where management believes
the Partnership enjoys an advantage over competitors.  As a result,  many of the
Partnership's   terminals   compete  against  other  large  petroleum   products
terminals,  rather than specialty liquids facilities.  Such specialty or "niche"
tankage is less abundant in the U.S. and "specialty"  liquids  typically command
higher terminal fees than lower-price bulk terminaling for petroleum products.

     The main  competition  to crude oil storage at Statia's  facilities is from
"lightering"  which is the  process  by which  liquid  cargo is  transferred  to
smaller vessels, usually while at sea. The price differential between lightering
and terminaling is primarily  driven by the charter rates for vessels of various
sizes.  Lightering  generally takes  significantly  longer than discharging at a
terminal.  Depending on charter rates, the longer charter period associated with
lightering is generally  offset by various costs  associated  with  terminaling,
including  storage  costs,  dock  charges  and  spill  response  fees.  However,
terminaling  is  generally  safer and reduces the risk of  environmental  damage
associated  with  lightering,  provides more  flexibility  in the  scheduling of
deliveries, and allows customers of Statia to deliver their products to multiple
locations. Lightering in U.S. territorial waters creates a risk of liability for
owners and  shippers of oil under the U.S. Oil  Pollution  Act of 1990 and other
state and federal  legislation.  In Canada,  similar  liability exists under the
Canadian Shipping Act.  Terminaling also provides  customers with the ability to
access value-added terminal services.

     In the bunkering business, Statia competes with ports offering bunker fuels
to which, or from which, each vessel travels or are along the route of travel of
the vessel.  Statia also  competes  with bunker  delivery  locations  around the
world. In the Western Hemisphere,  alternative bunker locations include ports on
the U.S.  East coast and Gulf coast and in Panama,  Puerto  Rico,  the  Bahamas,
Aruba,  Curacao,  and Halifax.  In addition,  Statia competes with Rotterdam and
various North Sea locations.


CAPITAL EXPENDITURES

     Capital  expenditures by the Pipelines,  including routine  maintenance and
expansion  expenditures,  but excluding  acquisitions,  were $10.3 million, $9.6
million and $9.5  million for 2004,  2003 and 2002,  respectively.  During these
periods,  adequate  capacity  existed on these  pipelines to accommodate  volume
growth,  and the  expenditures  required  for  environmental  matters  were  not
material in amount.  Capital  expenditures,  including  routine  maintenance and
expansion  expenditures,  but  excluding  acquisitions,  for  the  Partnership's
terminaling  operations were $29.5 million,  $34.6 million and $21.0 million for
2004, 2003 and 2002, respectively.

     Capital  expenditures of the  Partnership  during 2005,  including  routine
maintenance and expansion expenditures, but excluding acquisitions, are expected
to be approximately $40 million to $44 million. See "Management's Discussion and
Analysis of  Financial  Condition  and  Results of  Operations  - Liquidity  and
Capital  Resources."  Additional  expansion-related  capital  expenditures  will
depend on future  opportunities  to expand the  Partnership's  operations.  Such
future   expenditures,   however,   will  depend  on  many  factors  beyond  the
Partnership's  control,  including,  without  limitation,   demand  for  refined
petroleum products and terminaling  services in the Partnership's  market areas,
local, state and federal governmental regulations, fuel conservation efforts and
the  availability  of financing on acceptable  terms.  No assurance can be given
that required capital  expenditures will not exceed  anticipated  amounts during
the year or thereafter or that the Partnership  will have the ability to finance
such expenditures through borrowings or choose to do so.


REGULATION

Interstate Regulation

     The interstate common carrier petroleum product pipeline  operations of the
Partnership are subject to rate regulation by FERC under the Interstate Commerce
Act. The Interstate Commerce Act provides, among other things, that to be lawful
the rates of common carrier  petroleum  pipelines must be "just and  reasonable"
and not  unduly  discriminatory.  New and  changed  rates must be filed with the
FERC, which may investigate  their lawfulness on protest or its own motion.  The
FERC may suspend the  effectiveness of such rates for up to seven months. If the
suspension  expires before  completion of the  investigation,  the rates go into
effect,  but the pipeline can be required to refund to shippers,  with interest,
any difference  between the level the FERC determines to be lawful and the filed
rates under  investigation.  Rates that have become final and  effective  may be
challenged  by a  complaint  to FERC  filed by a shipper  or on the  FERC's  own
initiative.  Reparations  may be recovered by the party filing the complaint for
the  two-year  period  prior  to the  complaint,  if FERC  finds  the rate to be
unlawful.

     The FERC  allows  for a rate of return  for  petroleum  products  pipelines
determined  by adding (i) the  product of a rate of return  equal to the nominal
cost of debt  multiplied  by the  portion  of the rate base that is deemed to be
financed  with debt and (ii) the  product of a rate of return  equal to the real
(i.e., inflation-free) cost of equity multiplied by the portion of the rate base
that is deemed to be financed with equity.  The appropriate rate of return for a
petroleum  pipeline is determined on a case-by-case  basis,  taking into account
cost of capital, competitive factors and business and financial risks associated
with pipeline operations.

     Under  Title XVIII of the Energy  Policy Act of 1992 (the "EP Act"),  rates
that were in effect on  October  24,  1991 that were not  subject  to a protest,
investigation  or complaint  are deemed to be just and  reasonable.  Such rates,
commonly  referred to as grandfathered  rates, are subject to challenge only for
limited  reasons.  Any  relief  granted  pursuant  to  such  challenges  may  be
prospective only. Because the Partnership's rates that were in effect on October
24,  1991,  were not subject to  investigation  and protest at that time,  those
rates  could be deemed to be just and  reasonable  pursuant  to the EP Act.  The
Partnership's  current  rates became final and  effective in July 2000,  and the
Partnership   believes  that  its  currently  effective  tariffs  are  just  and
reasonable  and would  withstand  challenge  under the  FERC's  cost-based  rate
standards.  Because of the complexity of rate making, however, the lawfulness of
any rate is never assured.

     On  October  22,  1993,  the FERC  issued  Order No.  561  which  adopted a
simplified  rate making  methodology for future oil pipeline rate changes in the
form of  indexation.  Indexation,  which is also known as price cap  regulation,
establishes  ceiling  prices on oil  pipeline  rates based on  application  of a
broad-based  measure of inflation in the general economy to existing rates. Rate
increases up to the ceiling level are to be discretionary for the pipeline, and,
for  such  rate  increases,  there  will be no need to file  cost-of-service  or
supporting data.  Moreover,  so long as the ceiling is not exceeded,  a pipeline
may make a limitless  number of rate change  filings.  This  indexing  mechanism
calculates a ceiling rate. Rate decreases are required if the indexing mechanism
operates to reduce the  ceiling  rate below a  pipeline's  existing  rates.  The
pipeline may increase its rates to this calculated ceiling rate without filing a
formal cost based justification and with limited risk of shipper protests.

     The  indexation  method  is  to  serve  as  the  principal  basis  for  the
establishment  of oil  pipeline  rate changes in the future.  However,  the FERC
determined  that a pipeline  may  utilize any one of the  following  alternative
methodologies to indexing: (i) a cost-of-service  methodology may be utilized by
a pipeline to justify a change in a rate if a pipeline can demonstrate  that its
increased  costs  are  prudently  incurred  and  that  there  is  a  substantial
divergence  between such increased  costs and the rate that would be produced by
application  of the  index;  and  (ii) a  pipeline  may base  its  rates  upon a
"light-handed"  market-based  form of regulation if it is able to  demonstrate a
lack of significant market power in the relevant markets.

     On September 15, 1997,  the  Partnership  filed an  Application  for Market
Power  Determination  with the FERC seeking market based rates for approximately
half of its markets. In May 1998, the FERC granted the Partnership's application
and  approximately  half of the  markets  served by the East and West  Pipelines
subsequently became subject to market force regulation.

     In the FERC's  Lakehead  decision  issued June 15, 1995, the FERC partially
disallowed  Lakehead's  inclusion  of  income  taxes  in its  cost  of  service.
Specifically,  the FERC held that Lakehead was entitled to receive an income tax
allowance with respect to income attributable to its corporate partners, but was
not entitled to receive such an allowance for income attributable to partnership
interests held by individuals. Lakehead's motion for rehearing was denied by the
FERC  and  Lakehead  appealed  the  decision  to  the  U.S.  Court  of  Appeals.
Subsequently,  the case was settled by Lakehead and the appeal was withdrawn. In
another FERC proceeding  involving a different oil pipeline limited partnership,
various shippers challenged such pipeline's inclusion of an income tax allowance
in its cost of  service.  The FERC  decided  this case on the same  basis as its
holding in the Lakehead  case. On July 20, 2004,  the District of Columbia Court
of Appeals  vacated  the  Commission's  determination  regarding  the proper tax
allowance in that case and remanded the income tax allocation  issue for further
FERC consideration. FERC has requested and received comments as to the issue. If
the FERC were to partially or  completely  disallow the income tax  allowance in
the cost of service of the East and West pipelines on the basis set forth in the
Lakehead order, KPL believes that the Partnership's ability to pay distributions
to the  holders  of the Units  would not be  impaired;  however,  in view of the
uncertainties involved in this issue, there can be no assurance in this regard.

     The  Ammonia  Pipeline  rates  are  regulated  by  the  STB.  The  STB  was
established  in 1996 when the Interstate  Commerce  Commission was terminated by
the ICC Termination Act of 1995. The STB is headed by Board Members appointed by
the  President  and  confirmed  by the  Senate and is  authorized  to have three
members.  The STB  jurisdiction  generally  includes  railroad  rate and service
issues,  rail  restructuring  transactions  and labor matters  related  thereto;
certain trucking company,  moving van, and non-contiguous ocean shipping company
rate  matters;  and certain  pipeline  matters not regulated by the FERC. In the
performance  of  its  functions,  the  STB  is  charged  with  promoting,  where
appropriate,  substantive  and  procedural  regulatory  reform  in the  economic
regulation  of surface  transportation,  and with  providing  an  efficient  and
effective  forum for the  resolution  of disputes.  The STB seeks to  facilitate
commerce by providing an effective  forum for efficient  dispute  resolution and
facilitation of appropriate market-based business transactions.

     The  Partnership  issued a STB tariff that became  effective April 1, 2003.
The  tariff  filing  combined  the  STB  interstate  tariff  and  the  Louisiana
intrastate  tariff into one  document  and  standardized  the tariff  regulation
between the two  regulatory  bodies.  The tariff  filing  modified  the capacity
allocation  procedures  and  established a minimum tariff rate of $5.00 per ton.
The tariff  filing  implemented  a 7% tariff  increase  across all tariff rates.
Another  modification  was the removal of the "Industrial  User"  classification
which effectively increases the tariff rates actually paid for transportation to
certain  shippers by more than 7%. Dyno Nobel,  an industrial  user in Missouri,
and CF Industries filed protests  against the tariff filing.  See "Item 3. Legal
Proceedings, Ammonia Pipeline Matters" for a description of those matters.

Intrastate Regulation

     The  intrastate  operations  of the East  Pipeline in Kansas are subject to
regulation by the Kansas Corporation  Commission,  the intrastate  operations of
the West  Pipeline in Colorado  and  Wyoming  are subject to  regulation  by the
Colorado  Public Utility  Commission and the Wyoming Public Service  Commission,
respectively, and the intrastate operations of the North Pipeline are subject to
regulation by the North Dakota Public  Utility  Commission.  Like the FERC,  the
state  regulatory  authorities  require  that  shippers  be notified of proposed
intrastate  tariff  increases and have an opportunity to protest such increases.
The  Partnership  also files with such state  authorities  copies of  interstate
tariff changes filed with the FERC. In addition to challenges to new or proposed
rates,  challenges to intrastate  rates that have already  become  effective are
permitted by complaint of an interested  person or by independent  action of the
appropriate regulatory authority.

     The intrastate  operations of the Ammonia Pipeline in Louisiana are subject
to regulation by the Louisiana  Public  Service  Commission.  Shippers under the
Louisiana  intrastate  tariff  have  rights  similar to those  mentioned  in the
paragraph above.


ENVIRONMENTAL MATTERS

General

     The operations of the Partnership  are subject to federal,  state and local
laws and regulations relating to the protection of the environment in the United
States and to the  environmental  laws and  regulations of the host countries in
regard to the terminals  acquired  overseas.  Although the Partnership  believes
that its  operations are in general  compliance  with  applicable  environmental
regulations, risks of substantial costs and liabilities are inherent in pipeline
and terminal  operations,  and there can be no assurance that significant  costs
and  liabilities  will  not be  incurred  by the  Partnership.  Moreover,  it is
possible that other  developments,  such as  increasingly  strict  environmental
laws, regulations and enforcement policies thereunder, and claims for damages to
property or persons  resulting from the operations of the Partnership,  past and
present, could result in substantial costs and liabilities to the Partnership.

     See "Item 3 - Legal Proceedings" for information concerning several matters
pending against certain  subsidiaries  of the Partnership  involving  claims for
environmental damages.

Water

     The Oil Pollution Act ("OPA") was enacted in 1990 and amends  provisions of
the  Federal  Water  Pollution  Control  Act of 1972 and other  statutes as they
pertain to  prevention  and response to oil spills.  The OPA subjects  owners of
facilities  to strict,  joint and  potentially  unlimited  liability for removal
costs and certain other  consequences of an oil spill,  where such spill is into
navigable  waters,  along  shorelines or in the exclusive  economic zone. In the
event of an oil spill into such waters, substantial liabilities could be imposed
upon the  Partnership.  Regulations  concerning the  environment are continually
being  developed  and  revised  in ways that may  impose  additional  regulatory
burdens on the Partnership.

     Contamination  resulting  from  spills or  releases  of  refined  petroleum
products is not unusual  within the petroleum  pipeline and liquids  terminaling
industries.   The  East  Pipeline  and  ST  Services  have  experienced  limited
groundwater  contamination at various terminal and pipeline sites resulting from
various causes including activities of previous owners. Remediation projects are
underway or under construction using various remediation  techniques.  The costs
to remediate  contamination at several ST terminal  locations are being borne by
the former owners under indemnification  agreements.  Although no assurances can
be made, the Partnership  believes that the aggregate cost of these  remediation
efforts will not be material.

     The EPA has  promulgated  regulations  that may require the  Partnership to
apply for permits to discharge storm water runoff. Storm water discharge permits
also may be required in certain states in which the Partnership operates.  Where
such  requirements are applicable,  the Partnership has applied for such permits
and,  after the permits  are  received,  will be required to sample  storm water
effluent before releasing it. The Partnership believes that effluent limitations
could be met, if necessary,  with minor modifications to existing facilities and
operations.  Although no assurance in this regard can be given,  the Partnership
believes that the changes will not have a material  effect on the  Partnership's
financial condition or results of operations.

Aboveground Storage Tank Acts

     A number of the  states in which the  Partnership  operates  in the  United
States have passed  statutes  regulating  aboveground  tanks  containing  liquid
substances.  Generally, these statutes require that such tanks include secondary
containment systems or that the operators take certain  alternative  precautions
to ensure that no contamination results from any leaks or spills from the tanks.
Although  there is not total federal  regulation of all above ground tanks,  the
DOT has adopted an industry  standard that  addresses tank  inspection,  repair,
alteration and reconstruction. This action requires pipeline companies to comply
with the standard for tank  inspection and repair for all tanks regulated by the
DOT. The Partnership is in substantial  compliance with all above ground storage
tank laws in the states with such laws.  Although no assurance can be given, the
Partnership believes that the future implementation of above ground storage tank
laws by either  additional  states or by the federal  government will not have a
material adverse effect on the Partnership's  financial  condition or results of
operations.

Air Emissions

     The operations of the  Partnership are subject to the Federal Clean Air Act
and  comparable  state and local  statutes.  The  Partnership  believes that the
operations of its pipelines and  terminals are in  substantial  compliance  with
such statutes in all states in which they operate.

     Amendments  to the Federal  Clean Air Act  enacted in 1990  require or will
require most industrial  operations in the United States to incur future capital
expenditures in order to meet the air emission control  standards that have been
and are to be  developed  and  implemented  by the EPA and  state  environmental
agencies.  Pursuant  to  these  Clean  Air  Act  Amendments,  those  Partnership
facilities that emit volatile organic  compounds  ("VOC") or nitrogen oxides are
subject to  increasingly  stringent  regulations,  including  requirements  that
certain sources install maximum or reasonably  available control technology.  In
addition,  the 1999 Federal  Clean Air Act  Amendments  include a new  operating
permit  for major  sources  ("Title V  Permits"),  which  applies to some of the
Partnership's facilities. Additionally, new dockside loading facilities owned or
operated  by the  Partnership  in the United  States  will be subject to the New
Source  Performance  Standards that were proposed in May 1994. These regulations
require control of VOC emissions from the loading and unloading of tank vessels.

     Although the  Partnership is in substantial  compliance with applicable air
pollution laws, in anticipation  of the  implementation  of stricter air control
regulations,  the Partnership is taking actions to substantially  reduce its air
emissions.

Solid Waste

     The Partnership generates  non-hazardous solid waste that is subject to the
requirements of the Federal Resource  Conservation and Recovery Act ("RCRA") and
comparable  state  statutes in the United  States.  The EPA is  considering  the
adoption of stricter  disposal  standards for  non-hazardous  wastes.  RCRA also
governs the disposal of hazardous  wastes.  At present,  the  Partnership is not
required to comply with a substantial  portion of the RCRA requirements  because
the Partnership's  operations  generate minimal  quantities of hazardous wastes.
However,  it is anticipated that additional  wastes,  which could include wastes
currently generated during pipeline operations, will in the future be designated
as "hazardous wastes".  Hazardous wastes are subject to more rigorous and costly
disposal  requirements  than  are  non-hazardous  wastes.  Such  changes  in the
regulations may result in additional capital  expenditures or operating expenses
by the Partnership.

     At the terminal sites at which groundwater  contamination is present, there
is also limited soil contamination as a result of the aforementioned spills. The
Partnership is under no present requirements to remove these contaminated soils,
but the Partnership may be required to do so in the future.  Soil  contamination
also may be present at other Partnership  facilities at which spills or releases
have occurred.  Under certain circumstances,  the Partnership may be required to
clean  up such  contaminated  soils.  Although  these  costs  should  not have a
material  adverse effect on the  Partnership,  no assurance can be given in this
regard.

Superfund

     The Comprehensive  Environmental  Response,  Compensation and Liability Act
("CERCLA" or  "Superfund")  imposes  liability,  without  regard to fault or the
legality of the original act, on certain classes of persons that  contributed to
the release of a  "hazardous  substance"  into the  environment.  These  persons
include  the  owner or  operator  of the site and  companies  that  disposed  or
arranged for the disposal of the hazardous  substances found at the site. CERCLA
also authorizes the EPA and, in some instances, third parties to act in response
to threats to the public health or the  environment  and to seek to recover from
the  responsible  classes of persons the costs they incur.  In the course of its
ordinary  operations,  the  Partnership  may generate waste that may fall within
CERCLA's  definition  of  a  "hazardous  substance".   The  Partnership  may  be
responsible under CERCLA for all or part of the costs required to clean up sites
at which such wastes have been disposed.

Environmental Impact Statement

     The United States  National  Environmental  Policy Act of 1969 (the "NEPA")
applies to certain extensions or additions to a pipeline system.  Under NEPA, if
any  project  that would  significantly  affect the  quality of the  environment
requires a permit or approval from any United States federal agency,  a detailed
environmental  impact statement must be prepared.  The effect of the NEPA may be
to delay or prevent  construction  of new facilities or to alter their location,
design or method of construction.

Indemnification

     KPL has agreed to indemnify the Partnership  against liabilities for damage
to the  environment  resulting  from  operations of the East  Pipeline  prior to
October 3, 1989. Such  indemnification  does not extend to any liabilities  that
arise  after such date to the extent  such  liabilities  result  from  change in
environmental laws or regulations. Under such indemnity, KPL is presently liable
for the  remediation  of  contamination  at  certain  East  Pipeline  sites.  In
addition,  the  Partnership  was wholly or partially  indemnified  under certain
acquisition  contracts  for some  environmental  costs.  Most of such  contracts
contain  time and amount  limitations  on the  indemnities.  To the extent  that
environmental  liabilities exceed the amount of such indemnity,  the Partnership
has affirmatively assumed the excess environmental liabilities.


SAFETY REGULATION

     The Partnership's  pipelines are subject to regulation by the United States
Department of  Transportation  (the "DOT") under the Hazardous  Liquid  Pipeline
Safety Act of 1979  ("HLPSA")  relating  to the design,  installation,  testing,
construction,   operation,   replacement   and   management  of  their  pipeline
facilities. The HLPSA covers anhydrous ammonia, petroleum and petroleum products
pipelines and requires any entity that owns or operates  pipeline  facilities to
comply  with such  safety  regulations  and to permit  access to and  copying of
records and to make certain  reports and provide  information as required by the
Secretary to Transportation. The Federal Pipeline Safety Act of 1992 amended the
HLPSA to include  requirements of the future use of internal inspection devices.
The  Partnership  does  not  believe  that  it  will be  required  to  make  any
substantial capital  expenditures to comply with the requirements of HLPSA as so
amended.

     On November 3, 2000, the DOT issued new regulations  intended by the DOT to
assess the integrity of hazardous liquid pipeline segments that, in the event of
a leak  or  failure,  could  adversely  affect  highly  populated  areas,  areas
unusually   sensitive  to  environmental   impact  and  commercially   navigable
waterways.  Under the regulations,  an operator is required, among other things,
to conduct baseline  integrity  assessment tests (such as internal  inspections)
within seven  years,  conduct  future  integrity  tests at  typically  five-year
intervals  and  develop  and follow a written  risk-based  integrity  management
program covering the designated high consequence areas. The Partnership does not
believe that the  increased  costs of  compliance  with these  regulations  will
materially affect the Partnership's results of operations.

     The Partnership is subject to the requirements of the United States Federal
Occupational  Safety and Health Act ("OSHA") and comparable  state statutes that
regulate the  protection of the health and safety of workers.  In addition,  the
OSHA  hazard  communication   standard  requires  that  certain  information  be
collected  regarding hazardous materials used or produced in operations and that
this  information  be provided to  employees,  state and local  authorities  and
citizens.  The Partnership  believes that it is in general  compliance with OSHA
requirements,  including general industry standards, record keeping requirements
and monitoring of occupational exposure to benzene.

     The OSHA hazard  communication  standard,  the EPA community  right-to-know
regulations   under  Title  III  of  the   Federal   Superfund   Amendment   and
Reauthorization  Act, and comparable  state statutes  require the Partnership to
organize  information  about the  hazardous  materials  used in its  operations.
Certain parts of this information must be reported to employees, state and local
governmental  authorities,  and local  citizens  upon request.  In general,  the
Partnership  expects to  increase  its  expenditures  during the next  decade to
comply with more  stringent  industry and  regulatory  safety  standards such as
those described above. Such expenditures cannot be accurately  estimated at this
time,  although they are not expected to have a material  adverse  impact on the
Partnership.


EMPLOYEES

     The  Partnership  has no  employees.  The  business of the  Partnership  is
conducted by the general  partner,  KPL,  and its  affiliate,  Kaneb LLC,  which
employs all persons necessary for the operation of the  Partnership's  business.
At December 31, 2004,  approximately 1,114 persons were employed.  Approximately
154 of the persons at seven  terminal  locations in the United States and Canada
were subject to  representation  by labor unions and  collective  bargaining  or
similar contracts at that date. KPL and Kaneb LLC consider  relations with their
employees to be good.


AVAILABLE INFORMATION

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

     The  Partnership  also makes  available  free of charge on or  through  the
Partnership's  Internet site  (http://www.kaneb.com)  the  Partnership's  Annual
Report on Form 10-K,  Quarterly  Reports on Form 10-Q,  Current  Reports on Form
8-K, and other  information  statements and, if applicable,  amendments to those
reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon
as  reasonably   practicable   after  the  reports  and  other   information  is
electronically filed with, or furnished to, the SEC.


Item 2.     Properties

     The properties  owned or utilized by the Partnership  and its  subsidiaries
are  generally  described  in  Item 1 of  this  Report.  Additional  information
concerning the obligations of the Partnership and its subsidiaries for lease and
rental   commitments   is   presented   under  the  caption   "Commitments   and
Contingencies" in Note 6 to the Partnership's consolidated financial statements.
Such descriptions and information are hereby incorporated by reference into this
Item 2.

     The properties  used in the operations of the  Partnership's  pipelines are
owned by the  Partnership,  through its  subsidiary  entities,  except for KPL's
operational  headquarters,  located in  Wichita,  Kansas,  which is held under a
lease that expires in 2009. Statia's  facilities are owned through  subsidiaries
and the majority of ST's  facilities are owned,  while the remainder,  including
some of its  terminal  facilities  located  in port  areas  and its  operational
headquarters,   located  in  Richardson,  Texas,  are  held  pursuant  to  lease
agreements having various expiration dates, rental rates and other terms.


Item 3.     Legal Proceedings

     Grace  Litigation.  Certain  subsidiaries of the Partnership were sued in a
Texas state court in 1997 by Grace Energy Corporation ("Grace"), the entity from
which the  Partnership  acquired  ST  Services  in 1993.  The  lawsuit  involves
environmental  response and remediation costs allegedly  resulting from jet fuel
leaks in the early  1970's  from a pipeline.  The  pipeline,  which  connected a
former  Grace  terminal  with Otis Air Force  Base in  Massachusetts  (the "Otis
pipeline" or the "pipeline"), ceased operations in 1973 and was abandoned before
1978,  when the  connecting  terminal  was sold to an  unrelated  entity.  Grace
alleged that subsidiaries of the Partnership  acquired the abandoned pipeline as
part of the  acquisition of ST Services in 1993 and assumed  responsibility  for
environmental  damages  allegedly  caused by the jet fuel leaks.  Grace sought a
ruling  from the Texas court that these  subsidiaries  are  responsible  for all
liabilities,  including all present and future remediation expenses,  associated
with  these  leaks  and  that  Grace  has  no  obligation  to  indemnify   these
subsidiaries   for  these   expenses.   In  the   lawsuit,   Grace  also  sought
indemnification  for expenses of approximately $3.5 million that it had incurred
since 1996 for response and remediation  required by the State of  Massachusetts
and for  additional  expenses  that it  expects  to  incur  in the  future.  The
consistent position of the Partnership's subsidiaries has been that they did not
acquire the abandoned pipeline as part of the 1993 ST Services transaction,  and
therefore did not assume any responsibility for the environmental damage nor any
liability to Grace for the pipeline.

     At the end of the trial,  the jury  returned a verdict  including  findings
that (1) Grace had  breached a provision  of the 1993  acquisition  agreement by
failing to disclose  matters  related to the pipeline,  and (2) the pipeline was
abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired
ST Services.  On August 30, 2000,  the Judge entered final  judgment in the case
that Grace take nothing from the  subsidiaries on its claims seeking recovery of
remediation costs. Although the Partnership's subsidiaries have not incurred any
expenses in connection  with the  remediation,  the court also ruled, in effect,
that the subsidiaries would not be entitled to indemnification from Grace if any
such expenses were incurred in the future. Moreover, the Judge let stand a prior
summary  judgment  ruling  that  the  pipeline  was  an  asset  acquired  by the
Partnership's  subsidiaries as part of the 1993 ST Services transaction and that
any liabilities  associated  with the pipeline would have become  liabilities of
the  subsidiaries.  Based  on  that  ruling,  the  Massachusetts  Department  of
Environmental  Protection and Samson  Hydrocarbons  Company  (successor to Grace
Petroleum  Company) wrote letters to ST Services alleging its responsibility for
the remediation,  and ST Services  responded denying any liability in connection
with this  matter.  The Judge also awarded  attorney  fees to Grace of more than
$1.5 million.  Both the  Partnership's  subsidiaries and Grace have appealed the
trial  court's  final  judgment  to the Texas  Court of Appeals  in  Dallas.  In
particular,  the subsidiaries  have filed an appeal of the judgment finding that
the  Otis  pipeline  and any  liabilities  associated  with  the  pipeline  were
transferred to them as well as the award of attorney fees to Grace.

     On April 2, 2001,  Grace filed a petition in  bankruptcy,  which created an
automatic stay of actions  against Grace.  This automatic stay covers the appeal
of the Dallas  litigation,  and the Texas  Court of Appeals  has issued an order
staying all proceedings of the appeal because of the bankruptcy.  Once that stay
is lifted,  the Partnership's  subsidiaries that are party to the lawsuit intend
to resume vigorous prosecution of the appeal.

     The Otis Air Force Base is a part of the Massachusetts Military Reservation
("MMR Site"),  which has been declared a Superfund Site pursuant to CERCLA.  The
MMR Site contains a number of groundwater contamination plumes, two of which are
allegedly associated with the Otis pipeline,  and various other waste management
areas of concern,  such as landfills.  The United States  Department of Defense,
pursuant  to  a  Federal  Facilities  Agreement,  has  been  responding  to  the
Government  remediation demand for most of the contamination problems at the MMR
Site. Grace and others have also received and responded to formal inquiries from
the United  States  Government  in  connection  with the  environmental  damages
allegedly  resulting  from the jet fuel leaks.  The  Partnership's  subsidiaries
voluntarily   responded  to  an  invitation   from  the  Government  to  provide
information  indicating that they do not own the pipeline.  In connection with a
court-ordered  mediation between Grace and the Partnership's  subsidiaries,  the
Government  advised the parties in April 1999 that it has  identified  two spill
areas that it believes to be related to the pipeline  that is the subject of the
Grace suit.  The Government at that time advised the parties that it believed it
had incurred costs of approximately  $34 million,  and expected in the future to
incur costs of  approximately  $55 million,  for remediation of one of the spill
areas.  This  amount was not  intended to be a final  accounting  of costs or to
include all categories of costs. The Government also advised the parties that it
could not at that time allocate its costs attributable to the second spill area.

     By letter  dated July 26, 2001,  the United  States  Department  of Justice
("DOJ")  advised ST Services that the Government  intends to seek  reimbursement
from ST Services  under the  Massachusetts  Oil and Hazardous  Material  Release
Prevention  and  Response  Act  and  the   Declaratory   Judgment  Act  for  the
Government's  response  costs at the two spill areas  discussed  above.  The DOJ
relied in part on the Texas state court judgment,  which in the DOJ's view, held
that  ST   Services   was  the   current   owner   of  the   pipeline   and  the
successor-in-interest of the prior owner and operator. The Government advised ST
Services  that it believes it has incurred  costs  exceeding  $40  million,  and
expects  to  incur  future  costs  exceeding  an  additional  $22  million,  for
remediation  of  the  two  spill  areas.  The  Partnership   believes  that  its
subsidiaries  have  substantial  defenses.  ST Services  responded to the DOJ on
September  6, 2001,  contesting  the  Government's  positions  and  declining to
reimburse  any  response  costs.  The DOJ has not  filed a  lawsuit  against  ST
Services seeking cost recovery for its environmental  investigation and response
costs.  Representatives  of ST  Services  have met with  representatives  of the
Government  on  several  occasions  since  September  6,  2001  to  discuss  the
Government's  claims  and  to  exchange  information  related  to  such  claims.
Additional  exchanges  of  information  are  expected to occur in the future and
additional   meetings  may  be  held  to  discuss  possible  resolution  of  the
Government's  claims without  litigation.  The Partnership does not believe this
matter  will  have a  materially  adverse  effect  on its  financial  condition,
although there can be no assurances as to the ultimate outcome.

     PEPCO  Litigation.  On April 7, 2000, a fuel oil pipeline in Maryland owned
by Potomac Electric Power Company ("PEPCO") ruptured. Work performed with regard
to the pipeline was conducted by a  partnership  of which ST Services is general
partner.  PEPCO has reported  that it has incurred  total  cleanup  costs of $70
million to $75  million.  PEPCO  probably  will  continue to incur some  cleanup
related  costs for the  foreseeable  future,  primarily in  connection  with EPA
requirements  for monitoring the condition of some of the impacted areas.  Since
May 2000,  ST Services has  provisionally  contributed  a minority  share of the
cleanup expense,  which has been funded by ST Services' insurance  carriers.  ST
Services and PEPCO have not,  however,  reached a final  agreement  regarding ST
Services'  proportionate  responsibility  for this cleanup  effort,  if any, and
cannot  predict the amount,  if any, that  ultimately may be determined to be ST
Services' share of the remediation  expense,  but ST Services believes that such
amount will be covered by insurance and therefore will not materially  adversely
affect the Partnership's financial condition.

     As a result of the rupture,  purported  class  actions  were filed  against
PEPCO and ST Services  in federal  and state  court in Maryland by property  and
business owners alleging damages in unspecified  amounts under various theories,
including  under the Oil  Pollution  Act ("OPA") and  Maryland  common law.  The
federal  court  consolidated  all of the federal cases in a case styled as In re
Swanson  Creek Oil Spill  Litigation.  A settlement  of the  consolidated  class
action,  and a companion  state-court class action,  was reached and approved by
the federal judge. The settlement  involved creation and funding by PEPCO and ST
Services of a $2,250,000  class  settlement  fund, from which all  participating
claimants  would be paid  according to a  court-approved  formula,  as well as a
court-approved  payment  to  plaintiffs'  attorneys.  The  settlement  has  been
consummated  and the fund,  to which  PEPCO and ST  Services  contributed  equal
amounts, has been distributed. Participating claimants' claims have been settled
and  dismissed  with  prejudice.  A  number  of  class  members  elected  not to
participate  in the  settlement,  i.e., to "opt out," thereby  preserving  their
claims  against  PEPCO and ST  Services.  All  non-participant  claims have been
settled for  immaterial  amounts with ST Services'  portion of such  settlements
provided by its insurance carrier.

     PEPCO and ST Services  agreed with the federal  government and the State of
Maryland to pay costs of assessing  natural  resource  damages  arising from the
Swanson Creek oil spill under OPA and of selecting  restoration  projects.  This
process was  completed in mid-2002.  ST Services'  insurer has paid ST Services'
agreed 50 percent share of these assessment  costs. In late November 2002, PEPCO
and ST Services  entered into a Consent  Decree  resolving the federal and state
trustees' claims for natural resource  damages.  The decree required payments by
ST  Services  and  PEPCO  of a total of  approximately  $3  million  to fund the
restoration  projects and for remaining  damage  assessment  costs.  The federal
court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO
and ST Services  have each paid their 50% share and thus fully  performed  their
payment  obligations  under the Consent Decree.  ST Services'  insurance carrier
funded ST Services' payment.

     The U.S.  Department  of  Transportation  ("DOT")  has  issued a Notice  of
Proposed  Violation to PEPCO and ST Services  alleging  violations  over several
years of pipeline  safety  regulations and proposing a civil penalty of $647,000
jointly against the two companies.  ST Services and PEPCO have contested the DOT
allegations  and the proposed  penalty.  A hearing was held before the Office of
Pipeline Safety at the DOT in late 2001. In June of 2004, the DOT issued a final
order reducing the penalty to $256,250 jointly against ST Services and PEPCO and
$74,000 against ST Services.  On September 14, 2004, ST Services  petitioned for
reconsideration of the order.

     By letter  dated  January 4, 2002,  the Attorney  General's  Office for the
State of Maryland advised ST Services that it intended to seek penalties from ST
Services  in  connection  with the April 7, 2000  spill.  The State of  Maryland
subsequently asserted that it would seek penalties against ST Services and PEPCO
totaling up to $12 million.  A settlement  of this claim was reached in mid-2002
under  which ST  Services'  insurer  will pay a total of  slightly  more than $1
million  in  installments  over a five year  period.  PEPCO  has also  reached a
settlement  of  these  claims  with  the  State of  Maryland.  Accordingly,  the
Partnership believes that this matter will not have a material adverse effect on
its financial condition.

     On  December  13,  2002,  ST  Services  sued PEPCO in the  Superior  Court,
District of Columbia,  seeking, among other things, a declaratory judgment as to
ST Services' legal obligations,  if any, to reimburse PEPCO for costs of the oil
spill.  On  December  16,  2002,  PEPCO sued ST  Services  in the United  States
District Court for the District of Maryland,  seeking  recovery of all its costs
for  remediation  of and  response to the oil spill.  Pursuant  to an  agreement
between ST Services  and PEPCO,  ST  Services'  suit was  dismissed,  subject to
refiling.  ST  Services  has moved to  dismiss  PEPCO's  suit.  ST  Services  is
vigorously   defending   against   PEPCO's   claims  and  is  pursuing  its  own
counterclaims  for  return of  monies  ST  Services  has  advanced  to PEPCO for
settlements  and  cleanup  costs.  The  Partnership  believes  that any costs or
damages resulting from these lawsuits will be covered by insurance and therefore
will not materially adversely affect the Partnership's financial condition.  The
amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy
which has a $600,000  retention,  but the Partnership does not believe that such
retention,  if incurred,  would materially  adversely  affect the  Partnership's
financial condition.

     Paulsboro Litigation.  In 2003, Exxon Mobil filed a lawsuit in a New Jersey
state court against GATX  Corporation,  Kinder Morgan Liquid Terminals  ("Kinder
Morgan"),  the successor in interest to GATX Terminals Corporation ("GATX"), and
a  subsidiary  of  the  Partnership,  ST  Services,  seeking  reimbursement  for
remediation  costs  associated  with the  Paulsboro,  New Jersey  terminal.  The
terminal  was owned and operated by Exxon Mobil from the early 1950's until 1990
when  purchased by GATX.  ST Services  purchased the terminal in 2000 from GATX.
GATX was subsequently  acquired by Kinder Morgan.  As a condition to the sale to
GATX in 1990, Exxon Mobil undertook certain remediation obligations with respect
to the site.  In the lawsuit,  Exxon Mobil is claiming that it has complied with
its  remediation and  contractual  obligations and is entitled to  reimbursement
from GATX  Corporation,  the  parent  company  of GATX,  Kinder  Morgan,  and ST
Services  for costs in the  amount of  $400,000  that it claims  are  related to
releases at the site  subsequent to its sale of the terminal to GATX. It is also
alleging that any remaining  remediation  requirements are the responsibility of
GATX Corporation,  Kinder Morgan, or ST Services. Kinder Morgan has alleged that
it was relieved of any  remediation  obligations  pursuant to the sale agreement
between its  predecessor,  GATX,  and ST Services.  ST Services  believes  that,
except for remediation  involving immaterial amounts,  GATX Corporation or Exxon
Mobil are  responsible  for the  remaining  remediation  of the  site.  Costs of
completing the required  remediation depend on a number of factors and cannot be
determined at the current time.

     Ammonia  Pipeline  Matters.  A subsidiary of the Partnership  purchased the
approximately  2,000-mile  ammonia  pipeline system from Koch Pipeline  Company,
L.P. and Koch Fertilizer  Storage and Terminal Company in 2002. The rates of the
ammonia pipeline are subject to regulation by the Surface  Transportation  Board
(the  "STB").  The STB had  issued  an order in May  2000,  prescribing  maximum
allowable rates the Partnership's predecessor could charge for transportation to
certain  destination  points on the pipeline  system.  In 2003, the  Partnership
instituted  a 7% general  increase  to  pipeline  rates.  On August 1, 2003,  CF
Industries,  Inc. ("CFI") filed a complaint with the STB challenging  these rate
increases. On August 11, 2004, STB ordered the Partnership to pay reparations to
CFI  and  to  return  CFI's  rates  to  the  levels  permitted  under  the  rate
prescription.  The  Partnership has complied with the order.  The STB,  however,
indicated in the order that it would lift the rate prescription in the event the
Partnership could show "materially  changed  circumstances." The Partnership has
submitted  evidence of "materially  changed  circumstances,"  which specifically
includes  its  capital  investment  in the  pipeline.  CFI has  argued  that the
Partnership's acquisition costs should not be considered by the STB as a measure
of the  Partnership's  investment  base. The STB is expected to decide the issue
within the second quarter of 2005.

     Also, on June 16, 2003, Dyno Nobel Inc. ("Dyno") filed a complaint with the
STB  challenging  the 2003 rate increase on the basis that (i) the rate increase
constitutes a violation of a contract rate,  (ii) rates are  discriminatory  and
(iii)  the rates  exceed  permitted  levels.  Dyno  also  intervened  in the CFI
proceeding  described above.  Unlike CFI, Dyno's rates are not subject to a rate
prescription.  As of December 31, 2004, Dyno would be entitled to  approximately
$2 million in rate refunds,  should it be successful.  The Partnership believes,
however, that Dyno's claims are without merit.

     The Partnership has other contingent liabilities resulting from litigation,
claims and commitments  incident to the ordinary course of business.  Management
of the Partnership  believes,  after consulting with counsel,  that the ultimate
resolution of such  contingencies  will not have a materially  adverse effect on
the financial position, results of operations or liquidity of the Partnership.


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

     None.




<PAGE>
                                     PART II

Item 5. Market for the Registrant's  Partnership  Interests and Related Partners
        Matters

     KPP owns a 99% interest as sole  limited  partner and KPL owns a 1% general
partner  interest in the  Partnership.  There is no  established  public trading
market for the Partnership ownership interests.

     The Partnership  makes regular cash  distributions,  in accordance with its
partnership  agreement,  within 45 days after the end of each quarter to limited
partner and general partner interests.

     The  Partnership  is a limited  partnership  that is not subject to federal
income tax.  Instead,  the partners are required to report their allocable share
of the  Partnership  income,  gain,  loss,  deduction and credit,  regardless of
whether the Partnership makes distributions.

<PAGE>
Item 6. Summary Historical Financial and Operating Data

     The following table sets forth, for the periods and at the dates indicated,
selected  historical  financial data for Kaneb Pipe Line Operating  Partnership,
L.P.  and its  subsidiaries  (the  "Partnership").  The  data in the  table  (in
thousands)  is  derived  from  the  historical   financial   statements  of  the
Partnership  and should be read in conjunction  with the  Partnership's  audited
financial  statements.   See  also  "Management's  Discussion  and  Analysis  of
Financial Condition and Results of Operations."

<TABLE>
<CAPTION>
                                                              Year Ended December 31,
                                        --------------------------------------------------------------------
                                           2004           2003        2002 (a)      2001 (a)         2000
                                        -----------   -----------    -----------   -----------   -----------
<S>                                     <C>           <C>            <C>           <C>           <C>
Income Statement Data:
Revenues:
    Services..........................  $   379,155   $   354,591    $   288,669   $   207,796   $   156,232
    Products..........................      269,054       215,823         97,961          -              -
                                        -----------   -----------    -----------   -----------   -----------
                                            648,209       570,414        386,630       207,796       156,232
                                        -----------   -----------    -----------   -----------   -----------
Costs and expenses:
    Cost of products sold.............      246,858       195,100         90,898          -              -
    Operating costs...................      176,976       168,537        131,326        90,632        69,653
    Depreciation and amortization.....       56,648        53,155         39,425        23,184        16,253
    Gain on sale of assets............          -             -             (609)         -           (1,126)
    General and administrative........       30,937        25,121         19,869        11,889        11,881
                                        -----------   -----------    -----------   -----------   -----------
                                            511,419       441,913        280,909       125,705        96,661
                                        -----------   -----------    -----------   -----------   -----------

Operating income......................      136,790       128,501        105,721        82,091        59,571

Interest and other income.............          267           261          3,570         4,277           316
Interest expense......................      (42,750)      (38,757)       (28,110)      (14,783)      (12,283)
Loss on debt extinguishment...........          -             -           (3,282)       (6,540)          -
Income tax expense....................       (3,282)       (5,223)        (4,083)         (256)         (943)
                                        -----------   -----------    -----------   -----------   -----------

Income before cumulative effect of
    change in accounting principle....       91,025        84,782         73,816        64,789        46,661

Cumulative effect of change in
    accounting principle - adoption of
    new accounting standard for
    asset retirement obligations......          -          (1,593)          -               -             -
                                        -----------   -----------    -----------   -----------   -----------
Net income ...........................  $    91,025   $    83,189    $    73,816   $    64,789   $    46,661
                                        ===========   ===========    ===========   ===========   ===========

Cash distributions declared...........  $   107,214   $   102,948    $    79,816   $    62,156   $    53,485
                                        ===========   ===========    ===========   ===========   ===========


Balance Sheet Data (at year end):
Property and equipment, net...........  $ 1,148,591   $ 1,112,970    $ 1,092,192   $   481,274   $   321,355
Total assets..........................    1,325,316     1,264,682      1,215,410       548,371       375,063
Long-term debt........................      671,952       617,696        694,330       262,624       166,900
Partners' capital.....................      481,481       493,589        393,314       220,527       161,735

</TABLE>

(a)  See Note 3 to Consolidated Financial Statements regarding acquisitions.



<PAGE>
Item 7. Management's  Discussion and Analysis of Financial Condition and Results
        of Operations

     This  discussion  should  be  read in  conjunction  with  the  consolidated
financial  statements  of Kaneb  Pipe  Line  Operating  Partnership,  L.P.  (the
"Partnership")  and notes  thereto  and the  summary  historical  financial  and
operating data included elsewhere in this report.


OVERVIEW

     The Partnership, a limited partnership, is engaged in the refined petroleum
products  and  anhydrous  ammonia  pipeline  business  and  the  terminaling  of
petroleum  products  and  specialty  liquids.  Kaneb  Pipe Line  Partners,  L.P.
("KPP"), a master limited  partnership,  holds a 99% interest as limited partner
in the  Partnership.  Kaneb Pipe Line  Company LLC  ("KPL"),  now a wholly owned
subsidiary of Kaneb Services LLC ("KSL"), manages and controls the operations of
KPP through its general  partner  interest  and an 18% (at  December  31,  2004)
limited  partner  interest.  KPL owns a 1%  interest  as general  partner of the
Partnership and a 1% interest as general partner of KPP.

     On  October  31,  2004,  Valero  L.P.  and KPP  entered  into a  definitive
agreement to merge (the "KPP  Merger")  Valero L.P. and KPP.  Under the terms of
the agreement, each holder of units of limited partnership interests in KPP will
receive a number of Valero L.P.  common  units  based on an exchange  ratio that
fluctuates  within a fixed range to provide $61.50 in value of Valero L.P. units
for each unit of KPP. The actual  exchange  ratio will be determined at the time
of the closing of the proposed  merger and is subject to a fixed value collar of
plus or minus  five  percent  of Valero  L.P.'s  per unit  price of $57.25 as of
October 7, 2004. Should Valero L.P.'s per unit price fall below $54.39 per unit,
the exchange  ratio will remain fixed at 1.1307 Valero L.P.  units for each unit
of KPP. Likewise,  should Valero L.P.'s per unit price exceed $60.11 per unit of
KPP, the exchange  ratio will remain fixed at 1.0231 Valero L.P.  units for each
unit of KPP.

     In a separate definitive agreement, on October 31, 2004, Valero L.P. agreed
to acquire by merger (the "KSL Merger") all of the outstanding  common shares of
KSL for cash.  Under the terms of that  agreement,  Valero  L.P.  is offering to
purchase all of the outstanding shares of KSL at $43.31 per share.

     The  completion  of the KPP Merger is subject to the  customary  regulatory
approvals  including those under the  Hart-Scott-Rodino  Antitrust  Improvements
Act. The  completion  of the KPP Merger is also subject to completion of the KSL
Merger.  All required  unitholder and shareholder  approvals have been obtained.
Upon completion of the mergers,  the general partner of the combined partnership
will be owned by affiliates of Valero  Energy  Corporation  and KPP and KSL will
become wholly owned subsidiaries of Valero L.P.

     The Partnership's  petroleum  pipeline  business consists  primarily of the
transportation,  as a common carrier,  of refined petroleum  products in Kansas,
Nebraska,  Iowa, South Dakota,  North Dakota,  Colorado,  Wyoming and Minnesota.
Common  carrier  activities  are those  under which  transportation  through the
pipelines is available at published  tariffs  filed,  in the case of  interstate
shipments with the Federal Energy Regulatory  Commission (the "FERC"), or in the
case of intrastate shipments,  with the relevant state authority, to any shipper
of refined  petroleum  products who requests  such  services and  satisfies  the
conditions  and  specifications  for  transportation.  The  petroleum  pipelines
primarily  transport gasoline,  diesel oil, fuel oil and propane.  Substantially
all of the petroleum  pipeline  operations  constitute common carrier operations
that are subject to federal or state tariff  regulations.  The Partnership  also
owns an approximately 2,000-mile anhydrous ammonia pipeline system acquired from
Koch  Pipeline  Company,  L.P. in November of 2002 (see  "Liquidity  and Capital
Resources"). The fertilizer pipeline originates in southern Louisiana,  proceeds
north through  Arkansas and  Missouri,  and then branches east into Illinois and
Indiana and north and west into Iowa and Nebraska.  The Partnership's  petroleum
pipeline business depends on the level of demand for refined petroleum  products
in the  markets  served by the  pipelines  and the ability  and  willingness  of
refineries and marketers having access to the pipelines to supply such demand by
deliveries through the pipelines.  The Partnership's pipeline revenues are based
on volumes shipped and the distance over which such volumes are transported.

     The Partnership's  terminaling  business is one of the largest  independent
petroleum  products and specialty  liquids  terminaling  companies in the United
States.  In the United States,  ST Services operates 41 facilities in 20 states.
ST Services also owns and operates seven terminals located in the United Kingdom
and  eight  terminals  in  Australia  and  New  Zealand.  ST  Services  and  its
predecessors  have a long history in the terminaling  business and handle a wide
variety of liquids  from  petroleum  products to  specialty  chemicals to edible
liquids.  Statia,  acquired on February  28,  2002 (see  "Liquidity  and Capital
Resources"),  owns a  terminal  on the  Island  of  St.  Eustatius,  Netherlands
Antilles  and a terminal  at Point  Tupper,  Nova  Scotia,  Canada.  Independent
terminal owners  generally  compete on the basis of the location and versatility
of the terminals,  service and price.  Terminal versatility is a function of the
operator's  ability to offer handling for diverse products with complex handling
requirements.  The service function  typically provided by the terminal includes
the safe storage of product at specified  temperatures and other conditions,  as
well as receipt and delivery from the terminal. The ability to obtain attractive
pricing is dependent  largely on the quality,  versatility and reputation of the
facility.  Terminaling  revenues  are earned  based on fees for the  storage and
handling of products.

     The Partnership's  product sales business delivers bunker fuels to ships in
the  Caribbean and Nova Scotia,  Canada,  and sells bulk  petroleum  products to
various commercial customers at those locations.  In the bunkering business, the
Partnership  competes  with ports  offering  bunker fuels along the route of the
vessel.  Vessel  owners or  charterers  are charged  berthing and other fees for
associated  services such as pilotage,  tug  assistance,  line handling,  launch
service and emergency response services.


CONSOLIDATED RESULTS OF OPERATIONS
<TABLE>
<CAPTION>

                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2004                2003                 2002
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   648,209        $   570,414          $   386,630
                                                          ===========        ===========          ===========
Operating income.....................................     $   136,790        $   128,501          $   105,721
                                                          ===========        ===========          ===========
Income before cumulative effect of change in
    accounting principle.............................     $    91,025        $    84,782          $    73,816

Cumulative effect of change in accounting principle..           -                (1,593)                 -
                                                          -----------        ----------           -----------
Net income...........................................     $    91,025        $    83,189          $    73,816
                                                          ===========        ===========          ===========
Capital expenditures, excluding acquisitions.........     $    42,214        $    44,741          $    31,101
                                                          ===========        ===========          ===========
</TABLE>

     For the year ended December 31, 2004,  revenues increased by $77.8 million,
or 14%,  when compared to 2003,  due to a $53.2 million  increase in revenues in
the product sales  business  (see "Product  Sales  Operations"  below),  a $24.4
million  increase in  revenues in the  terminaling  business  (see  "Terminaling
Operations"  below)  and a $0.2  million  increase  in  pipeline  revenues  (see
"Pipeline  Operations" below).  Operating income for the year ended December 31,
2004  increased by $8.3 million,  or 6%, when  compared to 2003,  due to an $8.1
million increase in terminaling  operating income and a $3.2 million increase in
product sales operating  income,  partially offset by a $3.0 million decrease in
pipeline operating income.  2004 operating income is after $2.2 million of costs
associated  with the  Valero  L.P.  merger  agreement  and  compliance  with the
Sarbanes-Oxley  Act of 2002.  Income  before  cumulative  effect  of  change  in
accounting  principle  increased by $6.2 million,  or 7%, when compared to 2003.
Overall,  2004 net income  increased by $7.8  million,  or 9%, when  compared to
2003,  which  included a change of $1.6  million  for the  cumulative  effect of
change in accounting  principle - adoption of new accounting  standard for asset
retirement obligations.

     For the year ended December 31, 2003, revenues increased by $183.8 million,
or 48%,  when compared to 2002,  due to a $36.9 million  increase in revenues in
the pipeline  business,  a $29.0 million increase in revenues in the terminaling
business and a $117.9 million increase in product sales revenues. See "Liquidity
and Capital  Resources"  regarding 2002  acquisitions.  Operating income for the
year ended December 31, 2003  increased by $22.8 million,  or 22%, when compared
to 2002, due to a $13.2 million  increase in pipeline  operating  income, a $1.5
million increase in terminaling operating income and an $8.1 million increase in
product sales operating  income.  Income before  cumulative  effect of change in
accounting  principle increased by $11.0 million, or 15%, when compared to 2002.
Overall, 2003 net income,  including a charge of $1.6 million for the cumulative
effect of change in accounting  principle - adoption of new accounting  standard
for asset  retirement  obligations,  increased  by $9.4  million,  or 13%,  when
compared to 2002.


<PAGE>
PIPELINE OPERATIONS

<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2004                 2003                2002
                                                          -----------        -----------          -----------
                                                                             (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   119,803        $   119,633          $    82,698
Operating costs......................................          48,306             46,379               33,744
Depreciation and amortization........................          14,538             14,117                6,408
General and administrative...........................           8,106              7,277                3,923
                                                          -----------        -----------          -----------
Operating income.....................................     $    48,853        $    51,860          $    38,623
                                                          ===========        ===========          ===========
</TABLE>


     The  Partnership's  pipeline  revenues are based on volumes shipped and the
distances  over which such  volumes are  transported.  Because  tariff rates are
regulated by the FERC or STB, the  pipelines  compete on the basis of quality of
service, including delivering products at convenient locations on a timely basis
to meet the  needs of its  customers.  For the year  ended  December  31,  2004,
revenues  increased by $0.2 million,  when compared to 2003, due to increases in
barrel miles of products shipped on petroleum pipelines, substantially offset by
lower prices received for products  shipped on the anhydrous  ammonia  pipeline.
For the year ended December 31, 2003,  revenues  increased by $36.9 million,  or
45%,  when  compared to 2002,  due entirely to the  November  and December  2002
pipeline  acquisitions (see "Liquidity and Capital Resources").  Barrel miles on
petroleum  pipelines totaled 22.2 billion,  21.3 billion  (including 4.7 billion
for the petroleum  pipeline  acquired in December 2002) and 18.3 billion for the
years ended  December  31,  2004,  2003 and 2002,  respectively.  Total  volumes
shipped on the anhydrous ammonia pipeline aggregated 1,123 thousand tons in 2004
and 1,157 thousand tons in 2003.

     Operating  costs,  which  include  fuel  and  power  costs,  materials  and
supplies,  maintenance and repair costs, salaries,  wages and employee benefits,
and  property  and other  taxes,  increased  by $1.9  million  in 2004 and $12.6
million  in 2003.  The  increase  in 2004,  when  compared  to 2003,  was due to
unusually  high  expenses  relating  to  preventive  and other  maintenance  and
repairs,  including  those required by government  regulation,  and increases in
power and fuel costs.  The increase in 2003,  when compared to 2002,  was due to
the pipeline  acquisitions and increases in expenditures for routine repairs and
maintenance. For the year ended December 31, 2004, depreciation and amortization
increased  by $0.4  million,  when  compared to 2003,  due  primarily to routine
maintenance  capital  expenditures.  For  the  year  ended  December  31,  2003,
depreciation and amortization  increased by $7.7 million, when compared to 2002,
due to the pipeline  acquisitions and routine maintenance capital  expenditures.
General and  administrative  costs,  which includes  managerial,  accounting and
administrative  personnel costs,  office rental expense,  legal and professional
costs and other  non-operating  costs  increased by $0.8  million in 2004,  when
compared to 2003, due primarily to costs  associated with the Valero L.P. merger
agreement,  compliance  with the  Sarbanes-Oxley  Act of 2002 and  increases  in
personnel-related  costs.  General and  administrative  costs for the year ended
December 31, 2003  increased by $3.4 million,  when compared to 2002, due to the
pipeline acquisitions and increases in personnel-related costs.


TERMINALING OPERATIONS
<TABLE>
<CAPTION>

                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2004                 2003                2002
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   259,352        $   234,958          $   205,971
Operating costs......................................         122,791            114,030               94,480
Depreciation and amortization........................          41,232             38,089               32,368
Gain on sale of assets...............................           -                   -                    (609)
General and administrative...........................          20,666             16,307               14,692
                                                          -----------        -----------          -----------
Operating income.....................................     $    74,663        $    66,532          $    65,040
                                                          ===========        ===========          ===========
</TABLE>

     For the  year  ended  December  31,  2004,  the  Partnership's  terminaling
revenues  increased by $24.4  million,  or 10%,  when  compared to 2003,  due to
increases in both tankage  utilization and the average price realized per barrel
of tankage  utilized.  For the year ended December 31, 2003,  the  Partnership's
terminaling  revenues increased by $29.0 million, or 14%, when compared to 2002,
due to the 2002 terminal  acquisitions  (see "Liquidity and Capital  Resources")
and  overall  increases  in the  average  price  realized  per barrel of tankage
utilized. Approximately $25 million of the 2003 revenue increase was a result of
the terminal  acquisitions.  Average annual tankage utilized for the years ended
December 31, 2004, 2003 and 2002 aggregated 48.9 million  barrels,  46.7 million
barrels and 46.5 million barrels,  respectively.  Average revenues per barrel of
tankage utilized for the years ended December 31, 2004, 2003 and 2002 was $5.30,
$5.02 and $4.43, respectively.  The increase in 2004 average revenues per barrel
of tankage  utilized was  primarily  the result of favorable  market  conditions
domestically  and in Australia  and New Zealand and favorable  foreign  currency
exchange  differences.  The  increase  in 2003  average  revenues  per barrel of
tankage  utilized  was the result of changes in product mix  resulting  from the
2002 terminals acquisitions and favorable foreign currency exchange differences.

     For year  ended  December  31,  2004,  operating  costs  increased  by $8.8
million,  when compared to 2003, due to an overall  increase in planned terminal
maintenance.  In 2003, operating costs increased by $19.6 million, when compared
to 2002, due to the 2002 terminal  acquisitions,  repair costs  associated  with
hurricane  Isabel  and  increases  in  planned  maintenance.  For the year ended
December 31, 2004, depreciation and amortization increased by $3.1 million, when
compared to 2003, due to expansion and routine maintenance capital expenditures.
For the year ended December 31, 2003, depreciation and amortization increased by
$5.7 million, when compared to 2002, due to the 2002 terminal  acquisitions.  In
2002, KPP sold land and other  terminaling  business  assets for net proceeds of
approximately $1.1 million,  recognizing a gain on disposition of assets of $0.6
million.  General and administrative expenses increased by $4.4 million in 2004,
when  compared to 2003,  due to increases in  personnel-related  costs and costs
associated  with the  Valero  L.P.  merger  agreement  and  compliance  with the
Sarbanes-Oxley  Act of 2002.  General and  administrative  expenses increased by
$1.6 million in 2003,  when compared to 2002,  due to the terminal  acquisitions
and increases in personnel-related costs.


PRODUCT SALES OPERATIONS
<TABLE>
<CAPTION>

                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2004                 2003                2002
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   269,054        $   215,823          $    97,961
Cost of products sold................................         246,858            195,100               90,898
                                                          -----------        -----------          -----------
Gross margin.........................................     $    22,196        $    20,723          $     7,063
                                                          ===========        ===========          ===========
Operating income.....................................     $    13,274        $    10,109          $     2,058
                                                          ===========        ===========          ===========
</TABLE>

     The product sales business,  which was acquired with Statia (see "Liquidity
and Capital  Resources"),  delivers  bunker fuels to ships in the  Caribbean and
Nova  Scotia,  Canada and sells bulk  petroleum  products to various  commercial
interests.  For the  year  ended  December  31,  2004,  product  sales  revenues
increased by $53.2  million,  or 25%, when  compared to 2003,  due to an overall
increase in volumes sold and a general increase in prices.  Approximately  $44.9
million of the revenue increase was due to volume increases and $8.3 million was
due to price  increases,  when compared to 2003. Gross margin for the year ended
December 31, 2004, increased by $1.5 million,  when compared to 2003, due to the
increase in volumes sold and favorable  variations in prices  resulting from the
timing of purchases and sales. Operating income for 2004 increased $3.2 million,
when compared to 2003, due to higher sales volumes.

     For the year ended December 31, 2003, product sales revenues,  gross margin
and  operating  income  increased  by $117.9  million,  $13.7  million  and $8.1
million,  respectively,  when  compared to 2002,  due to increases in both sales
price and volumes.  Approximately $95.8 million of the 2003 revenue increase was
due to volume  increases  and $22.1  million  was due to price  increases,  when
compared to 2002. The results of operations for the year ended December 31, 2002
include  the  operations  of the  product  sales  business  since  the  date  of
acquisition, February 28, 2002.

     Product  inventories  are maintained at minimum  levels to meet  customers'
needs; however, market prices for petroleum products can fluctuate significantly
in short periods of time.


INTEREST AND OTHER INCOME

     In  September  of  2002,  the  Partnership  entered  into a  treasury  lock
contract,  maturing on  November  4, 2002,  for the purpose of locking in the US
Treasury  interest  rate  component on $150 million of  anticipated  thirty-year
public debt offerings. The treasury lock contract originally qualified as a cash
flow  hedging  instrument  under  Statement of  Financial  Accounting  Standards
("SFAS") No. 133. In October of 2002,  the  Partnership,  due to various  market
factors,  elected to defer issuance of the public debt  securities,  effectively
eliminating the cash flow hedging designation for the treasury lock contract. On
October 29, 2002,  the contract was settled  resulting in a net realized gain of
$3.0 million, which was recognized as a component of interest and other income.


INTEREST EXPENSE

     For the year ended December 31, 2004,  interest  expense  increased by $4.0
million, when compared to 2003, due to the May 2003 refinancing of variable rate
debt with $250 million of 5.875%  senior  unsecured  notes (see  "Liquidity  and
Capital  Resources")  and  overall  increases  in  interest  rates on  remaining
variable rate debt.

     For the year ended December 31, 2003,  interest expense  increased by $10.6
million,  when compared to 2002,  due to increases in fixed rate debt  resulting
from the 2002 pipeline and terminal  acquisitions  (see  "Liquidity  and Capital
Resources"),  partially offset by overall declines in interest rates on variable
rate debt.


INCOME TAXES

     Partnership  operations  are not subject to federal or state income  taxes.
However,  certain operations are conducted through separate taxable wholly-owned
U.S.  and  foreign  corporate  subsidiaries.  The income tax  expense  for these
subsidiaries was $3.3 million, $5.2 million and $4.1 million for the years ended
December 31, 2004, 2003 and 2002, respectively.

     On June 1,  1989,  the  governments  of the  Netherlands  Antilles  and St.
Eustatius  approved a Free Zone and Profit Tax Agreement  retroactive to January
1,  1989,  which  expired  on  December  31,  2000.  This  agreement  required a
subsidiary  of the  Partnership,  which was acquired with Statia on February 28,
2002,  to pay a 2% rate on  taxable  income,  as defined  therein,  or a minimum
payment of 500,000  Netherlands  Antilles  guilders ($0.3 million) per year. The
agreement  further  provided  that any amounts paid in order to meet the minimum
annual  payment  were  available  to offset  future  tax  liabilities  under the
agreement  to the extent that the minimum  annual  payment is greater than 2% of
taxable  income.  The  subsidiary  is  currently  engaged  in  discussions  with
representatives appointed by the Island Territory of St. Eustatius regarding the
renewal or  modification  of the agreement,  but the ultimate  outcome cannot be
predicted  at this time.  The  subsidiary  has  accrued  amounts  assuming a new
agreement becomes effective,  and continues to make payments, as required, under
the previous agreement.


LIQUIDITY AND CAPITAL RESOURCES

     Cash provided by operating  activities was $132.3  million,  $142.0 million
and  $91.8  million  for the  years  ended  December  31,  2004,  2003 and 2002,
respectively.  The decrease in 2004 operating cash flows, when compared to 2003,
was due primarily to changes in working capital and other liabilities  resulting
from the timing of cash receipts and disbursements and costs associated with the
Valero L.P. merger agreement and compliance with the Sarbanes-Oxley Act of 2002,
partially  offset by an overall  increase in net income.  The  increase in 2003,
when compared to 2002, was due to increases in pipeline, terminaling and product
sales   revenues  and  operating   income,   primarily  a  result  of  the  2002
acquisitions,  and changes in working capital components from the timing of cash
receipts and disbursements.

     Capital   expenditures,   including   routine   maintenance  and  expansion
expenditures, but excluding acquisitions,  were $42.2 million, $44.7 million and
$31.1  million  for the years  ended  2004,  2003 and 2002,  respectively.  Such
expenditures  included  $30.8  million  and $20.3  million  in  maintenance  and
environmental  expenditures  and $11.4  million and $24.4  million in  expansion
expenditures for the years ended December 31, 2004 and 2003,  respectively.  The
decrease in 2004 capital  expenditures,  when compared to 2003, is primarily the
result of decreases in planned  expansion  capital  expenditures  related to the
terminaling business.  The increase in 2003 capital expenditures,  when compared
to 2002, is the result of planned maintenance and expansion capital expenditures
related to the pipeline and terminaling  operations acquired in 2002 and planned
maintenance  capital  expenditures  in the  existing  pipeline  and  terminaling
businesses.   During  all  periods,   adequate   pipeline  capacity  existed  to
accommodate volume growth,  and the expenditures  required for environmental and
safety  improvements  were  not,  and  are not  expected  in the  future  to be,
significant.   Environmental   damages  are  included  under  the  Partnership's
insurance  coverages  (subject  to  deductibles  and  limits).  The  Partnership
anticipates  that  capital  expenditures   (including  routine  maintenance  and
expansion expenditures, but excluding acquisitions) will total approximately $40
million to $44 million in 2005. Such future expenditures,  however,  will depend
on many factors beyond the Partnership's control, including, without limitation,
demand  for  refined  petroleum   products  and  terminaling   services  in  the
Partnership's  market areas,  local, state and federal  government  regulations,
fuel conservation efforts and the availability of financing on acceptable terms.
No assurance can be given that  required  capital  expenditures  will not exceed
anticipated  amounts during the year or thereafter or that the Partnership  will
have the ability to finance such expenditures  through borrowings,  or choose to
do so.

     The  Partnership  makes regular cash  distributions  in accordance with its
Partnership  agreement  within 45 days after the end of each  quarter to limited
partner  and  general  partner  interests.  Aggregate  distributions  of  $106.6
million, $98.2 million and $74.4 million, were paid to limited partner interests
and general partner interests in 2004, 2003 and 2002, respectively.

     The  Partnership  expects to fund  future  cash  distributions  and routine
maintenance  capital  expenditures with existing cash and anticipated cash flows
from  operations.  Expansionary  capital  expenditures are expected to be funded
through  additional  Partnership  bank  borrowings  and/or  future  public  debt
offerings or KPP public equity offerings.

     In January of 2002, KPP issued  1,250,000  limited  partnership  units in a
public offering at $41.65 per unit,  generating  approximately  $49.7 million in
net  proceeds.   The  proceeds  were  used  to  reduce   borrowings   under  the
Partnership's revolving credit agreement.

     In February of 2002,  the  Partnership  issued $250 million of 7.75% senior
unsecured  notes  due  February  15,  2012.  The net  proceeds  from the  public
offering,  $248.2 million, were used to repay the Partnership's revolving credit
agreement  and  to  partially  fund  the  acquisition  of  all  of  the  liquids
terminaling subsidiaries of Statia Terminals Group NV ("Statia"). Under the note
indenture,  interest  is payable  semi-annually  in arrears on  February  15 and
August 15 of each year. The notes are redeemable,  as a whole or in part, at the
option of the  Partnership,  at any time,  at a  redemption  price  equal to the
greater of 100% of the principal  amount of the notes, or the sum of the present
value of the remaining scheduled payments of principal and interest,  discounted
to the redemption date at the applicable  U.S.  Treasury rate, as defined in the
indenture,  plus 30 basis points.  The note indenture contains certain financial
and operational covenants,  including certain limitations on investments,  sales
of assets and transactions with affiliates and, absent anevent of default,  such
covenants do not restrict  distributions to partners.  At December 31, 2004, the
Partnership was in compliance with all covenants.

     On February 28, 2002, the  Partnership  acquired  Statia for  approximately
$178 million in cash (net of acquired cash).  The acquired  Statia  subsidiaries
had approximately  $107 million in outstanding  debt,  including $101 million of
11.75% notes due in November  2003.  The cash portion of the purchase  price was
initially  funded by the  Partnership's  revolving credit agreement and proceeds
from the Partnership's February 2002 public debt offering. In April of 2002, the
Partnership  redeemed all of Statia's  11.75% notes at 102.938% of the principal
amount,  plus accrued  interest.  The redemption was funded by the Partnership's
revolving  credit  facility.  Under the  provisions  of the  11.75%  notes,  the
Partnership  incurred a $3.0 million prepayment  penalty,  of which $2.0 million
was recognized as loss on debt extinguishment in 2002.

     In May of 2002, KPP issued 1,565,000 limited  partnership units in a public
offering at a price of $39.60 per unit,  generating  approximately $59.1 million
in net  proceeds.  A  portion  of the  offering  proceeds  were used to fund its
September 2002 acquisition of the Australia and New Zealand terminals.

     On September 18, 2002, the  Partnership  acquired eight bulk liquid storage
terminals  in  Australia  and  New  Zealand  from  Burns  Philp & Co.  Ltd.  for
approximately $47 million in cash.

     On November 1, 2002, the Partnership  acquired an approximately  2,000-mile
anhydrous  ammonia  pipeline  system  from  Koch  Pipeline  Company,   L.P.  for
approximately  $139 million in cash. This fertilizer  pipeline system originates
in southern  Louisiana,  proceeds north through Arkansas and Missouri,  and then
branches  east  into  Illinois  and  Indiana  and  north  and west into Iowa and
Nebraska. The acquisition was initially financed with bank debt.

     In November of 2002, KPP issued 2,095,000  limited  partnership  units in a
public offering at $33.36 per unit,  generating  approximately  $66.7 million in
net proceeds.  The offering proceeds were used to reduce bank borrowings for the
fertilizer pipeline acquisition.

     On  December  24,  2002,  the  Partnership  acquired a  400-mile  petroleum
products  pipeline and four  terminals in North Dakota and Minnesota from Tesoro
Refining and Marketing Company for approximately  $100 million in cash,  subject
to normal  post-closing  adjustments.  The acquisition was initially funded with
bank debt.

     In March of 2003,  KPP  issued  3,122,500  limited  partnership  units in a
public offering at $36.54 per unit,  generating  approximately $109.1 million in
net proceeds. The proceeds were used to reduce bank borrowings.

     In April of 2003, the  Partnership  entered into a credit  agreement with a
group of banks that  provides  for a $400  million  unsecured  revolving  credit
facility  through  April of 2006.  The credit  facility,  which  provides for an
increase  in the  commitment  up to an  aggregate  of  $450  million  by  mutual
agreement  between the  Partnership  and the banks,  bears  interest at variable
rates and has a variable  commitment fee on unused amounts.  The credit facility
contains certain  financial and operating  covenants,  including  limitations on
investments,  sales of assets and  transactions  with  affiliates and, absent an
event of default,  does not restrict  distributions to partners. At December 31,
2004, the Partnership was in compliance with all covenants.  Initial  borrowings
on the  credit  agreement  ($324.2  million)  were  used to  repay  all  amounts
outstanding  under the  Partnership's  $275 million  credit  agreement  and $175
million  bridge  loan  agreement.  At  December  31,  2004,  $95.7  million  was
outstanding under the credit agreement.

     On May 19,  2003,  the  Partnership  issued $250  million of 5.875%  senior
unsecured  notes due June 1, 2013.  The net proceeds  from the public  offering,
$247.6 million,  were used to reduce amounts due under the 2003 revolving credit
agreement.  Under the note  indenture,  interest  is  payable  semi-annually  in
arrears on June 1 and December 1 of each year.  The notes are  redeemable,  as a
whole or in part, at the option of the Partnership, at any time, at a redemption
price equal to the greater of 100% of the principal  amount of the notes, or the
sum of the present  value of the remaining  scheduled  payments of principal and
interest,  discounted to the  redemption  date at the applicable  U.S.  Treasury
rate,  as defined in the  indenture,  plus 30 basis points.  The note  indenture
contains  certain  financial  and  operational   covenants,   including  certain
limitations on  investments,  sales of assets and  transactions  with affiliates
and, absent an event of default, such covenants do not restrict distributions to
partners.  At December 31, 2004,  the  Partnership  was in  compliance  with all
covenants.  In connection  with the offering,  on May 8, 2003,  the  Partnership
entered  into a  treasury  lock  contract  for the  purpose of locking in the US
Treasury  interest rate component on $100 million of the debt. The treasury lock
contract,  which qualified as a cash flow hedging instrument under SFAS No. 133,
was  settled  on May 19,  2003 with a cash  payment by the  Partnership  of $1.8
million. The settlement cost of the contract has been recorded as a component of
accumulated  other  comprehensive  income and is being  amortized,  as  interest
expense, over the life of the debt.

     The following is a schedule by period of the  Partnership's  debt repayment
obligations and material contractual commitments at December 31, 2004:
<TABLE>
<CAPTION>

                                                       Less than                                      After
                                           Total         1 year        1 -3 years    4 -5 years      5 years
                                         ----------    ----------      ----------    -----------   -----------
                                                                    (in thousands)
<S>                                     <C>           <C>              <C>           <C>           <C>
Debt:
    Revolving credit facility.........  $    95,669   $       -        $  95,669     $      -      $      -
    7.75% senior unsecured notes......      250,000           -              -              -         250,000
    5.875% senior unsecured notes.....      250,000           -              -              -         250,000
    Other bank debt...................       76,283           -           76,283            -             -
                                        -----------   -----------      ---------     ----------    ----------
       Debt subtotal..................      671,952           -          171,952            -         500,000
                                        -----------   -----------      ---------     ----------    ----------
Contractual commitment -
    Operating leases..................       51,905         9,756         14,717          9,292        18,140
                                        -----------   -----------      ---------     ----------    ----------
       Total..........................  $   723,857   $     9,756      $ 186,669     $    9,292    $  518,140
                                        ===========   ===========      =========     ==========    ==========
</TABLE>


     See also "Item 1 - Environmental Matters" and "Item 3 - Legal Proceedings".


OFF-BALANCE SHEET TRANSACTIONS

     The Partnership was not a party to any  off-balance  sheet  transactions at
December 31,  2004,  or for any of the years ended  December  31, 2004,  2003 or
2002.


CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     The  preparation of the  Partnership's  financial  statements in conformity
with accounting  principles  generally  accepted in the United States of America
requires  management to make estimates and assumptions  that affect the reported
amounts of assets and  liabilities  and  disclosures  of  contingent  assets and
liabilities at the date of the financial  statements and the reported amounts of
revenues and expenses during the reporting  period.  Actual results could differ
from those estimates.  Significant accounting policies are included in the Notes
to the Consolidated Financial Statements of the Partnership.

     Critical  accounting  policies  are those  that are most  important  to the
portrayal of the  Partnership's  financial  position and results of  operations.
These  policies  require  management's  most  difficult,  subjective  or complex
judgments, often employing the use of estimates about the effect of matters that
are inherently  uncertain.  The Partnership's most critical  accounting policies
pertain to impairment of property and equipment and environmental costs.

     The carrying  value of property and  equipment  is  periodically  evaluated
using  management's  estimates of  undiscounted  future cash flows,  or, in some
cases, third-party appraisals,  as the basis of determining if impairment exists
under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal
of  Long-Lived  Assets",  which was adopted  effective  January 1, 2002.  To the
extent that  impairment is indicated to exist,  an impairment loss is recognized
under SFAS No. 144 based on fair value.  The application of SFAS No. 144 did not
have a material  impact on the results of operations of the  Partnership for the
years ended  December 31, 2004,  2003 or 2002.  However,  future  evaluations of
carrying  value are dependent on many  factors,  several of which are out of the
Partnership's  control,  including  demand for refined  petroleum  products  and
terminaling  services in the  Partnership's  market areas, and local,  state and
federal governmental regulations.  To the extent that such factors or conditions
change, it is possible that future  impairments might occur,  which could have a
material effect on the results of operations of the Partnership.

     Environmental  expenditures that relate to current  operations are expensed
or  capitalized,  as  appropriate.  Expenditures  that  relate  to  an  existing
condition caused by past  operations,  and which do not contribute to current or
future  revenue  generation,   are  expensed.   Liabilities  are  recorded  when
environmental  assessments  and/or remedial efforts are probable,  and the costs
can be reasonably estimated.  Generally,  the timing of these accruals coincides
with the completion of a feasibility study or the Partnership's  commitment to a
formal  plan of  action.  The  application  of the  Partnership's  environmental
accounting  policies did not have a material impact on the results of operations
of the Partnership for the years ended December 31, 2004, 2003 or 2002. Although
the  Partnership  believes that its  operations are in general  compliance  with
applicable environmental regulations, risks of substantial costs and liabilities
are inherent in pipeline and terminaling  operations.  Moreover,  it is possible
that  other  developments,  such  as  increasingly  strict  environmental  laws,
regulations and enforcement policies thereunder, and legal claims for damages to
property or persons  resulting  from the  operations  of the  Partnership  could
result in substantial costs and liabilities,  any of which could have a material
effect on the results of operations of the Partnership.


Item 7(a). Quantitative and Qualitative Disclosures About Market Risk

     The principal  market risks  pursuant to this Item (i.e.,  the risk of loss
arising  from the  adverse  changes  in market  rates and  prices)  to which the
Partnership  is  exposed  are  interest  rates  on the  Partnership's  debt  and
investment  portfolios,  fluctuations of petroleum product prices on inventories
held for resale, and fluctuations in foreign currency.

     The  Partnership's  investment  portfolio  consists  of  cash  equivalents;
accordingly,  the carrying amounts  approximate  fair value.  The  Partnership's
investments are not material to its financial position or performance.  Assuming
variable  rate debt of $131.2  million  at  December  31,  2004,  a one  percent
increase  in  interest  rates  would  increase  annual net  interest  expense by
approximately  $1.3 million.  Information  regarding the Partnership's  interest
rate hedging  transactions  are included in "Item 7 -Interest  and Other Income"
and "Item 7 - Liquidity and Capital Resources".

     The  product  sales  business  periodically   purchases  refined  petroleum
products for resale as bunker fuel and sales to commercial interests.  Petroleum
inventories are generally held for short periods of time, not exceeding 90 days.
As the Partnership does not engage in derivative transactions to hedge the value
of the  inventory,  it is  subject  to market  risk from  changes  in global oil
markets.


Item 8. Financial Statements and Supplementary Data

     The financial statements and supplementary data of the Partnership begin on
page F-1 of this report.  Such  information is hereby  incorporated by reference
into this Item 8.


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

     None.

Item 9(a). Controls and Procedures

     Kaneb Pipe Line Company  LLC's  principal  executive  officer and principal
financial  officer,  after evaluating as of December 31, 2004, the effectiveness
of the  Partnership's  disclosure  controls and  procedures (as defined in Rules
13a-15(e) and 15d-15(e) of the Securities  Exchange Act of 1934), have concluded
that, as of such date, the Partnership's  disclosure controls and procedures are
adequate  and  effective  to ensure that  material  information  relating to the
Partnership  and its  consolidated  subsidiaries  would be made known to them by
others within those entities.

     During  the  fourth  quarter  of 2004,  there  have been no  changes in the
Partnership's  internal  controls over financial  reporting that have materially
affected, or are reasonably likely to materially affect, those internal controls
subsequent to the date of the  evaluation.  As a result,  no corrective  actions
were required or undertaken.


                                    PART III

Item 10. Directors and Executive Officers of the Registrant

     The Partnership  does not have directors or officers.  All directors of the
general  partner  are  elected  annually  by  KPL.  All  officers  serve  at the
discretion of the directors.  The information contained in Item 10 of KPP's Form
10-K, for the year ended December 31, 2004, is incorporated by reference in this
report.

CODE OF ETHICS

     The Partnership  has adopted a Code of Ethics  applicable to all employees,
including the  principal  executive  officer,  principal  financial  officer and
directors of the General  Partner.  The Partnership  has also adopted  Corporate
Governance Guidelines, which address director qualification standards;  director
access to management,  and as necessary and appropriate,  independent  advisors;
director compensation; director orientation and continuing education; management
succession and annual performance evaluation of the board. Copies of the Code of
Ethics and the Corporate Governance  Guidelines are available on Kaneb's website
at  www.kaneb.com  and will be  provided  without  charge by written  request to
Investor Relations, 2435 North Central Expressway, Richardson, Texas 75080.

Item 11. Executive Compensation

     The officers of the general  partner  manage and operate the  Partnership's
business.   The  Partnership  does  not  directly  employ  any  of  the  persons
responsible for managing or operating the Partnership's operations,  but instead
reimburses the general partner for the services of such persons. The information
contained in Item 11 of KPP's Form 10-K for the year ended December 31, 2004, is
incorporated by reference in this report.


Item 12. Security Ownership of Certain Beneficial Owners and Management

     KPP owns a 99%  interest  as the  sole  limited  partner  and KPL owns a 1%
general partner interest in the Partnership.  Information  identifying  security
ownership by the  Directors and Officers of KPL is contained in Item 12 of KPP's
Form 10-K for the year ended December 31, 2004, and is incorporated by reference
in this report.


Item 13. Certain Relationships and Related Transactions

     KPL is entitled to certain  reimbursements under the Partnership Agreement.
For   additional   information   regarding   the   nature  and  amount  of  such
reimbursements,   see  Note  7  to  the  Partnership's   consolidated  financial
statements.


Item 14. Principal Accounting Fees and Services

     The information  contained in Item 14 of KPP's Form 10-K for the year ended
December 31, 2004 is incorporated by reference in this report.


<PAGE>
                                     PART IV

Item 15. Exhibits and Financial Statement Schedules

<TABLE>
<CAPTION>
    (a) (1)Financial Statements Beginning                                                                Page

         Set forth below is a list of financial statements appearing in this
report.

<S>                                                                                                       <C>
         Kaneb Pipe Line Operating Partnership, L.P. and Subsidiaries Financial Statements:
           Report of Independent Registered Public Accounting Firm..................................      F - 1
           Consolidated Statements of Income - Three Years Ended December 31, 2004...................     F - 2
           Consolidated Balance Sheets - December 31, 2004 and 2003..................................     F - 3
           Consolidated Statements of Cash Flows - Three Years Ended December 31, 2004...............     F - 4
           Consolidated Statements of Partners' Capital - Three Years ended December 31, 2004........     F - 5
           Notes to Consolidated Financial Statements................................................     F - 6

    (a) (2)Financial Statement Schedules

     Set forth  below is the  financial  statement  schedule  appearing  in this
report.

          Schedule II - Kaneb Pipe Line Operating Partnership, L.P. Valuation and Qualifying Accounts
            - Years Ended December 31, 2004, 2003 and 2002...........................................     F -22

          Schedules,  other than the one listed above, have been omitted because
          of the  absence of the  conditions  under  which they are  required or
          because the  required  information  is  included  in the  consolidated
          financial statements or related notes thereto.
</TABLE>

    (a) (3)List of Exhibits

          2.1  Agreement and Plan of Merger dated as of October 31, 2004,  filed
               as Exhibit 2.1 to Registrant's  Form 8-K, filed October 31, 2004,
               which exhibit is hereby incorporated by reference.

          3.1  Amended and  Restated  Agreement  of Limited  Partnership,  dated
               September 27, 1989, filed as Exhibit 3.1 to the Registrant's Form
               10-K for the year  ended  December  31,  2001,  which  exhibit is
               hereby incorporated by reference.

          3.2  Amendment   to  Amended  and   Restated   Agreement   of  Limited
               Partnership  dated October 27, 2003,  filed as Exhibit 3.2 to the
               Registrant's  Form 10-K for the year  ended  December  31,  2003,
               which exhibit is hereby incorporated by reference.

          10.1 Formation  and  Purchase  Agreement,  between  and among  Support
               Terminal Operating Partnership, L.P., Northville Industries Corp.
               and AFFCO,  Corp.,  dated October 30, 1998, filed as exhibit 10.9
               to KPP's Form 10-K for the year ended  December 31,  1998,  which
               exhibit is hereby incorporated by reference.

          10.2 Credit  Agreement,  between and among,  Kaneb Pipe Line Operating
               Partnership,  L.P., ST Services, Ltd. and SunTrust Bank, Atlanta,
               dated January 27, 1999, filed as Exhibit 10.11 to KPP's Form 10-K
               for the year ended  December  31, 1998,  which  exhibit is hereby
               incorporated by reference.

          10.3 Revolving  Credit  Agreement,  dated as of April 24,  2003  among
               Kaneb  Pipe Line  Operating  Partnership,  L.P.,  Kaneb Pipe Line
               Partners,  L.P., The Lenders From Time To Time Party Hereto,  and
               SunTrust Bank, as Administrative Agent, filed as Exhibit 10.11 to
               the  Registrant's  Form 10-Q for the period ended March 31, 2003,
               which exhibit is hereby incorporated by reference.

          10.4*Amended and  Restated  Kaneb LLC 2002 Long Term  Incentive  Plan,
               dated June 30,  2003,  filed as Exhibit  10.1 to the  exhibits to
               Registrant's  Form 10-Q for the period ended June 30,  2003,  and
               incorporated  herein by reference.  10.5* Supplement to the Kaneb
               LLC 2002 Long Term Incentive Plan,  dated effective as of October
               31, 2004,  between Kaneb LLC and the  participant  named therein,
               filed as Exhibit  10.1 to the  exhibits to  Registrant's  Current
               Report on Form 8-K file November 3, 2004, and incorporated herein
               by reference.

          21   List of Subsidiaries, filed herewith.

          22   Form S-4, as amended and filed  January 25, 2005, by Valero L.P.,
               and incorporated herein by reference.

          23   Consent of KPMG LLP, filed herewith.

          31.1 Certification of Chief Executive Officer, Pursuant to Section 302
               of the Sarbanes-Oxley Act of 2002, dated as of March 16, 2005.

          31.2 Certification of Chief Financial Officer, Pursuant to Section 302
               of the Sarbanes-Oxley Act of 2002, dated as of March 16, 2005.

          32.1 Certification  of Chief  Executive  Officer,  Pursuant to Section
               906(a) of the  Sarbanes-Oxley  Act of 2002, dated as of March 16,
               2005.

          32.2 Certification  of Chief  Financial  Officer,  Pursuant to Section
               906(a) of the  Sarbanes-Oxley  Act of 2002, dated as of March 16,
               2005.

     *    Denotes management contract.

<PAGE>
             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the Partners of
Kaneb Pipe Line Operating Partnership, L.P.


We have  audited  the  consolidated  financial  statements  of Kaneb  Pipe  Line
Operating  Partnership,  L.P. and its subsidiaries (the "Partnership") as listed
in the index appearing under Item 15(a)(1). In connection with our audits of the
consolidated financial statements,  we have also audited the financial statement
schedule  as  listed  in  the  index  appearing   under  Item  15(a)(2).   These
consolidated  financial  statements  and  financial  statement  schedule are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on the  consolidated  financial  statements  and financial  statement
schedule based on our audits.

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

In our opinion, the consolidated  financial statements referred to above present
fairly, in all material  respects,  the financial position of the Partnership as
of December 31, 2004 and 2003,  and the results of its  operations  and its cash
flows for each of the years in the three-year period ended December 31, 2004, in
conformity with U.S.  generally  accepted  accounting  principles.  Also, in our
opinion,  the related financial statement schedule,  when considered in relation
to the  basic  consolidated  financial  statements  taken as a  whole,  presents
fairly, in all material respects the information set forth therein.

As  described  in  Note  2,  the  Partnership  adopted  Statement  of  Financial
Accounting  Standards No. 143 "Accounting for Asset  Retirement  Obligations" in
2003.

                                       KPMG LLP

Dallas, Texas
March 11, 2005



                                      F - 1

<PAGE>
          KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                                           Year Ended December 31,
                                                        -----------------------------------------------------------
                                                               2004                 2003                 2002
                                                        -----------------    -----------------    -----------------

<S>                                                       <C>                   <C>                  <C>
Revenues:
   Services...........................................    $ 379,155,000         $ 354,591,000        $  288,669,000
   Products...........................................      269,054,000           215,823,000            97,961,000
                                                          -------------         -------------        --------------
      Total revenues..................................      648,209,000           570,414,000           386,630,000
                                                          -------------         -------------        --------------
Costs and expenses:
   Cost of products sold..............................      246,858,000           195,100,000            90,898,000
   Operating costs....................................      176,976,000           168,537,000           131,326,000
   Depreciation and amortization......................       56,648,000            53,155,000            39,425,000
   Gain on sale of assets.............................            -                     -                  (609,000)
   General and administrative.........................       30,937,000            25,121,000            19,869,000
                                                          -------------         -------------        --------------
      Total costs and expenses........................      511,419,000           441,913,000           280,909,000
                                                          -------------         -------------        --------------
Operating income......................................      136,790,000           128,501,000           105,721,000

Interest and other income.............................          267,000               261,000             3,570,000
Interest expense......................................      (42,750,000)          (38,757,000)          (28,110,000)
Loss on debt extinguishment...........................            -                     -                (3,282,000)
                                                          -------------         -------------        --------------
Income before income taxes and cumulative effect of
   change in accounting principle.....................       94,307,000            90,005,000            77,899,000

Income tax expense....................................       (3,282,000)           (5,223,000)           (4,083,000)
                                                          -------------         -------------        ---------------
Income before cumulative effect of change in
   accounting principle...............................       91,025,000            84,782,000            73,816,000

Cumulative effect of change in accounting principle -
   adoption of new accounting standard for asset
   retirement obligations.............................            -                (1,593,000)                -
                                                          -------------         -------------        --------------
Net income ...........................................    $  91,025,000         $  83,189,000        $   73,816,000
                                                          =============         =============        ==============

</TABLE>

                See notes to consolidated financial statements.

                                      F - 2

<PAGE>


          KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>

                                                                                           December 31,
                                                                             --------------------------------------
                                                                                   2004                  2003
                                                                             ----------------      ----------------
                                     ASSETS
<S>                                                                          <C>                   <C>
Current assets:
   Cash and cash equivalents...............................................  $     34,336,000      $     38,626,000
   Accounts receivable (net of allowance for doubtful accounts
      of $1,283,000 in 2004 and $1,693,000 in 2003)........................        71,035,000            51,864,000
   Inventories.............................................................        15,519,000             9,324,000
   Prepaid expenses and other..............................................        12,371,000             9,205,000
                                                                             ----------------      ----------------
      Total current assets.................................................       133,261,000           109,019,000
                                                                             ----------------      ----------------
Property and equipment.....................................................     1,450,972,000         1,360,319,000
Less accumulated depreciation..............................................       302,381,000           247,349,000
                                                                             ----------------      ----------------
      Net property and equipment...........................................     1,148,591,000         1,112,970,000
                                                                             ----------------      ----------------

Investment in affiliates...................................................        25,939,000            25,456,000

Excess of cost over fair value of net assets of acquired business and
   other assets............................................................        17,525,000            17,237,000
                                                                             ----------------      ----------------
                                                                             $  1,325,316,000      $  1,264,682,000
                                                                             ================      ================


                        LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:
   Accounts payable........................................................  $     44,071,000      $     27,941,000
   Accrued expenses........................................................        28,894,000            31,642,000
   Accrued distributions payable...........................................        26,960,000            26,344,000
   Accrued interest payable................................................         9,365,000             9,297,000
   Accrued taxes, other than income taxes..................................         4,828,000             4,031,000
   Deferred terminaling fees...............................................         8,851,000             7,061,000
   Payable to general partner..............................................         4,528,000             3,630,000
                                                                             ----------------      ----------------
      Total current liabilities............................................       127,497,000           109,946,000
                                                                             ----------------      ----------------

Long-term debt.............................................................       671,952,000           617,696,000

Other liabilities and deferred taxes.......................................        44,386,000            43,451,000

Commitments and contingencies

Partners' capital:
   Limited partner.........................................................       464,263,000           480,323,000
   General partner.........................................................           820,000               894,000
   Accumulated other comprehensive income..................................        16,398,000            12,372,000
                                                                             ----------------      ----------------
      Total partners' capital..............................................       481,481,000           493,589,000
                                                                             ----------------      ----------------
                                                                             $  1,325,316,000      $  1,264,682,000
                                                                             ================      ================


</TABLE>

                See notes to consolidated financial statements.

                                      F - 3

<PAGE>
          KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                           Year Ended December 31,
                                                          ---------------------------------------------------------
                                                              2004                  2003                  2002
                                                          -------------         -------------        --------------
<S>                                                       <C>                   <C>                  <C>
Operating activities:
   Net income ........................................    $  91,025,000         $  83,189,000        $   73,816,000
   Adjustments to reconcile net income to net
      cash provided by operating activities:
      Depreciation and amortization...................       56,648,000            53,155,000            39,425,000
      Equity in earnings of affiliates, net of
        distributions.................................         (483,000)              148,000            (3,164,000)
      Gain on sale of assets..........................            -                     -                  (609,000)
      Deferred income taxes...........................         (671,000)            1,683,000             3,105,000
      Cumulative effect of change in accounting
        principle.....................................            -                 1,593,000                 -
      Other liabilities...............................       (1,666,000)            1,190,000            (1,341,000)
      Changes in working capital components:
        Accounts receivable...........................      (19,171,000)           (2,938,000)          (12,379,000)
        Inventories, prepaid expenses and other.......       (9,361,000)           (5,109,000)           (6,601,000)
        Accounts payable and accrued expenses.........       15,112,000            10,829,000            (1,192,000)
        Payable to general partner....................          898,000            (1,773,000)              702,000
                                                         --------------         -------------        --------------
           Net cash provided by operating activities..      132,331,000           141,967,000            91,762,000
                                                         --------------         -------------        --------------

Investing activities:
   Acquisitions, net of cash acquired.................      (41,853,000)           (1,644,000)         (468,477,000)
   Capital expenditures...............................      (42,214,000)          (44,741,000)          (31,101,000)
   Proceeds from sale of assets.......................            -                     -                 1,107,000
   Other, net.........................................        1,327,000            (1,109,000)              306,000
                                                         --------------         -------------        --------------
           Net cash used in investing activities......      (82,740,000)          (47,494,000)         (498,165,000)
                                                         --------------         -------------        ---------------
Financing activities:
   Issuance of debt...................................       51,080,000           291,377,000           746,087,000
   Payments of debt...................................            -              (382,831,000)         (426,647,000)
   Distributions......................................     (106,598,000)          (98,243,000)          (74,439,000)
   Net proceeds from issuance of units by KPP.........            -               109,056,000           175,527,000
                                                         --------------         -------------        --------------
           Net cash provided by (used in) financing
               activities.............................      (55,518,000)          (80,641,000)          420,528,000
                                                         --------------         -------------        --------------
Effect of exchange rate changes on cash...............        1,637,000             2,766,000                 -
                                                         --------------         -------------        --------------
Increase (decrease) in cash and cash equivalents......       (4,290,000)           16,598,000            14,125,000
Cash and cash equivalents at beginning of period......       38,626,000            22,028,000             7,903,000
                                                         --------------         -------------        --------------
Cash and cash equivalents at end of period............   $   34,336,000         $  38,626,000        $   22,028,000
                                                         ==============         =============        ==============
Supplemental cash flow information - cash paid for
   interest...........................................   $   41,321,000         $  34,818,000        $   25,942,000
                                                         ==============         =============        ==============
</TABLE>


                See notes to consolidated financial statements.

                                      F - 4

<PAGE>
          KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
<TABLE>
<CAPTION>

                                                                            Accumulated
                                                                               Other
                                                Limited        General     Comprehensive                    Comprehensive
                                                Partner        Partner     Income (Loss)      Total            Income
                                            --------------   -----------   ------------- ---------------  ----------------
<S>                                         <C>              <C>           <C>           <C>              <C>
Partners' capital at January 1, 2002.....   $  221,363,000   $ 1,030,000   $(1,866,000)  $  220,527,000

  2002 income allocation.................       73,078,000       738,000           -         73,816,000   $    73,816,000

  Distributions declared.................      (79,064,000)     (752,000)          -        (79,816,000)             -

  Issuance of units by KPP, net of
    offering costs.......................      175,527,000          -              -        175,527,000              -

  Foreign currency translation adjustment            -              -        3,260,000        3,260,000         3,260,000
                                            --------------   -----------   -----------   --------------   ---------------
  Comprehensive income for the year......                                                                 $    77,076,000
                                                                                                          ===============

Partners' capital at December 31, 2002...      390,904,000     1,016,000     1,394,000      393,314,000

  2003 income allocation.................       82,357,000       832,000           -         83,189,000   $    83,189,000

  Distributions declared.................     (101,994,000)     (954,000)          -       (102,948,000)             -

  Issuance of units by KPP, net of
    offering costs.......................      109,056,000          -              -        109,056,000              -

  Foreign currency translation adjustment            -              -       12,662,000       12,662,000        12,662,000

  Interest rate hedging transaction......            -              -       (1,684,000)      (1,684,000)       (1,684,000)
                                            --------------  ------------   -----------   --------------   ---------------
  Comprehensive income for the year......                                                                 $    94,167,000
                                                                                                          ===============

Partners' capital at December 31, 2003...      480,323,000       894,000    12,372,000      493,589,000

  2004 income allocation.................       90,115,000       910,000           -         91,025,000   $    91,025,000

  Distributions declared.................     (106,230,000)     (984,000)          -       (107,214,000)             -

  Foreign currency translation adjustment            -              -        3,846,000        3,846,000         3,846,000

  Interest rate hedging transaction......            -              -          180,000          180,000           180,000

  Amortization of restricted KPP units...           55,000          -             -              55,000              -
                                            --------------  ------------   -----------   --------------   ---------------
  Comprehensive income for the year......                                                                 $    95,051,000
                                                                                                          ===============
Partners' capital at December 31, 2004...   $  464,263,000   $   820,000   $16,398,000   $  481,481,000
                                            ==============   ===========   ===========   ==============
</TABLE>


                See notes to consolidated financial statements.

                                      F - 5

<PAGE>
                   KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.   PARTNERSHIP ORGANIZATION

     General

     Kaneb Pipe Line Operating Partnership, L.P. (the "Partnership"),  a limited
partnership,  owns and  operates a refined  petroleum  products  and  fertilizer
pipeline  business and a petroleum  products and specialty  liquids  storage and
terminaling business.  Kaneb Pipe Line Partners,  L.P. ("KPP"), a master limited
partnership,  holds a 99% interest as limited partner in the Partnership.  Kaneb
Pipe Line Company LLC ("KPL"),  a wholly owned  subsidiary of Kaneb Services LLC
("KSL"),  manages and controls the operations of KPP through its general partner
interest and 18% (at December 31, 2004) limited partnership interest. KPL owns a
1% interest as general  partner of the  Partnership and a 1% interest as general
partner of KPP.

     Valero L.P. Merger Agreement

     On  October  31,  2004,  Valero  L.P.  and KPP  entered  into a  definitive
agreement to merge (the "KPP  Merger")  Valero L.P. and KPP.  Under the terms of
the agreement, each holder of units of limited partnership interests in KPP will
receive a number of Valero L.P.  common  units  based on an exchange  ratio that
fluctuates  within a fixed range to provide $61.50 in value of Valero L.P. units
for each unit of KPP. The actual  exchange  ratio will be determined at the time
of the closing of the proposed  merger and is subject to a fixed value collar of
plus or minus  five  percent  of Valero  L.P.'s  per unit  price of $57.25 as of
October 7, 2004. Should Valero L.P.'s per unit price fall below $54.39 per unit,
the exchange  ratio will remain fixed at 1.1307 Valero L.P.  units for each unit
of KPP. Likewise,  should Valero L.P.'s per unit price exceed $60.11 per unit of
KPP, the exchange  ratio will remain fixed at 1.0231 Valero L.P.  units for each
unit of KPP.

     In a separate definitive agreement, on October 31, 2004, Valero L.P. agreed
to acquire by merger (the "KSL Merger") all of the outstanding  common shares of
KSL for cash.  Under the terms of that  agreement,  Valero  L.P.  is offering to
purchase all of the outstanding shares of KSL at $43.31 per share.

     The  completion  of the KPP Merger is subject to the  customary  regulatory
approvals  including those under the  Hart-Scott-Rodino  Antitrust  Improvements
Act. The  completion  of the KPP Merger is also subject to completion of the KSL
Merger.  All required  unitholder and shareholder  approvals have been obtained.
Upon completion of the mergers,  the general partner of the combined partnership
will be owned by affiliates of Valero  Energy  Corporation  and KPP and KSL will
become wholly owned subsidiaries of Valero L.P.

     Issuance of KPP Limited Partnership Units

     In March of 2003,  KPP  issued  3,122,500  limited  partnership  units in a
public offering at $36.54 per unit,  generating  approximately $109.1 million in
net proceeds. The proceeds were used to reduce bank borrowings (See Note 5).

     In November of 2002, KPP issued 2,095,000  limited  partnership  units in a
public offering at $33.36 per unit,  generating  approximately  $66.7 million in
net proceeds.  The offering proceeds were used to reduce bank borrowings for the
November 2002 fertilizer pipeline acquisition (see Notes 3 and 5).

     In May of 2002, KPP issued 1,565,000 limited  partnership units in a public
offering at a price of $39.60 per unit,  generating  approximately $59.1 million
in net  proceeds.  A  portion  of the  offering  proceeds  were used to fund its
September 2002 acquisition of the Australia and New Zealand  terminals (see Note
3).

     In January of 2002, KPP issued  1,250,000  limited  partnership  units in a
public offering at $41.65 per unit,  generating  approximately  $49.7 million in
net  proceeds.   The  proceeds  were  used  to  reduce   borrowings   under  the
Partnership's revolving credit agreement (see Note 5).


2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     The  following   significant   accounting  policies  are  followed  by  the
Partnership in the preparation of the consolidated financial statements.

     Cash and Cash Equivalents

     The  Partnership's  policy is to invest cash in highly  liquid  investments
with original maturities of three months or less.  Accordingly,  uninvested cash
balances are kept at minimum levels.  Such investments are valued at cost, which
approximates market, and are classified as cash equivalents.

     Inventories

     Inventories consist primarily of petroleum products purchased for resale in
the product sales operations and are valued at the lower of cost or market. Cost
is determined by using the weighted-average cost method.

     Property and Equipment

     Property and  equipment are carried at  historical  cost.  Additions of new
equipment  and  major  renewals  and  replacements  of  existing  equipment  are
capitalized.  Repairs and minor  replacements  that do not  materially  increase
values or extend  useful  lives  are  expensed.  Depreciation  of  property  and
equipment  is provided  on a  straight-line  basis at rates based upon  expected
useful  lives of various  classes of assets,  as  disclosed in Note 4. The rates
used for pipeline and storage  facilities  are the same as those which have been
promulgated by the Federal Energy Regulatory Commission. Upon disposal of assets
depreciated on an individual basis, the gains and losses are included in current
operating income.  Upon disposal of assets depreciated on a group basis,  unless
unusual in nature or amount,  residual cost,  less salvage,  is charged  against
accumulated depreciation.

     Effective  January 1, 2002, the Partnership  adopted Statement of Financial
Accounting  Standards  ("SFAS")  No.  144,  "Accounting  for the  Impairment  or
Disposal  of  Long-Lived  Assets",  which  addresses  financial  accounting  and
reporting for the impairment or disposal of long-lived  assets.  The adoption of
SFAS No.  144 did not  have a  material  impact  on the  consolidated  financial
statements  of the  Partnership.  Under  SFAS No.  144,  the  carrying  value of
property and equipment is periodically  evaluated using undiscounted future cash
flows  as the  basis  for  determining  if  impairment  exists.  To  the  extent
impairment is indicated to exist, an impairment loss will be recognized based on
fair value.

     Revenue and Income Recognition

     The pipeline business provides pipeline transportation of refined petroleum
products, liquified petroleum gases, and anhydrous ammonia fertilizer.  Pipeline
revenues are recognized as services are provided. The Partnership's  terminaling
services business  provides  terminaling and other ancillary  services.  Storage
fees are  generally  billed one month in advance  and are  reported  as deferred
income.  Terminaling revenues are recognized in the month services are provided.
Revenues for the product sales business are recognized  when product is sold and
title and risk pass to the customer.

     Foreign Currency Translation

     The  Partnership  translates the balance sheet of its foreign  subsidiaries
using year-end  exchange rates and translates income statement amounts using the
average exchange rates in effect during the year. The gains and losses resulting
from  the  change  in  exchange  rates  from  year to year  have  been  reported
separately as a component of accumulated  other  comprehensive  income (loss) in
Partners' Capital. Gains and losses resulting from foreign currency transactions
are included in the  consolidated  statements of income.  The local  currency is
considered to be the functional currency,  except in the Netherland Antilles and
Canada, where the U.S. dollar is the functional currency.

     Excess of Cost Over Fair Value of Net Assets of Acquired Business

     Effective January 1, 2002, the Partnership  adopted SFAS No. 142, "Goodwill
and Other  Intangible  Assets," which  eliminates the  amortization  of goodwill
(excess of cost over fair value of net assets of  acquired  business)  and other
intangible assets with indefinite lives.  Under SFAS No. 142,  intangible assets
with lives restricted by contractual,  legal, or other means will continue to be
amortized over their useful lives.  At December 31, 2004, the Partnership had no
intangible assets subject to amortization under SFAS No. 142. Goodwill and other
intangible assets not subject to amortization are tested for impairment annually
or more  frequently  if events or changes  in  circumstances  indicate  that the
assets might be impaired.  SFAS No. 142 requires a two-step  process for testing
impairment.  First,  the fair value of each  reporting  unit is  compared to its
carrying value to determine  whether an indication of impairment  exists.  If an
impairment is indicated, then the fair value of the reporting unit's goodwill is
determined  by  allocating  the unit's fair value to its assets and  liabilities
(including any unrecognized intangible assets) as if the reporting unit had been
acquired in a business  combination.  The amount of  impairment  for goodwill is
measured  as the  excess of its  carrying  value over its fair  value.  Based on
valuations and analysis  performed by the  Partnership at initial  adoption date
and at each annual evaluation date, including December 31, 2004, the Partnership
determined that the implied fair value of its goodwill  exceeded  carrying value
and, therefore, no impairment charge was necessary.

     Environmental Matters

     Environmental  expenditures that relate to current  operations are expensed
or  capitalized,  as  appropriate.  Expenditures  that  relate  to  an  existing
condition caused by past  operations,  and which do not contribute to current or
future  revenue  generation,   are  expensed.   Liabilities  are  recorded  when
environmental  assessments  and/or remedial efforts are probable,  and the costs
can be reasonably estimated.  Generally,  the timing of these accruals coincides
with the completion of a feasibility study or the Partnership's  commitment to a
formal plan of action.

     Asset Retirement Obligations

     Effective January 1, 2003, the Partnership adopted SFAS No. 143 "Accounting
for  Asset  Retirement  Obligations",  which  establishes  requirements  for the
removal-type  costs associated with asset  retirements.  At the initial adoption
date of SFAS No. 143, the Partnership recorded an asset retirement obligation of
approximately  $5.5  million and  recognized  a  cumulative  effect of change in
accounting  principle of $1.6 million for its legal  obligations  to  dismantle,
dispose of, and restore  certain  leased  pipeline and  terminaling  facilities,
including  petroleum and chemical  storage  tanks,  terminaling  facilities  and
barges.  The Partnership  did not record a retirement  obligation for certain of
its pipeline and terminaling assets because sufficient  information is presently
not  available  to  estimate  a range  of  potential  settlement  dates  for the
obligation.  In these cases, the obligation will be initially  recognized in the
period in which  sufficient  information  exists to estimate the obligation.  At
December 31, 2004, the Partnership  had no assets which were legally  restricted
for purposes of settling asset  retirement  obligations.  The effect of SFAS No.
143,  assuming  adoption on January 1, 2002,  was not material to the results of
operations of the  Partnership  for the years ended December 31, 2004,  2003 and
2002. For the years ended December 31, 2004 and 2003,  accretion expense of $0.2
million and $0.4 million, respectively, was included in operating costs.

     Comprehensive Income

     The  Partnership  follows  the  provisions  of  SFAS  No.  130,  "Reporting
Comprehensive Income", for the reporting and display of comprehensive income and
its components in a full set of general purpose financial  statements.  SFAS No.
130  requires  additional  disclosure  and does  not  affect  the  Partnership's
financial position or results of operations.

     Income Taxes

     Income (loss) before income tax expense and extraordinary items, is made up
of the following components:

<TABLE>
<CAPTION>
                                                                              Year Ended December 31,
                                                          ---------------------------------------------------------
                                                              2004                  2003                  2002
                                                          -------------         -------------        --------------
<S>                                                       <C>                   <C>                  <C>
       Partnership operations........................     $  75,917,000         $  71,104,000        $   71,614,000
       Corporate operations:
            Domestic.................................        (4,888,000)           (3,055,000)            2,046,000
            Foreign..................................        23,278,000            21,956,000             4,239,000
                                                          -------------         -------------        --------------
                                                          $  94,307,000         $  90,005,000        $   77,899,000
                                                          =============         =============        ==============
</TABLE>

     Partnership  operations  are not subject to federal or state income  taxes.
However,  certain  operations of terminaling  operations  are conducted  through
wholly-owned  corporate  subsidiaries which are taxable entities.  The provision
for  income  taxes  for the  periods  ended  December  31,  2004,  2003 and 2002
primarily  consists  of U.S.  and foreign  income  taxes of $3.3  million,  $5.2
million and $4.1 million,  respectively. The net deferred tax liability of $21.5
million,  $20.6 million and $17.8  million at December 31, 2004,  2003 and 2002,
respectively,  consists of deferred  tax  liabilities  of $35.1  million,  $48.8
million  and $41.7  million,  respectively,  and  deferred  tax  assets of $13.6
million,  $28.2  million  and $23.9  million,  respectively.  The  deferred  tax
liabilities   consist   primarily  of  tax   depreciation   in  excess  of  book
depreciation.  The deferred tax assets  consist  primarily of net operating loss
carryforwards.   The  U.S.   corporate   operations   have  net  operating  loss
carryforwards for tax purposes totaling  approximately $42.8 million,  which are
subject to various limitations on use and expire in years 2008 through 2023.

     On June 1,  1989,  the  governments  of the  Netherlands  Antilles  and St.
Eustatius  approved a Free Zone and Profit Tax Agreement  retroactive to January
1,  1989,  which  expired  on  December  31,  2000.  This  agreement  required a
subsidiary  of the  Partnership,  which was acquired with Statia on February 28,
2002 (see Note 3), to pay a 2% rate on taxable income, as defined therein,  or a
minimum  payment of 500,000  Netherlands  Antilles  guilders  ($0.3 million) per
year. The agreement  further provided that any amounts paid in order to meet the
minimum annual payment were available to offset future tax liabilities under the
agreement  to the extent that the minimum  annual  payment is greater than 2% of
taxable  income.  The  subsidiary  is  currently  engaged  in  discussions  with
representatives appointed by the Island Territory of St. Eustatius regarding the
renewal or  modification  of the agreement,  but the ultimate  outcome cannot be
predicted  at this time.  The  subsidiary  has  accrued  amounts  assuming a new
agreement becomes effective,  and continues to make payments, as required, under
the previous agreement.

     Since the  income or loss of the  operations  which are  conducted  through
limited  partnerships  will be  included  in the tax  returns of the  individual
partners of the Partnership,  no provision for income taxes has been recorded in
the accompanying  financial statements on these earnings. The tax returns of the
Partnership are subject to examination by federal and state taxing  authorities.
If any such examination results in adjustments to distributive shares of taxable
income or loss, the tax liability of the partners would be adjusted accordingly.

     The tax  attributes of the  Partnership's  net assets flow directly to each
individual  partner.  Individual  partners will have different  investment bases
depending upon the timing and prices of  acquisition  of Partnership  interests.
Further, each partner's tax accounting,  which is partially dependent upon their
individual  tax  position,  may  differ  from  the  accounting  followed  in the
financial  statements.  Accordingly,  there  could  be  significant  differences
between each individual partner's tax basis and their proportionate share of the
net assets reported in the financial  statements.  SFAS No. 109, "Accounting for
Income Taxes," requires  disclosure of the aggregate  difference in the basis of
its net assets for  financial  and tax  reporting  purposes.  Management  of the
Partnership  does not believe  that,  in the  Partnership's  circumstances,  the
aggregate difference would be meaningful information.

     Cash  Distributions

     The  Partnership  makes regular cash  distributions  in accordance with its
Partnership  agreement  within 45 days after the end of each  quarter to limited
partner  and  general  partner  interests.  Aggregate  distributions  of  $106.6
million, $98.2 million and $74.4 million, were paid to limited partner interests
and general partner interests in 2004, 2003 and 2002, respectively.

     Derivative Instruments

     The  Partnership  follows the provisions of SFAS No. 133,  "Accounting  for
Derivative Instruments and Hedging Activities", which establishes the accounting
and reporting standards for such activities.  Under SFAS No. 133, companies must
recognize  all  derivative  instruments  on their  balance  sheet at fair value.
Changes in the value of derivative instruments, which are considered hedges, are
offset against the change in fair value of the hedged item through earnings,  or
recognized in other comprehensive  income until the hedged item is recognized in
earnings,  depending  on the nature of the hedge.  SFAS No.  133  requires  that
unrealized  gains and losses on derivatives not qualifying for hedge  accounting
be recognized currently in earnings.

     On May 19,  2003,  the  Partnership  issued $250  million of 5.875%  senior
unsecured  notes due June 1, 2013 (see Note 5.) In connection with the offering,
on May 8, 2003,  the  Partnership  entered into a treasury lock contract for the
purpose of locking in the US Treasury interest rate component on $100 million of
the debt.  The treasury lock  contract,  which  qualified as a cash flow hedging
instrument  under SFAS No. 133,  was settled on May 19, 2003 with a cash payment
by the Partnership of $1.8 million. The settlement cost of the contract has been
recorded as a component of accumulated other  comprehensive  income and is being
amortized,  as interest expense,  over the life of the debt. For the years ended
December 31, 2004 and 2003,  $0.2  million and $0.1  million,  respectively,  of
amortization is included in interest expense.

     In  September  of  2002,  the  Partnership  entered  into a  treasury  lock
contract,  maturing on  November  4, 2002,  for the purpose of locking in the US
Treasury  interest  rate  component on $150 million of  anticipated  thirty-year
public debt offerings. The treasury lock contract originally qualified as a cash
flow hedging instrument under SFAS No. 133. In October of 2002, the Partnership,
due to various  market  factors,  elected to defer  issuance  of the public debt
securities,  effectively  eliminating the cash flow hedging  designation for the
treasury lock contract.  On October 29, 2002, the contract was settled resulting
in a net realized gain of $3.0 million,  which was  recognized as a component of
interest and other income.

     Estimates

     The  preparation of the  Partnership's  financial  statements in conformity
with accounting  principles  generally  accepted in the United States of America
requires  management to make estimates and assumptions  that affect the reported
amounts of assets and  liabilities  and  disclosures  of  contingent  assets and
liabilities at the date of the financial  statements and the reported amounts of
revenues and expenses during the reporting  period.  Actual results could differ
from those estimates.

     Recent Accounting Pronouncements

     Effective   January  1,  2003,  the  Partnership   adopted  SFAS  No.  146,
"Accounting  for Costs  Associated  with  Exit or  Disposal  Activities",  which
requires that all  restructurings  initiated after December 31, 2002 be recorded
when they are incurred  and can be measured at fair value.  The adoption of SFAS
No.  146  had  no  effect  on  the  consolidated  financial  statements  of  the
Partnership.

     The Partnership has adopted the provisions of FASB  Interpretation  No. 45,
"Guarantor's  Accounting and Disclosure  Requirements  of Guarantees,  Including
Indirect  Guarantees  of  Indebtedness  to  Others,  an  interpretation  of FASB
Statements No. 5, 57, and 107, and a rescission of FASB  Interpretation No. 34."
This  interpretation  elaborates on the disclosures to be made by a guarantor in
its  interim  and  annual  financial  statements  about  its  obligations  under
guarantees  issued.  The  interpretation  also  clarifies  that a  guarantor  is
required to  recognize,  at inception of a guarantee,  a liability  for the fair
value of the obligation  undertaken.  The initial  recognition  and  measurement
provisions of the interpretation are applicable to guarantees issued or modified
after December 31, 2002. The application of this interpretation had no effect on
the consolidated financial statements of the Partnership.

     In December 2003, the FASB issued  Interpretation  No. 46 (Revised December
2003),  "Consolidation  of Variable  Interest  Entities (FIN 46R),  primarily to
clarify the required  accounting  for  interests in variable  interest  entities
(VIEs).  This standard  replaces FASB  Interpretation  No. 46,  Consolidation of
Variable Interest  Entities,  that was issued in January 2003 to address certain
situations in which a company  should  include in its financial  statements  the
assets,  liabilities  and  activities of another  entity.  For the  Partnership,
application  of FIN 46R is  required  for  interests  in  certain  VIEs that are
commonly referred to as  special-purpose  entities,  or SPEs, as of December 31,
2003 and for  interests  in all other  types of VIEs as of March 31,  2004.  The
application  of FIN 46R did  not  have a  material  impact  on the  consolidated
financial statements of the Partnership.

     The Partnership  has adopted the provisions of SFAS No. 149,  "Amendment of
Statement 133 on Derivative  Instruments and Hedging  Activities",  which amends
and clarifies financial accounting and reporting for derivative  instruments and
hedging  activities.  The  adoption of SFAS No.  149,  which was  effective  for
derivative  contracts and hedging  relationships  entered into or modified after
June  30,  2003,  had no  impact  on the  Partnership's  consolidated  financial
statements.

     On July 1, 2003,  the  Partnership  adopted SFAS No. 150,  "Accounting  for
Certain  Financial  Instruments  with  Characteristics  of both  Liabilities and
Equity",  which requires certain  financial  instruments,  which were previously
accounted for as equity,  to be classified as liabilities.  The adoption of SFAS
No.  150  had  no  effect  on  the  consolidated  financial  statements  of  the
Partnership.


3.   ACQUISITIONS

     On  December  24,  2002,  the  Partnership  acquired a  400-mile  petroleum
products  pipeline and four  terminals in North Dakota and Minnesota from Tesoro
Refining and Marketing Company for approximately  $100 million in cash,  subject
to normal  post-closing  adjustments.  The acquisition was initially funded with
bank debt (see Note 5).  Based on the  evaluations  performed,  no amounts  were
assigned  to  goodwill  or to other  intangible  assets  in the  purchase  price
allocation.

     On November 1, 2002, the Partnership  acquired an approximately  2,000-mile
anhydrous  ammonia  pipeline  system  from  Koch  Pipeline  Company,   L.P.  for
approximately  $139 million in cash. This fertilizer  pipeline system originates
in southern  Louisiana,  proceeds north through Arkansas and Missouri,  and then
branches  east  into  Illinois  and  Indiana  and  north  and west into Iowa and
Nebraska.  The acquisition was initially funded with bank debt (see Note 5). The
results of  operations  and cash flows of the acquired  business are included in
the  consolidated  financial  statements  of the  Partnership  since the date of
acquisition.  Based on the  evaluations  performed,  no amounts were assigned to
goodwill or to other intangible assets in the purchase price allocation.

     On September 18, 2002, the  Partnership  acquired eight bulk liquid storage
terminals  in  Australia  and  New  Zealand  from  Burns  Philp & Co.  Ltd.  for
approximately  $47 million in cash.  The results of operations and cash flows of
the acquired business are included in the consolidated  financial  statements of
the  Partnership  since  the  date  of  acquisition.  Based  on the  evaluations
performed, no amounts were assigned to goodwill or to other intangible assets in
the purchase price allocation.

     On  February  28,  2002,  the  Partnership  acquired  all  of  the  liquids
terminaling   subsidiaries   of  Statia   Terminals   Group  NV  ("Statia")  for
approximately  $178 million in cash (net of acquired cash).  The acquired Statia
subsidiaries had approximately $107 million in outstanding debt,  including $101
million of 11.75% notes due in November  2003.  The cash portion of the purchase
price was initially funded by the  Partnership's  revolving credit agreement and
proceeds from the Partnership's February 2002 public debt offering (see Note 5).
In April of 2002,  the  Partnership  redeemed  all of Statia's  11.75%  notes at
102.938% of the principal  amount,  plus accrued  interest.  The  redemption was
funded by the  Partnership's  revolving  credit facility (see Note 5). Under the
provisions  of the  11.75%  notes,  the  Partnership  incurred  a  $3.0  million
prepayment  penalty,  of  which  $2.0  million  was  recognized  as loss on debt
extinguishment in 2002.

     The  results of  operations  and cash flows of Statia are  included  in the
consolidated   financial  statements  of  the  Partnership  since  the  date  of
acquisition.  Based on the  valuations  performed,  no amounts were  assigned to
goodwill or to other tangible  assets. A summary of the allocation of the Statia
purchase price, net of cash acquired, is as follows:

        Current assets ..............................         $  10,898,000
        Property and equipment ......................           320,008,000
        Other assets ................................                53,000
        Current liabilities .........................           (39,052,000)
        Long-term debt ..............................          (107,746,000)
        Other liabilities ...........................            (5,957,000)
                                                              -------------
            Purchase price ..........................         $ 178,204,000
                                                              =============


4.   PROPERTY AND EQUIPMENT

     The cost of property and equipment is summarized as follows:
<TABLE>
<CAPTION>
                                                       Estimated
                                                         Useful                            December 31,
                                                          Life               --------------------------------------
                                                         (Years)                    2004                2003
                                                     --------------          ------------------   -----------------

<S>                                                  <C>                     <C>                  <C>
       Land......................................           -                $       84,878,000   $      75,912,000
       Buildings.................................        25 - 35                     39,077,000          36,229,000
       Pipeline and terminaling equipment........        15 - 40                  1,187,323,000       1,115,458,000
       Marine equipment..........................        15 - 30                     87,937,000          87,204,000
       Furniture and fixtures....................        5 - 15                      15,201,000          11,388,000
       Transportation equipment..................         3 - 6                       7,790,000           7,360,000
       Construction work-in-progress.............           -                        28,766,000          26,768,000
                                                                             ------------------   -----------------
       Total property and equipment..............                                 1,450,972,000       1,360,319,000
       Less accumulated depreciation.............                                   302,381,000         247,349,000
                                                                             ------------------   -----------------
       Net property and equipment................                            $    1,148,591,000   $   1,112,970,000
                                                                             ==================   =================
</TABLE>


5.   LONG-TERM DEBT

     Long-term debt is summarized as follows:

<TABLE>
<CAPTION>
                                                                                           December 31,
                                                                             --------------------------------------
                                                                                    2004                2003
                                                                             ------------------   -----------------

<S>                                                                          <C>                  <C>
       $400 million revolving credit facility, due in April of 2006.......   $       95,669,000   $      54,169,000
       $250 million 5.875% senior unsecured notes, due in June of 2013....          250,000,000         250,000,000
       $250 million 7.75% senior unsecured notes, due in February of 2012.          250,000,000         250,000,000
       Term loans, due in April of 2006...................................           40,770,000          29,243,000
       Australian bank facility, due in April of 2006.....................           35,513,000          34,284,000
                                                                             ------------------   -----------------
       Total long-term debt...............................................   $      671,952,000   $     617,696,000
                                                                             ==================   =================
</TABLE>

     In April of 2003, the  Partnership  entered into a credit  agreement with a
group of banks that  provides  for a $400  million  unsecured  revolving  credit
facility  through  April of 2006.  The credit  facility,  which  provides for an
increase  in the  commitment  up to an  aggregate  of  $450  million  by  mutual
agreement  between the  Partnership  and the banks,  bears  interest at variable
rates and has a variable  commitment fee on unused amounts.  The credit facility
contains certain  financial and operating  covenants,  including  limitations on
investments,  sales of assets and  transactions  with  affiliates and, absent an
event of default,  does not restrict  distributions to partners. At December 31,
2004, the Partnership was in compliance with all covenants.  Initial  borrowings
on the  credit  agreement  ($324.2  million)  were  used to  repay  all  amounts
outstanding  under the  Partnership's  $275 million  credit  agreement  and $175
million  bridge  loan  agreement.  At  December  31,  2004,  $95.7  million  was
outstanding under the credit agreement.

     On May 19,  2003,  the  Partnership  issued $250  million of 5.875%  senior
unsecured  notes due June 1, 2013.  The net proceeds  from the public  offering,
$247.6  million,  were used to reduce  amounts  due under the  revolving  credit
agreement.  Under the note  indenture,  interest  is  payable  semi-annually  in
arrears on June 1 and December 1 of each year.  The notes are  redeemable,  as a
whole or in part, at the option of the Partnership, at any time, at a redemption
price equal to the greater of 100% of the principal  amount of the notes, or the
sum of the present  value of the remaining  scheduled  payments of principal and
interest,  discounted to the  redemption  date at the applicable  U.S.  Treasury
rate,  as defined in the  indenture,  plus 30 basis points.  The note  indenture
contains  certain  financial  and  operational   covenants,   including  certain
limitations on  investments,  sales of assets and  transactions  with affiliates
and, absent an event of default, such covenants do not restrict distributions to
partners.  At December 31, 2004,  the  Partnership  was in  compliance  with all
covenants.

     In February of 2002,  the  Partnership  issued $250 million of 7.75% senior
unsecured  notes  due  February  15,  2012.  The net  proceeds  from the  public
offering,  $248.2 million, were used to repay the Partnership's revolving credit
agreement and to partially fund the Statia  acquisition  (see Note 3). Under the
note indenture,  interest is payable semi-annually in arrears on February 15 and
August 15 of each year. The notes are redeemable,  as a whole or in part, at the
option of the  Partnership,  at any time,  at a  redemption  price  equal to the
greater of 100% of the principal  amount of the notes, or the sum of the present
value of the remaining scheduled payments of principal and interest,  discounted
to the redemption date at the applicable  U.S.  Treasury rate, as defined in the
indenture,  plus 30 basis points.  The note indenture contains certain financial
and operational covenants,  including certain limitations on investments,  sales
of assets and transactions with affiliates and, absent an event of default, such
covenants do not restrict  distributions to partners.  At December 31, 2004, the
Partnership was in compliance with all covenants.


6.   COMMITMENTS AND CONTINGENCIES

     Total rent expense under operating  leases amounted to $9.4 million,  $14.5
million and $13.4 million for the years ended December 31, 2002,  2003 and 2004,
respectively.

     The following is a schedule by years of future minimum lease payments under
operating leases as of December 31, 2004:
<TABLE>
<CAPTION>
<S>         <C>                                                         <C>
     Year ending December 31:
            2005..................................................      $    9,756,000
            2006..................................................           8,536,000
            2007..................................................           6,181,000
            2008..................................................           5,279,000
            2009..................................................           4,013,000
            Thereafter............................................          18,140,000
                                                                        --------------
      Total minimum lease payments................................      $   51,905,000
                                                                        ==============
</TABLE>

     The operations of the Partnership  are subject to federal,  state and local
laws and  regulations  in the United  States and the various  foreign  locations
relating to protection of the environment. Although the Partnership believes its
operations are in general compliance with applicable environmental  regulations,
risks of additional  costs and liabilities are inherent in pipeline and terminal
operations, and there can be no assurance that significant costs and liabilities
will not be incurred by the  Partnership.  Moreover,  it is possible  that other
developments, such as increasingly stringent environmental laws, regulations and
enforcement policies  thereunder,  and claims for damages to property or persons
resulting  from the operations of the  Partnership,  could result in substantial
costs and  liabilities  to the  Partnership.  The  Partnership  has  recorded an
undiscounted  reserve for environmental claims in the amount of $23.0 million at
December 31, 2004,  including $16.9 million related to acquisitions of pipelines
and  terminals.  During  2004,  2003 and  2002,  respectively,  the  Partnership
incurred  $6.7  million,  $2.1 million and $2.4 million of costs related to such
acquisition reserves and reduced the liability accordingly.

     KPL has indemnified the Partnership  against  liabilities for damage to the
environment  resulting from  operations of the pipeline prior to October 3, 1989
(the date of formation of the Partnership).  The indemnification does not extend
to any liabilities that arise after such date to the extent that the liabilities
result from changes in environmental laws and regulations.

     Certain subsidiaries of the Partnership were sued in a Texas state court in
1997  by  Grace  Energy  Corporation  ("Grace"),   the  entity  from  which  the
Partnership  acquired ST Services in 1993.  The lawsuit  involves  environmental
response and remediation  costs  allegedly  resulting from jet fuel leaks in the
early  1970's from a pipeline.  The  pipeline,  which  connected a former  Grace
terminal with Otis Air Force Base in  Massachusetts  (the "Otis pipeline" or the
"pipeline"),  ceased  operations in 1973 and was abandoned before 1978, when the
connecting  terminal  was  sold  to an  unrelated  entity.  Grace  alleged  that
subsidiaries of the Partnership  acquired the abandoned  pipeline as part of the
acquisition of ST Services in 1993 and assumed  responsibility for environmental
damages  allegedly caused by the jet fuel leaks.  Grace sought a ruling from the
Texas  court  that  these  subsidiaries  are  responsible  for all  liabilities,
including all present and future  remediation  expenses,  associated  with these
leaks and that Grace has no obligation to indemnify these subsidiaries for these
expenses.  In the  lawsuit,  Grace also sought  indemnification  for expenses of
approximately  $3.5  million  that it had  incurred  since 1996 for response and
remediation  required by the State of Massachusetts and for additional  expenses
that  it  expects  to  incur  in the  future.  The  consistent  position  of the
Partnership's  subsidiaries  has been that they did not  acquire  the  abandoned
pipeline  as part of the 1993 ST Services  transaction,  and  therefore  did not
assume any  responsibility  for the  environmental  damage nor any  liability to
Grace for the pipeline.

     At the end of the trial,  the jury  returned a verdict  including  findings
that (1) Grace had  breached a provision  of the 1993  acquisition  agreement by
failing to disclose  matters  related to the pipeline,  and (2) the pipeline was
abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired
ST Services.  On August 30, 2000,  the Judge entered final  judgment in the case
that Grace take nothing from the  subsidiaries on its claims seeking recovery of
remediation costs. Although the Partnership's subsidiaries have not incurred any
expenses in connection  with the  remediation,  the court also ruled, in effect,
that the subsidiaries would not be entitled to indemnification from Grace if any
such expenses were incurred in the future. Moreover, the Judge let stand a prior
summary  judgment  ruling  that  the  pipeline  was  an  asset  acquired  by the
Partnership's  subsidiaries as part of the 1993 ST Services transaction and that
any liabilities  associated  with the pipeline would have become  liabilities of
the  subsidiaries.  Based  on  that  ruling,  the  Massachusetts  Department  of
Environmental  Protection and Samson  Hydrocarbons  Company  (successor to Grace
Petroleum  Company) wrote letters to ST Services alleging its responsibility for
the remediation,  and ST Services  responded denying any liability in connection
with this  matter.  The Judge also awarded  attorney  fees to Grace of more than
$1.5 million.  Both the  Partnership's  subsidiaries and Grace have appealed the
trial  court's  final  judgment  to the Texas  Court of Appeals  in  Dallas.  In
particular,  the subsidiaries  have filed an appeal of the judgment finding that
the  Otis  pipeline  and any  liabilities  associated  with  the  pipeline  were
transferred to them as well as the award of attorney fees to Grace.

     On April 2, 2001,  Grace filed a petition in  bankruptcy,  which created an
automatic stay of actions  against Grace.  This automatic stay covers the appeal
of the Dallas  litigation,  and the Texas  Court of Appeals  has issued an order
staying all proceedings of the appeal because of the bankruptcy.  Once that stay
is lifted,  the Partnership's  subsidiaries that are party to the lawsuit intend
to resume vigorous prosecution of the appeal.

     The Otis Air Force Base is a part of the Massachusetts Military Reservation
("MMR Site"),  which has been declared a Superfund Site pursuant to CERCLA.  The
MMR Site contains a number of groundwater contamination plumes, two of which are
allegedly associated with the Otis pipeline,  and various other waste management
areas of concern,  such as landfills.  The United States  Department of Defense,
pursuant  to  a  Federal  Facilities  Agreement,  has  been  responding  to  the
Government  remediation demand for most of the contamination problems at the MMR
Site. Grace and others have also received and responded to formal inquiries from
the United  States  Government  in  connection  with the  environmental  damages
allegedly  resulting  from the jet fuel leaks.  The  Partnership's  subsidiaries
voluntarily   responded  to  an  invitation   from  the  Government  to  provide
information  indicating that they do not own the pipeline.  In connection with a
court-ordered  mediation between Grace and the Partnership's  subsidiaries,  the
Government  advised the parties in April 1999 that it has  identified  two spill
areas that it believes to be related to the pipeline  that is the subject of the
Grace suit.  The Government at that time advised the parties that it believed it
had incurred costs of approximately  $34 million,  and expected in the future to
incur costs of  approximately  $55 million,  for remediation of one of the spill
areas.  This  amount was not  intended to be a final  accounting  of costs or to
include all categories of costs. The Government also advised the parties that it
could not at that time allocate its costs attributable to the second spill area.

     By letter  dated July 26, 2001,  the United  States  Department  of Justice
("DOJ")  advised ST Services that the Government  intends to seek  reimbursement
from ST Services  under the  Massachusetts  Oil and Hazardous  Material  Release
Prevention  and  Response  Act  and  the   Declaratory   Judgment  Act  for  the
Government's  response  costs at the two spill areas  discussed  above.  The DOJ
relied in part on the Texas state court judgment,  which in the DOJ's view, held
that  ST   Services   was  the   current   owner   of  the   pipeline   and  the
successor-in-interest of the prior owner and operator. The Government advised ST
Services  that it believes it has incurred  costs  exceeding  $40  million,  and
expects  to  incur  future  costs  exceeding  an  additional  $22  million,  for
remediation  of  the  two  spill  areas.  The  Partnership   believes  that  its
subsidiaries  have  substantial  defenses.  ST Services  responded to the DOJ on
September  6, 2001,  contesting  the  Government's  positions  and  declining to
reimburse  any  response  costs.  The DOJ has not  filed a  lawsuit  against  ST
Services seeking cost recovery for its environmental  investigation and response
costs.  Representatives  of ST  Services  have met with  representatives  of the
Government  on  several  occasions  since  September  6,  2001  to  discuss  the
Government's  claims  and  to  exchange  information  related  to  such  claims.
Additional  exchanges  of  information  are  expected to occur in the future and
additional   meetings  may  be  held  to  discuss  possible  resolution  of  the
Government's  claims without  litigation.  The Partnership does not believe this
matter  will  have a  materially  adverse  effect  on its  financial  condition,
although there can be no assurances as to the ultimate outcome.

     On April 7, 2000, a fuel oil pipeline in Maryland owned by Potomac Electric
Power Company ("PEPCO") ruptured. Work performed with regard to the pipeline was
conducted by a partnership  of which ST Services is general  partner.  PEPCO has
reported that it has incurred total cleanup costs of $70 million to $75 million.
PEPCO  probably  will  continue  to incur  some  cleanup  related  costs for the
foreseeable future, primarily in connection with EPA requirements for monitoring
the  condition of some of the impacted  areas.  Since May 2000,  ST Services has
provisionally  contributed a minority  share of the cleanup  expense,  which has
been funded by ST Services' insurance carriers.  ST Services and PEPCO have not,
however,   reached  a  final  agreement  regarding  ST  Services'  proportionate
responsibility  for this cleanup effort,  if any, and cannot predict the amount,
if any,  that  ultimately  may be  determined  to be ST  Services'  share of the
remediation  expense,  but ST Services believes that such amount will be covered
by  insurance  and  therefore   will  not   materially   adversely   affect  the
Partnership's financial condition.

     As a result of the rupture,  purported  class  actions  were filed  against
PEPCO and ST Services  in federal  and state  court in Maryland by property  and
business owners alleging damages in unspecified  amounts under various theories,
including  under the Oil  Pollution  Act ("OPA") and  Maryland  common law.  The
federal  court  consolidated  all of the federal cases in a case styled as In re
Swanson  Creek Oil Spill  Litigation.  A settlement  of the  consolidated  class
action,  and a companion  state-court class action,  was reached and approved by
the federal judge. The settlement  involved creation and funding by PEPCO and ST
Services of a $2,250,000  class  settlement  fund, from which all  participating
claimants  would be paid  according to a  court-approved  formula,  as well as a
court-approved  payment  to  plaintiffs'  attorneys.  The  settlement  has  been
consummated  and the fund,  to which  PEPCO and ST  Services  contributed  equal
amounts, has been distributed. Participating claimants' claims have been settled
and  dismissed  with  prejudice.  A  number  of  class  members  elected  not to
participate  in the  settlement,  i.e., to "opt out," thereby  preserving  their
claims  against  PEPCO and ST  Services.  All  non-participant  claims have been
settled for  immaterial  amounts with ST Services'  portion of such  settlements
provided by its insurance carrier.

     PEPCO and ST Services  agreed with the federal  government and the State of
Maryland to pay costs of assessing  natural  resource  damages  arising from the
Swanson Creek oil spill under OPA and of selecting  restoration  projects.  This
process was  completed in mid-2002.  ST Services'  insurer has paid ST Services'
agreed 50 percent share of these assessment  costs. In late November 2002, PEPCO
and ST Services  entered into a Consent  Decree  resolving the federal and state
trustees' claims for natural resource  damages.  The decree required payments by
ST  Services  and  PEPCO  of a total of  approximately  $3  million  to fund the
restoration  projects and for remaining  damage  assessment  costs.  The federal
court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO
and ST Services  have each paid their 50% share and thus fully  performed  their
payment  obligations  under the Consent Decree.  ST Services'  insurance carrier
funded ST Services' payment.

     The U.S.  Department  of  Transportation  ("DOT")  has  issued a Notice  of
Proposed  Violation to PEPCO and ST Services  alleging  violations  over several
years of pipeline  safety  regulations and proposing a civil penalty of $647,000
jointly against the two companies.  ST Services and PEPCO have contested the DOT
allegations  and the proposed  penalty.  A hearing was held before the Office of
Pipeline Safety at the DOT in late 2001. In June of 2004, the DOT issued a final
order reducing the penalty to $256,250 jointly against ST Services and PEPCO and
$74,000 against ST Services.  On September 14, 2004, ST Services  petitioned for
reconsideration of the order.

     By letter  dated  January 4, 2002,  the Attorney  General's  Office for the
State of Maryland advised ST Services that it intended to seek penalties from ST
Services  in  connection  with the April 7, 2000  spill.  The State of  Maryland
subsequently asserted that it would seek penalties against ST Services and PEPCO
totaling up to $12 million.  A settlement  of this claim was reached in mid-2002
under  which ST  Services'  insurer  will pay a total of  slightly  more than $1
million  in  installments  over a five year  period.  PEPCO  has also  reached a
settlement  of  these  claims  with  the  State of  Maryland.  Accordingly,  the
Partnership believes that this matter will not have a material adverse effect on
its financial condition.

     On  December  13,  2002,  ST  Services  sued PEPCO in the  Superior  Court,
District of Columbia,  seeking, among other things, a declaratory judgment as to
ST Services' legal obligations,  if any, to reimburse PEPCO for costs of the oil
spill.  On  December  16,  2002,  PEPCO sued ST  Services  in the United  States
District Court for the District of Maryland,  seeking  recovery of all its costs
for  remediation  of and  response to the oil spill.  Pursuant  to an  agreement
between ST Services  and PEPCO,  ST  Services'  suit was  dismissed,  subject to
refiling.  ST  Services  has moved to  dismiss  PEPCO's  suit.  ST  Services  is
vigorously   defending   against   PEPCO's   claims  and  is  pursuing  its  own
counterclaims  for  return of  monies  ST  Services  has  advanced  to PEPCO for
settlements  and  cleanup  costs.  The  Partnership  believes  that any costs or
damages resulting from these lawsuits will be covered by insurance and therefore
will not materially adversely affect the Partnership's financial condition.  The
amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy
which has a $600,000  retention,  but the Partnership does not believe that such
retention,  if incurred,  would materially  adversely  affect the  Partnership's
financial condition.

     In 2003,  Exxon Mobil filed a lawsuit in the New Jersey state court against
GATX  Corporation,   Kinder  Morgan  Liquid  Terminals  ("Kinder  Morgan"),  the
successor in interest to GATX Terminals Corporation  ("GATX"),  and ST Services,
seeking  reimbursement for remediation costs associated with the Paulsboro,  New
Jersey  terminal.  The  terminal  was owned and operated by Exxon Mobil from the
early  1950's  until 1990 when  purchased  by GATX.  ST Services  purchased  the
terminal in 2000 from GATX. GATX was subsequently  acquired by Kinder Morgan. As
a  condition  to the  sale  to GATX  in  1990,  Exxon  Mobil  undertook  certain
remediation obligations with respect to the site. In the lawsuit, Exxon Mobil is
claiming that it has complied with its remediation  and contractual  obligations
and is entitled to reimbursement  from GATX  Corporation,  the parent company of
GATX, Kinder Morgan, and ST Services for costs in the amount of $400,000 that it
claims  are  related  to  releases  at the  site  subsequent  to its sale of the
terminal  to  GATX.  It  is  also   alleging  that  any  remaining   remediation
requirements are the  responsibility of GATX  Corporation,  Kinder Morgan, or ST
Services.  Kinder  Morgan has alleged  that it was  relieved of any  remediation
obligations pursuant to the sale agreement between its predecessor, GATX, and ST
Services. ST Services believes that, except for remediation involving immaterial
amounts,  GATX  Corporation  or Exxon Mobil are  responsible  for the  remaining
remediation of the site. Costs of completing the required  remediation depend on
a number of factors and cannot be determined at the current time.

     A subsidiary  of the  Partnership  purchased the  approximately  2,000-mile
ammonia  pipeline  system from Koch Pipeline  Company,  L.P. and Koch Fertilizer
Storage and  Terminal  Company in 2002.  The rates of the ammonia  pipeline  are
subject to regulation by the Surface  Transportation  Board (the "STB"). The STB
had  issued  an order in May  2000,  prescribing  maximum  allowable  rates  the
Partnership's predecessor could charge for transportation to certain destination
points on the pipeline system. In 2003, the Partnership  instituted a 7% general
increase to pipeline rates. On August 1, 2003, CF Industries, Inc. ("CFI") filed
a complaint with the STB challenging  these rate increases.  On August 11, 2004,
STB ordered the  Partnership to pay reparations to CFI and to return CFI's rates
to the  levels  permitted  under  the rate  prescription.  The  Partnership  has
complied with the order. The STB, however,  indicated in the order that it would
lift the rate  prescription in the event the Partnership  could show "materially
changed  circumstances."  The Partnership has submitted  evidence of "materially
changed  circumstances,"  which specifically  includes its capital investment in
the pipeline. CFI has argued that the Partnership's acquisition costs should not
be considered by the STB as a measure of the Partnership's  investment base. The
STB is expected to decide the issue within the second quarter of 2005.

     Also, on June 16, 2003, Dyno Nobel Inc. ("Dyno") filed a complaint with the
STB  challenging  the 2003 rate increase on the basis that (i) the rate increase
constitutes a violation of a contract rate,  (ii) rates are  discriminatory  and
(iii)  the rates  exceed  permitted  levels.  Dyno  also  intervened  in the CFI
proceeding  described above.  Unlike CFI, Dyno's rates are not subject to a rate
prescription.  As of December 31, 2004, Dyno would be entitled to  approximately
$2 million in rate refunds,  should it be successful.  The Partnership believes,
however, that Dyno's claims are without merit.

     The Partnership has other contingent liabilities resulting from litigation,
claims and commitments  incident to the ordinary course of business.  Management
of the Partnership  believes,  after consulting with counsel,  that the ultimate
resolution of such  contingencies  will not have a materially  adverse effect on
the financial position, results of operations or liquidity of the Partnership.


7.   RELATED PARTY TRANSACTIONS

     The  Partnership has no employees and is managed and controlled by KPL. KPL
and KSL are entitled to  reimbursement  of all direct and indirect costs related
to the business activities of the Partnership.  These costs, which totaled $36.0
million,  $36.3 million and $27.3 million for the years ended December 31, 2004,
2003 and 2002, respectively,  include compensation and benefits paid to officers
and employees of KPL and KSL,  insurance  premiums,  general and  administrative
costs,  tax information and reporting costs,  legal and audit fees.  Included in
this amount is $24.2  million,  $26.6 million and $17.7 million of  compensation
and benefits,  paid to officers and employees of KPL and KSL for the years ended
December 31, 2004,  2003 and 2002,  respectively.  In addition,  the Partnership
paid $0.8 million in 2004,  $0.6 million in 2003 and $0.6 million in 2002 for an
allocable portion of KPL's overhead expenses. At December 31, 2004 and 2003, the
Partnership  owed KPL and KSL $4.5 million and $3.6 million,  respectively,  for
these expenses which are due under normal invoice terms.


8.   BUSINESS SEGMENT DATA

     The Partnership  conducts  business through three principal  segments;  the
"Pipeline Operations," which consists primarily of the transportation of refined
petroleum  products and fertilizer in the Midwestern states as a common carrier,
the "Terminaling  Operations,"  which provides  storage for petroleum  products,
specialty chemicals and other liquids, and the "Product Sales Operations", which
delivers bunker fuel to ships in the Caribbean and Nova Scotia, Canada and sells
bulk petroleum products to various commercial interests.

     The Partnership  measures segment profit as operating income.  Total assets
are those assets controlled by each reportable segment. Business segment data is
as follows:

<TABLE>
<CAPTION>

                                                                                  Year Ended December 31,
                                                                ------------------------------------------------------
                                                                       2004                2003              2002
                                                                ----------------    ---------------     --------------
<S>                                                             <C>                 <C>                 <C>
       Business segment revenues:
         Pipeline operations..................................  $    119,803,000    $   119,633,000     $   82,698,000
         Terminaling operations...............................       259,352,000        234,958,000        205,971,000
         Product sales operations.............................       269,054,000        215,823,000         97,961,000
                                                                ----------------    ---------------     --------------
                                                                $    648,209,000    $   570,414,000     $  386,630,000
                                                                ================    ===============     ==============
       Business segment profit:
         Pipeline operations..................................  $     48,853,000    $    51,860,000     $   38,623,000
         Terminaling operations...............................        74,663,000         66,532,000         65,040,000
         Product sales operations.............................        13,274,000         10,109,000          2,058,000
                                                                ----------------    ---------------     --------------
            Operating income..................................       136,790,000        128,501,000        105,721,000
         Interest and other income ...........................           267,000            261,000          3,570,000
         Interest expense.....................................       (42,750,000)       (38,757,000)       (28,110,000)
         Loss on debt extinguishment..........................             -                   -            (3,282,000)
                                                                ----------------    ---------------     --------------
            Income before income taxes and cumulative effect
              of change in accounting principle...............  $     94,307,000    $    90,005,000     $   77,899,000
                                                                ================    ===============     ==============
       Business segment assets:
         Depreciation and amortization:
            Pipeline operations...............................  $     14,538,000    $    14,117,000     $    6,408,000
            Terminaling operations............................        41,232,000         38,089,000         32,368,000
            Product sales operations..........................           878,000            949,000            649,000
                                                                ----------------    ---------------     --------------

                                                                $     56,648,000    $    53,155,000     $   39,425,000
                                                                ================    ===============     ==============
         Capital expenditures (excluding acquisitions):
            Pipeline operations...............................  $     10,334,000    $     9,584,000     $    9,469,000
            Terminaling operations............................        29,511,000         34,572,000         20,953,000
            Product sales operations..........................         2,369,000            585,000            679,000
                                                                ----------------    ---------------     --------------
                                                                $     42,214,000    $    44,741,000     $   31,101,000
                                                                ================    ===============     ==============
         Total assets:
           Pipeline operations................................  $    351,195,000    $   352,901,000     $  352,657,000
           Terminaling operations.............................       917,966,000        874,185,000        844,321,000
            Product sales operations..........................        56,155,000         37,596,000         18,432,000
                                                                ----------------    ---------------     --------------
                                                                $  1,325,316,000    $ 1,264,682,000     $1,215,410,000
                                                                ================    ===============     ==============
</TABLE>

     The following geographical area data includes revenues and operating income
based on location of the operating  segment and net property and equipment based
on physical location.

<TABLE>
<CAPTION>
                                                                                  Year Ended December 31,
                                                                ------------------------------------------------------
                                                                       2004                2003              2002
                                                                ----------------    ---------------     --------------
<S>                                                             <C>                 <C>                 <C>
       Geographical area revenues:
         United States........................................  $    251,775,000    $   240,518,000     $  202,124,000
         United Kingdom.......................................        29,540,000         26,392,000         23,937,000
         Netherlands Antilles.................................       298,273,000        241,693,000        132,387,000
         Canada...............................................        43,671,000         41,689,000         23,207,000
         Australia and New Zealand............................        24,950,000         20,122,000          4,975,000
                                                                ----------------    ---------------     --------------
                                                                $    648,209,000    $   570,414,000     $  386,630,000
                                                                ================    ===============     ==============
       Geographical area operating income:
         United States........................................  $     93,965,000    $    87,962,000     $   82,906,000
         United Kingdom.......................................         7,704,000          8,583,000          7,318,000
         Netherlands Antilles.................................        22,629,000         19,223,000          9,616,000
         Canada...............................................         5,248,000          6,777,000          4,398,000
         Australia and New Zealand............................         7,244,000          5,956,000          1,483,000
                                                                ----------------    ---------------     --------------
                                                                $    136,790,000    $   128,501,000     $  105,721,000
                                                                ================    ===============     ==============
</TABLE>

<TABLE>
<CAPTION>

                                                                                       December 31,
                                                                ------------------------------------------------------
                                                                       2004                2003              2002
                                                                ----------------    ---------------     --------------
<S>                                                             <C>                 <C>                 <C>
       Geographical area net property and equipment:
         United States........................................  $    718,236,000    $   693,295,000     $  690,178,000
         United Kingdom.......................................        63,968,000         51,392,000         46,543,000
         Netherlands Antilles.................................       211,382,000        217,143,000        224,810,000
         Canada...............................................        71,374,000         74,995,000         78,789,000
         Australia and New Zealand............................        83,631,000         76,145,000         51,872,000
                                                                ----------------    ---------------     --------------
                                                                $  1,148,591,000    $ 1,112,970,000     $1,092,192,000
                                                                ================    ===============     ==============
</TABLE>


9.   FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK

     The  estimated  fair value of all debt as of December 31, 2004 and 2003 was
approximately  $728 million and $630 million,  as compared to the carrying value
of $672 million and $618 million, respectively. These fair values were estimated
using  discounted  cash  flow  analysis,  based  on  the  Partnership's  current
incremental borrowing rates for similar types of borrowing  arrangements.  These
estimates are not  necessarily  indicative of the amounts that would be realized
in a current market exchange. See Note 2 regarding derivative instruments.

     The Partnership markets and sells its services to a broad base of customers
and performs ongoing credit  evaluations of its customers.  The Partnership does
not believe it has a  significant  concentration  of credit risk at December 31,
2004. No customer  constituted  10 percent or more of  consolidated  revenues in
2004, 2003 or 2002.


10.  QUARTERLY FINANCIAL DATA (unaudited)

     Quarterly operating results for 2004 and 2003 are summarized as follows:

<TABLE>
<CAPTION>
                                                                            Quarter Ended
                                            --------------------------------------------------------------------------
                                                March 31,           June 30,         September 30,       December 31,
                                            ----------------    ----------------    ---------------     --------------
2004:
<S>                                         <C>                 <C>                 <C>                 <C>
       Revenues.......................      $    146,413,000    $    153,958,000    $   167,668,000     $  180,170,000
                                            ================    ================    ===============     ==============
       Operating income...............      $     32,562,000    $     35,650,000    $    34,146,000     $   34,432,000
                                            ================    ================    ===============     ==============
       Net income.....................      $     20,979,000    $     24,531,000    $    22,291,000     $   23,224,000
                                            ================    ================    ===============     ==============

2003:
       Revenues.......................      $    140,757,000    $    146,948,000    $   140,404,000     $  142,305,000
                                            ================    ================    ===============     ==============
       Operating income...............      $     33,598,000    $     33,041,000    $    32,016,000     $   29,846,000
                                            ================    ================    ===============     ==============
       Net income.....................      $     22,049,000(a) $     22,829,000    $    20,323,000     $   17,988,000
                                            ================    ================    ===============     ==============
</TABLE>

(a)  Includes cumulative effect of change in accounting  principle - adoption of
     new accounting  standard for asset retirement  obligations of approximately
     $1.6 million in expense.


<PAGE>
                                                                     Schedule II

                   KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
                        VALUATION AND QUALIFYING ACCOUNTS
                                 (in thousands)

<TABLE>
<CAPTION>

                                                                    Additions
                                                         ------------------------------
                                        Balance at        Charged to        Charged to                      Balance at
                                       Beginning of       Costs and            Other                          End of
                                          Period           Expenses          Accounts       Deductions        Period
                                       ------------      ------------      ------------     ----------     ------------

<S>                                     <C>               <C>              <C>              <C>            <C>
ALLOWANCE DEDUCTED FROM
  ASSETS TO WHICH THEY APPLY

Year Ended December 31, 2004:
   For doubtful receivables
     classified as current assets...    $     1,693       $       832      $       -        $  (1,242)(b)  $    1,283
                                        ===========       ===========      ===========      =========      ==========

Year Ended December 31, 2003:
   For doubtful receivables
     classified as current assets...    $     1,765       $       401      $       -        $    (473)(b)  $    1,693
                                        ===========       ===========      ===========      =========      ==========

Year Ended December 31, 2002:
   For doubtful receivables
     classified as current assets...    $       278       $       925      $       841(a)   $    (279)(b)  $    1,765
                                        ===========       ===========      ===========      =========      ==========
</TABLE>


Notes:

(a)  Allowance for doubtful receivables from 2002 acquisitions.

(b)  Receivable write-offs and reclassifications, net of recoveries.


<PAGE>
                                   SIGNATURES

     Pursuant  to the  requirements  of Section  13 or 15 (d) of the  Securities
Exchange  Act of 1934,  Kaneb Pipe Line  Operating  Partnership,  L.P.  has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.

                                         KANEB PIPE LINE OPERATING
                                         PARTNERSHIP, L.P.
                                         By:      Kaneb Pipe Line Company LLC
                                                  General Partner

                                         By:       //s// EDWARD D. DOHERTY
                                             -----------------------------------
                                             Chairman of the Board and
                                             Chief  Executive Officer
                                             Date: March 16, 2005


     Pursuant to the  requirements  of the  Securities and Exchange Act of 1934,
this report has been signed  below by the  following  persons on behalf of Kaneb
Pipe Line Operating Partnership, L.P. and in the capacities with Kaneb Pipe Line
Company LLC and on the date indicated.

<TABLE>
<CAPTION>
      Signature                                                       Title                      Date
----------------------------------------                       ----------------------        ---------------

Principal Executive Officer
<S>                                                            <C>                           <C>
      //s//  EDWARD D. DOHERTY                                 Chairman of the Board         March 16, 2005
----------------------------------------                       and Chief Executive Officer

Principal Accounting Officer
     //s//  HOWARD C. WADSWORTH                                Vice President                March 16, 2005
----------------------------------------                       Treasurer & Secretary


Directors

         //s//  SANGWOO AHN                                    Director                      March 16, 2005
----------------------------------------


        //s//  JOHN R. BARNES                                  Director                      March 16, 2005
----------------------------------------


       //s//  MURRAY R. BILES                                  Director                      March 16, 2005
----------------------------------------


        //s//  FRANK M. BURKE                                  Director                      March 16, 2005
----------------------------------------


       //s//  CHARLES R. COX                                   Director                      March 16, 2005
----------------------------------------


         //s//  HANS KESSLER                                   Director                      March 16, 2005
----------------------------------------


       //s//  JAMES R. WHATLEY                                 Director                      March 16, 2005
----------------------------------------

</TABLE>



<PAGE>
                                                                    Exhibit 31.1


                    CERTIFICATION OF CHIEF EXECUTIVE OFFICER
            PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Edward D. Doherty, Chief Executive Officer of Kaneb Pipe Line Company LLC, as
General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:

1.   I have  reviewed  this  annual  report  on Form  10-K of  Kaneb  Pipe  Line
     Operating Partnership, L.P.;

2.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information included in this annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The  registrant's  other  certifying  officers  and I are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules  13a-15(e) and 15d-15(e))  and internal  control over
     financial  reporting  (as  defined  in  Exchange  Act Rules  13a-15(f)  and
     15d-15(f)) for the registrant and have:

     a)   designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  to ensure  that  material  information  relating  to the
          registrant,  including its consolidated subsidiaries, is made known to
          us by others within those entities,  particularly during the period in
          which this annual report is being prepared;

     b)   designed such internal  control over  financial  reporting,  or caused
          such internal  control over  financial  reporting to be designed under
          our  supervision,   to  provide  reasonable  assurance  regarding  the
          reliability  of financial  reporting and the  preparation of financial
          statements for external purposes in accordance with generally accepted
          accounting principles;

     c)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and  procedures  and presented in this annual  report our  conclusions
          about the effectiveness of the disclosure controls and procedures,  as
          of the end of the period covered by this annual report,  based on such
          evaluation; and

     d)   disclosed  in  this  annual  report  any  change  in the  registrant's
          internal  control over financial  reporting  that occurred  during the
          registrant's most recent fiscal quarter that has materially  affected,
          or  is  reasonably  likely  to  materially  affect,  the  registrant's
          internal control over financial reporting; and

5.   The registrant's other certifying  officers and I have disclosed,  based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     a)   all significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.


Date: March 16, 2005


                                                //s//  EDWARD D. DOHERTY
                                             -----------------------------------
                                             Edward D. Doherty
                                             Chief Executive Officer


<PAGE>
                                                                    Exhibit 31.2


                    CERTIFICATION OF CHIEF FINANCIAL OFFICER
            PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Howard C. Wadsworth,  Chief Financial Officer of Kaneb Pipe Line Company LLC,
as General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:

1.   I have  reviewed  this  annual  report  on Form  10-K of  Kaneb  Pipe  Line
     Operating Partnership, L.P.;

2.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information included in this annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The  registrant's  other  certifying  officers  and I are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules  13a-15(e) and 15d-15(e))  and internal  control over
     financial  reporting  (as  defined  in  Exchange  Act Rules  13a-15(f)  and
     15d-15(f)) for the registrant and have:

     a)   designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  to ensure  that  material  information  relating  to the
          registrant,  including its consolidated subsidiaries, is made known to
          us by others within those entities,  particularly during the period in
          which this annual report is being prepared;

     b)   designed such internal  control over  financial  reporting,  or caused
          such internal  control over  financial  reporting to be designed under
          our  supervision,   to  provide  reasonable  assurance  regarding  the
          reliability  of financial  reporting and the  preparation of financial
          statements for external purposes in accordance with generally accepted
          accounting principles;

     c)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and  procedures  and presented in this annual  report our  conclusions
          about the effectiveness of the disclosure controls and procedures,  as
          of the end of the period covered by this annual report,  based on such
          evaluation; and

     d)   disclosed  in  this  annual  report  any  change  in the  registrant's
          internal  control over financial  reporting  that occurred  during the
          registrant's most recent fiscal quarter that has materially  affected,
          or  is  reasonably  likely  to  materially  affect,  the  registrant's
          internal control over financial reporting; and

5.   The registrant's other certifying  officers and I have disclosed,  based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     a)   all significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.


Date: March 16, 2005



                                               //s//  HOWARD C. WADSWORTH
                                             -----------------------------------
                                             Howard C. Wadsworth
                                             Chief Financial Officer





<PAGE>
                                                                    Exhibit 32.1


                    CERTIFICATION OF CHIEF EXECUTIVE OFFICER
          PURSUANT TO SECTION 906(A) OF THE SARBANES-OXLEY ACT OF 2002


The  undersigned,  being the Chief Executive  Officer of Kaneb Pipe Line Company
LLC, as General  Partner of Kaneb Pipe Line  Operating  Partnership,  L.P.  (the
"Partnership"),  hereby  certifies  that, to his  knowledge,  the  Partnership's
Annual Report on Form 10-K for the year ended December 31, 2004,  filed with the
United States  Securities and Exchange  Commission  pursuant to Section 13(a) or
15(d) of the Securities  Exchange Act of 1934 (15 U.S.C.  78m or 78o(d)),  fully
complies  with the  requirements  of  Section  13(a) or 15(d) of the  Securities
Exchange Act of 1934 and that information contained in such Annual Report fairly
presents,  in all material  respects,  the  financial  condition  and results of
operations of the Partnership.

This  written  statement  is being  furnished  to the  Securities  and  Exchange
Commission  as an exhibit to such Form 10-K.  A signed  original of this written
statement required by Section 906 has been provided to Kaneb Pipe Line Operating
Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership,
L.P. and furnished to the Securities  and Exchange  Commission or its staff upon
request.

Date:    March 16, 2005



                                        //s//  EDWARD D. DOHERTY
                                        ----------------------------------------
                                        Edward D. Doherty
                                        Chief Executive Officer




<PAGE>
                                                                    Exhibit 32.2



                    CERTIFICATION OF CHIEF FINANCIAL OFFICER
          PURSUANT TO SECTION 906(A) OF THE SARBANES-OXLEY ACT OF 2002


The  undersigned,  being the Chief Financial  Officer of Kaneb Pipe Line Company
LLC, as General  Partner of Kaneb Pipe Line  Operating  Partnership,  L.P.  (the
"Partnership"),  hereby  certifies  that, to his  knowledge,  the  Partnership's
Annual Report on Form 10-K for the year ended December 31, 2004,  filed with the
United States  Securities and Exchange  Commission  pursuant to Section 13(a) or
15(d) of the Securities  Exchange Act of 1934 (15 U.S.C.  78m or 78o(d)),  fully
complies  with the  requirements  of  Section  13(a) or 15(d) of the  Securities
Exchange Act of 1934 and that information contained in such Annual Report fairly
presents,  in all material  respects,  the  financial  condition  and results of
operations of the Partnership.

This  written  statement  is being  furnished  to the  Securities  and  Exchange
Commission  as an exhibit to such Form 10-K.  A signed  original of this written
statement required by Section 906 has been provided to Kaneb Pipe Line Operating
Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership,
L.P. and furnished to the Securities  and Exchange  Commission or its staff upon
request.

Date:    March 16, 2005


                                               //s//  HOWARD C. WADSWORTH
                                         ---------------------------------------
                                         Howard C. Wadsworth
                                         Vice President, Treasurer and Secretary
                                         (Chief Financial Officer)


<PAGE>
                                                                      Exhibit 23


            Consent of Independent Registered Public Accounting Firm


The Partners of
Kaneb Pipe Line Operating Partnership, L.P.:


     We consent to the incorporation by reference in the registration  statement
numbers  333-71638  and  333-108642  on Form S-3 of Kaneb  Pipe  Line  Operating
Partnership,  L.P.  of our report  dated  March 11,  2005,  with  respect to the
consolidated balance sheets of Kaneb Pipe Line Operating  Partnership,  L.P. and
subsidiaries  as of  December  31, 2004 and 2003,  and the related  consolidated
statements of income,  partners' capital and cash flows for each of the years in
the three-year period ended December 31, 2004, and related  financial  statement
schedule,  which report  appears in the December 31, 2004 annual  report on Form
10-K of Kaneb Pipe Line  Operating  Partnership,  L.P.  Our  report  refers to a
change in accounting for asset retirement obligations in 2003.


                                        KPMG LLP


Dallas, Texas
March 16, 2005