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, 2002

                                       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

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

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

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

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

Indicate  by check mark  whether  the  registrant  is an  accelerated  filer (as
defined in Exchange Act Rule 12b-2). Yes X   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 1) 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 2) Statia  Terminals  International  N.V. 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 the 1950s 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.

     Most 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  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.

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 that  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 8
inch 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 and the two pipelines
will be connected at that  location in the near  future.  The North  Pipeline is
presently  supplied  exclusively by the Mandan  refinery.  Once connected to the
East Pipeline, it will be capable of delivering or receiving products to or from
the East Pipeline.

Ammonia Pipeline

     On  November  1, 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. 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 but it was leased
back to Koch Nitrogen. The administrative  headquarters for the Ammonia Pipeline
is located in Hermann, Missouri. The Ammonia Pipeline is connected to twenty-two
other  non-Partnership  owned terminals and also has several industrial delivery
locations.  Product  is  primarily  supplied  to the  pipeline  from  plants  in
Louisiana and foreign-source product 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,
2002, these three systems combined transported a total of 3.5 million barrels of
diesel fuel, representing an aggregate of $1.0 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  and  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 and North Pipeline
systems which were acquired on November 1 and December 24, 2002, respectively:

<TABLE>
<CAPTION>

                                                              Year Ended December 31,
                               ------------------------------------------------------------------------------------
                                    2002             2001              2000             1999              1998
                               -------------     -------------    --------------    -------------    --------------
<S>                                   <C>               <C>               <C>              <C>               <C>
Volume (1)..................          89,780            92,116            89,192           85,356            77,965
Barrel miles (2)............          18,275            18,567            17,843           18,440            17,007
Revenues (3)................         $78,240           $74,976           $70,685          $67,607           $63,421

</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)
                               ------------------------------------------------------------------------------------
                                    2002             2001              2000             1999              1998
                               -------------     -------------    --------------    -------------    --------------
<S>                                   <C>               <C>               <C>              <C>               <C>
Gasoline....................          45,106            46,268            44,215           41,472            37,983
Diesel and fuel oil.........          40,450            42,354            41,087           40,435            36,237
Propane.....................           4,224             3,494             3,890            3,449             3,745
                               -------------     -------------    --------------    -------------    --------------
Total.......................          89,780            92,116            89,192           85,356            77,965
                               =============     =============    ==============    =============    ==============
</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 anticipated to reflect the
same  agricultural  nature as the East Pipeline except for the Minneapolis  area
terminal which should be more like the Denver metropolitan area demand.

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 the useful lives
of the Pipelines.  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 refined  petroleum  products injected in and delivered through the
Pipelines  and  automatically  signals the  Wichita  headquarters  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   under  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  Partnership's  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 petroleum  product  shipments are tested or receive  refinery
certifications  to  ensure  compliance  with the  Partnership's  specifications.
Shippers are generally invoiced by the Partnership  immediately upon the product
entering one of the Pipelines.

<PAGE>
     The following  table shows the number of tanks owned by the  Partnership at
each refined  petroleum  product  terminal  location at December  31, 2002,  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 2002,  approximately  56.8% and 90.1% of the deliveries of
the East Pipeline and the West Pipeline,  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.

Demand for and Sources of Refined Petroleum Products

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

     Most of the refined petroleum  products delivered through the East Pipeline
and the western three  terminals on the North  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 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,  until the connection
to the East  Pipeline is complete,  is 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  Partnership's  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 2002 was produced at three  refineries  located at McPherson  and El
Dorado,  Kansas and Ponca City,  Oklahoma,  and operated by National Cooperative
Refining Association ("NCRA"),  Frontier Refining and Conoco, 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  28.9%  of the  total  amount  of  product  shipped  over the East
Pipeline  in 2002.  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 Conoco 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 (1) the level of
demand for direct  application  of anhydrous  ammonia as a  fertilizer  for crop
production ("Direct  Application" or "DA"); (2) the weather (DA is not effective
if the  ground  is too  wet)  and (3) the  price of  natural  gas  (the  primary
component of anhydrous ammonia).

     The Ammonia Pipeline is the largest of three anhydrous ammonia pipelines in
the US 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 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  58 shippers  in 2002.  The
principal  shippers  include  four  integrated  oil  companies,  three  refining
companies, two large farm cooperatives and one railroad. Transportation revenues
attributable  to the top 10 shippers of the East and West  Pipelines  were $61.5
million, $51.5 million, and $48.7 million, which accounted for 74%, 69%, and 69%
of  total  revenues  shipped  for  each  of the  years  2002,  2001,  and  2000,
respectively.

Competition and Business Considerations

     The East and North Pipelines' major competitor is an independent, regulated
common  carrier   pipeline  system  owned  by  The  Williams   Companies,   Inc.
("Williams")  that operates  approximately 100 miles east of and parallel to the
East Pipeline and in close proximity to the North Pipeline.  The Williams system
is a  substantially  more  extensive  system than the East and North  Pipelines.
Competition with Williams 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 Williams' 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
Phillips  Petroleum  Company.  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  pipelines
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's  pipelines  deliver  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  the
Partnership's  pipelines  will  be  built  in  the  near  future,  provided  the
Partnership's  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 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  direct  competition for smaller niche markets but are not competitive
for larger demand markets.


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.  In January 2001, the Partnership completed the
acquisition of Shore Terminals LLC for a purchase price of $107 million cash and
1,975,090 KPP limited  partnership units (valued at $56.5 million at the date of
the agreement).

     For the  year  ended  December  31,  2002,  the  Partnership's  terminaling
business  accounted for approximately 53% of the Partnership's  revenues.  As of
December 31, 2002, ST operated 39 facilities in 20 states,  with a total storage
capacity of approximately  33.3 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 2002,  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 three-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 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  2.8  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 35 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.



<PAGE>
     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>
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
Martinez, CA                       2,800,000            16       Petroleum
Jacksonville, FL                   2,066,000            30       Petroleum
Texas City, TX                     2,002,000           124       Chemicals and Petrochemicals

Other U. S. Terminals:
Montgomery, AL(b)                    162,000             7       Petroleum, Jet Fuel
Moundville, AL(b)                    310,000             6       Jet Fuel
Tucson, AZ(a)                        181,000             7       Petroleum
Los Angeles, CA                      597,000            20       Petroleum
Richmond, CA                         617,000            25       Petroleum
Stockton, CA                         706,000            32       Petroleum
Homestead, FL(b)                      72,000             2       Jet Fuel
Augusta, GA                          110,000             8       Petroleum
Bremen, GA                           180,000             8       Petroleum, Jet Fuel
Brunswick, GA                        302,000             3       Fertilizer, Pulp Liquor
Columbus, GA                         180,000            25       Petroleum, Chemicals
Macon, GA(b)                         307,000            10       Petroleum, Jet Fuel
Savannah, GA                         861,000            19       Petroleum, Chemicals
Blue Island, IL                      752,000            19       Petroleum
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
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                           229,000             7       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, Jet Fuel
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                        166,000            42       Chemicals, Fertilizer
Milwaukee, WI                        308,000             7       Petroleum


</TABLE>

<PAGE>
<TABLE>
<CAPTION>
                                    Tankage         No. of               Primary Products
          Facility                  Capacity         Tanks                     Handled
-----------------------------------------------------------------------------------------------------
<S>                                <C>                  <C>
Foreign Terminals:
St. Eustatius, Netherlands
Antilles.                         11,334,000            51       Petroleum, crude oil
Point Tupper, Canada               7,501,000            37       Petroleum, crude oil
Sydney, Australia                    330,000            65       Chemicals, fats and oils
Melbourne, Australia                 468,000           118       Specialty chemicals
Geelong, Australia                   145,000            12       Specialty chemicals
Adelaide, Australia                   90,000            24       Chemicals, tallow, petroleum
Auckland, New Zealand (a)             64,000            39       Fats, oils and chemicals
New Plymouth, New Zealand             35,000            10       Fats, oils and chemicals
Mt. Managui, New Zealand              52,000            21       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
                                 ---------------  --------------
                                  58,735,000         1,452
                                 ===============  ==============

</TABLE>

(a)  The terminal is 50% owned by ST.
(b)  Facility  also  includes  pipelines  to  U.S.   government   military  base
     locations.


Customers

     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 six of the eleven  locations  have been utilized  solely by the U.S.
Government.  One of these locations is presently without government business. Of
the eleven  locations,  six include pipelines which deliver jet fuel directly to
nearby military bases.

     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.

 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.  Possible  transportation  modes  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";  though some inland facilities are served by
barges on navigable rivers.

     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 a
greater  diversity of terminals 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
they enjoy 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 $9.5 million,  $4.3
million,  and $3.4 million for 2002, 2001 and 2000,  respectively.  During these
periods,  adequate  capacity  existed on the  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 $21.0 million,  $12.9 million, and $6.1 million for
2002, 2001 and 2000, respectively.

     Capital  expenditures of the  Partnership  during 2003,  including  routine
maintenance and expansion expenditures, but excluding acquisitions, are expected
to be approximately $40 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 the
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  in general  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.

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.


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.

     Groundwater  remediation  efforts  are  ongoing  at all  four  of the  West
Pipeline's  terminals and at a Wyoming pump station.  Regulatory  officials have
been consulted in the  development of remediation  plans. In connection with the
purchase of the West Pipeline,  the Partnership agreed to implement  remediation
plans at these  specific  sites over the  succeeding  five years  following  the
acquisition in return for the payment by the seller,  Wyco Pipe Line Company, of
$1,312,000 to the Partnership to cover the discounted  estimated future costs of
these remediations.

     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 the 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

     KPP'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 any  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
maintained  about  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 higher  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, 2002,  approximately 1,071 persons were employed.  Approximately
105 of the  persons at 6 terminal  unit  locations  in the  United  States  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  does not have an Internet  site,  but makes  available by
written  request,  at no cost,  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.


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 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 2004.  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.

     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 except one have
been  settled  for  immaterial   amounts  with  ST  Services'  portion  of  such
settlements  provided by its insurance carrier.  ST Services'  insurance carrier
has assumed the defense of the continuing  action and ST Services  believes that
the carrier would assume the defense of any new litigation by a  non-participant
in  the  settlement,   should  any  such  litigation  be  commenced.  While  the
Partnership  cannot predict the amount,  if any, of any liability it may have in
the continuing  action or in other potential  suits relating to this matter,  it
believes  that the current and potential  plaintiffs'  claims will be covered by
insurance and therefore these actions will not have a material adverse effect on
its financial condition.

     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  causes of action,  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 the oil  spill.  Both  parties  have  pending
motions to dismiss the other party's  suit.  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 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 or results of operations of the Partnership.


<PAGE>


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

     None


                                     PART II

Item 5. Market for the Registrant's Units and Related Unitholder 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.



<PAGE>

Item 6. Summary Historical Financial and Operating Data

     The following table sets forth, for the periods and at the dates indicated,
selected  historical  financial and operating data for Kaneb Pipe Line Operating
Partnership,  L.P. and subsidiaries (the  "Partnership").  The data in the table
(in thousands, except per unit amounts) 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,
                                         --------------------------------------------------------------------
                                           2002 (a)      2001 (a)         2000          1999          1998
                                         ----------    ----------      ---------     ----------    ----------
<S>                                     <C>            <C>             <C>           <C>           <C>
Income Statement Data:
Revenues..............................  $   386,630    $  207,796      $ 156,232     $  158,028    $  125,812
                                         ----------    ----------      ---------     ----------    ----------

Cost of products sold.................       90,898           -             -               -             -
Operating costs.......................      131,326        90,632         69,653         69,148        52,200
Depreciation and amortization.........       39,425        23,184         16,253         15,043        12,148
Gain on sale of assets................         (609)          -           (1,126)           -             -
General and administrative............       19,869        11,889         11,881          9,424         6,261
                                        -----------    ----------      ---------     ----------    ----------
Total costs and expenses..............      280,909       125,705         96,661         93,615        70,609
                                        -----------    ----------      ---------     ----------    ----------

Operating income......................      105,721        82,091         59,571         64,413        55,203
Interest and other income.............        3,570         4,277            316            408           626
Interest expense......................      (28,110)      (14,783)       (12,283)       (13,390)      (11,304)
Loss on debt extinguishment...........       (3,282)       (6,540)          -               -             -
                                         ----------    ----------      ---------     ----------    ----------
Income before income taxes............       77,899        65,045         47,604         51,431        44,525
Income tax expense....................       (4,083)         (256)          (943)        (1,496)         (418)
                                        -----------    ----------      ---------     ----------    ----------
Net income............................  $    73,816    $   64,789      $  46,661     $   49,935    $   44,107
                                        ===========    ==========      =========     ==========    ==========

Cash distributions declared...........  $    79,816    $   62,156      $  53,485     $   51,850    $   42,900
                                        ===========    ==========      =========     ==========    ==========

Balance Sheet Data (at year end):
Property and equipment, net...........  $ 1,092,192    $  481,274      $ 321,355     $  316,883    $  268,626
Total assets..........................    1,215,410       548,371        375,063        365,953       308,432
Long-term debt........................      694,330       262,624        166,900        155,987       153,000
Partners' capital.....................      393,314       220,527        161,735        169,321       106,437

</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"),  a  wholly-owned
subsidiary of Kaneb Services LLC ("KSL"), manages and controls the operations of
KPP  through its general  partner  interest  and a 20% (at  December  31,  2002)
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   terminaling  business  is  conducted  through  Support
Terminal Services  operation ("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 39 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.

     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 these two locations.


CONSOLIDATED RESULTS OF OPERATIONS
<TABLE>
<CAPTION>

                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2002                2001                 2000
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   386,630        $   207,796          $   156,232
                                                          ===========        ===========          ===========

Operating income.....................................     $   105,721        $    82,091          $    59,571
                                                          ===========        ===========          ===========

Net income...........................................     $    73,816        $    64,789          $    46,661
                                                          ===========        ===========          ===========

Capital expenditures, excluding acquisitions.........     $    31,101        $    17,246          $     9,483
                                                          ===========        ===========          ===========
</TABLE>


     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"  regarding 2002  acquisitions.  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.

     For the year ended December 31, 2001,  revenues increased by $51.6 million,
or 33%,  compared to 2000,  due to a $47.3  million  increase in revenues in the
terminaling  business  and a $4.3  million  increase in revenues in the pipeline
business.  Terminaling revenues include the operations of Shore from the January
3, 2001  acquisition  date (see  "Liquidity and Capital  Resources").  Operating
income for the year ended December 31, 2001 increased by $22.5 million,  or 38%,
when compared to 2000, due to a $22.0 million  increase in terminaling  business
operating  income and a $0.6  million  increase  in pipeline  operating  income.
Overall,  net income for the year ended  December  31, 2001  increased  by $18.1
million, or 39% when compared to 2000.


PIPELINE OPERATIONS
<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2002                 2001                2000
                                                          -----------        -----------          -----------
                                                                             (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $    82,698        $    74,976          $    70,685
Operating costs......................................          33,744             28,844               25,223
Depreciation and amortization........................           6,408              5,478                5,180
General and administrative...........................           3,923              3,881                4,069
                                                          -----------        -----------          -----------
Operating income.....................................     $    38,623        $    36,773          $    36,213
                                                          ===========        ===========          ===========
</TABLE>

     Pipeline revenues are based on volumes shipped and the distances over which
such volumes are  transported.  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
November and December 2002 pipeline  acquisitions  (see  "Liquidity  and Capital
Resources").  Approximately  $4.5  million of the 2002  revenue  increase  was a
result of the  pipeline  acquisitions.  For the year ended  December  31,  2001,
revenues increased by $4.3 million, or 6%, compared to 2000, due to increases in
barrel miles shipped and increases in terminaling charges.  Because tariff rates
are  regulated  by the FERC,  the  pipelines  compete  primarily on the basis of
quality of service,  including  delivering products at convenient locations on a
timely  basis to meet the  needs of its  customers.  Barrel  miles on  petroleum
pipelines  totaled  18.3  billion,  18.6  billion and 17.8 billion for the years
ended December 31, 2002, 2001 and 2000, 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 $4.9 million in 2002 and $3.6 million
in 2001. The increase in 2002 was due to the pipeline acquisitions and increases
in expenditures  for routine repairs and  maintenance.  The increase in 2001 was
due to increases in fuel and power costs and expenses from  pipeline  relocation
projects.  For the year ended December 31, 2002,  depreciation  and amortization
increased  by  $0.9  million,  when  compared  to  2001,  due  to  the  pipeline
acquisitions.  General and administrative  costs include managerial,  accounting
and   administrative   personnel  costs,   office  rental  expense,   legal  and
professional costs and other non-operating costs.


TERMINALING OPERATIONS
<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2002                 2001                2000
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $   205,971        $   132,820          $    85,547
Operating costs......................................          94,480             61,788               44,430
Depreciation and amortization........................          32,368             17,706               11,073
Gain on sale of assets...............................            (609)              -                  (1,126)
General and administrative...........................          14,692              8,008                7,812
                                                          -----------        -----------          -----------
Operating income.....................................     $    65,040        $    45,318          $    23,358
                                                          ===========        ===========          ===========
</TABLE>

     For the year ended December 31, 2002,  revenues increased by $73.2 million,
or 55%, compared to 2001, due to 2002 terminal  acquisitions (see "Liquidity and
Capital Resources") and overall increases in utilizations at existing locations.
Approximately  $63 million of the revenue  increase was a result of the terminal
acquisitions.  For the year ended December 31, 2001, revenues increased by $47.3
million,  or 55%, compared to 2000, due to the Shore acquisition (see "Liquidity
and  Capital  Resources")  and  overall  increases  in  utilization  at existing
locations.  Approximately  $36 million of the 2001 revenue increase was a result
of the Shore  acquisition.  Average annual tankage  utilized for the years ended
December 31, 2002, 2001 and 2000 aggregated 46.5 million  barrels,  30.1 million
barrels, and 21.0 million barrels, respectively.  Average revenues per barrel of
tankage utilized for the years ended December 31, 2002, 2001 and 2000 was $4.43,
$4.41, and $4.12, respectively. The increase in 2001 average revenues per barrel
of tankage utilized was due to more favorable domestic market  conditions,  when
compared to 2000.

     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.  In 2001,  operating costs increased by $17.4 million,  when
compared to 2000, due to the Shore  acquisition  and increases in volumes stored
at  existing  locations.  For the  years  ended  December  31,  2002  and  2001,
depreciation  and  amortization  increased  by $14.7  million and $6.6  million,
respectively,   due  to  the  terminal  acquisitions.  In  2002  and  2000,  the
Partnership sold land and other terminaling  business assets for net proceeds of
approximately $1.1 million and $2.0 million, respectively,  recognizing gains on
disposition  of assets of $0.6 million and $1.1 million,  respectively.  General
and administrative expense increased by $6.7 million in 2002 and by $0.2 million
in 2001. The increase in general and administrative expense in 2002, compared to
2001,  is due  to the  2002  terminal  acquisitions  and  overall  increases  in
personnel  costs.  The  increase  in general and  administrative  costs in 2001,
compared  to  2000,  is  due to  the  Shore  acquisition,  partially  offset  by
extraordinary high litigation costs in 2000.


PRODUCT SALES OPERATIONS
<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                          ---------------------------------------------------
                                                             2002                 2001                2000
                                                          -----------        -----------          -----------
                                                                            (in thousands)

<S>                                                       <C>                <C>                  <C>
Revenues.............................................     $    97,961        $      -             $      -
Cost of products sold................................          90,898               -                    -
                                                          -----------        -----------          -----------
Gross margin.........................................     $     7,063        $      -             $
                                                          ===========        ===========          ===========
Operating income.....................................     $     2,058        $      -             $      -
                                                          ===========        ===========          ===========
</TABLE>

     The product sales  business,  which was acquired with Statia in February of
2002 (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.  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 in the Consolidated Financial Statements 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 in the  Consolidated  Financial
Statements  as a component of interest and other  income.  On May 22, 2001,  the
contracts were settled resulting in a gain of $3.8 million.


INTEREST EXPENSE

     For the year ended December 31, 2002,  interest expense  increased by $13.3
million,  compared to 2001,  due to  increases in 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,  2001,  interest  expense  increased  by $2.5
million,  compared to 2000,  due to increases in debt  resulting  from the Shore
acquisition  (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 taxes. However,
certain  operations are conducted through  wholly-owned  corporate  subsidiaries
which are taxable  entities.  The income tax expense for the year ended December
31,  2002  includes  $1.9  million in income tax  expense  relating  to separate
taxable wholly-owned corporate subsidiaries acquired in 2002 (see "Liquidity and
Capital Resources").


LIQUIDITY AND CAPITAL RESOURCES

     Cash provided by operating activities was $91.8 million, $95.7 million, and
$62.0 million for the years 2002, 2001 and 2000,  respectively.  The decrease in
2002,  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.  The increase in 2001,
compared to 2000,  is due to increases  in  terminaling  revenues and  operating
income,  a result of the Shore  acquisition  and  increases  in  utilization  at
existing terminaling locations.

     Capital   expenditures,   including   routine   maintenance  and  expansion
expenditures, but excluding acquisitions, were $31.1 million, $17.2 million, and
$9.5 million for 2002, 2001 and 2000, respectively. The increase in 2002 capital
expenditures,  when  compared  to 2001,  is the  result of  routine  maintenance
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 $40
million in 2003. 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 $79.8 million,
$62.2 million and $53.5 million,  were declared with respect to limited  partner
interests and general partner interests in 2002, 2001 and 2000, respectively.

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

     The  Partnership  has a credit  agreement  with a group of banks  that,  as
amended, provides for a $275 million unsecured revolving credit facility through
January 2, 2004. The credit  facility bears interest at variable rates and has a
variable  commitment fee on unutilized  amounts.  The credit  facility  contains
certain   financial  and  operational   covenants,   including   limitations  on
investments,  sales of assets and  transactions  with  affiliates and, absent an
event of default,  the covenants do not restrict  distributions to partners.  At
December 31, 2002, the  Partnership  was in compliance  with all  covenants.  At
December  31,  2002,  $243.0  million was drawn on the  facility,  at an average
annual interest rate of 2.18%.

     On December 24, 2002, the Partnership entered into a $175 million unsecured
bridge loan agreement with a group of banks in connection with its 2002 pipeline
acquisitions. The bridge loan agreement, as amended, expires in January of 2004.
The bridge loan  agreement  bears  interest at variable rates (2.67% at December
31, 2002) and contains certain  operational and financial  covenants and, absent
an event of default, the covenants do not restrict distributions to partners. At
December 31, 2002, the  Partnership  was in compliance  with all covenants.  The
Partnership  expects to repay the bridge loan with additional  Partnership  bank
borrowings and/or future debt offerings or KPP public equity offerings.

     The  Partnership,  through  two  wholly-owned  subsidiaries,  has a  credit
agreement with a bank that provides for the issuance of term loans in connection
with its 1999 United Kingdom terminal acquisition. The term loans ($26.3 million
at December  31,  2002),  with a fixed rate of 7.25%,  are,  as amended,  due in
January of 2004. The term loans under the credit agreement are unsecured and are
pari passu with the $275 million revolving credit facility.  The term loans also
contain certain financial and operational  covenants.  At December 31, 2002, 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 in the Consolidated Financial Statements
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 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  the  amount of  indebtedness
outstanding 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, 2002, 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
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 financed by bank debt maturing in January of 2004.

     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 funded with bank debt
maturing in January of 2004.

     On March 21, 2003,  KPP issued  3,000,000  limited  partnership  units in a
public offering at $36.54 per unit,  generating  approximately $104.8 million in
net  proceeds.  The proceeds  will be used to reduce the amount of  indebtedness
under the Partnership's bridge facility.

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


CRITICAL ACCOUNTING POLICIES

     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 presented in the Notes
to the Consolidated Financial Statements.

     Critical  accounting  policies  are those  that are most  important  to the
portrayal to our financial  position and results of  operations.  These policies
require  management's  most difficult,  subjective or complex  judgments,  often
employing the use of estimates  about the effect of matters that are  inherently
uncertain.  Our most  critical  accounting  policies  pertain to  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
year ended December 31, 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, 2002, 2001 or 2000. 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 PRONOUNCEMENTS

     The Financial  Accounting  Standards Board (the "FASB") has issued SFAS No.
143   "Accounting  for  Asset   Retirement   Obligations",   which   establishes
requirements for the removal-type costs associated with asset  retirements.  The
Partnership  is currently  assessing  the impact of SFAS No. 143,  which must be
adopted in the first quarter of 2003.

     In April of 2002, the FASB issued SFAS No. 145,  which,  among other items,
affects  the income  statement  classification  of gains and  losses  from early
extinguishment  of debt.  Under SFAS No. 145,  early  extinguishment  of debt is
considered a risk management strategy, with resulting gains and losses no longer
classified  as an  extraordinary  item,  unless  the debt  extinguishment  meets
certain  unusual in nature and  infrequency  of  occurrence  criteria,  which is
expected to be rare.  Effective  October 1, 2002,  the  Partnership  adopted the
provisions  of  SFAS  No.  145  and  has  reclassified  all  previously-reported
extraordinary  losses on debt  extinguishment,  before income taxes, to "Loss on
debt extinguishment" in the consolidated statements of income.

     In July of 2002,  the  FASB  issued  SFAS No.  146  "Accounting  for  Costs
Associated with Exit or Disposal Activities",  which requires all restructurings
initiated  after December 31, 2002 be recorded when they are incurred and can be
measured at fair value.  The  Partnership  is currently  assessing the impact of
SFAS No. 146, which must be adopted in the first quarter of 2003.

     In November of 2002, the FASB issued  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 disclosure  requirements are effective for financial statements of
interim or annual  periods ending after December 15, 2002 and have been adopted.
Management  of  the   Partnership   believes  that  the   application   of  this
interpretation will have no effect on the consolidated  financial  statements of
the Partnership.

     In January of 2003, the FASB issued  Interpretation No. 46,  "Consolidation
of  Variable  Interest  Entities,   an  interpretation  of  ARB  No.  51."  This
interpretation  addressed the consolidation by business  enterprises of variable
interest entities as defined in the interpretation.  The interpretation  applies
immediately to variable  interests in variable  interest  entities created after
January 31,  2003,  and to variable  interests  in  variable  interest  entities
obtained after January 31, 2003. The interpretation requires certain disclosures
in  financial  statements  issued  after  January 31,  2003.  Management  of the
Partnership  believes that the application of this  interpretation  will have no
effect on the consolidated financial statements of the Partnership.


Item 7(a). Quantitative and Qualitative Disclosure 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.  The
Partnership  centrally  manages its debt and investment  portfolios  considering
investment  opportunities  and  risks  and  overall  financing  strategies.  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 $418 million at December  31,  2002, a one percent  increase in interest
rates would increase annual net interest expense by approximately $4.2 million.

     Information  regarding  the  Partnership's  September  2002  interest  rate
hedging transaction is included in "Item 7-Interest and Other Income."

     The  product  sales  business  periodically   purchases  refined  petroleum
products  for  resale  as bunker  fuel,  for small  volume  sales to  commercial
interests  and to maintain an  inventory  of  blendstocks  for  customers.  Such
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.  Increases or decreases in the market value of inventory,
which  were  not  significant  in  2002,  are  reflected  in the  product  sales
operations cost of the products sold.

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.


<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, 2002, is incorporated by reference in this
report.


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, 2002, 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,  2002,  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. Controls and Procedures

     Included in its recent Release No. 34-46427, effective August 29, 2002, the
Securities and Exchange  Commission adopted rules requiring  reporting companies
to maintain disclosure  controls and procedures to provide reasonable  assurance
that a  registrant  is  able  to  record,  process,  summarize  and  report  the
information required in the registrant's  quarterly and annual reports under the
Securities  Exchange Act of 1934 (the "Exchange Act"). While management believes
that the  Partnership's  existing  disclosure  controls and procedures have been
effective to  accomplish  these  objectives,  it intends to continue to examine,
refine and formalize the Partnership's disclosure controls and procedures and to
monitor ongoing developments in this area.

     KPL's principal  executive officer and principal  financial officer,  after
evaluating  the  effectiveness  of the  Partnership's  disclosure  controls  and
procedures (as defined in Exchange Act Rules 13a-14(c) and Rule 15d-14(c)) as of
a date  within 90 days  before the filing date of this  Report,  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.

     There have been no changes in the  Partnership's  internal  controls  or in
other factors known to management that could significantly affect those internal
controls  subsequent  to  the  date  of  the  evaluation,  nor  were  there  any
significant  deficiencies or material  weaknesses in the Partnership's  internal
controls. As a result, no corrective actions were required or undertaken.




<PAGE>
                                     PART IV


Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
<TABLE>
<CAPTION>
<S>    <C>                                                                                              <C>
    (a)(1)  Financial Statements                                                                        Beginning
                                                                                                          Page

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


         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, 2002...................     F - 2
           Consolidated Balance Sheets - December 31, 2002 and 2001..................................     F - 3
           Consolidated Statements of Cash Flows - Three Years Ended December 31, 2002...............     F - 4
           Consolidated Statements of Partners' Capital - Three Years ended December 31, 2002........     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 Pipeline Operating Partnership, L.P. Valuation and Qualifying
           Accounts - Years Ended December 31, 2002, 2001, and 2000..................................    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.

          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, 1993,  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 December 28, 2000 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 10.7 to
               KPP's  Form 10-K for the year  ended  December  31,  2000,  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  Registrant's  Current  Report on
               Form 8-K,  dated  January 24, 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 24, 2002,
               and incorporated herein by reference.

          21   List of Subsidiaries, filed herewith.

          23   Consent of KPMG LLP, filed herewith.

          99.1 Certification  of Chief  Executive  Officer,  Pursuant to Section
               906(a) of the  Sarbanes-Oxley  Act of 2002, dated as of March 28,
               2003, filed herewith.

          99.2 Certification  of Chief  Financial  Officer,  Pursuant to Section
               906(a) of the  Sarbanes-Oxley  Act of 2002, dated as of March 28,
               2003, filed herewith.


     (b)  Reports on Form 8-K

          Current Report on Form 8-K filed with the SEC on October 21, 2002.
          Current Report on Form 8-K filed with the SEC on November 7, 2002.
          Current Report on Form 8-K filed with the SEC on November 27, 2002.




<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,  2002 and 2001,  and the results of their
operations  and their cash flows for each of the years in the three year  period
ended  December 31, 2002, 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.

                                    KPMG LLP



Dallas, Texas
February 25, 2003, except as to note 11,
     which is as of March 21, 2003




                                     F - 1
<PAGE>
          KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>


                                                                           Year Ended December 31,
                                                        -----------------------------------------------------------
                                                               2002                 2001                 2000
                                                        -----------------    -----------------    -----------------
<S>                                                     <C>                  <C>                  <C>
Revenues:
   Services...........................................  $     288,669,000    $     207,796,000    $     156,232,000
   Products...........................................         97,961,000               -                    -
                                                        -----------------    -----------------    -----------------
      Total revenues..................................        386,630,000          207,796,000          156,232,000
                                                        -----------------    -----------------    -----------------

Costs and expenses:
   Cost of products sold..............................         90,898,000               -                    -
   Operating costs....................................        131,326,000           90,632,000           69,653,000
   Depreciation and amortization......................         39,425,000           23,184,000           16,253,000
   Gain on sale of assets.............................           (609,000)              -                (1,126,000)
   General and administrative.........................         19,869,000           11,889,000           11,881,000
                                                        -----------------    -----------------    -----------------
      Total costs and expenses........................        280,909,000          125,705,000           96,661,000
                                                         -----------------    -----------------   -----------------


Operating income......................................        105,721,000           82,091,000           59,571,000

Interest and other income.............................          3,570,000            4,277,000              316,000
Interest expense......................................        (28,110,000)         (14,783,000)         (12,283,000)
Loss on debt extinguishment...........................         (3,282,000)          (6,540,000)              -
                                                        -----------------    -----------------    -----------------
Income before income taxes ...........................         77,899,000           65,045,000           47,604,000

Income tax expense....................................         (4,083,000)            (256,000)            (943,000)
                                                        -----------------    -----------------    -----------------
Net income............................................  $      73,816,000    $      64,789,000    $      46,661,000
                                                        =================    =================    =================

</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,
                                                                             --------------------------------------
                                                                                   2002                  2001
                                                                             ----------------       ---------------
                                     ASSETS
<S>                                                                          <C>                    <C>
Current assets:
   Cash and cash equivalents...............................................  $     22,028,000       $     7,903,000
   Accounts receivable (net of allowance for doubtful accounts
      of $1,765,000 in 2002 and $278,000 in 2001)..........................        48,926,000            24,005,000
   Inventories.............................................................         4,922,000                 -
   Prepaid expenses and other..............................................         8,498,000             2,721,000
                                                                             ----------------       ---------------
      Total current assets.................................................        84,374,000            34,629,000
                                                                             ----------------       ---------------

Property and equipment.....................................................     1,288,762,000           639,084,000
Less accumulated depreciation..............................................       196,570,000           157,810,000
                                                                             ----------------       ---------------
      Net property and equipment...........................................     1,092,192,000           481,274,000
                                                                             ----------------       ---------------

Investment in affiliates...................................................        25,604,000            22,252,000

Excess of cost over fair value of net assets of acquired business and
   other assets............................................................        13,240,000            10,216,000
                                                                             ----------------       ---------------
                                                                             $  1,215,410,000       $   548,371,000
                                                                             ================       ===============


                        LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:
   Accounts payable........................................................  $     22,064,000        $    6,541,000
   Accrued expenses........................................................        29,339,000             9,415,000
   Accrued distributions payable...........................................        21,639,000            16,263,000
   Accrued interest payable................................................         7,896,000               548,000
   Accrued taxes, other than income taxes..................................         3,598,000             2,635,000
   Deferred terminaling fees...............................................         6,246,000             6,503,000
   Payable to general partner..............................................         5,403,000             4,701,000
                                                                             ----------------        --------------
      Total current liabilities............................................        96,185,000            46,606,000
                                                                             ----------------        --------------

Long-term debt.............................................................       694,330,000           262,624,000

Other liabilities and deferred taxes.......................................        31,581,000            18,614,000

Commitments and contingencies

Partners' capital:
   Limited partner.........................................................       390,904,000           221,363,000
   General partner.........................................................         1,016,000             1,030,000
   Accumulated other comprehensive income (loss)
      - foreign currency translation adjustment............................         1,394,000            (1,866,000)
                                                                             ----------------        --------------
      Total partners' capital..............................................       393,314,000           220,527,000
                                                                             ----------------        --------------

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

</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,
                                                          ---------------------------------------------------------
                                                              2002                  2001                  2000
                                                          -------------         -------------        --------------
<S>                                                       <C>                   <C>                  <C>
Operating activities:
   Net income ........................................    $  73,816,000         $  64,789,000        $  46,661,000
   Adjustments to reconcile net income to net
      cash provided by operating activities:
      Depreciation and amortization...................       39,425,000            23,184,000           16,253,000
      Equity in earnings of affiliates, net of
        distributions.................................       (3,164,000)               (5,000)            (154,000)
      Gain on sale of assets..........................         (609,000)                 -              (1,126,000)
      Deferred income taxes...........................        3,105,000               256,000              943,000
      Other liabilities...............................       (1,341,000)           (5,422,000)             841,000
      Changes in working capital components:
        Accounts receivable...........................      (12,379,000)             (824,000)          (4,162,000)
        Inventories, prepaid expenses and other.......       (6,601,000)            1,601,000             (255,000)
        Accounts payable and accrued expenses.........       (1,192,000)            9,298,000            2,511,000
        Payable to general partner....................          702,000             2,812,000              478,000
                                                         --------------         -------------       --------------
           Net cash provided by operating activities..       91,762,000            95,689,000           61,990,000
                                                         --------------         -------------       --------------

Investing activities:
   Acquisitions, net of cash acquired.................     (468,477,000)         (111,562,000)         (12,053,000)
   Capital expenditures...............................      (31,101,000)          (17,246,000)          (9,483,000)
   Proceeds from sale of assets.......................        1,107,000             2,807,000            1,961,000
   Other, net.........................................          306,000              (111,000)            (212,000)
                                                         --------------         -------------       --------------
           Net cash used in investing activities......     (498,165,000)         (126,112,000)         (19,787,000)
                                                         ---------------        -------------       --------------
Financing activities:
   Issuance of debt...................................      746,087,000           260,500,000           14,613,000
   Payments of debt...................................     (426,647,000)         (164,776,000)          (3,700,000)
   Distributions......................................      (74,439,000)          (62,156,000)         (53,485,000)
   Net proceeds from issuance of units by KPP.........      175,527,000                 -                   -
                                                         --------------         -------------       --------------
           Net cash provided by (used in) financing
               activities.............................      420,528,000            33,568,000          (42,572,000)
                                                         --------------         -------------       --------------
Increase (decrease) in cash and cash equivalents......       14,125,000             3,145,000             (369,000)
Cash and cash equivalents at beginning of period......        7,903,000             4,758,000            5,127,000
                                                         --------------         -------------       --------------
Cash and cash equivalents at end of period............   $   22,028,000         $   7,903,000       $    4,758,000
                                                         ==============         =============       ==============

Supplemental cash flow information:
   Cash paid for interest.............................   $   25,942,000         $  14,028,000       $   12,438,000
                                                         ==============         =============       ==============
   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>
Partners' capital at January 1, 2000.....   $  169,056,000  $  1,040,000   $  (775,000)  $  169,321,000

  2000 income allocation.................       46,194,000       467,000           -         46,661,000   $    46,661,000

  Distributions declared.................      (52,962,000)     (523,000)          -        (53,485,000)             -

  Foreign currency translation adjustment            -               -        (762,000)        (762,000)         (762,000)
                                            --------------   -----------   -----------   --------------   ---------------
  Comprehensive income for the year......                                                                 $    45,899,000
                                                                                                          ===============
Partners' capital at December 31, 2000...      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...............       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...............      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
                                            ==============   ===========   ===========   ==============

</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 20% (at December 31, 2002) limited partnership interest. KPL owns a
1% interest as general  partner of the  Partnership and a 1% interest as general
partner of KPP.

     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  the  amount of  indebtedness
outstanding 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.

     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  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.

     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 for 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, 2002, 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, 2002, 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 years ended December 31, 2001 and 2000 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.

     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 only requires  additional  disclosure and does not affect the  Partnership's
financial position or results of operations.

     Income Taxes

     Income  (loss)  before  income  tax  expense  is made  up of the  following
components:
<TABLE>
<CAPTION>
                                                                             Year Ended December 31,
                                                          ---------------------------------------------------------
                                                              2002                  2001                  2000
                                                          -------------         -------------        --------------
<S>                                                       <C>                   <C>                  <C>
       Partnership operations........................     $  71,614,000         $  62,650,000        $   43,538,000
       Corporate operations:
            Domestic.................................         2,046,000            (1,594,000)              510,000
            Foreign..................................         4,239,000             3,989,000             3,556,000
                                                          -------------         -------------        --------------
                                                          $  77,899,000         $  65,045,000        $   47,604,000
                                                          =============         =============        ==============
</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,  2002,  2001 and 2000
primarily  consists  of U.S.  and foreign  income  taxes of $4.1  million,  $0.3
million, and $0.9 million, respectively. The net deferred tax liability of $17.8
million and $6.1 million at December 31, 2002 and 2001,  respectively,  consists
of deferred tax  liabilities of $41.7 million and $12.5  million,  respectively,
and deferred tax assets of $23.9  million and $6.4  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  $27.6 million which are
subject to various limitations on use and expire in years 2009 through 2021.

     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,  or a minimum
payment of 500,000  Netherlands  Antilles guilders ($0.3 million) per year. This
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. During 1999, the subsidiary and representatives appointed by the
governments of the Netherlands Antilles and St. Eustatius completed a draft of a
new agreement  applicable to the subsidiary and certain affiliates and submitted
the draft for approval to each government. The draft as submitted called for the
new  agreement  to be  effective  retroactively  from  January 1, 1998,  through
December 31,  2010,  with  extension  provisions  to 2015.  The  subsidiary  has
proposed  certain  modifications  to the 1999 draft  including  extension of the
expiration of the new agreement to January 1, 2026 to match certain  Netherlands
Antilles  legislation.  The  subsidiary  has  accrued  amounts  which may become
payable  should the new agreement  become  effective.  On November 1, 2002,  the
subsidiary  received a new draft agreement submitted on behalf of the government
of St.  Eustatius  only,  which was  formally  rejected by the  subsidiary.  The
subsidiary is continuing  discussions with representatives of the governments of
the Netherlands  Antilles and St. Eustatius,  but the ultimate outcome cannot be
predicted at this time. The subsidiary  continues to honor the provisions of the
expired Free Zone and Profit Tax Agreement and make payments, as required, under
the 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  by a  publicly  held  partnership  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 $79.8 million,
$62.2 million and $53.5  million were  declared with respect to limited  partner
interests and general partner interests in 2002, 2001 and 2000, 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.

     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.

     Change in Presentation

     Certain prior year  financial  statement  items have been  reclassified  to
conform with the 2002 presentation.

     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

     The  FASB has  issued  SFAS  No.  143,  "Accounting  for  Asset  Retirement
Obligations",   which  establishes   requirements  for  the  removal-type  costs
associated with asset  retirements.  The Partnership is currently  assessing the
impact of SFAS No. 143, which must be adopted in the first quarter of 2003.

     In April of 2002, the FASB issued SFAS No. 145,  which,  among other items,
affects  the income  statement  classification  of gains and  losses  from early
extinguishment  of debt.  Under SFAS No. 145,  early  extinguishment  of debt is
considered a risk management strategy, with resulting gains and losses no longer
classified  as an  extraordinary  item,  unless  the debt  extinguishment  meets
certain  unusual in nature and  infrequency  of  occurrence  criteria,  which is
expected to be rare.  Effective  October 1, 2002,  the  Partnership  adopted the
provisions  of  SFAS  No.  145  and  has  reclassified  all  previously-reported
extraordinary losses on debt extinguishment, before minority interest and income
taxes,  to  "Loss  on  debt  extinguishment"  in the  accompanying  consolidated
statements of income.

     In July of 2002,  the FASB  issued  SFAS No.  146,  "Accounting  for  Costs
Associated with Exit or Disposal Activities",  which requires all restructurings
initiated  after December 31, 2002 be recorded when they are incurred and can be
measured at fair value.  The  Partnership  is currently  assessing the impact of
SFAS No. 146, which must be adopted in the first quarter of 2003.

     In November of 2002, the FASB issued  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 disclosure  requirements are effective for financial statements of
interim or annual  periods ending after December 15, 2002 and have been adopted.
Management  of  the   Partnership   believes  that  the   application   of  this
interpretation will have no effect on the consolidated  financial  statements of
the Partnership.

     In January of 2003, the FASB issued  Interpretation No. 46,  "Consolidation
of  Variable  Interest  Entities,   an  interpretation  of  ARB  No.  51."  This
interpretation  addressed the consolidation by business  enterprises of variable
interest entities as defined in the interpretation.  The interpretation  applies
immediately to variable  interests in variable  interest  entities created after
January 31,  2003,  and to variable  interests  in  variable  interest  entities
obtained after January 31, 2003. The interpretation requires certain disclosures
in  financial  statements  issued  after  January 31,  2003.  Management  of the
Partnership  believes that the application of this  interpretation  will have 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 funded with bank debt
maturing  in January of 2004 (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.  At December 31,
2002, the final  valuation of the acquired  assets and  liabilities has not been
completed  and,   accordingly,   the  Partnership  has  recorded  a  preliminary
allocation of the purchase price based on the estimated fair value. Based on the
preliminary purchase price allocation, no amounts are assigned to goodwill or to
other intangible assets.

     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 funded by bank debt maturing in January of 2004
(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.  At December  31,  2002,  the final  valuation  of the
acquired  assets and liabilities  has not been completed and,  accordingly,  the
Partnership has recorded a preliminary allocation of the purchase price based on
the estimated fair value. Based on the preliminary purchase price allocation, no
amounts are assigned to goodwill or to other intangible assets.

     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.  At December 31, 2002, the final
valuation of the acquired  assets and  liabilities  has not been  completed and,
accordingly,  the  Partnership  has  recorded a  preliminary  allocation  of the
purchase  price  based on the  estimated  fair value.  Based on the  preliminary
purchase  price  allocation,  no amounts  are  assigned  to goodwill or to other
intangible assets.

     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 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.  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 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
                                                                  =============

     In connection with the acquisition of Statia,  the Partnership has adopted,
and is in the final stages of  implementing,  a plan to relocate  and  integrate
Statia's businesses with the Partnership's existing operations.  The plan, which
provides for the  severance  and/or  relocation  of certain  administrative  and
operating  employees and  activities,  will be fully  implemented in early 2003.
Costs of $13.9 million  incurred in the  implementation  of the plan,  which are
recorded  in the  allocation  of the Statia  purchase  price,  include  employee
severance benefits, relocation costs and lease costs. At December 31, 2002, $7.9
million was accrued for such costs.

     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 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)                    2002                  2001
                                                     --------------          ----------------       ---------------

<S>                                                      <C>                 <C>                    <C>
       Land......................................           -                $     72,152,000       $    43,005,000
       Buildings.................................        25 - 35                   27,559,000            10,834,000
       Pipeline and terminaling equipment........        15 - 40                1,032,914,000           534,292,000
       Marine equipment..........................        15 - 30                   84,641,000               -
       Machinery and equipment...................        15 - 40                   34,880,000            32,750,000
       Furniture and fixtures....................         5 - 16                    7,892,000             3,900,000
       Transportation equipment..................         3 - 6                     5,414,000             5,092,000
       Construction work-in-progress.............           -                      23,310,000             9,211,000
                                                                             ----------------       ---------------
       Total property and equipment..............                               1,288,762,000           639,084,000
       Less accumulated depreciation.............                                 196,570,000           157,810,000
                                                                             ----------------       ---------------
       Net property and equipment................                            $  1,092,192,000       $   481,274,000
                                                                             ================       ===============
</TABLE>

5.   LONG-TERM DEBT

     Long-term debt is summarized as follows:

<TABLE>
<CAPTION>
                                                                                           December 31,
                                                                              -------------------------------------
                                                                                    2002                  2001
                                                                              ---------------        --------------
<S>                                                                           <C>                    <C>
       $275 million revolving credit facility, due in January of 2004....     $   243,000,000        $ 238,900,000
       $250 million 7.75% senior unsecured notes, due in February of 2012         250,000,000               -
       Bridge facility, due in January of 2004...........................         175,000,000               -
       Term loans, due in January of 2004................................          26,330,000            23,724,000
                                                                              ---------------        --------------
       Total long-term debt..............................................     $   694,330,000        $  262,624,000
                                                                              ===============        ==============
</TABLE>

     The  Partnership  has a credit  agreement  with a group of banks  that,  as
amended, provides for a $275 million unsecured revolving credit facility through
January 2, 2004. The credit  facility bears interest at variable rates and has a
variable  commitment fee on unutilized  amounts.  The credit  facility  contains
certain   financial  and  operational   covenants,   including   limitations  on
investments,  sales of assets and transactions  with affiliates,  and, absent an
event of default,  the covenants do not restrict  distributions to partners.  At
December 31, 2002, the  Partnership  was in compliance  with all  covenants.  In
January  2001,  proceeds  from  the  facility  were  used to  repay  in full the
Partnership's  $128  million of  mortgage  notes.  Under the  provisions  of the
mortgage notes,  the Partnership  incurred $6.5 million in prepayment  penalties
which was recognized as loss on debt  extinguishment in 2001. An additional $107
million was used to finance the cash portion of the 2001 Shore  acquisition (see
Note 3). At December  31, 2002,  $243.0  million was drawn on the facility at an
interest rate of 2.18%.

     On December 24, 2002, the Partnership entered into a $175 million unsecured
bridge loan agreement with a group of banks in connection with its 2002 pipeline
acquisitions. The bridge loan agreement, as amended, expires in January of 2004.
The bridge loan  agreement  bears  interest at variable rates (2.67% at December
31, 2002) and contains certain  operational and financial  covenants and, absent
an event of default, the covenants do not restrict distributions to partners. At
December 31, 2002, the  Partnership  was in compliance  with all covenants.  The
Partnership  expects  to repay  the  bridge  loan  with  additional  Partnership
borrowings and/or future debt offerings or KPP public equity offerings.

     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, 2002, the
Partnership was in compliance with all covenants.

     The  Partnership,  through  two  wholly-owned  subsidiaries,  has a  credit
agreement with a bank that provides for the issuance of term loans in connection
with its 1999 United Kingdom terminal acquisition. The term loans ($26.3 million
at December  31,  2002),  with a fixed rate of 7.25%,  are,  as amended,  due in
January of 2004. The term loans under the credit agreement are unsecured and are
pari passu with the $275 million revolving credit facility.  The term loans also
contain certain financial and operational  covenants.  At December 31, 2002, the
Partnership was in compliance with all covenants.


6.   COMMITMENTS AND CONTINGENCIES

     The following is a schedule by years of future minimum lease payments under
operating leases as of December 31, 2002:

     Year ending December 31:
        2003...............................................      $    6,734,000
        2004...............................................           3,038,000
        2005...............................................             840,000
        2006...............................................             612,000
        2007...............................................             412,000
        Thereafter.........................................             360,000
                                                                 --------------
           Total minimum lease payments....................      $   11,996,000
                                                                 ==============

     Total rent expense under operating  leases  amounted to $9.4 million,  $4.2
million,  and $3.1 million for the years ended December 31, 2002, 2001 and 2000,
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 $18.7 million at
December 31, 2002,  including $12.6 million related to acquisitions of pipelines
and terminals. During 2002 and 2001, respectively, the Partnership incurred $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  acquired with Statia (see Note 3)
are parties to a 1996 agreement with Praxair, Inc. ("Praxair"),  wherein Praxair
has agreed to pay certain  environmental costs related to the Point Tupper, Nova
Scotia,  Canada  facility.  Based on  investigations  conducted and  information
available to date, the potential cost for future  remediation and compliance for
these matters is estimated at approximately  $7.3 million,  substantially all of
which the Partnership believes is the responsibility of Praxair.

     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.

     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 except one have
been  settled  for  immaterial   amounts  with  ST  Services'  portion  of  such
settlements  provided by its insurance carrier.  ST Services'  insurance carrier
has assumed the defense of the continuing  action and ST Services  believes that
the carrier would assume the defense of any new litigation by a  non-participant
in  the  settlement,   should  any  such  litigation  be  commenced.  While  the
Partnership  cannot predict the amount,  if any, of any liability it may have in
the continuing  action or in other potential  suits relating to this matter,  it
believes  that the current and potential  plaintiffs'  claims will be covered by
insurance and therefore these actions will not have a material adverse effect on
its financial condition.

     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  causes of action,  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 the oil  spill.  Both  parties  have  pending
motions to dismiss the other party's  suit.  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 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 or results of operations 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 $27.3
million, $18.1 million, and $17.8 million for the years ended December 31, 2002,
2001 and 2000, 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 $17.7 million,  $14.3 million,  and $12.3 million of compensation
and benefits,  paid to officers and employees of KPL and KSL for the years ended
December 31, 2002,  2001 and 2000,  respectively.  In addition,  the Partnership
paid $0.6 million in 2002, $0.5 million in 2001, and $0.2 million in 2000 for an
allocable portion of KPL's overhead expenses. At December 31, 2002 and 2001, the
Partnership  owed KPL and KSL $5.4 million and $4.7 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 fuels 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.

<TABLE>
<CAPTION>

                                                                                  Year Ended December 31,
                                                                ------------------------------------------------------
                                                                       2002                2001              2000
                                                                ----------------    ---------------     --------------
<S>                                                             <C>                 <C>                 <C>
       Business segment revenues:
         Pipeline operations..................................  $     82,698,000    $    74,976,000     $   70,685,000
         Terminaling operations...............................       205,971,000        132,820,000         85,547,000
         Product sales operations.............................        97,961,000              -                 -
                                                                ----------------    ---------------     --------------
                                                                $    386,630,000    $   207,796,000     $  156,232,000
                                                                ================    ===============     ==============
       Business segment profit:
         Pipeline operations..................................  $     38,623,000    $    36,773,000     $   36,213,000
         Terminaling operations...............................        65,040,000         45,318,000         23,358,000
         Product sales operations.............................         2,058,000              -                 -
                                                                ----------------    ---------------     --------------
            Operating income..................................       105,721,000         82,091,000         59,571,000
         Interest and other income ...........................         3,570,000          4,277,000            316,000
         Interest expense.....................................       (28,110,000)       (14,783,000)       (12,283,000)
         Loss on debt extinguishment..........................        (3,282,000)        (6,540,000)            -
                                                                ----------------    ---------------     --------------
            Income before income taxes........................  $     77,899,000    $    65,045,000     $   47,604,000
                                                                ================    ===============     ==============
       Business segment assets:
         Depreciation and amortization:
            Pipeline operations...............................  $      6,408,000    $     5,478,000     $    5,180,000
            Terminaling operations............................        32,368,000         17,706,000         11,073,000
            Product sales operations..........................           649,000              -                 -
                                                                ----------------    ---------------     --------------
                                                                $     39,425,000    $    23,184,000     $   16,253,000
                                                                ================    ===============     ==============
         Capital expenditures (excluding acquisitions):
            Pipeline operations...............................  $      9,469,000    $     4,309,000     $    3,439,000
            Terminaling operations............................        20,953,000         12,937,000          6,044,000
            Product sales operations..........................           679,000              -                 -
                                                                ----------------    ---------------     --------------
                                                                $     31,101,000    $    17,246,000     $    9,483,000
                                                                ================    ===============     ==============

                                                                                       December 31,
                                                                ------------------------------------------------------
                                                                      2002                2001               2000
                                                                ----------------    ---------------     --------------
         Total assets:
           Pipeline operations................................  $    352,657,000    $   105,156,000     $  102,656,000
           Terminaling operations.............................       844,321,000        443,215,000        272,407,000
            Product sales operations..........................        18,432,000              -                 -
                                                                ----------------    ---------------     --------------
                                                                $  1,215,410,000    $   548,371,000     $  375,063,000
                                                                ================    ===============     ==============

</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,
                                                                ------------------------------------------------------
                                                                       2002                2001              2000
                                                                ----------------    ---------------     --------------
<S>                                                             <C>                 <C>                 <C>
       Geographical area revenues:
         United States........................................  $    202,124,000    $   186,734,000     $  136,729,000
         United Kingdom.......................................        23,937,000         21,062,000         19,503,000
         Netherlands Antilles.................................       132,387,000              -                 -
         Canada...............................................        23,207,000              -                 -
         Australia and New Zealand............................         4,975,000              -                 -
                                                                ----------------    ---------------     --------------
                                                                $    386,630,000    $   207,796,000     $  156,232,000
                                                                ================    ===============     ==============
       Geographical area operating income:
         United States........................................  $     82,906,000    $    76,575,000     $   55,122,000
         United Kingdom.......................................         7,318,000          5,516,000          4,449,000
         Netherlands Antilles.................................         9,616,000              -                 -
         Canada...............................................         4,398,000              -                 -
         Australia and New Zealand............................         1,483,000              -                 -
                                                                ----------------    ---------------     --------------
                                                                $    105,721,000    $    82,091,000     $   59,571,000
                                                                ================    ===============     ==============

                                                                                       December 31,
                                                                ------------------------------------------------------
                                                                       2002                2001              2000
                                                                ----------------    ---------------     --------------
       Geographical area net property and equipment:
         United States........................................  $    690,178,000    $   440,104,000     $  282,685,000
         United Kingdom.......................................        46,543,000         41,170,000         38,670,000
         Netherlands Antilles.................................       224,810,000              -                 -
         Canada...............................................        78,789,000              -                 -
         Australia and New Zealand............................        51,872,000              -                 -
                                                                ----------------    ---------------     --------------
                                                                $  1,092,192,000    $   481,274,000     $  321,355,000
                                                                ================    ===============     ==============
</TABLE>

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

     The  estimated  fair  value of debt as of  December  31,  2002 and 2001 was
approximately  $709 million and $263 million,  as compared to the carrying value
of $694 million and $263,  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.  The  Partnership had no derivative  financial  instruments at
December 31, 2002.

     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,
2002. No customer  constituted  10 percent or more of  consolidated  revenues in
2002, 2001 and 2000.


10.  QUARTERLY FINANCIAL DATA (unaudited)

     Quarterly operating results for 2002 and 2001 are summarized as follows:

<TABLE>
<CAPTION>

                                                                            Quarter Ended
                                            --------------------------------------------------------------------------
                                                March 31,           June 30,          September 30,      December 31,
                                            ----------------    ----------------    ---------------     --------------
<S>                                         <C>                 <C>                 <C>                 <C>
       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(a) $    19,491,000     $   19,776,000(b)
                                            ================    ================    ===============     ==============
       2001:
       Revenues.......................      $     48,069,000    $     52,952,000    $    53,403,000     $   53,372,000
                                            ================    ================    ===============     ==============

       Operating income...............      $     18,335,000    $     21,871,000    $    22,076,000     $   19,809,000
                                            ================    ================    ===============     ==============

       Net income.....................      $      8,272,000(c) $     21,144,000(d) $    18,523,000     $   16,850,000
                                            ================    ================    ===============     ==============
</TABLE>


(a)  Includes loss on debt extinguishment of approximately $1.9 million.
(b)  Includes loss on debt extinguishment of approximately $1.2 million and gain
     on interest rate lock transaction at approximately $3.0 million.
(c)  Includes loss on debt extinguishment of approximately $6.5 million and gain
     on interest rate lock transaction of approximately $0.6 million.
(d)  Includes  gain on interest  rate lock  transaction  of  approximately  $3.2
     million.


11.  SUBSEQUENT EVENT

     On March 21, 2003,  KPP issued  3,000,000  limited  partnership  units in a
public offering at $36.54 per unit,  generating  approximately $104.8 million in
net  proceeds.  The proceeds  will be used to reduce the amount of  indebtedness
under the Partnership's bridge facility.




<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, 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
                                       =============      ===========      ==========       ===========      =========
Year Ended December 31, 2000:
   For doubtful receivables
     classified as current assets...   $         278      $       400      $     -          $     (428)(b)   $     250
                                       =============      ===========      ==========       ==========       =========

</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 28, 2003


     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 28, 2003
----------------------------------------                       and Chief Executive Officer
Principal Accounting Officer
    //s// HOWARD C. WADSWORTH                                  Vice President                March 28, 2003
----------------------------------------                       Treasurer & Secretary

Directors

      //s//  SANGWOO AHN                                       Director                      March 28, 2003
----------------------------------------


      //s//  JOHN R. BARNES                                    Director                      March 28, 2003
----------------------------------------


      //s//  MURRAY R. BILES                                   Director                      March 28, 2003
----------------------------------------


      //s//  FRANK M. BURKE, JR.                               Director                      March 28, 2003
----------------------------------------


      //s//  CHARLES R. COX                                    Director                      March 28, 2003
----------------------------------------


      //s//  HANS KESSLER                                      Director                      March 28, 2003
----------------------------------------


    //s//   JAMES R. WHATLEY                                   Director                      March 28, 2003
----------------------------------------

</TABLE>



<PAGE>

                    CERTIFICATION OF CHIEF EXECUTIVE OFFICER


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-14 and 15d-14) for the registrant and have:

     a)   designed  such  disclosure  controls  and  procedures  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)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

     c)   presented   in  this   annual   report  our   conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

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

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrant's  other  certifying  officers and I have indicated in this
     annual report whether there were significant  changes in internal  controls
     or in other  factors  that could  significantly  affect  internal  controls
     subsequent  to the  date  of our  most  recent  evaluation,  including  any
     corrective  actions with regard to  significant  deficiencies  and material
     weaknesses.


Date: March 28, 2003




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


<PAGE>


                    CERTIFICATION OF CHIEF FINANCIAL OFFICER


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-14 and 15d-14) for the registrant and have:

     a)   designed  such  disclosure  controls  and  procedures  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)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

     c)   presented   in  this   annual   report  our   conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

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

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrant's  other  certifying  officers and I have indicated in this
     annual report whether there were significant  changes in internal  controls
     or in other  factors  that could  significantly  affect  internal  controls
     subsequent  to the  date  of our  most  recent  evaluation,  including  any
     corrective  actions with regard to  significant  deficiencies  and material
     weaknesses.


Date: March 28, 2003




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