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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
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:
Year Ended December 31,
------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
------------- ------------- -------------- ------------- --------------
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
(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:
Year Ended December 31,
(thousands of barrels)
------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
------------- ------------- -------------- ------------- --------------
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
============= ============= ============== ============= ==============
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.
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.
Location of Number Tankage Truck
Terminals of Tanks Capacity Capacity(a)
----------------------------- -------- --------- -----------
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
====== ===========
(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.
The following table outlines the Partnership's terminal locations,
capacities, tanks and primary products handled:
Tankage No. of Primary Products
Facility Capacity Tanks Handled
- -----------------------------------------------------------------------------------------------------
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
Tankage No. of Primary Products
Facility Capacity Tanks Handled
- -----------------------------------------------------------------------------------------------------
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
=============== ==============
(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.
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.
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."
Year Ended December 31,
--------------------------------------------------------------------
2002 (a) 2001 (a) 2000 1999 1998
---------- ---------- --------- ---------- ----------
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
(a) See Note 3 to Consolidated Financial Statements regarding acquisitions.
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
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
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
=========== =========== ===========
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
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
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
=========== =========== ===========
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
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
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
=========== =========== ===========
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
Year Ended December 31,
---------------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 97,961 $ - $ -
Cost of products sold................................ 90,898 - -
----------- ----------- -----------
Gross margin......................................... $ 7,063 $ - $
=========== =========== ===========
Operating income..................................... $ 2,058 $ - $ -
=========== =========== ===========
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.
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.
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(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
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.
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
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
-----------------------------------------------------------
2002 2001 2000
----------------- ----------------- -----------------
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
================= ================= =================
See notes to consolidated financial statements.
F - 2
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------------------------
2002 2001
---------------- ---------------
ASSETS
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
================ ==============
See notes to consolidated financial statements.
F - 3
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------------------------------
2002 2001 2000
------------- ------------- --------------
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 $ -
============== ============= ==============
See notes to consolidated financial statements.
F - 4
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
Accumulated
Other
Limited General Comprehensive Comprehensive
Partner Partner Income (Loss) Total Income
-------------- ------------ ------------- -------------- -------------
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
============== =========== =========== ==============
See notes to consolidated financial statements.
F - 5
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:
Year Ended December 31,
---------------------------------------------------------
2002 2001 2000
------------- ------------- --------------
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
============= ============= ==============
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:
Estimated
Useful December 31,
Life --------------------------------------
(Years) 2002 2001
-------------- ---------------- ---------------
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
================ ===============
5. LONG-TERM DEBT
Long-term debt is summarized as follows:
December 31,
-------------------------------------
2002 2001
--------------- --------------
$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
=============== ==============
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.
Year Ended December 31,
------------------------------------------------------
2002 2001 2000
---------------- --------------- --------------
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
================ =============== ==============
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.
Year Ended December 31,
------------------------------------------------------
2002 2001 2000
---------------- --------------- --------------
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
================ =============== ==============
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:
Quarter Ended
--------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
---------------- ---------------- --------------- --------------
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
================ ================ =============== ==============
(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.
Schedule II
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
VALUATION AND QUALIFYING ACCOUNTS
(in thousands)
Additions
-----------------------------
Balance at Charged to Charged to Balance at
Beginning of Costs and Other End of
Period Expenses Accounts Deductions Period
------------ ----------- ------------- ---------- ----------
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
============= =========== ========== ========== =========
Notes:
(a) Allowance for doubtful receivables from 2002 acquisitions.
(b) Receivable write-offs and reclassifications, net of recoveries.
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.
Signature Title Date
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
- ----------------------------------------
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
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
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Howard C. Wadsworth
Vice President, Treasurer and Secretary
Chief Executive Officer