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, 2003

                                       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.

                          X   Yes      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).

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




<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 the 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").


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  consists of 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  1,118,393 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 presently  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  which  was  leased  back to Koch  Nitrogen.  The  operations
headquarters  for the  Ammonia  Pipeline is located in  Hermann,  Missouri.  The
Ammonia  Pipeline is connected to twenty-two  other third party owned  terminals
and  also  has  several  industrial  facility  delivery  locations.  Product  is
primarily  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,
2003, these three systems combined transported a total of 3.7 million barrels of
diesel fuel, representing an aggregate of $1.5 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.  In addition
information on the North Pipeline  system prior to 2003 is not included.  During
the year of  2003,  the  Ammonia  Pipeline  shipped  1,155,160  tons of  ammonia
generating $21.3 million of revenue.
<TABLE>
<CAPTION>

                                                              Year Ended December 31,
                               ------------------------------------------------------------------------------------
                                    2003             2002              2001             2000              1999
                               -------------     -------------    --------------    -------------    --------------
<S>                            <C>               <C>              <C>               <C>              <C>
Volume (1)..................         102,928            89,780            92,116           89,192            85,356
Barrel miles (2)............          21,327            18,275            18,567           17,843            18,440
Revenues (3)................         $98,329           $78,240           $74,976          $70,685           $67,607
</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)
                               ------------------------------------------------------------------------------------
                                    2003             2002              2001             2000              1999
                               -------------     -------------    --------------    -------------    --------------
<S>                            <C>               <C>              <C>               <C>               <C>
Gasoline....................          53,205            45,106            46,268           44,215            41,472
Diesel and fuel oil.........          46,072            40,450            42,354           41,087            40,435
Propane.....................           3,651             4,224             3,494            3,890             3,449
                               -------------     -------------    --------------    -------------    --------------
Total.......................         102,928            89,780            92,116           89,192            85,356
                               =============     =============    ==============    =============    ==============
</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 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 Pipeline's  rights-of-way and possible damage to
the Pipelines.

         The  Partnership  uses  state-of-the-art  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  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
Surface Transportation Board, 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, 2003, 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>
             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 13 storage  tanks at El Dorado,  Kansas  and 10 storage  tanks at  McPherson,
Kansas, with aggregate capacities of approximately  584,393 and 534,000 barrels,
respectively.   During  2003,  approximately  56.7%,  91.7%  and  85.5%  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  to
support their leased terminal obligations.

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 Pipeline.  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 2003 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
Conoco/Phillips,  Inc.  respectively.  The NCRA and Frontier Refining refineries
are connected  directly to the East  Pipeline.  The McPherson,  Kansas  refinery
operated  by NCRA  accounted  for  approximately  30.1% of the  total  amount of
product  shipped  over the East  Pipeline in 2003.  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 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 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  55 shippers in 2003. The
principal  shippers  include  four  integrated  oil  companies,   four  refining
companies,  three  large  farm  cooperatives  and one  railroad.  Transportation
revenues  attributable to the top 10 shippers were $86.6 million,  $61.5 million
and $51.5  million,  which  accounted for 72%, 74% and 69% of total  Partnership
revenues shipped for each of the years 2003, 2002 and 2001, 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.  Twenty-one 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
Conoco/Phillips. 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  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.  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, 2003,  the  Partnership's  terminaling
business  accounted for approximately 41% of the Partnership's  revenues.  As of
December 31, 2003, ST operated 37 facilities in 20 states,  with a total storage
capacity of approximately  33.9 million  barrels.  ST also owns and operates six
terminals   located  in  the  United   Kingdom,   having  a  total  capacity  of
approximately  5.5  million  barrels.  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 2003,  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 BPD 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  (collectively  "Steuart") 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.

         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 31 other terminal  facilities located throughout the United States,
six facilities in the United  Kingdom,  four facilities in Australia and four 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 and caustic
solutions, as well as petroleum products;  Vancouver,  Washington, which handles
chemicals and fertilizer;  Eastham,  United Kingdom which handles  chemicals and
animal fats; 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                     2,161,000           136       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
Bremen, GA                           182,000             9       Petroleum, Jet Fuel
Brunswick, GA                        302,000             3       Fertilizer, Pulp Liquor
Columbus, GA                         175,000            24       Petroleum, Chemicals
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       Petroleum, Fertilizer
Indianapolis, IN                     410,000            18       Petroleum
Westwego, LA                         849,000            53       Molasses, Fertilizer, Caustic,
                                                                 Chemicals
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
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
Dumfries, VA                         554,000            16       Petroleum, Asphalt
Virginia Beach, VA(b)                 40,000             2       Jet Fuel
Tacoma, WA                           377,000            15       Petroleum
Vancouver, WA                        543,000            55       Chemicals, Fertilizer, Petroleum
Milwaukee, WI                        308,000             7       Petroleum

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 sulphur
Glasgow, Scotland                    344,000            16       Petroleum
Leith, Scotland                      459,000            34       Petroleum, Chemicals
Belfast, Northern Ireland            407,000            41       Petroleum
                                 ---------------  --------------
                                  59,538,000         1,502
                                 ===============  ==============

</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,  six 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 $9.6 million, $9.5
million and $4.3  million for 2003,  2002 and 2001,  respectively.  During these
periods,  adequate  capacity  existed on these  pipelines to accommodate  volume
growth, and the expenditures  required for environmental and safety improvements
were not material in amount. Capital expenditures, including routine maintenance
and expansion expenditures,  but excluding  acquisitions,  for the Partnership's
terminaling  operations were $34.6 million,  $21.0 million and $12.9 million for
2003, 2002 and 2001, respectively.

         Capital  expenditures of the Partnership during 2004, including routine
maintenance and expansion expenditures, but excluding acquisitions, are expected
to be approximately $28 million to $32 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. 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 Surface  Transportation
Board (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,
has filed a protest  against  the tariff  filing.  Dyno's  protest  centered  on
basically two issues.  First, it questioned the Partnership's  ability to file a
tariff without first obtaining  approval from the STB. Second, it questioned the
amount of effective increase on its particular situation on a cost justification
basis. CF Industries also filed a protest questioning the Partnership's  ability
to file a tariff without first obtaining  approval from the STB. The Partnership
believes it has  regulatory  precedent in making the tariff  filing and can cost
justify the tariff rate change.  Initial data requests  have been  submitted and
answered,  and  summary  judgment  has  been  requested  on  the  issue  of  the
Partnership's ability to file a tariff change. The cost justification portion of
the Dyno  protest  will go forward  after the  resolution  of the tariff  filing
issue.

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 similar rights as 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  two
lawsuits  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.  The  Partnership  plans to install bottom loading and vapor
recovery  equipment on the loading  racks at selected  terminal  sites along the
East Pipeline that do not already have such emissions control  equipment.  These
modifications  will  substantially  reduce the total air emissions  from each of
these  facilities.  Having begun in 1993, this project is being phased in over a
period of years.

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, 2003,  approximately 1,060 persons were employed.  Approximately
152 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 Dallas,  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 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 against 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 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 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.  ST Services does not  anticipate  any
further hearings on the subject and is still awaiting the DOT's ruling.

         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.

         The  Partnership  has  other  contingent   liabilities  resulting  from
litigation,  claims and commitments incident to the ordinary course of business.
Management of the Partnership believes, based on the advice of 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 interest 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.


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,
                                        ---------------------------------------------------------------------
                                           2003          2002 (a)       2001 (a)       2000           1999
                                        ----------    -----------      ---------     ---------     ----------
<S>                                     <C>           <C>              <C>           <C>           <C>
Income Statement Data:
Revenues:
    Services..........................  $   354,591   $   288,669      $ 207,796     $  156,232    $  158,028
    Products..........................      215,823        97,961           -               -             -
                                        -----------   -----------      ---------     ----------    ----------
                                            570,414       386,630        207,796        156,232       158,028
                                        -----------   -----------      ---------     ----------    ----------
Costs and expenses:
    Cost of products sold.............      195,100        90,898           -               -             -
    Operating costs...................      168,537       131,326         90,632         69,653        69,148
    Depreciation and amortization.....       53,155        39,425         23,184         16,253        15,043
    Gain on sale of assets............         -             (609)           -           (1,126)          -
    General and administrative........       25,121        19,869         11,889         11,881         9,424
                                        -----------   -----------      ---------     ----------    ----------
                                            441,913       280,909        125,705         96,661        93,615
                                        -----------   -----------      ---------     ----------    ----------

Operating income......................      128,501       105,721         82,091         59,571        64,413

Interest and other income.............          261         3,570          4,277            316           408
Interest expense......................      (38,757)      (28,110)       (14,783)       (12,283)      (13,390)
Loss on debt extinguishment...........          -          (3,282)        (6,540)           -             -
Income tax expense....................       (5,223)       (4,083)          (256)          (943)       (1,496)
                                        -----------   -----------      ---------     ----------    ----------

Income before cumulative effect of
    change in accounting principle....       84,782        73,816         64,789         46,661        49,935

Cumulative effect of change in
    accounting principle - adoption
    of new accounting standard for
    asset retirement obligations......       (1,593)          -              -              -             -
                                        -----------   -----------      ----------    ----------    ----------

Net income ...........................  $    83,189   $    73,816      $  64,789     $   46,661    $   49,935
                                        ===========   ===========      =========     ==========    ==========

Cash distributions declared...........  $   102,948   $    79,816      $  62,156     $   53,485    $   51,850
                                        ===========   ===========      =========     ==========    ==========

Balance Sheet Data (at year end):
Property and equipment, net...........  $ 1,112,970   $ 1,092,192      $ 481,274     $  321,355    $  316,883
Total assets..........................    1,264,682     1,215,410        548,371        375,063       365,953
Long-term debt........................      617,696       694,330        262,624        166,900       155,987
Partners' capital.....................      493,589       393,314        220,527        161,735       169,321
</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.


GENERAL

         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,  2003)
limited  partner  interest.  KPL owns a 1%  interest  as general  partner of the
Partnership and a 1% interest as general partner of KPP.

         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 conducted  through Support
Terminal  Services  ("ST  Services")  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.  In the United
States,  ST Services  operates 37 facilities in 20 states. ST Services also owns
and operates six 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.

OVERVIEW

         In 2003, The Partnership integrated the major acquisitions completed in
2002 and focused on the  performance  of those  operations,  as well as its core
business,  to generate  increased cash flow. The  Partnership's  success in this
effort enabled it to increase cash distributions twice in 2003. On an annualized
basis, KPP raised its  distribution  $0.08 in May 2003 and then another $0.12 in
November 2003. The Partnership had a very strong year as revenues increased 48%,
operating income increased 22% and net income increased 13%.

         In 2003, the  Partnership  completed the financing for the $600 million
of acquisitions  it made in 2002,  which were financed half with equity and half
with debt.  In March 2003,  KPP sold  approximately  three  million  units - the
largest and most  successful  equity  offering in its history.  The  Partnership
completed the placement of its permanent  financing in May 2003, and over 85% of
that debt is at favorable fixed rates,  thereby  limiting its exposure to rising
interest rates.  The Partnership  also completed a new revolving credit facility
of $400 million, with the ability to increase it to $450 million.

         The  Partnership  has a very  strong  balance  sheet and the  financial
capacity for further  expansion.  The Partnership has integrated and assimilated
the substantial  acquisitions  it made in 2002 and has seen the  contribution of
those  operations to its results in 2003.  The  Partnership  now actively  seeks
opportunities for strategic and substantial growth.


CONSOLIDATED RESULTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2003                2002                 2001
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   570,414        $   386,630          $   207,796
                                                          ===========        ===========          ===========
Operating income.....................................     $   128,501        $   105,721          $    82,091
                                                          ===========        ===========          ===========
Income before cumulative effect of change in
    accounting principle.............................     $    84,782        $    73,816          $    64,789

Cumulative effect of change in accounting principle..         (1,593)               -                    -
                                                          ----------         -----------          -----------
Net income...........................................     $    83,189        $    73,816          $    64,789
                                                          ===========        ===========          ===========
Capital expenditures, excluding acquisitions.........     $    44,741        $    31,101          $    17,246
                                                          ===========        ===========          ===========
</TABLE>

         For the year ended  December  31,  2003,  revenues  increased by $183.8
million,  or 48%,  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 a $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.

         For the year ended  December  31,  2002,  revenues  increased by $178.8
million,  or 86%,  compared to 2001, due to a $73.2 million increase in revenues
in the  terminaling  business  and a $7.7  million  increase  in revenues in the
pipeline  business.  2002  revenues  also include $97.9 million in product sales
revenues  from a  business  acquired  with  Statia  in  February  of  2002.  See
"Liquidity and Capital Resources".  Operating income for the year ended December
31, 2002  increased by $23.6  million,  or 29%, when compared to 2001,  due to a
$19.7 million increase in terminaling  business operating income, a $1.9 million
increase in pipeline operating income and 2002 product sales operating income of
$2.1 million. Overall, net income for the year ended December 31, 2002 increased
by $9.0 million, or 14%, when compared to 2001.


PIPELINE OPERATIONS
<TABLE>
<CAPTION>

                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2003                 2002                2001
                                                          -----------        -----------          -----------
                                                                             (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   119,633        $    82,698          $    74,976
Operating costs......................................          46,379             33,744               28,844
Depreciation and amortization........................          14,117              6,408                5,478
General and administrative...........................           7,277              3,923                3,881
                                                          -----------        -----------          -----------
Operating income.....................................     $    51,860        $    38,623          $    36,773
                                                          ===========        ===========          ===========
</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,  2003,
revenues  increased by $36.9 million,  or 45%, compared to 2002, due entirely to
the November and December 2002 pipeline acquisitions (see "Liquidity and Capital
Resources").  For the year ended December 31, 2002,  revenues  increased by $7.7
million,  or 10%,  compared to 2001,  due to higher per barrel rates realized on
volumes  shipped  on  existing  pipelines  and as a result of the 2002  pipeline
acquisitions.  Approximately  $4.5  million of the 2002  revenue  increase was a
result of the pipeline acquisitions. Barrel miles on petroleum pipelines totaled
21.3  billion  (including  4.7 billion for the  petroleum  pipeline  acquired in
December of 2002),  18.3 billion and 18.6  billion for the years ended  December
31, 2003, 2002 and 2001, respectively.

         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 $12.6  million  in 2003 and $4.9
million in 2002. The increase in 2003 was due to the 2002 pipeline  acquisitions
and  increases  in  planned  maintenance.  The  increase  in 2002 was due to the
pipeline  acquisitions  and increases in  expenditures  for routine  repairs and
maintenance.  For the years ended December 31, 2003 and 2002,  depreciation  and
amortization  increased by $7.7  million and $0.9  million,  respectively,  when
compared to the respective prior year, due to the pipeline acquisitions. 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 $3.4  million in 2003,  when
compared to 2002,  due primarily to the pipeline  acquisitions  and increases in
personnel-related costs.


TERMINALING OPERATIONS

<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2003                 2002                2001
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   234,958        $   205,971          $   132,820
Operating costs......................................         114,030             94,480               61,788
Depreciation and amortization........................          38,089             32,368               17,706
Gain on sale of assets...............................           -                   (609)                -
General and administrative...........................          16,307             14,692                8,008
                                                          -----------        -----------          -----------
Operating income.....................................     $    66,532        $    65,040          $    45,318
                                                          ===========        ===========          ===========
</TABLE>

         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.  For the
year ended  December 31, 2002,  revenues  increased  by $73.2  million,  or 55%,
compared to 2001,  due to the  terminal  acquisitions  and overall  increases in
utilizations  at  existing  locations.  Approximately  $25  million  of the 2003
revenue  increase and $63 million of the 2002  revenue  increase was a result of
the terminal  acquisitions.  Average annual tankage utilized for the years ended
December 31, 2003, 2002 and 2001 aggregated 46.7 million  barrels,  46.5 million
barrels and 30.1 million barrels,  respectively.  Average revenues per barrel of
tankage utilized for the years ended December 31, 2003, 2002 and 2001 was $5.02,
$4.43 and $4.41, respectively.  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 foreign  currency  exchange  differences.  The
increase in 2002 average revenues per barrel of tankage utilized was due to more
favorable domestic market conditions, when compared to 2001.

         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.  In 2002, operating costs
increased by $32.7  million,  when  compared to 2001,  due to the 2002  terminal
acquisitions  and  increases in volumes  stored at existing  locations.  For the
years ended December 31, 2003 and 2002,  depreciation and amortization increased
by  $5.7  million  and  $14.7  million,   respectively,   due  to  the  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  expense  increased by $1.6
million in 2003 and by $6.7 million in 2002,  due to the  terminal  acquisitions
and increases in personnel-related costs.


PRODUCT SALES OPERATIONS
<TABLE>
<CAPTION>

                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2003                 2002                2001
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   215,823        $    97,961          $      -
Cost of products sold................................         195,100             90,898                 -
                                                          -----------        -----------          -----------
Gross margin.........................................     $    20,723        $     7,063          $      -
                                                          ===========        ===========          ===========
Operating income.....................................     $    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,  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 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.

         In March of 2001,  the  Partnership  entered into two contracts for the
purpose of locking in interest  rates on $100  million of  anticipated  ten-year
public debt offerings. As the interest rate locks were not designated as hedging
instruments pursuant to the requirements of SFAS No. 133, increases or decreases
in the fair value of the  contracts  are included as a component of interest and
other income. On May 22, 2001, the contracts were settled resulting in a gain of
$3.8 million, which is included in interest and other income in 2001.


INTEREST EXPENSE

         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.

         For the year ended  December 31, 2002,  interest  expense  increased by
$13.3 million,  when compared to 2001,  due to overall  increases in debt levels
resulting from the 2002  acquisitions  (see "Liquidity and Capital  Resources"),
partially offset by 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 $5.2 million, $4.1 million and $0.3 million for the years
ended  December  31,  2003,  2002  and  2001,  respectively.  The  2003 and 2002
increases in income taxes,  compared to the respective prior year, was primarily
due to foreign taxes on terminaling  operations acquired in 2002 (see "Liquidity
and Capital Resources").

         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  requires 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  provides  that any amounts paid in order to meet the minimum
annual  payment  will be 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 $142.0 million, $91.8 million
and $95.7 million for the years 2003, 2002 and 2001, respectively.  The increase
in 2003,  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.  The 2002  decrease in cash  provided by operating
activities,  when compared to 2001, was due to the payment of  personnel-related
costs assumed with the Statia acquisition,  initial working capital requirements
of the  pipeline  businesses  acquired  in 2002 and  changes in working  capital
components  resulting  from  the  timing  of cash  receipts  and  disbursements,
partially offset by overall increases in revenues and operating income.

         Capital  expenditures,  including  routine  maintenance  and  expansion
expenditures, but excluding acquisitions,  were $44.7 million, $31.1 million and
$17.2 million for 2003,  2002 and 2001,  respectively.  The increase in 2003 and
2002 capital  expenditures,  when compared to the respective  prior year, is the
result of planned maintenance and expansion capital  expenditures related to the
pipeline  and  terminaling  operations  acquired in 2002 and higher  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 $28 million to $32 million in 2004. 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 $98.2 million,
$74.4  million and $62.2  million,  were paid to limited  partner  interests and
general partner interests in 2003, 2002 and 2001, 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 2001,  the  Partnership  used proceeds from its revolving
credit agreement to repay in full its $128 million of mortgage notes.  Under the
provisions  of the  mortgage  notes,  the  Partnership  incurred a $6.5  million
prepayment penalty which was recognized as loss on debt extinguishment in 2001.

         In  January of 2001,  the  Partnership  acquired  Shore  Terminals  LLC
("Shore") for $107 million in cash and 1,975,090 KPP limited  partnership  units
(valued  at  $56.5  million  on the  date of  agreement  and its  announcement).
Financing for the cash portion of the purchase  price was initially  supplied by
the Partnership's revolving credit facility.

         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 an event of default, such
covenants do not restrict  distributions to partners.  At December 31, 2003, 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
the  Partnership's  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 new 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,
2003, 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,  2003,  $54.2  million  was
outstanding under the new 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, 2003,  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 as of December 31,
2003:
<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.........  $    54,169   $       -        $  54,169     $      -      $      -
    7.75% senior unsecured notes......      250,000           -              -              -         250,000
    5.875% senior unsecured notes.....      250,000           -              -              -         250,000
    Other bank debt...................       63,527           -           63,527            -             -
                                        -----------   -----------      ---------     ----------    ----------
       Debt subtotal..................      617,696           -          117,696            -         500,000
                                        -----------   -----------      ---------     ----------    ----------
Contractual commitments:
    Operating leases..................       10,723         4,325          3,706          2,350           342
                                        -----------   -----------      ---------     ----------    ----------
       Contractual commitments
          subtotal....................       10,723         4,325          3,706          2,350           342
                                        -----------   -----------      ---------     ----------    ----------
       Total..........................  $   628,419   $     4,325      $ 121,402     $    2,350    $  500,342
                                        ===========   ===========      =========     ==========    ==========
</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, 2003, or for any of the years ended December 31, 2003,  2002 and
2001.


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.

         Critical  accounting  policies are those that are most important to the
portrayal to 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, 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, 2003, 2002 or 2001. 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.


RECENT ACCOUNTING PRONOUNCEMENT

         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 has not and is not expected to have a material
impact on the consolidated financial statements of the Partnership.


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

         The  principal  market risks  (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 $117.7  million  at  December  31,  2003,  a one  percent
increase  in  interest  rates  would  increase  annual net  interest  expense by
approximately  $1.2 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.

         A  significant  portion  of the  terminaling  business  is  exposed  to
fluctuations  in foreign  currency  exchange  rates.  (See "Item 7 - Terminaling
Operations".)


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, 2003, 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 2003,  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.




<PAGE>
                                    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, 2003, 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.  A copy of the Code of Ethics 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, 2003, 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  interest 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, 2003, 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, 2003 is incorporated by reference in this report.


<PAGE>


                                     PART IV

Item 15.   Exhibits, Financial Statement Schedules, and Reports on Form 8-K
<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:
           Independent Auditors' Report..............................................................     F - 1
           Consolidated Statements of Income - Three Years Ended December 31, 2003...................     F - 2
           Consolidated Balance Sheets - December 31, 2003 and 2002..................................     F - 3
           Consolidated Statements of Cash Flows - Three Years Ended December 31, 2003...............     F - 4
           Consolidated Statements of Partners' Capital - Three Years ended December 31, 2003........     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, 2003, 2002 and 2001..............................................     F - 21
</TABLE>

         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.

    (a)(3) List of Exhibits

         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 herewith.

         10.1     ST Agreement and Plan of Merger dated December 21, 1992 by and
                  between Grace Energy  Corporation,  Support Terminal Services,
                  Inc.,  Standard Transpipe Corp., and Kaneb Pipe Line Operating
                  Partnership, NSTS, Inc. and NSTI, Inc. as amended by Amendment
                  of STS Merger  Agreement dated March 2, 1993, filed as Exhibit
                  10.1 of the  exhibits  to  KPP's  Current  Report  on Form 8-K
                  ("Form  8-K"),  dated March 16, 993,  which  exhibit is hereby
                  incorporated by reference.

         10.2     Agreement  for Sale and  Purchase of Assets  between Wyco Pipe
                  Line  Company and the  Partnership,  dated  February 19, 1995,
                  filed as Exhibit 10.1 of the exhibits to KPP's March 1995 Form
                  8-K, which exhibit is hereby incorporated by reference.

         10.3     Asset Purchase  Agreements between and among Steuart Petroleum
                  Company,  SPC Terminals,  Inc., Piney Point Industries,  Inc.,
                  Steuart  Investment   Company,   Support  Terminals  Operating
                  Partnership,  L.P.  and the  Partnership,  as  amended,  dated
                  August 27, 1995,  filed as Exhibits 10.1, 10.2, 10.3, and 10.4
                  of the  exhibits  to KPP's  Current  Report  on Form 8-K dated
                  January 3, 1996,  which  exhibits are hereby  incorporated  by
                  reference.

         10.4     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.

         10.5     Agreement,  between  and among,  GATX  Terminals  Limited,  ST
                  Services,  Ltd., ST Eastham, Ltd., GATX Terminals Corporation,
                  Support Terminals Operating  Partnership,  L.P. and Kaneb Pipe
                  Line Partners,  L.P., dated January 26, 1999, filed as Exhibit
                  10.10 to KPP's Form 10-K for the year ended December 31, 1998,
                  which exhibit is hereby incorporated by reference.

         10.6     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.

         10.7     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.

         10.8     Securities Purchase Agreement Among Shore Terminals LLC, Kaneb
                  Pipe Line Partners,  L.P. and the Sellers Named Therein, dated
                  as of  September  22,  2000,  Amendment  No.  1 To  Securities
                  Purchase  Agreement,   dated  as  of  November  28,  2000  and
                  Registration  Rights  Agreement,  dated as of January 3, 2001,
                  filed as Exhibits 10.1, 10.2 and 10.3 of the exhibits to KPP's
                  Current  Report  on Form 8-K  dated  January  3,  2001,  which
                  exhibits are hereby incorporated by reference.

         10.9     Stock  Purchase  Agreement,  dated as of November 12, 2001, by
                  and between Kaneb Pipe Line Operating  Partnership,  L.P., and
                  Statia  Terminals  Group  NV, a public  company  with  limited
                  liability   organized   under  the  laws  of  the  Netherlands
                  Antilles,  filed  as  Exhibit  10.1 to the  exhibits  to KPP's
                  Current  Report on Form  8-K,  dated  January  11,  2002,  and
                  incorporated herein by reference.

         10.10    Voting and Option  Agreement dated as of November 12, 2001, by
                  and between Kaneb Pipe Line Operating  Partnership,  L.P., and
                  Statia Terminals Holdings N.V., a Netherlands Antilles company
                  and a shareholder of Statia  Terminals Group NV, a Netherlands
                  Antilles  company  filed as Exhibit  10.1 to the  exhibits  to
                  Registrant's  Current  Report on Form 8-K,  dated  January 11,
                  2002, and incorporated herein by reference.

         10.11*   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.

         21       List of Subsidiaries, filed herewith.

         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 12,
                  2004.

         31.2     Certification of Chief Financial Officer,  Pursuant to Section
                  302 of the Sarbanes-Oxley Act of 2002, dated as of March 12,
                  2004.

         32.1     Certification of Chief Executive Officer,  Pursuant to Section
                  906(a) of the  Sarbanes-Oxley  Act of 2002,  dated as of March
                  12, 2004.

         32.2     Certification of Chief Financial Officer,  Pursuant to Section
                  906(a) of the  Sarbanes-Oxley  Act of 2002,  dated as of March
                  12, 2004.

         *        Denotes management contract.

(b)      Reports on Form 8-K

         Current Report on Form 8-K filed with the SEC on October 30, 2003.


<PAGE>
                          INDEPENDENT AUDITORS' REPORT





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 auditing standards generally accepted
in the  United  States of  America.  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 and
its  subsidiaries  as of December  31,  2003 and 2002,  and the results of their
operations and their cash flows for each of the years in the  three-year  period
ended  December 31, 2003, in conformity  with  accounting  principles  generally
accepted in the United  States of America.  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
February 20, 2004



                                      F - 1

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


<TABLE>
<CAPTION>
                                                                           Year Ended December 31,
                                                        -----------------------------------------------------------
                                                               2003                 2002                 2001
                                                        -----------------    -----------------    -----------------

<S>                                                       <C>                   <C>                  <C>
Revenues:
   Services...........................................    $ 354,591,000         $ 288,669,000        $  207,796,000
   Products...........................................      215,823,000            97,961,000               -
                                                          -------------         -------------        --------------

      Total revenues..................................      570,414,000           386,630,000           207,796,000
                                                          -------------         -------------        --------------

Costs and expenses:
   Cost of products sold..............................      195,100,000            90,898,000               -
   Operating costs....................................      168,537,000           131,326,000            90,632,000
   Depreciation and amortization......................       53,155,000            39,425,000            23,184,000
   Gain on sale of assets.............................            -                  (609,000)                -
   General and administrative.........................       25,121,000            19,869,000            11,889,000
                                                          -------------         -------------        --------------

      Total costs and expenses........................      441,913,000           280,909,000           125,705,000
                                                          -------------         -------------        --------------

Operating income......................................      128,501,000           105,721,000            82,091,000

Interest and other income.............................          261,000             3,570,000             4,277,000
Interest expense......................................      (38,757,000)          (28,110,000)          (14,783,000)
Loss on debt extinguishment...........................            -                (3,282,000)           (6,540,000)
                                                          -------------         -------------        --------------

Income before income taxes and cumulative effect of
   change in accounting principle.....................       90,005,000            77,899,000            65,045,000

Income tax expense....................................       (5,223,000)           (4,083,000)             (256,000)
                                                          -------------         --------------       --------------

Income before cumulative effect of change in
   accounting principle...............................       84,782,000            73,816,000            64,789,000

Cumulative effect of change in accounting principle -
   adoption of new accounting standard for asset
   retirement obligations.............................       (1,593,000)                -                     -
                                                          -------------         -------------        --------------
Net income ...........................................    $  83,189,000         $  73,816,000        $   64,789,000
                                                          =============         =============        ==============

</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,
                                                                             --------------------------------------
                                                                                   2003                  2002
                                                                             ----------------      ----------------
                                     ASSETS
<S>                                                                          <C>                   <C>
Current assets:
   Cash and cash equivalents...............................................  $     38,626,000      $     22,028,000
   Accounts receivable (net of allowance for doubtful accounts
      of $1,693,000 in 2003 and $1,765,000 in 2002)........................        51,864,000            48,926,000
   Inventories.............................................................         9,324,000             4,922,000
   Prepaid expenses and other..............................................         9,205,000             8,498,000
                                                                             ----------------      ----------------

      Total current assets.................................................       109,019,000            84,374,000
                                                                             ----------------      ----------------

Property and equipment.....................................................     1,360,319,000         1,288,762,000
Less accumulated depreciation..............................................       247,349,000           196,570,000
                                                                             ----------------      ----------------

      Net property and equipment...........................................     1,112,970,000         1,092,192,000
                                                                             ----------------      ----------------

Investment in affiliates...................................................        25,456,000            25,604,000

Excess of cost over fair value of net assets of acquired business and
   other assets............................................................        17,237,000            13,240,000
                                                                             ----------------      ----------------
                                                                             $  1,264,682,000      $  1,215,410,000
                                                                             ================      ================


                        LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:
   Accounts payable........................................................  $     27,941,000      $     22,064,000
   Accrued expenses........................................................        31,642,000            29,339,000
   Accrued distributions payable...........................................        26,344,000            21,639,000
   Accrued interest payable................................................         9,297,000             7,896,000
   Accrued taxes, other than income taxes..................................         4,031,000             3,598,000
   Deferred terminaling fees...............................................         7,061,000             6,246,000
   Payable to general partner..............................................         3,630,000             5,403,000
                                                                             ----------------      ----------------
      Total current liabilities............................................       109,946,000            96,185,000
                                                                             ----------------      ----------------

Long-term debt.............................................................       617,696,000           694,330,000

Other liabilities and deferred taxes.......................................        43,451,000            31,581,000

Commitments and contingencies

Partners' capital:
   Limited partners........................................................       480,323,000           390,904,000
   General partner.........................................................           894,000             1,016,000
   Accumulated other comprehensive income..................................        12,372,000             1,394,000
                                                                             ----------------      ----------------
      Total partners' capital..............................................       493,589,000           393,314,000
                                                                             ----------------      ----------------
                                                                             $  1,264,682,000      $  1,215,410,000
                                                                             ================      ================

</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,
                                                          ---------------------------------------------------------
                                                              2003                  2002                  2001
                                                          -------------         -------------        --------------
<S>                                                       <C>                   <C>                  <C>
Operating activities:
   Net income ........................................    $  83,189,000         $  73,816,000        $   64,789,000
   Adjustments to reconcile net income to net
      cash provided by operating activities:
      Depreciation and amortization...................       53,155,000            39,425,000            23,184,000
      Equity in earnings of affiliates, net of
        distributions.................................          148,000            (3,164,000)               (5,000)
      Gain on sale of assets..........................            -                  (609,000)                 -
      Deferred income taxes...........................        1,683,000             3,105,000               256,000
      Cumulative effect of change in accounting
        principle.....................................        1,593,000                 -                     -
      Other liabilities...............................        1,190,000            (1,341,000)           (5,422,000)
      Changes in working capital components:
        Accounts receivable...........................       (2,938,000)          (12,379,000)             (824,000)
        Inventories, prepaid expenses and other.......       (5,109,000)           (6,601,000)            1,601,000
        Accounts payable and accrued expenses.........       10,829,000            (1,192,000)            9,298,000
        Payable to general partner....................       (1,773,000)              702,000             2,812,000
                                                         --------------         -------------        --------------
           Net cash provided by operating activities..      141,967,000            91,762,000            95,689,000
                                                         --------------         -------------        --------------


Investing activities:
   Acquisitions, net of cash acquired.................       (1,644,000)         (468,477,000)         (111,562,000)
   Capital expenditures...............................      (44,741,000)          (31,101,000)          (17,246,000)
   Proceeds from sale of assets.......................            -                 1,107,000             2,807,000
   Other, net.........................................       (1,109,000)              306,000              (111,000)
                                                         --------------         -------------        --------------
           Net cash used in investing activities......      (47,494,000)         (498,165,000)         (126,112,000)
                                                         --------------         --------------       --------------

Financing activities:
   Issuance of debt...................................      291,377,000           746,087,000           260,500,000
   Payments of debt...................................     (382,831,000)         (426,647,000)         (164,776,000)
   Distributions......................................      (98,243,000)          (74,439,000)          (62,156,000)
   Net proceeds from issuance of units by KPP.........      109,056,000           175,527,000                 -
                                                         --------------         -------------        --------------
           Net cash provided by (used in) financing
               activities.............................      (80,641,000)          420,528,000            33,568,000
                                                         --------------         -------------        --------------
Effect of exchange rate changes on cash...............        2,766,000                 -                     -
                                                         --------------         -------------        --------------
Increase in cash and cash equivalents.................       16,598,000            14,125,000             3,145,000
Cash and cash equivalents at beginning of period......       22,028,000             7,903,000             4,758,000
                                                         --------------         -------------        --------------
Cash and cash equivalents at end of period............   $   38,626,000         $  22,028,000        $    7,903,000
                                                         ==============         =============        ==============
Supplemental cash flow information:
   Cash paid for interest.............................   $   34,818,000         $  25,942,000        $   14,028,000
                                                         ==============         =============        ==============
   Non-cash investing and financing activities -
      Issuance of units by KPP in connection with
      acquisition of terminals........................   $       -              $       -            $   56,488,000
                                                         ==============         =============        ==============
</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 31, 2001....   $  162,288,000   $   984,000  $ (1,537,000)   $ 161,735,000

  2001 income allocation.................       64,141,000       648,000           -         64,789,000   $    64,789,000

  Distributions declared.................      (61,554,000)     (602,000)          -        (62,156,000)             -

  Issuance of units by KPP, net of
    offering costs.......................       56,488,000           -             -         56,488,000              -

  Foreign currency translation
    adjustment...........................            -               -        (329,000)        (329,000)         (329,000)
                                            --------------   -----------   -----------   --------------   ---------------
  Comprehensive income for the year......                                                                 $    64,460,000
                                                                                                          ===============

Partners' capital at December 31, 2001...      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
                                            ==============   ===========   ===========   ==============

</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

       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, 2003) limited  partnership
interest.  KPL owns a 1% interest as general partner of the Partnership and a 1%
interest as general partner of KPP.

       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
the  Partnership's  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, 2003, 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 December 31, 2003, the Partnership  determined that
the implied fair value of its goodwill exceeded  carrying value and,  therefore,
no  impairment  charge was  necessary.  Goodwill  amortization  included  in the
results of operations of the  Partnership  for the year ended  December 31, 2001
was not material.

       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, 2003, 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, 2001,
was not material to the results of operations of the  Partnership  for the years
ended  December  31, 2003,  2002 and 2001.  In 2003,  accretion  expense of $0.4
million 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,
                                                          ---------------------------------------------------------
                                                              2003                  2002                  2001
                                                          -------------         -------------        --------------

<S>                                                       <C>                   <C>                  <C>
       Partnership operations........................     $  71,104,000         $  71,614,000        $   62,650,000
       Corporate operations:
            Domestic.................................        (3,055,000)            2,046,000            (1,594,000)
            Foreign..................................        21,956,000             4,239,000             3,989,000
                                                          -------------         -------------        --------------
                                                          $  90,005,000         $  77,899,000        $   65,045,000
                                                          =============         =============        ==============
</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,  2003,  2002 and 2001
primarily  consists  of U.S.  and foreign  income  taxes of $5.2  million,  $4.1
million and $0.3 million,  respectively. The net deferred tax liability of $20.6
million and $17.8 million at December 31, 2003 and 2002, respectively,  consists
of deferred tax  liabilities of $48.8 million and $41.7  million,  respectively,
and deferred tax assets of $28.2 million and $23.9  million,  respectively.  The
deferred tax liabilities consist primarily of tax depreciation in excess of book
depreciation and 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  $43.1 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  requires 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 provides that any amounts paid in order to meet the
minimum annual payment will be 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  units.
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 $98.2 million,
$74.4  million and $62.2  million,  were paid to limited  partner  interests and
general partner interests in 2003, 2002 and 2001, respectively.

       Derivative Instruments

       Effective January 1, 2001, the Partnership adopted 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 January
1,  2001,  the  Partnership  was not a party to any  derivative  contracts  and,
accordingly,  initial  adoption  of SFAS No.  133 at that  date did not have any
effect on the Partnership's result of operations or financial position.

       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 year ended
December 31, 2003, $0.1 million 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.

       In March of 2001,  the  Partnership  entered into two  contracts  for the
purpose of locking in interest  rates on $100  million of  anticipated  ten-year
public debt offerings. As the interest rate locks were not designated as hedging
instruments pursuant to the requirements of SFAS No. 133, increases or decreases
in the fair value of the contracts  were included as a component of interest and
other income. On May 22, 2001, the contracts were settled resulting in a gain of
$3.8 million, which is included in interest and other income in 2001.

       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 initial  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 initial  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 has not and is not expected to 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
                                                                  =============

       Assuming the Statia  acquisition  occurred on January 1, 2001,  unaudited
pro forma  revenues  and net income  would have been  $411.3  million  and $72.8
million,  respectively, for the year ended December 31, 2002, and $410.0 million
and $63.9 million, respectively, for the year ended December 31, 2001.

       On  January  3,  2001,  the  Partnership  acquired  Shore  Terminals  LLC
("Shore") for $107 million in cash and 1,975,090 KPP limited  partnership  units
(valued  at  $56.5  million  on the  date of  agreement  and its  announcement).
Financing for the cash portion of the purchase  price was initially  supplied by
the  Partnership's  revolving  credit facility (see Note 5). The acquisition was
accounted for using the purchase method of accounting.


4.     PROPERTY AND EQUIPMENT

       The cost of property and equipment is summarized as follows:
<TABLE>
<CAPTION>

                                                        Estimated
                                                         Useful                             December 31,
                                                          Life               --------------------------------------
                                                         (Years)                    2003                2002
                                                     --------------          ------------------   -----------------

<S>                                                  <C>                     <C>                  <C>
       Land......................................           -                $       75,912,000   $      72,152,000
       Buildings.................................        25 - 35                     36,229,000          27,559,000
       Pipeline and terminaling equipment........        15 - 40                  1,115,458,000       1,067,794,000
       Marine equipment..........................        15 - 30                     87,204,000          84,641,000
       Furniture and fixtures....................        5 - 15                      11,388,000           7,892,000
       Transportation equipment..................         3 - 6                       7,360,000           5,414,000
       Construction work-in-progress.............           -                        26,768,000          23,310,000
                                                                             ------------------   -----------------
       Total property and equipment..............                                 1,360,319,000       1,288,762,000
       Less accumulated depreciation.............                                   247,349,000         196,570,000
                                                                             ------------------   -----------------
       Net property and equipment................                            $    1,112,970,000   $   1,092,192,000
                                                                             ==================   =================

</TABLE>


5.     LONG-TERM DEBT

       Long-term debt is summarized as follows:
<TABLE>
<CAPTION>
                                                                                           December 31,
                                                                              -------------------------------------
                                                                                    2003                  2002
                                                                              ---------------        --------------

<S>                                                                           <C>                    <C>
       $400 million revolving credit facility, due in April of 2006........   $    54,169,000        $        -
       $250 million 5.875% senior unsecured notes, due in June of 2013.....       250,000,000                 -
       $250 million 7.75% senior unsecured notes, due in February of 2012..       250,000,000           250,000,000
       $275 million revolving credit facility, repaid in April of 2003.....             -               243,000,000
       Bank bridge facility, repaid in April of 2003.......................             -               175,000,000
       Term loans, due in April of 2006....................................        29,243,000            26,330,000
       Australian bank facility, due in April of 2006......................        34,284,000                 -
                                                                              ---------------        --------------
       Total long-term debt................................................   $   617,696,000        $  694,330,000
                                                                              ===============        ==============
</TABLE>

         In April of 2003, the Partnership  entered into a new 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,
2003, 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,  2003,  $54.2  million  was
outstanding under the new 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, 2003,  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, 2003, the
Partnership was in compliance with all covenants.

       In January of 2001,  the  Partnership  used  proceeds  from its revolving
credit agreement to repay in full its $128 million of mortgage notes.  Under the
provisions  of the  mortgage  notes,  the  Partnership  incurred a $6.5  million
prepayment penalty, which was recognized as loss on debt extinguishment in 2001.


6.     COMMITMENTS AND CONTINGENCIES

       The  following is a schedule by years of future  minimum  lease  payments
under operating leases as of December 31, 2003:

        Year ending December 31:
                 2004......................................      $    4,325,000
                 2005......................................           2,028,000
                 2006......................................           1,678,000
                 2007......................................           1,416,000
                 2008......................................             934,000
                 Thereafter................................             342,000
                                                                 --------------
           Total minimum lease payments....................      $   10,723,000
                                                                 ==============

       Total rent expense under operating leases amounted to $14.5 million, $9.4
million and $4.2 million for the years ended  December 31, 2003,  2002 and 2001,
respectively.

       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 $28.6 million at
December 31, 2003,  including $25.5 million related to acquisitions of pipelines
and  terminals.  During  2003,  2002 and  2001,  respectively,  the  Partnership
incurred  $2.1  million,  $2.4 million and $5.2 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  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 against  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 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 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.  ST Services does not  anticipate  any
further hearings on the subject and is still awaiting the DOT's ruling.

       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.

       The  Partnership  has  other   contingent   liabilities   resulting  from
litigation,  claims and commitments incident to the ordinary course of business.
Management of the Partnership believes, based on the advice of 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  $36.3  million,  $27.3  million  and $18.1  million for the years ended
December  31,  2003,  2002 and  2001,  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 $26.6  million,  $17.7 million and $14.3
million of compensation and benefits,  paid to officers and employees of KPL and
KSL for the years ended  December  31,  2003,  2002 and 2001,  respectively.  In
addition,  the  Partnership  paid $0.6 million in 2003, $0.6 million in 2002 and
$0.5 million in 2001 for an allocable  portion of KPL's  overhead  expenses.  At
December 31, 2003 and 2002,  the  Partnership  owed KPL and KSL $3.6 million and
$5.4  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,
                                                                ------------------------------------------------------
                                                                       2003                2002              2001
                                                                ----------------    ---------------     --------------
 <S>                                                             <C>                 <C>                 <C>
      Business segment revenues:
         Pipeline operations..................................  $    119,633,000    $    82,698,000     $   74,976,000
         Terminaling operations...............................       234,958,000        205,971,000        132,820,000
         Product sales operations.............................       215,823,000         97,961,000             -
                                                                ----------------    ---------------     --------------

                                                                $    570,414,000    $   386,630,000     $  207,796,000
                                                                ================    ===============     ==============
       Business segment profit:
         Pipeline operations..................................  $     51,860,000    $    38,623,000     $   36,773,000
         Terminaling operations...............................        66,532,000         65,040,000         45,318,000
         Product sales operations.............................        10,109,000          2,058,000             -
                                                                ----------------    ---------------     --------------
            Operating income..................................       128,501,000        105,721,000         82,091,000
         Interest and other income ...........................           261,000          3,570,000          4,277,000
         Interest expense.....................................       (38,757,000)       (28,110,000)       (14,783,000)
         Loss on debt extinguishment..........................             -             (3,282,000)        (6,540,000)
                                                                ----------------    ---------------     --------------
            Income before income taxes and cumulative effect
              of change in accounting principle...............  $     90,005,000    $    77,899,000     $   65,045,000
                                                                ================    ===============     ==============

       Business segment assets:
         Depreciation and amortization:
            Pipeline operations...............................  $     14,117,000    $     6,408,000     $    5,478,000
            Terminaling operations............................        38,089,000         32,368,000         17,706,000
            Product sales operations..........................           949,000            649,000             -
                                                                ----------------    ---------------     --------------

                                                                $     53,155,000    $    39,425,000     $   23,184,000
                                                                ================    ===============     ==============

         Capital expenditures (excluding acquisitions):
            Pipeline operations...............................  $      9,584,000    $     9,469,000     $    4,309,000
            Terminaling operations............................        34,572,000         20,953,000         12,937,000
            Product sales operations..........................           585,000            679,000             -
                                                                ----------------    ---------------     --------------

                                                                $     44,741,000    $    31,101,000     $   17,246,000
                                                                ================    ===============     ==============

</TABLE>
<TABLE>
<CAPTION>

                                                                                       December 31,
                                                                ------------------------------------------------------
                                                                      2003                2002               2001
                                                                ----------------    ---------------     --------------
 <S>                                                             <C>                 <C>                 <C>
        Total assets:
           Pipeline operations................................  $    352,901,000    $   352,657,000     $  105,156,000
           Terminaling operations.............................       874,185,000        844,321,000        443,215,000
           Product sales operations...........................        37,596,000         18,432,000             -
                                                                ----------------    ---------------     --------------

                                                                $  1,264,682,000    $ 1,215,410,000     $  548,371,000
                                                                ================    ===============     ==============

</TABLE>


<PAGE>


       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,
                                                                ------------------------------------------------------
                                                                       2003                2002              2001
                                                                ----------------    ---------------     --------------
<S>                                                             <C>                 <C>                 <C>
       Geographical area revenues:
         United States........................................  $    240,518,000    $   202,124,000     $  186,734,000
         United Kingdom.......................................        26,392,000         23,937,000         21,062,000
         Netherlands Antilles.................................       241,693,000        132,387,000             -
         Canada...............................................        41,689,000         23,207,000             -
         Australia and New Zealand............................        20,122,000          4,975,000             -
                                                                ----------------    ---------------     --------------

                                                                $    570,414,000    $   386,630,000     $  207,796,000
                                                                ================    ===============     ==============


       Geographical area operating income:
         United States........................................  $     87,962,000    $    82,906,000     $   76,575,000
         United Kingdom.......................................         8,583,000          7,318,000          5,516,000
         Netherlands Antilles.................................        19,223,000          9,616,000             -
         Canada...............................................         6,777,000          4,398,000             -
         Australia and New Zealand............................         5,956,000          1,483,000             -
                                                                ----------------    ---------------     --------------

                                                                $    128,501,000    $   105,721,000     $   82,091,000
                                                                ================    ===============     ==============

</TABLE>
<TABLE>
<CAPTION>
                                                                                       December 31,
                                                                ------------------------------------------------------
                                                                       2003                2002              2001
                                                                ----------------    ---------------     --------------
<S>                                                             <C>                 <C>                 <C>
       Geographical area net property and equipment:
         United States........................................  $    693,295,000    $   690,178,000     $  440,104,000
         United Kingdom.......................................        51,392,000         46,543,000         41,170,000
         Netherlands Antilles.................................       217,143,000        224,810,000             -
         Canada...............................................        74,995,000         78,789,000             -
         Australia and New Zealand............................        76,145,000         51,872,000             -
                                                                ----------------    ---------------     --------------

                                                                $  1,112,970,000    $ 1,092,192,000     $  481,274,000
                                                                ================    ===============     ==============
</TABLE>


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

       The estimated fair value of all debt as of December 31, 2003 and 2002 was
approximately  $630 million and $709 million,  as compared to the carrying value
of $618 million and $694 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, 2003. No customer constituted 10 percent or more of consolidated
revenues in 2003, 2002 or 2001.


10.    QUARTERLY FINANCIAL DATA (unaudited)

       Quarterly operating results for 2003 and 2002 are summarized as follows:

<TABLE>
<CAPTION>
                                                                            Quarter Ended
                                            --------------------------------------------------------------------------
                                                March 31,           June 30,          September 30,      December 31,
                                            ----------------    ----------------    ---------------     --------------
<S>                                         <C>                 <C>                 <C>                 <C>
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
                                            ================    ================    ===============     ==============


2002:
       Revenues.......................      $     67,642,000    $    100,702,000    $   103,304,000     $  114,982,000
                                            ================    ================    ===============     ==============

       Operating income...............      $     23,225,000    $     27,756,000    $    27,870,000     $   26,870,000
                                            ================    ================    ===============     ==============

       Net income.....................      $     17,416,000    $     17,133,000(b) $    19,491,000     $   19,776,000(c)
                                            ================    ================    ===============     ==============
</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.

(b)      Includes loss on debt extinguishment of approximately $1.9 million.

(c)      Includes loss on debt  extinguishment of approximately $1.2 million and
         gain on interest rate lock transaction at approximately $3.0 million.






<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, 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
                                       =============      ===========     =============     ========        ==========

Year Ended December 31, 2001:
   For doubtful receivables
     classified as current assets...   $         250      $       124     $        -        $    (96)(b)    $      278
                                       =============      ===========     =============     ========        ==========

</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 12, 2004


         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
----------------------------------------                       ---------------------------   --------------
<S>                                                            <C>                           <C>
Principal Executive Officer
      //s//  EDWARD D. DOHERTY                                 Chairman of the Board         March 12, 2004
----------------------------------------                       and Chief Executive Officer

Principal Accounting Officer
     //s//  HOWARD C. WADSWORTH                                Vice President                March 12, 2004
----------------------------------------                       Treasurer & Secretary


Directors

         //s//  SANGWOO AHN                                    Director                      March 12, 2004
----------------------------------------



        //s//  JOHN R. BARNES                                  Director                      March 12, 2004
----------------------------------------



       //s//  MURRAY R. BILES                                  Director                      March 12, 2004
----------------------------------------



     //s//  FRANK M. BURKE, JR.                                Director                      March 12, 2004
----------------------------------------



       //s//  CHARLES R. COX                                   Director                      March 12, 2004
----------------------------------------



         //s//  HANS KESSLER                                   Director                      March 12, 2004
----------------------------------------



       //s//  JAMES R. WHATLEY                                 Director                      March 12, 2004
----------------------------------------


</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))  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)       [intentionally omitted pursuant to SEC Release No. 34-47986];

         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 12, 2004
                                               //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))  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)       [intentionally omitted pursuant to SEC Release No. 34-47986];

         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 12, 2004


                                                //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, 2003,  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 12, 2004
                                               //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, 2003,  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 12, 2004


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