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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, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 333-44634
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
(Exact name of Registrant as specified in its Charter)
Delaware 75-2287683
(State or other jurisdiction of IRS Employer
incorporation or organization) Identification No.)
2435 North Central Expressway
Richardson, Texas 75080
- ---------------------------------------- --------------------
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (972) 699-4062
Title of each class
--------------------------------------------------------
7.75% Senior Unsecured Notes due 2012
5.875% Senior Unsecured Notes due 2013
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
X Yes No
----- ----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Subsection 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K.
N/A
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
X Yes No
----- ----
PART I
Item 1. Business
GENERAL
Kaneb Pipe Line Operating Partnership, L.P., a Delaware limited
partnership (the "Partnership"), is engaged in the refined petroleum products
and anhydrous ammonia pipeline business and the terminaling of petroleum
products and specialty liquids. Kaneb Pipe Line Partners, L.P. ("KPP") (NYSE:
KPP), a master limited partnership, holds a 99% interest as a limited partner in
the Partnership. Kaneb Pipe Line Company LLC, a Delaware limited liability
company ("KPL"), a wholly-owned subsidiary of Kaneb Services LLC, a Delaware
limited liability company ("KSL") (NYSE: KSL), holds the 1% interest as general
partner of the Partnership and a 1% interest as general partner of KPP. The
terminaling business of the Partnership is conducted through Support Terminals
Operating Partnership, L.P. ("STOP"), and its affiliated partnerships and
corporate entities, which operate under the trade names "ST Services" and
"StanTrans," among others; and Statia Terminals Holdings Company LLC and its
subsidiary entities ("Statia").
PIPELINE BUSINESS
Introduction
The Partnership's pipeline business consists primarily of the
transportation of refined petroleum products as a common carrier in Kansas,
Nebraska, Iowa, South Dakota, North Dakota, Colorado, Wyoming and Minnesota. On
December 24, 2002, the Partnership acquired the Northern Great Plains Product
System from Tesoro Refining and Marketing Company for approximately $100
million. This product pipeline system is now referred to as the Partnership's
North Pipeline. On November 1, 2002, the Partnership acquired a 2,000 mile
anhydrous ammonia pipeline from Koch Pipeline Company, LP and Koch Fertilizer
Storage and Terminal Company for approximately $139 million. The Partnership's
three refined petroleum products pipelines and the anhydrous ammonia pipeline
are described below.
East Pipeline
Construction of the East Pipeline commenced in 1953 with a line from
southern Kansas to Geneva, Nebraska. During subsequent years, the East Pipeline
was extended northward to its present terminus at Jamestown, North Dakota, west
to North Platte, Nebraska and east into the State of Iowa. The East Pipeline,
which moves refined products from south to north, now consists of 2,090 miles of
pipeline ranging in size from 6 inches to 16 inches.
The East Pipeline system also consists of 17 product terminals in
Kansas, Nebraska, Iowa, South Dakota and North Dakota with total storage
capacity of approximately 3.5 million barrels and an additional 23 product tanks
with total storage capacity of approximately 1,118,393 barrels at its tank farm
installations at McPherson and El Dorado, Kansas. The system also has six origin
pump stations in Kansas and 38 booster pump stations throughout the system.
Additionally, the system maintains various office and warehouse facilities, and
an extensive quality control laboratory.
The East Pipeline transports refined petroleum products, including
propane, received from refineries in southeast Kansas and other connecting
pipelines to its terminals along the system and to receiving pipeline
connections in Kansas. Shippers on the East Pipeline obtain refined petroleum
products from refineries connected to the East Pipeline or through other
pipelines directly connected to the pipeline system. Five connecting pipelines
can deliver propane for shipment through the East Pipeline from gas processing
plants in Texas, New Mexico, Oklahoma and Kansas.
Much of the refined petroleum products delivered through the East
Pipeline are ultimately used as fuel for railroads or in agricultural
operations, including fuel for farm equipment, irrigation systems, trucks used
for transporting crops and crop drying facilities. Demand for refined petroleum
products for agricultural use, and the relative mix of products required, is
affected by weather conditions in the markets served by the East Pipeline.
Government agricultural policies and crop prices also affect the agricultural
sector. Although periods of drought suppress agricultural demand for some
refined petroleum products, particularly those used for fueling farm equipment,
the demand for fuel for irrigation systems often increases during such times.
The mix of refined petroleum products delivered varies seasonally, with
gasoline demand peaking in early summer, diesel fuel demand peaking in late
summer and propane demand higher in the fall. In addition, weather conditions in
the areas served by the East Pipeline affect both the demand for and the mix of
the refined petroleum products delivered through the East Pipeline, although
historically any impact on total volumes shipped has been short-term. Tariffs
charged to shippers for transportation of products do not vary according to the
type of product delivered.
West Pipeline
The Partnership acquired the West Pipeline in February 1995, increasing
the Partnership's pipeline business in South Dakota and expanding it into
Wyoming and Colorado. The West Pipeline system includes approximately 550 miles
of pipeline in Wyoming, Colorado and South Dakota, four truck-loading terminals
and numerous pump stations situated along the system. The system's four product
terminals have a total storage capacity of over 1.7 million barrels.
The West Pipeline originates near Casper, Wyoming, where it serves as a
connecting point with Sinclair's Little America Refinery and the Seminoe
Pipeline which transports product from Billings, Montana area refineries. At
Douglas, Wyoming, a 6 inch pipeline branches off to serve the Partnership's
Rapid City, South Dakota terminal approximately 190 miles away. The 6 inch
pipeline also receives product from Wyoming Refining's pipeline at a connection
located near the Wyoming/South Dakota border. From Douglas, the Partnership's
pipeline continues southward through a delivery point at the Burlington Northern
junction to terminals at Cheyenne, Wyoming, the Denver metropolitan area and
Fountain, Colorado.
The West Pipeline system parallels the Partnership's East Pipeline to
the west. The East Pipeline's North Platte line terminates in western Nebraska,
approximately 200 miles east of the West Pipeline's Cheyenne, Wyoming Terminal.
The West Pipeline serves Denver and other eastern Colorado markets and supplies
jet fuel to Ellsworth Air Force Base at Rapid City, South Dakota, as compared to
the East Pipeline's largely agricultural service area. The West Pipeline has a
relatively small number of shippers who, with few exceptions, are also shippers
on the Partnership's East Pipeline system.
North Pipeline
The North Pipeline, acquired in December 2002, runs from west to east
approximately 440 miles from its origin at the Tesoro Refining and Marketing
Company's Mandan, North Dakota refinery to the Minneapolis, Minnesota area. It
has four product terminals, one in North Dakota and three in Minnesota, with a
total tankage capacity of 1.3 million barrels. The North Pipeline crosses the
Partnership's East Pipeline near Jamestown, North Dakota where the two pipelines
are connected. The North Pipeline is presently supplied exclusively by the
Mandan refinery, however, it is capable of delivering or receiving products to
or from the East Pipeline.
Ammonia Pipeline
In November 2002, the Partnership acquired the anhydrous ammonia
pipeline (the "Ammonia Pipeline") from two Koch companies. Anhydrous ammonia is
primarily used as agricultural fertilizer through direct application. Other uses
are as a component of various types of dry fertilizer as well as use as a
cleaning agent in power plant scrubbers. The 2,000 mile pipeline originates in
the Louisiana delta area where it has access to three marine terminals on the
Mississippi River. It moves north through Louisiana and Arkansas into Missouri,
where at Hermann, Missouri, one branch splits going east into Illinois and
Indiana, and the other branch continues north into Iowa and then turning west
into Nebraska. The Partnership acquired a storage and loading terminal near
Hermann, Missouri which was leased back to Koch Nitrogen. The operations
headquarters for the Ammonia Pipeline is located in Hermann, Missouri. The
Ammonia Pipeline is connected to twenty-two other third party owned terminals
and also has several industrial facility delivery locations. Product is
primarily supplied to the pipeline from plants in Louisiana and foreign-source
product delivered through the marine terminals.
Other Systems
The Partnership also owns three single-use pipelines, located near
Umatilla, Oregon; Rawlins, Wyoming and Pasco, Washington, each of which supplies
diesel fuel to a railroad fueling facility. The Oregon and Washington lines are
fully automated, however the Wyoming line utilizes a coordinated startup
procedure between the refinery and the railroad. For the year ended December 31,
2003, these three systems combined transported a total of 3.7 million barrels of
diesel fuel, representing an aggregate of $1.5 million in revenues.
Pipelines Products and Activities
The revenues for the East Pipeline, West Pipeline, North Pipeline,
Ammonia Pipeline and Other Pipelines (collectively, the "Pipelines") are based
upon volumes and distances of product shipped. The following table reflects the
total volume, barrel miles of refined petroleum products shipped and total
operating revenues earned by the Pipelines for each of the periods indicated,
but does not include any information on the Ammonia Pipeline. In addition
information on the North Pipeline system prior to 2003 is not included. During
the year of 2003, the Ammonia Pipeline shipped 1,155,160 tons of ammonia
generating $21.3 million of revenue.
Year Ended December 31,
------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
------------- ------------- -------------- ------------- --------------
Volume (1).................. 102,928 89,780 92,116 89,192 85,356
Barrel miles (2)............ 21,327 18,275 18,567 17,843 18,440
Revenues (3)................ $98,329 $78,240 $74,976 $70,685 $67,607
(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)
------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
------------- ------------- -------------- ------------- --------------
Gasoline.................... 53,205 45,106 46,268 44,215 41,472
Diesel and fuel oil......... 46,072 40,450 42,354 41,087 40,435
Propane..................... 3,651 4,224 3,494 3,890 3,449
------------- ------------- -------------- ------------- --------------
Total....................... 102,928 89,780 92,116 89,192 85,356
============= ============= ============== ============= ==============
Diesel and fuel oil are used in farm machinery and equipment,
over-the-road transportation, railroad fueling and residential fuel oil.
Gasoline is primarily used in over-the-road transportation and propane is used
for crop drying, residential heating and to power irrigation equipment. The mix
of refined petroleum products delivered varies seasonally, with gasoline demand
peaking in early summer, diesel fuel demand peaking in late summer and propane
demand higher in the fall. In addition, weather conditions in the areas served
by the East Pipeline affect both the demand for and the mix of the refined
petroleum products delivered through the East Pipeline, although historically
any overall impact on the total volumes shipped has been short-term. Tariffs
charged to shippers for transportation of products do not vary according to the
type of product delivered. Demand on the North Pipeline is mainly of the same
agricultural nature as the East Pipeline except for the Minneapolis terminal
area which is more metropolitan.
Maintenance and Monitoring
The Pipelines have been constructed and are maintained in a manner
consistent with applicable federal, state and local laws and regulations,
standards prescribed by the American Petroleum Institute and accepted industry
practice. Further, protective measures are taken and routine preventive
maintenance is performed on the Pipelines in order to prolong their useful
lives. Such measures include cathodic protection to prevent external corrosion,
inhibitors to prevent internal corrosion and periodic inspection of the
Pipelines. Additionally, the Pipelines are patrolled at regular intervals to
identify equipment or activities by third parties that, if left unchecked, could
result in encroachment upon the Pipeline's rights-of-way and possible damage to
the Pipelines.
The Partnership uses state-of-the-art Supervisory Control and Data
Acquisition remote supervisory control software programs to continuously monitor
and control the Pipelines from the Wichita, Kansas headquarters and from the
Roseville, Minnesota terminal for the North Pipeline. The system monitors
quantities of products injected in and delivered through the Pipelines and
automatically signals the Wichita or Roseville personnel upon deviations from
normal operations that requires attention.
Pipeline Operations
For pipeline operations, integrity management and public safety, the
East Pipeline, the West Pipeline, the North Pipeline and the Ammonia Pipeline
are subject to federal regulation by one or more of the following governmental
agencies or laws: the Federal Energy Regulatory Commission ("FERC"), the Surface
Transportation Board, the Department of Transportation, the Environmental
Protection Agency, and the Homeland Security Act. Additionally, the operations
and integrity of the Pipelines are subject to the respective state jurisdictions
along the route of the systems. See "Regulation."
Except for the three single-use pipelines and certain ethanol
facilities, all of the Partnership's pipeline operations constitute common
carrier operations and are subject to federal tariff regulation. In May 1998,
the Partnership was authorized by the FERC to adopt market-based rates in
approximately one-half of its markets on the East and West systems. Common
carrier activities are those for which transportation through the Partnership's
Pipelines is available at published tariffs filed, in the case of interstate
petroleum product shipments, with the FERC or, in the case of intrastate
petroleum product shipments in Kansas, Colorado, Wyoming and North Dakota, with
the relevant state authority, to any shipper of refined petroleum products who
requests such services and satisfies the conditions and specifications for
transportation. The Ammonia Pipeline is subject to federal regulation by the
Surface Transportation Board, rather than the FERC.
In general, a shipper on one of the Partnership's refined petroleum
products pipelines delivers products to the pipeline from refineries or third
party pipelines that connect to the Pipelines. The Pipelines' refined petroleum
products operations also include 25 truck-loading terminals through which
refined petroleum products are delivered to storage tanks and then loaded into
petroleum transport trucks. Five of the 25 terminals also receive propane into
storage tanks and then load it into transport trucks. The Ammonia Pipeline
receives product from anhydrous ammonia plants or from the marine terminals for
imported product. Tariffs for transportation are charged to shippers based upon
transportation from the origination point on the pipeline to the point of
delivery. Such tariffs also include charges for terminaling and storage of
product at the Pipeline's terminals. Pipelines are generally the lowest cost
method for intermediate and long-haul overland transportation of refined
petroleum products.
Each shipper transporting product on a pipeline is required to supply
the Partnership with a notice of shipment indicating sources of products and
destinations. All shipments are tested or receive refinery certifications to
ensure compliance with the Partnership's specifications. Petroleum shippers are
generally invoiced by the Partnership immediately upon the product entering one
of the Petroleum Pipelines.
The following table shows the number of tanks owned by the Partnership
at each refined petroleum product terminal location at December 31, 2003, the
storage capacity in barrels and truck capacity of each terminal location.
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 2003, approximately 56.7%, 91.7% and 85.5% of the
deliveries of the East, the West and the North Pipelines, respectively, were
made through their terminals, and the remainder of the respective deliveries of
such lines were made to other pipelines and customer owned storage tanks.
Storage of product at terminals pending delivery is considered by the
Partnership to be an integral part of the petroleum product delivery service of
the pipelines. Shippers generally store refined petroleum products for less than
one week. Ancillary services, including injection of shipper-furnished and
generic additives, are available at each terminal.
The Partnership owns 1,500 tons of ammonia storage at the terminal near
Hermann, Missouri. One half of the capacity is leased to Koch Nitrogen to
support their leased terminal obligations.
Demand for and Sources of Refined Petroleum Products
The Partnership's pipeline business depends in large part on the level
of demand for refined petroleum products in the markets served by the pipelines
and the ability and willingness of refiners and marketers having access to the
pipelines to supply such demand by deliveries through the pipelines.
Much of the refined petroleum products delivered through the East
Pipeline and the western three terminals on the North Pipeline is ultimately
used as fuel for railroads or in agricultural operations, including fuel for
farm equipment, irrigation systems, trucks used for transporting crops and crop
drying facilities. Demand for refined petroleum products for agricultural use,
and the relative mix of products required, is affected by weather conditions in
the markets served by the East and North Pipeline. The agricultural sector is
also affected by government agricultural policies and crop prices. Although
periods of drought suppress agricultural demand for some refined petroleum
products, particularly those used for fueling farm equipment, the demand for
fuel for irrigation systems often increases during such times.
While there is some agricultural demand for the refined petroleum
products delivered through the West Pipeline, as well as military jet fuel
volumes, most of the demand is centered in the Denver and Colorado Springs area.
Because demand on the West Pipeline and the Minneapolis area terminal of the
North Pipeline is significantly weighted toward urban and suburban areas, the
product mix on the West Pipeline and that terminal includes a substantially
higher percentage of gasoline than the product mix on the East Pipeline.
The Partnership's refined petroleum products pipelines are also
dependent upon adequate levels of production of refined petroleum products by
refineries connected to the Pipelines, directly or through connecting pipelines.
The refineries are, in turn, dependent upon adequate supplies of suitable grades
of crude oil. The refineries connected directly to the East Pipeline obtain
crude oil from producing fields located primarily in Kansas, Oklahoma and Texas,
and, to a much lesser extent, from other domestic or foreign sources. In
addition, refineries in Kansas, Oklahoma and Texas are also connected to the
East Pipeline through other pipelines. These refineries obtain their supplies of
crude oil from a variety of sources. The refineries connected directly to the
West Pipeline are located in Casper and Cheyenne, Wyoming and Denver, Colorado.
Refineries in Billings and Laurel, Montana are connected to the West Pipeline
through other pipelines. These refineries obtain their supplies of crude oil
primarily from Rocky Mountain sources. The North Pipeline, is heavily dependent
on the Tesoro Mandan refinery which primarily operates on North Dakota crude oil
although it has the ability to access other crude oils. If operations at any one
refinery were discontinued, the Partnership believes (assuming unchanged demand
for refined petroleum products in markets served by the refined petroleum
products pipelines) that the effects thereof would be short-term in nature, and
the Partnership's business would not be materially adversely affected over the
long term because such discontinued production could be replaced by other
refineries or by other sources.
The majority of the refined petroleum product transported through the
East Pipeline in 2003 was produced at three refineries located at McPherson and
El Dorado, Kansas and Ponca City, Oklahoma, and operated by the National
Cooperative Refining Association ("NCRA"), Frontier Refining and
Conoco/Phillips, Inc. respectively. The NCRA and Frontier Refining refineries
are connected directly to the East Pipeline. The McPherson, Kansas refinery
operated by NCRA accounted for approximately 30.1% of the total amount of
product shipped over the East Pipeline in 2003. The East Pipeline also has
direct access by third party pipelines to four other refineries in Kansas,
Oklahoma and Texas and to Gulf Coast supplies of products through connecting
pipelines that receive products from pipelines originating on the Gulf Coast.
Five connecting pipelines can deliver propane from gas processing plants in
Texas, New Mexico, Oklahoma and Kansas to the East Pipeline for shipment.
The majority of the refined petroleum products transported through the
West Pipeline is produced at the Frontier Refinery located at Cheyenne, Wyoming,
the Valero Energy Corporation and Suncor Refineries located at Denver, Colorado,
and Sinclair's Little America Refinery located at Casper, Wyoming, all of which
are connected directly to the West Pipeline. The West Pipeline also has access
to three Billings, Montana, area refineries through a connecting pipeline.
Demand for and Sources of Anhydrous Ammonia
The Partnership's Ammonia Pipeline business depends on the level of
demand for direct application of anhydrous ammonia as a fertilizer for crop
production ("Direct Application" or "DA"), the weather (DA is not effective if
the ground is too wet or too dry) and the price of natural gas (the primary
component of anhydrous ammonia).
The Ammonia Pipeline is the largest of three anhydrous ammonia
pipelines in the United States and the only one that has the capability of
receiving foreign production directly into the system and transporting anhydrous
ammonia into the nation's corn belt. This ability to receive either domestic or
foreign anhydrous ammonia is a competitive advantage over the next largest
ammonia system which originates in Oklahoma and extends into Iowa.
Corn producers have several fertilizer alternatives such as liquid, dry
or Direct Application. Liquid and dry fertilizers are both upgrades of anhydrous
ammonia and therefore are generally more costly but are less sensitive to
weather conditions during application. DA is the cheapest method of fertilizer
application but cannot be applied if the ground is too wet or extremely dry.
Principal Customers
The Partnership had a total of approximately 55 shippers in 2003. The
principal shippers include four integrated oil companies, four refining
companies, three large farm cooperatives and one railroad. Transportation
revenues attributable to the top 10 shippers were $86.6 million, $61.5 million
and $51.5 million, which accounted for 72%, 74% and 69% of total Partnership
revenues shipped for each of the years 2003, 2002 and 2001, respectively.
Competition and Business Considerations
The East and North Pipelines' major competitor is an independent,
regulated common carrier pipeline system owned by Magellan Midstream Partners,
L.P. ("Magellan"), formerly the Williams Companies, Inc., that operates
approximately 100 miles east of and parallel to the East Pipeline and in close
proximity to the North Pipeline. The Magellan system is a substantially more
extensive system than the East and North Pipelines. Competition with Magellan is
based primarily on transportation charges, quality of customer service and
proximity to end users, although refined product pricing at either the origin or
terminal point on a pipeline may outweigh transportation costs. Twenty-one of
the East Pipeline's and all four of the North Pipeline's delivery terminals are
located within 2 to 145 miles of, and in direct competition with Magellan's
terminals.
The West Pipeline competes with the truck-loading racks of the Cheyenne
and Denver refineries and the Denver terminals of the Chase Terminal Company and
Conoco/Phillips. Valero L.P. terminals in Denver and Colorado Springs, connected
to a Valero L.P. pipeline from their Texas Panhandle Refinery, are major
competitors to the West Pipeline's Denver and Fountain Terminals, respectively.
Because pipelines are generally the lowest cost method for intermediate
and long-haul movement of refined petroleum products, the Partnership's more
significant competitors are common carrier and proprietary pipelines owned and
operated by major integrated and large independent oil companies and other
companies in the areas where the Partnership delivers products. Competition
between common carrier pipelines is based primarily on transportation charges,
quality of customer service and proximity to end users. The Partnership believes
high capital costs, tariff regulation, environmental considerations and problems
in acquiring rights-of-way make it unlikely that other competing pipeline
systems comparable in size and scope to its pipelines will be built in the near
future, provided its pipelines have available capacity to satisfy demand and its
tariffs remain at reasonable levels.
The costs associated with transporting products from a loading terminal
to end users limit the geographic size of the market that can be served
economically by any terminal. Transportation to end users from the loading
terminals of the Partnership is conducted principally by trucking operations of
unrelated third parties. Trucks may competitively deliver products in some of
the areas served by the Partnership's pipelines. However, trucking costs render
that mode of transportation not competitive for longer hauls or larger volumes.
The Partnership does not believe that trucks are, or will be, effective
competition to its long-haul volumes over the long term.
Competitors of the Ammonia Pipeline include another anhydrous ammonia
pipeline which originates in Oklahoma and terminates in Iowa. The competitor
pipeline has the same DA demand and weather issues as the Ammonia Pipeline but
is restricted to domestically produced anhydrous ammonia. Barges and railroads
represent other forms of direct competition to the pipeline under certain market
conditions.
LIQUIDS TERMINALING BUSINESS
Introduction
The Partnership's terminaling business is conducted through the Support
Terminal Services operation ("ST Services" or "ST") and Statia Terminals
International N.V. ("Statia"). ST Services is one of the largest independent
petroleum products and specialty liquids terminaling companies in the United
States. Statia, acquired on February 28, 2002 for a purchase price of $178
million (net of cash acquired), plus the assumption of $107 million of debt,
owns and operates the Partnership's two largest terminals and provides related
value-added services, including crude oil and petroleum product blending and
processing, berthing of vessels at their marine facilities, and emergency and
spill response services. In addition to its terminaling services, Statia sells
bunkers, which is the fuel marine vessels consume, and bulk petroleum products
to various commercial interests.
For the year ended December 31, 2003, the Partnership's terminaling
business accounted for approximately 41% of the Partnership's revenues. As of
December 31, 2003, ST operated 37 facilities in 20 states, with a total storage
capacity of approximately 33.9 million barrels. ST also owns and operates six
terminals located in the United Kingdom, having a total capacity of
approximately 5.5 million barrels. In September 2002, ST acquired eight
terminals in Australia and New Zealand with a total capacity of approximately
1.2 million barrels for approximately $47 million in cash. ST Services and its
predecessors have a long history in the terminaling business and handle a wide
variety of liquids from petroleum products to specialty chemicals to edible
liquids. At the end of 2003, Statia's tank capacity was 18.8 million barrels,
including an 11.3 million barrel storage and transshipment facility located on
the Netherlands Antilles island of St. Eustatius, and a 7.5 million barrel
storage and transshipment facility located at Point Tupper, Nova Scotia, Canada.
The Partnership's terminal facilities provide storage and handling
services on a fee basis for petroleum products, specialty chemicals and other
liquids. The Partnership's six largest terminal facilities are located on the
Island of St. Eustatius, Netherlands Antilles; in Point Tupper, Nova Scotia,
Canada; in Piney Point, Maryland; in Linden, New Jersey (50% owned joint
venture); in Crockett, California; and in Martinez, California.
Description of Largest Terminal Facilities
St. Eustatius, Netherlands Antilles
Statia owns and operates an 11.3 million barrel petroleum terminaling
facility located on the Netherlands Antilles island of St. Eustatius, which is
located at a point of minimal deviation from major shipping routes. This
facility is capable of handling a wide range of petroleum products, including
crude oil and refined products, and can accommodate the world's largest tankers
for loading and discharging crude oil. A two-berth jetty, a two-berth monopile
with platform and buoy systems, a floating hose station, and an offshore single
point mooring buoy with loading and unloading capabilities serve the terminal's
customers' vessels. The St. Eustatius facility has a total of 51 tanks. The fuel
oil and petroleum product facilities have in-tank and in-line blending
capabilities, while the crude tanks have tank-to-tank blending capability as
well as in-tank mixers. In addition to the storage and blending services at St.
Eustatius, the facility has the flexibility to utilize certain storage capacity
for both feedstock and refined products to support its atmospheric distillation
unit, which is capable of processing up to 15,000 BPD of feedstock, ranging from
condensates to heavy crude oil. Statia owns and operates all of the berthing
facilities at its St. Eustatius terminal and charges vessels a fee for their
use. Vessel owners or charterers may incur separate fees for associated services
such as pilotage, tug assistance, line handling, launch service, emergency
response services, and other ship services.
Point Tupper, Nova Scotia, Canada
Statia owns and operates a 7.5 million barrel terminaling facility
located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova
Scotia, Canada, which is located approximately 700 miles from New York City, 850
miles from Philadelphia and 2,500 miles from Mongstad, Norway. This facility is
the deepest independent, ice-free marine terminal on the North American Atlantic
coast, with access to the East Coast and Canada as well as the Midwestern United
States via the St. Lawrence Seaway and the Great Lakes system. With one of the
premier jetty facilities in North America, the Point Tupper facility can
accommodate substantially all of the world's largest, fully-laden very large
crude carriers and ultra large crude carriers for loading and discharging crude
oil, petroleum products, and petrochemicals. The Point Tupper facility has a
total of 37 tanks. Its butane sphere is one of the largest of its kind in North
America. The facility's tanks were renovated in 1994 to comply with construction
standards that meet or exceed American Petroleum Institute, NFPA, and other
material industry standards. Crude oil and petroleum product movements at the
terminal are fully automated. Separate Statia fees apply for the use of the
jetty facility as well as associated services, including pilotage, tug
assistance, line handling, launch service, spill response services, and other
ship services. Statia also charters tugs, mooring launches, and other vessels to
assist with the movement of vessels through the Strait of Canso and the safe
berthing of vessels at Point Tupper and to provide other services to vessels.
Piney Point, Maryland
The largest domestic terminal currently owned by ST is located on
approximately 400 acres on the Potomac River. The facility was acquired as part
of the purchase of the liquids terminaling assets of Steuart Petroleum Company
and certain of its affiliates (collectively "Steuart") in December 1995. The
Piney Point terminal has approximately 5.4 million barrels of storage capacity
in 28 tanks and is the closest deep-water facility to Washington, D.C. This
terminal competes with other large petroleum terminals in the East Coast
water-borne market extending from New York Harbor to Norfolk, Virginia. The
terminal currently stores petroleum products consisting primarily of fuel oils
and asphalt. The terminal has a dock with a 36-foot draft for tankers and four
berths for barges. It also has truck-loading facilities, product-blending
capabilities and is connected to a pipeline which supplies residual fuel oil to
two power generating stations.
Linden, New Jersey
In October 1998, ST entered into a joint venture relationship with
Northville Industries Corp. ("Northville") to acquire a 50% ownership interest
in and the management of the terminal facility at Linden, New Jersey that was
previously owned by Northville. The 44-acre facility provides ST with deep-water
terminaling capabilities at New York Harbor and primarily stores petroleum
products, including gasoline, jet fuel and fuel oils. The facility has a total
capacity of approximately 3.9 million barrels in 22 tanks, can receive products
via ship, barge and pipeline and delivers product by ship, barge, pipeline and
truck. The terminal owns two docks and leases a third with draft limits of 35,
24 and 24 feet, respectively.
Crockett, California
The Crockett Terminal was acquired in January 2001 as a part of the
Shore acquisition. The terminal has approximately 3 million barrels of tankage
and is located in the San Francisco Bay area. The facility provides deep-water
access for handling petroleum products and gasoline additives such as ethanol.
The terminal offers pipeline connections to various refineries and pipelines. It
receives and delivers product by vessel, barge, pipeline and truck-loading
facilities. The terminal also has railroad tank car unloading capability.
Martinez, California
The Martinez Terminal, also acquired in January 2001 as a part of the
Shore acquisition, is located in the refinery area of San Francisco Bay. It has
approximately 3.1 million barrels of tankage and handles refined petroleum
products as well as crude oil. The terminal is connected to a pipeline and to
area refineries by pipelines and can also receive and deliver products by vessel
or barge. It also has a truck rack for product delivery.
The Partnership's facilities have been designed with engineered
structural measures to minimize the possibility of the occurrence and the level
of damage in the event of a spill or fire. All loading areas, tanks, pipes and
pumping areas are "contained" to collect any spillage and insure that only
properly treated water is discharged from the site.
Other Terminal Sites
In addition to the four major domestic facilities described above, ST
Services has 31 other terminal facilities located throughout the United States,
six facilities in the United Kingdom, four facilities in Australia and four in
New Zealand. These other facilities primarily store petroleum products for a
variety of customers, with the exception of the facilities in Texas City, Texas,
which handles specialty chemicals; Columbus, Georgia, which handles aviation
gasoline and specialty chemicals; Winona, Minnesota, which handles nitrogen
fertilizer solutions; Savannah, Georgia, which handles chemicals and caustic
solutions, as well as petroleum products; Vancouver, Washington, which handles
chemicals and fertilizer; Eastham, United Kingdom which handles chemicals and
animal fats; and Runcorn, United Kingdom, which handles molten sulphur, and the
Australian and New Zealand terminals which handle chemicals and animal fats and
oil. Overall, these facilities provide ST Services with locations which are
diverse geographically, in products handled and in customers served.
The following table outlines the Partnership's terminal locations,
capacities, tanks and primary products handled:
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, Ethanol
Martinez, CA 3,106,000 19 Petroleum
Jacksonville, FL 2,069,000 30 Petroleum
Texas City, TX 2,161,000 136 Chemicals, Petrochemicals,
Petroleum
Other U. S. Terminals:
Montgomery, AL(b) 162,000 7 Petroleum, Jet Fuel
Moundville, AL 310,000 6 Jet Fuel
Tucson, AZ(a) 174,000 7 Petroleum
Los Angeles, CA 597,000 20 Petroleum
Richmond, CA 617,000 25 Petroleum, Ethanol
Stockton, CA 706,000 32 Petroleum, Ethanol, Fertilizer
Bremen, GA 182,000 9 Petroleum, Jet Fuel
Brunswick, GA 302,000 3 Fertilizer, Pulp Liquor
Columbus, GA 175,000 24 Petroleum, Chemicals
Macon, GA(b) 307,000 10 Petroleum, Jet Fuel
Savannah, GA 903,000 28 Petroleum, Chemicals
Blue Island, IL 752,000 19 Petroleum, Ethanol
Chillicothe, IL(a) 270,000 6 Petroleum
Peru, IL 221,000 8 Petroleum, Fertilizer
Indianapolis, IN 410,000 18 Petroleum
Westwego, LA 849,000 53 Molasses, Fertilizer, Caustic,
Chemicals
Andrews AFB Pipeline, MD(b) 72,000 3 Jet Fuel
Baltimore, MD 832,000 50 Chemicals, Asphalt, Jet Fuel
Salisbury, MD 177,000 14 Petroleum
Winona, MN 267,000 8 Fertilizer
Reno, NV 107,000 7 Petroleum
Paulsboro, NJ 1,580,000 18 Petroleum
Alamogordo, NM(b) 120,000 5 Jet Fuel
Drumright, OK 315,000 4 Petroleum
Portland, OR 1,119,000 31 Petroleum
Philadelphia, PA 894,000 11 Petroleum
Dumfries, VA 554,000 16 Petroleum, Asphalt
Virginia Beach, VA(b) 40,000 2 Jet Fuel
Tacoma, WA 377,000 15 Petroleum
Vancouver, WA 543,000 55 Chemicals, Fertilizer, Petroleum
Milwaukee, WI 308,000 7 Petroleum
Foreign Terminals:
St. Eustatius, Netherlands
Antilles. 11,350,000 60 Petroleum, crude oil
Point Tupper, Canada 7,514,000 40 Petroleum, crude oil
Sydney, Australia 330,000 65 Chemicals, fats and oils
Melbourne, Australia 468,000 118 Specialty chemicals
Geelong, Australia 145,000 14 Specialty chemicals, petroleum
Adelaide, Australia 90,000 24 Chemicals, tallow, petroleum
Auckland, New Zealand (a) 74,000 44 Fats, oils and chemicals
New Plymouth, New Zealand 35,000 10 Fats, oils and chemicals
Mt. Maunganui, New Zealand 83,000 24 Fats, oils and chemicals
Wellington, New Zealand 50,000 13 Fats, oils and chemicals
Grays, England 1,945,000 53 Petroleum
Eastham, England 2,185,000 162 Chemicals, Petroleum, Animal Fats
Runcorn, England 146,000 4 Molten sulphur
Glasgow, Scotland 344,000 16 Petroleum
Leith, Scotland 459,000 34 Petroleum, Chemicals
Belfast, Northern Ireland 407,000 41 Petroleum
--------------- --------------
59,538,000 1,502
=============== ==============
(a) The terminal is 50% owned by ST.
(b) Facility also includes pipelines to U.S. government military base
locations.
Customers
Statia provides terminaling services for crude oil and refined
petroleum products to many of the world's largest producers of crude oil,
integrated oil companies, oil traders, and refiners. Statia's crude oil
transshipment customers include an oil producer that leases and utilizes 5.0
million barrels of storage at St. Eustatius, and a major international oil
company which leases and utilizes 3.6 million barrels of storage at Point
Tupper, both of which have long-term contracts with Statia. In addition, two
different international oil companies each lease and utilize 1.0 million barrels
of clean products storage at St. Eustatius and Point Tupper, respectively. Also
in Canada, a consortium consisting of major oil companies sends natural gas
liquids via pipeline to certain processing facilities on land leased from
Statia. After processing, certain products are stored at the Point Tupper
facility under a long-term contract. In addition, Statia's blending capabilities
have attracted customers who have leased capacity primarily for blending
purposes and who have contributed to Statia's bunker fuel and bulk product
sales.
The storage and transport of jet fuel for the U.S. Department of
Defense is an important part of ST's business. Eleven of ST's terminal sites are
involved in the terminaling or transport (via pipeline) of jet fuel for the
Department of Defense and four of the eleven locations have been utilized solely
by the U.S. Government. Of the eleven locations, six include pipelines which
deliver jet fuel directly to nearby military bases.
Competition and Business Considerations
In addition to the terminals owned by independent terminal operators,
such as the Partnership, many major energy and chemical companies own extensive
terminal storage facilities. Although such terminals often have the same
capabilities as terminals owned by independent operators, they generally do not
provide terminaling services to third parties. In many instances, major energy
and chemical companies that own storage and terminaling facilities are also
significant customers of independent terminal operators, such as the
Partnership. Such companies typically have strong demand for terminals owned by
independent operators when independent terminals have more cost effective
locations near key transportation links, such as deep-water ports. Major energy
and chemical companies also need independent terminal storage when their owned
storage facilities are inadequate, either because of size constraints, the
nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the
location and versatility of terminals, service and price. A favorably located
terminal will have access to various cost effective transportation modes both to
and from the terminal. Transportation modes typically include waterways,
railroads, roadways and pipelines. Terminals located near deep-water port
facilities are referred to as "deep-water terminals" and terminals without such
facilities are referred to as "inland terminals"; although some inland
facilities located on or near navigable rivers are served by barges.
Terminal versatility is a function of the operator's ability to offer
handling for diverse products with complex handling requirements. The service
function typically provided by the terminal includes, among other things, the
safe storage of the product at specified temperature, moisture and other
conditions, as well as receipt at and delivery from the terminal, all of which
must be in compliance with applicable environmental regulations. A terminal
operator's ability to obtain attractive pricing is often dependent on the
quality, versatility and reputation of the facilities owned by the operator.
Although many products require modest terminal modification, operators with
versatile storage capabilities typically require less modification prior to
usage, ultimately making the storage cost to the customer more attractive.
A few companies offering liquid terminaling facilities have
significantly more capacity than the Partnership. However, much of the
Partnership's tankage can be described as "niche" facilities that are equipped
to properly handle "specialty" liquids or provide facilities or services where
management believes the Partnership enjoys an advantage over competitors. As a
result, many of the Partnership's terminals compete against other large
petroleum products terminals, rather than specialty liquids facilities. Such
specialty or "niche" tankage is less abundant in the U.S. and "specialty"
liquids typically command higher terminal fees than lower-price bulk terminaling
for petroleum products.
The main competition to crude oil storage at Statia's facilities is
from "lightering" which is the process by which liquid cargo is transferred to
smaller vessels, usually while at sea. The price differential between lightering
and terminaling is primarily driven by the charter rates for vessels of various
sizes. Lightering generally takes significantly longer than discharging at a
terminal. Depending on charter rates, the longer charter period associated with
lightering is generally offset by various costs associated with terminaling,
including storage costs, dock charges, and spill response fees. However,
terminaling is generally safer and reduces the risk of environmental damage
associated with lightering, provides more flexibility in the scheduling of
deliveries, and allows customers of Statia to deliver their products to multiple
locations. Lightering in U.S. territorial waters creates a risk of liability for
owners and shippers of oil under the U.S. Oil Pollution Act of 1990 and other
state and federal legislation. In Canada, similar liability exists under the
Canadian Shipping Act. Terminaling also provides customers with the ability to
access value-added terminal services.
In the bunkering business, Statia competes with ports offering bunker
fuels to which, or from which, each vessel travels or are along the route of
travel of the vessel. Statia also competes with bunker delivery locations around
the world. In the Western Hemisphere, alternative bunker locations include ports
on the U.S. East coast and Gulf coast and in Panama, Puerto Rico, the Bahamas,
Aruba, Curacao, and Halifax. In addition, Statia competes with Rotterdam and
various North Sea locations.
CAPITAL EXPENDITURES
Capital expenditures by the Pipelines, including routine maintenance
and expansion expenditures, but excluding acquisitions, were $9.6 million, $9.5
million and $4.3 million for 2003, 2002 and 2001, respectively. During these
periods, adequate capacity existed on these pipelines to accommodate volume
growth, and the expenditures required for environmental and safety improvements
were not material in amount. Capital expenditures, including routine maintenance
and expansion expenditures, but excluding acquisitions, for the Partnership's
terminaling operations were $34.6 million, $21.0 million and $12.9 million for
2003, 2002 and 2001, respectively.
Capital expenditures of the Partnership during 2004, including routine
maintenance and expansion expenditures, but excluding acquisitions, are expected
to be approximately $28 million to $32 million. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources." Additional expansion-related capital expenditures will
depend on future opportunities to expand the Partnership's operations. Such
future expenditures, however, will depend on many factors beyond the
Partnership's control, including, without limitation, demand for refined
petroleum products and terminaling services in the Partnership's market areas,
local, state and federal governmental regulations, fuel conservation efforts and
the availability of financing on acceptable terms. No assurance can be given
that required capital expenditures will not exceed anticipated amounts during
the year or thereafter or that the Partnership will have the ability to finance
such expenditures through borrowings or choose to do so.
REGULATION
Interstate Regulation
The interstate common carrier petroleum product pipeline operations of
the Partnership are subject to rate regulation by FERC under the Interstate
Commerce Act. The Interstate Commerce Act provides, among other things, that to
be lawful the rates of common carrier petroleum pipelines must be "just and
reasonable" and not unduly discriminatory. New and changed rates must be filed
with the FERC, which may investigate their lawfulness on protest or its own
motion. The FERC may suspend the effectiveness of such rates for up to seven
months. If the suspension expires before completion of the investigation, the
rates go into effect, but the pipeline can be required to refund to shippers,
with interest, any difference between the level the FERC determines to be lawful
and the filed rates under investigation. Rates that have become final and
effective may be challenged by a complaint to FERC filed by a shipper or on the
FERC's own initiative. Reparations may be recovered by the party filing the
complaint for the two-year period prior to the complaint, if FERC finds the rate
to be unlawful.
The FERC allows for a rate of return for petroleum products pipelines
determined by adding (i) the product of a rate of return equal to the nominal
cost of debt multiplied by the portion of the rate base that is deemed to be
financed with debt and (ii) the product of a rate of return equal to the real
(i.e., inflation-free) cost of equity multiplied by the portion of the rate base
that is deemed to be financed with equity. The appropriate rate of return for a
petroleum pipeline is determined on a case-by-case basis, taking into account
cost of capital, competitive factors and business and financial risks associated
with pipeline operations.
Under Title XVIII of the Energy Policy Act of 1992 (the "EP Act"),
rates that were in effect on October 24, 1991 that were not subject to a
protest, investigation or complaint are deemed to be just and reasonable. Such
rates, commonly referred to as grandfathered rates, are subject to challenge
only for limited reasons. Any relief granted pursuant to such challenges may be
prospective only. Because the Partnership's rates that were in effect on October
24, 1991, were not subject to investigation and protest at that time, those
rates could be deemed to be just and reasonable pursuant to the EP Act. The
Partnership's current rates became final and effective in July 2000, and the
Partnership believes that its currently effective tariffs are just and
reasonable and would withstand challenge under the FERC's cost-based rate
standards. Because of the complexity of rate making, however, the lawfulness of
any rate is never assured.
On October 22, 1993, the FERC issued Order No. 561 which adopted a
simplified rate making methodology for future oil pipeline rate changes in the
form of indexation. Indexation, which is also known as price cap regulation,
establishes ceiling prices on oil pipeline rates based on application of a
broad-based measure of inflation in the general economy to existing rates. Rate
increases up to the ceiling level are to be discretionary for the pipeline, and,
for such rate increases, there will be no need to file cost-of-service or
supporting data. Moreover, so long as the ceiling is not exceeded, a pipeline
may make a limitless number of rate change filings. This indexing mechanism
calculates a ceiling rate. Rate decreases are required if the indexing mechanism
operates to reduce the ceiling rate below a pipeline's existing rates. The
pipeline may increase its rates to this calculated ceiling rate without filing a
formal cost based justification and with limited risk of shipper protests.
The indexation method is to serve as the principal basis for the
establishment of oil pipeline rate changes in the future. However, the FERC
determined that a pipeline may utilize any one of the following alternative
methodologies to indexing: (i) a cost-of-service methodology may be utilized by
a pipeline to justify a change in a rate if a pipeline can demonstrate that its
increased costs are prudently incurred and that there is a substantial
divergence between such increased costs and the rate that would be produced by
application of the index; and (ii) a pipeline may base its rates upon a
"light-handed" market-based form of regulation if it is able to demonstrate a
lack of significant market power in the relevant markets.
On September 15, 1997, the Partnership filed an Application for Market
Power Determination with the FERC seeking market based rates for approximately
half of its markets. In May 1998, the FERC granted the Partnership's application
and approximately half of the markets served by the East and West Pipelines
subsequently became subject to market force regulation.
In the FERC's Lakehead decision issued June 15, 1995, the FERC
partially disallowed Lakehead's inclusion of income taxes in its cost of
service. Specifically, the FERC held that Lakehead was entitled to receive an
income tax allowance with respect to income attributable to its corporate
partners, but was not entitled to receive such an allowance for income
attributable to partnership interests held by individuals. Lakehead's motion for
rehearing was denied by the FERC and Lakehead appealed the decision to the U.S.
Court of Appeals. Subsequently, the case was settled by Lakehead and the appeal
was withdrawn. In another FERC proceeding involving a different oil pipeline
limited partnership, various shippers challenged such pipeline's inclusion of an
income tax allowance in its cost of service. The FERC decided this case on the
same basis as its holding in the Lakehead case. If the FERC were to partially or
completely disallow the income tax allowance in the cost of service of the East
and West pipelines on the basis set forth in the Lakehead order, KPL believes
that the Partnership's ability to pay distributions to the holders of the Units
would not be impaired; however, in view of the uncertainties involved in this
issue, there can be no assurance in this regard.
The Ammonia Pipeline rates are regulated by the Surface Transportation
Board (the "STB"). The STB was established in 1996 when the Interstate Commerce
Commission was terminated by the ICC Termination Act of 1995. The STB is headed
by Board Members appointed by the President and confirmed by the Senate and is
authorized to have three members. The STB jurisdiction generally includes
railroad rate and service issues, rail restructuring transactions and labor
matters related thereto; certain trucking company, moving van, and
non-contiguous ocean shipping company rate matters; and certain pipeline matters
not regulated by the FERC. In the performance of its functions, the STB is
charged with promoting, where appropriate, substantive and procedural regulatory
reform in the economic regulation of surface transportation, and with providing
an efficient and effective forum for the resolution of disputes. The STB seeks
to facilitate commerce by providing an effective forum for efficient dispute
resolution and facilitation of appropriate market-based business transactions.
The Partnership issued a STB tariff that became effective April 1,
2003. The tariff filing combined the STB interstate tariff and the Louisiana
intrastate tariff into one document and standardized the tariff regulation
between the two regulatory bodies. The tariff filing modified the capacity
allocation procedures and established a minimum tariff rate of $5.00 per ton.
The tariff filing implemented a 7% tariff increase across all tariff rates.
Another modification was the removal of the "Industrial User" classification
which effectively increases the tariff rates actually paid for transportation to
certain shippers by more than 7%. Dyno Nobel, an industrial user in Missouri,
has filed a protest against the tariff filing. Dyno's protest centered on
basically two issues. First, it questioned the Partnership's ability to file a
tariff without first obtaining approval from the STB. Second, it questioned the
amount of effective increase on its particular situation on a cost justification
basis. CF Industries also filed a protest questioning the Partnership's ability
to file a tariff without first obtaining approval from the STB. The Partnership
believes it has regulatory precedent in making the tariff filing and can cost
justify the tariff rate change. Initial data requests have been submitted and
answered, and summary judgment has been requested on the issue of the
Partnership's ability to file a tariff change. The cost justification portion of
the Dyno protest will go forward after the resolution of the tariff filing
issue.
Intrastate Regulation
The intrastate operations of the East Pipeline in Kansas are subject to
regulation by the Kansas Corporation Commission, the intrastate operations of
the West Pipeline in Colorado and Wyoming are subject to regulation by the
Colorado Public Utility Commission and the Wyoming Public Service Commission,
respectively, and the intrastate operations of the North Pipeline are subject to
regulation by the North Dakota Public Utility Commission. Like the FERC, the
state regulatory authorities require that shippers be notified of proposed
intrastate tariff increases and have an opportunity to protest such increases.
The Partnership also files with such state authorities copies of interstate
tariff changes filed with the FERC. In addition to challenges to new or proposed
rates, challenges to intrastate rates that have already become effective are
permitted by complaint of an interested person or by independent action of the
appropriate regulatory authority.
The intrastate operations of the Ammonia Pipeline in Louisiana are
subject to regulation by the Louisiana Public Service Commission. Shippers under
the Louisiana intrastate tariff have similar rights as those mentioned in the
paragraph above.
ENVIRONMENTAL MATTERS
General
The operations of the Partnership are subject to federal, state and
local laws and regulations relating to the protection of the environment in the
United States and to the environmental laws and regulations of the host
countries in regard to the terminals acquired overseas. Although the Partnership
believes that its operations are in general compliance with applicable
environmental regulations, risks of substantial costs and liabilities are
inherent in pipeline and terminal operations, and there can be no assurance that
significant costs and liabilities will not be incurred by the Partnership.
Moreover, it is possible that other developments, such as increasingly strict
environmental laws, regulations and enforcement policies thereunder, and claims
for damages to property or persons resulting from the operations of the
Partnership, past and present, could result in substantial costs and liabilities
to the Partnership.
See "Item 3 - Legal Proceedings" for information concerning two
lawsuits against certain subsidiaries of the Partnership involving claims for
environmental damages.
Water
The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions
of the Federal Water Pollution Control Act of 1972 and other statutes as they
pertain to prevention and response to oil spills. The OPA subjects owners of
facilities to strict, joint and potentially unlimited liability for removal
costs and certain other consequences of an oil spill, where such spill is into
navigable waters, along shorelines or in the exclusive economic zone. In the
event of an oil spill into such waters, substantial liabilities could be imposed
upon the Partnership. Regulations concerning the environment are continually
being developed and revised in ways that may impose additional regulatory
burdens on the Partnership.
Contamination resulting from spills or releases of refined petroleum
products is not unusual within the petroleum pipeline and liquids terminaling
industries. The East Pipeline and ST Services have experienced limited
groundwater contamination at various terminal and pipeline sites resulting from
various causes including activities of previous owners. Remediation projects are
underway or under construction using various remediation techniques. The costs
to remediate contamination at several ST terminal locations are being borne by
the former owners under indemnification agreements. Although no assurances can
be made, the Partnership believes that the aggregate cost of these remediation
efforts will not be material.
The EPA has promulgated regulations that may require the Partnership to
apply for permits to discharge storm water runoff. Storm water discharge permits
also may be required in certain states in which the Partnership operates. Where
such requirements are applicable, the Partnership has applied for such permits
and, after the permits are received, will be required to sample storm water
effluent before releasing it. The Partnership believes that effluent limitations
could be met, if necessary, with minor modifications to existing facilities and
operations. Although no assurance in this regard can be given, the Partnership
believes that the changes will not have a material effect on the Partnership's
financial condition or results of operations.
Aboveground Storage Tank Acts
A number of the states in which the Partnership operates in the United
States have passed statutes regulating aboveground tanks containing liquid
substances. Generally, these statutes require that such tanks include secondary
containment systems or that the operators take certain alternative precautions
to ensure that no contamination results from any leaks or spills from the tanks.
Although there is not total federal regulation of all above ground tanks, the
DOT has adopted an industry standard that addresses tank inspection, repair,
alteration and reconstruction. This action requires pipeline companies to comply
with the standard for tank inspection and repair for all tanks regulated by the
DOT. The Partnership is in substantial compliance with all above ground storage
tank laws in the states with such laws. Although no assurance can be given, the
Partnership believes that the future implementation of above ground storage tank
laws by either additional states or by the federal government will not have a
material adverse effect on the Partnership's financial condition or results of
operations.
Air Emissions
The operations of the Partnership are subject to the Federal Clean Air
Act and comparable state and local statutes. The Partnership believes that the
operations of its pipelines and terminals are in substantial compliance with
such statutes in all states in which they operate.
Amendments to the Federal Clean Air Act enacted in 1990 require or will
require most industrial operations in the United States to incur future capital
expenditures in order to meet the air emission control standards that have been
and are to be developed and implemented by the EPA and state environmental
agencies. Pursuant to these Clean Air Act Amendments, those Partnership
facilities that emit volatile organic compounds ("VOC") or nitrogen oxides are
subject to increasingly stringent regulations, including requirements that
certain sources install maximum or reasonably available control technology. In
addition, the 1999 Federal Clean Air Act Amendments include a new operating
permit for major sources ("Title V Permits"), which applies to some of the
Partnership's facilities. Additionally, new dockside loading facilities owned or
operated by the Partnership in the United States will be subject to the New
Source Performance Standards that were proposed in May 1994. These regulations
require control of VOC emissions from the loading and unloading of tank vessels.
Although the Partnership is in substantial compliance with applicable
air pollution laws, in anticipation of the implementation of stricter air
control regulations, the Partnership is taking actions to substantially reduce
its air emissions. The Partnership plans to install bottom loading and vapor
recovery equipment on the loading racks at selected terminal sites along the
East Pipeline that do not already have such emissions control equipment. These
modifications will substantially reduce the total air emissions from each of
these facilities. Having begun in 1993, this project is being phased in over a
period of years.
Solid Waste
The Partnership generates non-hazardous solid waste that is subject to
the requirements of the Federal Resource Conservation and Recovery Act ("RCRA")
and comparable state statutes in the United States. The EPA is considering the
adoption of stricter disposal standards for non-hazardous wastes. RCRA also
governs the disposal of hazardous wastes. At present, the Partnership is not
required to comply with a substantial portion of the RCRA requirements because
the Partnership's operations generate minimal quantities of hazardous wastes.
However, it is anticipated that additional wastes, which could include wastes
currently generated during pipeline operations, will in the future be designated
as "hazardous wastes". Hazardous wastes are subject to more rigorous and costly
disposal requirements than are non-hazardous wastes. Such changes in the
regulations may result in additional capital expenditures or operating expenses
by the Partnership.
At the terminal sites at which groundwater contamination is present,
there is also limited soil contamination as a result of the aforementioned
spills. The Partnership is under no present requirements to remove these
contaminated soils, but the Partnership may be required to do so in the future.
Soil contamination also may be present at other Partnership facilities at which
spills or releases have occurred. Under certain circumstances, the Partnership
may be required to clean up such contaminated soils. Although these costs should
not have a material adverse effect on the Partnership, no assurance can be given
in this regard.
Superfund
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA" or "Superfund") imposes liability, without regard to fault or the
legality of the original act, on certain classes of persons that contributed to
the release of a "hazardous substance" into the environment. These persons
include the owner or operator of the site and companies that disposed or
arranged for the disposal of the hazardous substances found at the site. CERCLA
also authorizes the EPA and, in some instances, third parties to act in response
to threats to the public health or the environment and to seek to recover from
the responsible classes of persons the costs they incur. In the course of its
ordinary operations, the Partnership may generate waste that may fall within
CERCLA's definition of a "hazardous substance". The Partnership may be
responsible under CERCLA for all or part of the costs required to clean up sites
at which such wastes have been disposed.
Environmental Impact Statement
The United States National Environmental Policy Act of 1969 (the
"NEPA") applies to certain extensions or additions to a pipeline system. Under
NEPA, if any project that would significantly affect the quality of the
environment requires a permit or approval from any United States federal agency,
a detailed environmental impact statement must be prepared. The effect of the
NEPA may be to delay or prevent construction of new facilities or to alter their
location, design or method of construction.
Indemnification
KPL has agreed to indemnify the Partnership against liabilities for
damage to the environment resulting from operations of the East Pipeline prior
to October 3, 1989. Such indemnification does not extend to any liabilities that
arise after such date to the extent such liabilities result from change in
environmental laws or regulations. Under such indemnity, KPL is presently liable
for the remediation of contamination at certain East Pipeline sites. In
addition, the Partnership was wholly or partially indemnified under certain
acquisition contracts for some environmental costs. Most of such contracts
contain time and amount limitations on the indemnities. To the extent that
environmental liabilities exceed the amount of such indemnity, the Partnership
has affirmatively assumed the excess environmental liabilities.
SAFETY REGULATION
The Partnership's pipelines are subject to regulation by the United
States Department of Transportation (the "DOT") under the Hazardous Liquid
Pipeline Safety Act of 1979 ("HLPSA") relating to the design, installation,
testing, construction, operation, replacement and management of their pipeline
facilities. The HLPSA covers anhydrous ammonia, petroleum and petroleum products
pipelines and requires any entity that owns or operates pipeline facilities to
comply with such safety regulations and to permit access to and copying of
records and to make certain reports and provide information as required by the
Secretary to Transportation. The Federal Pipeline Safety Act of 1992 amended the
HLPSA to include requirements of the future use of internal inspection devices.
The Partnership does not believe that it will be required to make any
substantial capital expenditures to comply with the requirements of HLPSA as so
amended.
On November 3, 2000, the DOT issued new regulations intended by the DOT
to assess the integrity of hazardous liquid pipeline segments that, in the event
of a leak or failure, could adversely affect highly populated areas, areas
unusually sensitive to environmental impact and commercially navigable
waterways. Under the regulations, an operator is required, among other things,
to conduct baseline integrity assessment tests (such as internal inspections)
within seven years, conduct future integrity tests at typically five-year
intervals and develop and follow a written risk-based integrity management
program covering the designated high consequence areas. The Partnership does not
believe that the increased costs of compliance with these regulations will
materially affect the Partnership's results of operations.
The Partnership is subject to the requirements of the United States
Federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes that regulate the protection of the health and safety of workers. In
addition, the OSHA hazard communication standard requires that certain
information be collected regarding hazardous materials used or produced in
operations and that this information be provided to employees, state and local
authorities and citizens. The Partnership believes that it is in general
compliance with OSHA requirements, including general industry standards, record
keeping requirements and monitoring of occupational exposure to benzene.
The OSHA hazard communication standard, the EPA community right-to-know
regulations under Title III of the Federal Superfund Amendment and
Reauthorization Act, and comparable state statutes require the Partnership to
organize information about the hazardous materials used in its operations.
Certain parts of this information must be reported to employees, state and local
governmental authorities, and local citizens upon request. In general, the
Partnership expects to increase its expenditures during the next decade to
comply with more stringent industry and regulatory safety standards such as
those described above. Such expenditures cannot be accurately estimated at this
time, although they are not expected to have a material adverse impact on the
Partnership.
EMPLOYEES
The Partnership has no employees. The business of the Partnership is
conducted by the general partner, KPL, and its affiliate, Kaneb LLC, which
employs all persons necessary for the operation of the Partnership's business.
At December 31, 2003, approximately 1,060 persons were employed. Approximately
152 of the persons at seven terminal locations in the United States and Canada
were subject to representation by labor unions and collective bargaining or
similar contracts at that date. KPL and Kaneb LLC consider relations with their
employees to be good.
AVAILABLE INFORMATION
The Partnership files annual, quarterly, and other reports and other
information with the Securities and Exchange Commission ("SEC") under the
Securities Exchange Act of 1934 (the "Exchange Act"). You may read and copy any
materials that the Partnership files with the SEC at the SEC's Public Reference
Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain additional
information about the Public Reference Room by calling the SEC at
1-800-SEC-0330. In addition, the SEC maintains an Internet site
(http://www.sec.gov) that contains reports, proxy information statements, and
other information regarding issuers that file electronically with the SEC.
The Partnership also makes available free of charge on or through the
Partnership's Internet site (http://www.kaneb.com) the Partnership's Annual
Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form
8-K, and other information statements and, if applicable, amendments to those
reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon
as reasonably practicable after the reports and other information is
electronically filed with, or furnished to, the SEC.
Item 2. Properties
The properties owned or utilized by the Partnership and its
subsidiaries are generally described in Item 1 of this Report. Additional
information concerning the obligations of the Partnership and its subsidiaries
for lease and rental commitments is presented under the caption "Commitments and
Contingencies" in Note 6 to the Partnership's consolidated financial statements.
Such descriptions and information are hereby incorporated by reference into this
Item 2.
The properties used in the operations of the Partnership's pipelines
are owned by the Partnership, through its subsidiary entities, except for KPL's
operational headquarters, located in Wichita, Kansas, which is held under a
lease that expires in 2009. Statia's facilities are owned through subsidiaries
and the majority of ST's facilities are owned, while the remainder, including
some of its terminal facilities located in port areas and its operational
headquarters, located in Dallas, Texas, are held pursuant to lease agreements
having various expiration dates, rental rates and other terms.
Item 3. Legal Proceedings
Grace Litigation. Certain subsidiaries of the Partnership were sued in
a Texas state court in 1997 by Grace Energy Corporation ("Grace"), the entity
from which the Partnership acquired ST Services in 1993. The lawsuit involves
environmental response and remediation costs allegedly resulting from jet fuel
leaks in the early 1970's from a pipeline. The pipeline, which connected a
former Grace terminal with Otis Air Force Base in Massachusetts (the "Otis
pipeline" or the "pipeline"), ceased operations in 1973 and was abandoned before
1978, when the connecting terminal was sold to an unrelated entity. Grace
alleged that subsidiaries of the Partnership acquired the abandoned pipeline, as
part of the acquisition of ST Services in 1993 and assumed responsibility for
environmental damages allegedly caused by the jet fuel leaks. Grace sought a
ruling from the Texas court that these subsidiaries are responsible for all
liabilities, including all present and future remediation expenses, associated
with these leaks and that Grace has no obligation to indemnify these
subsidiaries for these expenses. In the lawsuit, Grace also sought
indemnification for expenses of approximately $3.5 million that it incurred
since 1996 for response and remediation required by the State of Massachusetts
and for additional expenses that it expects to incur in the future. The
consistent position of the Partnership's subsidiaries has been that they did not
acquire the abandoned pipeline as part of the 1993 ST Services transaction, and
therefore did not assume any responsibility for the environmental damage nor any
liability to Grace for the pipeline.
At the end of the trial, the jury returned a verdict including findings
that (1) Grace had breached a provision of the 1993 acquisition agreement by
failing to disclose matters related to the pipeline, and (2) the pipeline was
abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired
ST Services. On August 30, 2000, the Judge entered final judgment in the case
that Grace take nothing from the subsidiaries on its claims seeking recovery of
remediation costs. Although the Partnership's subsidiaries have not incurred any
expenses in connection with the remediation, the court also ruled, in effect,
that the subsidiaries would not be entitled to indemnification from Grace if any
such expenses were incurred in the future. Moreover, the Judge let stand a prior
summary judgment ruling that the pipeline was an asset acquired by the
Partnership's subsidiaries as part of the 1993 ST Services transaction and that
any liabilities associated with the pipeline would have become liabilities of
the subsidiaries. Based on that ruling, the Massachusetts Department of
Environmental Protection and Samson Hydrocarbons Company (successor to Grace
Petroleum Company) wrote letters to ST Services alleging its responsibility for
the remediation, and ST Services responded denying any liability in connection
with this matter. The Judge also awarded attorney fees to Grace of more than
$1.5 million. Both the Partnership's subsidiaries and Grace have appealed the
trial court's final judgment to the Texas Court of Appeals in Dallas. In
particular, the subsidiaries have filed an appeal of the judgment finding that
the Otis pipeline and any liabilities associated with the pipeline were
transferred to them as well as the award of attorney fees to Grace.
On April 2, 2001, Grace filed a petition in bankruptcy, which created
an automatic stay against actions against Grace. This automatic stay covers the
appeal of the Dallas litigation, and the Texas Court of Appeals has issued an
order staying all proceedings of the appeal because of the bankruptcy. Once that
stay is lifted, the Partnership's subsidiaries that are party to the lawsuit
intend to resume vigorous prosecution of the appeal.
The Otis Air Force Base is a part of the Massachusetts Military
Reservation ("MMR Site"), which has been declared a Superfund Site pursuant to
CERCLA. The MMR Site contains a number of groundwater contamination plumes, two
of which are allegedly associated with the Otis pipeline, and various other
waste management areas of concern, such as landfills. The United States
Department of Defense, pursuant to a Federal Facilities Agreement, has been
responding to the Government remediation demand for most of the contamination
problems at the MMR Site. Grace and others have also received and responded to
formal inquiries from the United States Government in connection with the
environmental damages allegedly resulting from the jet fuel leaks. The
Partnership's subsidiaries voluntarily responded to an invitation from the
Government to provide information indicating that they do not own the pipeline.
In connection with a court-ordered mediation between Grace and the Partnership's
subsidiaries, the Government advised the parties in April 1999 that it has
identified two spill areas that it believes to be related to the pipeline that
is the subject of the Grace suit. The Government at that time advised the
parties that it believed it had incurred costs of approximately $34 million, and
expected in the future to incur costs of approximately $55 million, for
remediation of one of the spill areas. This amount was not intended to be a
final accounting of costs or to include all categories of costs. The Government
also advised the parties that it could not at that time allocate its costs
attributable to the second spill area.
By letter dated July 26, 2001, the United States Department of Justice
("DOJ") advised ST Services that the Government intends to seek reimbursement
from ST Services under the Massachusetts Oil and Hazardous Material Release
Prevention and Response Act and the Declaratory Judgment Act for the
Government's response costs at the two spill areas discussed above. The DOJ
relied in part on the Texas state court judgment, which in the DOJ's view, held
that ST Services was the current owner of the pipeline and the
successor-in-interest of the prior owner and operator. The Government advised ST
Services that it believes it has incurred costs exceeding $40 million, and
expects to incur future costs exceeding an additional $22 million, for
remediation of the two spill areas. The Partnership believes that its
subsidiaries have substantial defenses. ST Services responded to the DOJ on
September 6, 2001, contesting the Government's positions and declining to
reimburse any response costs. The DOJ has not filed a lawsuit against ST
Services seeking cost recovery for its environmental investigation and response
costs. Representatives of ST Services have met with representatives of the
Government on several occasions since September 6, 2001 to discuss the
Government's claims and to exchange information related to such claims.
Additional exchanges of information are expected to occur in the future and
additional meetings may be held to discuss possible resolution of the
Government's claims without litigation. The Partnership does not believe this
matter will have a materially adverse effect on its financial condition,
although there can be no assurances as to the ultimate outcome.
PEPCO Litigation. On April 7, 2000, a fuel oil pipeline in Maryland
owned by Potomac Electric Power Company ("PEPCO") ruptured. Work performed with
regard to the pipeline was conducted by a partnership of which ST Services is
general partner. PEPCO has reported that it has incurred total cleanup costs of
$70 million to $75 million. PEPCO probably will continue to incur some cleanup
related costs for the foreseeable future, primarily in connection with EPA
requirements for monitoring the condition of some of the impacted areas. Since
May 2000, ST Services has provisionally contributed a minority share of the
cleanup expense, which has been funded by ST Services' insurance carriers. ST
Services and PEPCO have not, however, reached a final agreement regarding ST
Services' proportionate responsibility for this cleanup effort, if any, and
cannot predict the amount, if any, that ultimately may be determined to be ST
Services' share of the remediation expense, but ST believes that such amount
will be covered by insurance and therefore will not materially adversely affect
the Partnership's financial condition.
As a result of the rupture, purported class actions were filed against
PEPCO and ST Services in federal and state court in Maryland by property and
business owners alleging damages in unspecified amounts under various theories,
including under the Oil Pollution Act ("OPA") and Maryland common law. The
federal court consolidated all of the federal cases in a case styled as In re
Swanson Creek Oil Spill Litigation. A settlement of the consolidated class
action, and a companion state-court class action, was reached and approved by
the federal judge. The settlement involved creation and funding by PEPCO and ST
Services of a $2,250,000 class settlement fund, from which all participating
claimants would be paid according to a court-approved formula, as well as a
court-approved payment to plaintiffs' attorneys. The settlement has been
consummated and the fund, to which PEPCO and ST Services contributed equal
amounts, has been distributed. Participating claimants' claims have been settled
and dismissed with prejudice. A number of class members elected not to
participate in the settlement, i.e., to "opt out," thereby preserving their
claims against PEPCO and ST Services. All non-participant claims have been
settled for immaterial amounts with ST Services' portion of such settlements
provided by its insurance carrier.
PEPCO and ST Services agreed with the federal government and the State
of Maryland to pay costs of assessing natural resource damages arising from the
Swanson Creek oil spill under OPA and of selecting restoration projects. This
process was completed in mid-2002. ST Services' insurer has paid ST Services'
agreed 50 percent share of these assessment costs. In late November 2002, PEPCO
and ST Services entered into a Consent Decree resolving the federal and state
trustees' claims for natural resource damages. The decree required payments by
ST Services and PEPCO of a total of approximately $3 million to fund the
restoration projects and for remaining damage assessment costs. The federal
court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO
and ST have each paid their 50% share and thus fully performed their payment
obligations under the Consent Decree. ST Services' insurance carrier funded ST
Services' payment.
The U.S. Department of Transportation ("DOT") has issued a Notice of
Proposed Violation to PEPCO and ST Services alleging violations over several
years of pipeline safety regulations and proposing a civil penalty of $647,000
jointly against the two companies. ST Services and PEPCO have contested the DOT
allegations and the proposed penalty. A hearing was held before the Office of
Pipeline Safety at the DOT in late 2001. ST Services does not anticipate any
further hearings on the subject and is still awaiting the DOT's ruling.
By letter dated January 4, 2002, the Attorney General's Office for the
State of Maryland advised ST Services that it intended to seek penalties from ST
Services in connection with the April 7, 2000 spill. The State of Maryland
subsequently asserted that it would seek penalties against ST Services and PEPCO
totaling up to $12 million. A settlement of this claim was reached in mid-2002
under which ST Services' insurer will pay a total of slightly more than $1
million in installments over a five year period. PEPCO has also reached a
settlement of these claims with the State of Maryland. Accordingly, the
Partnership believes that this matter will not have a material adverse effect on
its financial condition.
On December 13, 2002, ST Services sued PEPCO in the Superior Court,
District of Columbia, seeking, among other things, a declaratory judgment as to
ST Services' legal obligations, if any, to reimburse PEPCO for costs of the oil
spill. On December 16, 2002, PEPCO sued ST Services in the United States
District Court for the District of Maryland, seeking recovery of all its costs
for remediation of and response to the oil spill. Pursuant to an agreement
between ST Services and PEPCO, ST Services' suit was dismissed, subject to
refiling. ST Services has moved to dismiss PEPCO's suit. ST Services is
vigorously defending against PEPCO's claims and is pursuing its own
counterclaims for return of monies ST Services has advanced to PEPCO for
settlements and cleanup costs. The Partnership believes that any costs or
damages resulting from these lawsuits will be covered by insurance and therefore
will not materially adversely affect the Partnership's financial condition. The
amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy
which has a $600,000 retention, but the Partnership does not believe that such
retention, if incurred, would materially adversely affect the Partnership's
financial condition.
The Partnership has other contingent liabilities resulting from
litigation, claims and commitments incident to the ordinary course of business.
Management of the Partnership believes, based on the advice of counsel, that the
ultimate resolution of such contingencies will not have a materially adverse
effect on the financial position, results of operations or liquidity of the
Partnership.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for the Registrant's Partnership Interests and Related Partners
Matters
KPP owns a 99% interest as sole limited partner interest and KPL owns a
1% general partner interest in the Partnership. There is no established public
trading market for the Partnership ownership interests.
The Partnership makes regular cash distributions, in accordance with
its partnership agreement, within 45 days after the end of each quarter to
limited partner and general partner interests.
The Partnership is a limited partnership that is not subject to federal
income tax. Instead, the partners are required to report their allocable share
of the Partnership income, gain, loss, deduction and credit, regardless of
whether the Partnership makes distributions.
Item 6. Summary Historical Financial and Operating Data
The following table sets forth, for the periods and at the dates
indicated, selected historical financial data for Kaneb Pipe Line Operating
Partnership, L.P. and its subsidiaries (the "Partnership"). The data in the
table (in thousands) is derived from the historical financial statements of the
Partnership and should be read in conjunction with the Partnership's audited
financial statements. See also "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
Year Ended December 31,
---------------------------------------------------------------------
2003 2002 (a) 2001 (a) 2000 1999
---------- ----------- --------- --------- ----------
Income Statement Data:
Revenues:
Services.......................... $ 354,591 $ 288,669 $ 207,796 $ 156,232 $ 158,028
Products.......................... 215,823 97,961 - - -
----------- ----------- --------- ---------- ----------
570,414 386,630 207,796 156,232 158,028
----------- ----------- --------- ---------- ----------
Costs and expenses:
Cost of products sold............. 195,100 90,898 - - -
Operating costs................... 168,537 131,326 90,632 69,653 69,148
Depreciation and amortization..... 53,155 39,425 23,184 16,253 15,043
Gain on sale of assets............ - (609) - (1,126) -
General and administrative........ 25,121 19,869 11,889 11,881 9,424
----------- ----------- --------- ---------- ----------
441,913 280,909 125,705 96,661 93,615
----------- ----------- --------- ---------- ----------
Operating income...................... 128,501 105,721 82,091 59,571 64,413
Interest and other income............. 261 3,570 4,277 316 408
Interest expense...................... (38,757) (28,110) (14,783) (12,283) (13,390)
Loss on debt extinguishment........... - (3,282) (6,540) - -
Income tax expense.................... (5,223) (4,083) (256) (943) (1,496)
----------- ----------- --------- ---------- ----------
Income before cumulative effect of
change in accounting principle.... 84,782 73,816 64,789 46,661 49,935
Cumulative effect of change in
accounting principle - adoption
of new accounting standard for
asset retirement obligations...... (1,593) - - - -
----------- ----------- ---------- ---------- ----------
Net income ........................... $ 83,189 $ 73,816 $ 64,789 $ 46,661 $ 49,935
=========== =========== ========= ========== ==========
Cash distributions declared........... $ 102,948 $ 79,816 $ 62,156 $ 53,485 $ 51,850
=========== =========== ========= ========== ==========
Balance Sheet Data (at year end):
Property and equipment, net........... $ 1,112,970 $ 1,092,192 $ 481,274 $ 321,355 $ 316,883
Total assets.......................... 1,264,682 1,215,410 548,371 375,063 365,953
Long-term debt........................ 617,696 694,330 262,624 166,900 155,987
Partners' capital..................... 493,589 393,314 220,527 161,735 169,321
(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"), now a wholly owned
subsidiary of Kaneb Services LLC ("KSL"), manages and controls the operations of
KPP through its general partner interest and an 18% (at December 31, 2003)
limited partner interest. KPL owns a 1% interest as general partner of the
Partnership and a 1% interest as general partner of KPP.
The Partnership's petroleum pipeline business consists primarily of the
transportation, as a common carrier, of refined petroleum products in Kansas,
Nebraska, Iowa, South Dakota, North Dakota, Colorado, Wyoming and Minnesota.
Common carrier activities are those under which transportation through the
pipelines is available at published tariffs filed, in the case of interstate
shipments with the Federal Energy Regulatory Commission (the "FERC"), or in the
case of intrastate shipments, with the relevant state authority, to any shipper
of refined petroleum products who requests such services and satisfies the
conditions and specifications for transportation. The petroleum pipelines
primarily transport gasoline, diesel oil, fuel oil and propane. Substantially
all of the petroleum pipeline operations constitute common carrier operations
that are subject to federal or state tariff regulations. The Partnership also
owns an approximately 2,000-mile anhydrous ammonia pipeline system acquired from
Koch Pipeline Company, L.P. in November of 2002 (see "Liquidity and Capital
Resources"). The fertilizer pipeline originates in southern Louisiana, proceeds
north through Arkansas and Missouri, and then branches east into Illinois and
Indiana and north and west into Iowa and Nebraska. The Partnership's petroleum
pipeline business depends on the level of demand for refined petroleum products
in the markets served by the pipelines and the ability and willingness of
refineries and marketers having access to the pipelines to supply such demand by
deliveries through the pipelines. The Partnership's pipeline revenues are based
on volumes shipped and the distance over which such volumes are transported.
The Partnership's terminaling business is conducted through Support
Terminal Services ("ST Services") and Statia Terminals International N.V.
("Statia"). ST Services is one of the largest independent petroleum products and
specialty liquids terminaling companies in the United States. In the United
States, ST Services operates 37 facilities in 20 states. ST Services also owns
and operates six terminals located in the United Kingdom and eight terminals in
Australia and New Zealand. ST Services and its predecessors have a long history
in the terminaling business and handle a wide variety of liquids from petroleum
products to specialty chemicals to edible liquids. Statia, acquired on February
28, 2002 (see "Liquidity and Capital Resources"), owns a terminal on the Island
of St. Eustatius, Netherlands Antilles and a terminal at Point Tupper, Nova
Scotia, Canada. Independent terminal owners generally compete on the basis of
the location and versatility of the terminals, service and price. Terminal
versatility is a function of the operator's ability to offer handling for
diverse products with complex handling requirements. The service function
typically provided by the terminal includes the safe storage of product at
specified temperatures and other conditions, as well as receipt and delivery
from the terminal. The ability to obtain attractive pricing is dependent largely
on the quality, versatility and reputation of the facility. Terminaling revenues
are earned based on fees for the storage and handling of products.
The Partnership's product sales business delivers bunker fuels to ships
in the Caribbean and Nova Scotia, Canada, and sells bulk petroleum products to
various commercial customers at those locations. In the bunkering business, the
Partnership competes with ports offering bunker fuels along the route of the
vessel. Vessel owners or charterers are charged berthing and other fees for
associated services such as pilotage, tug assistance, line handling, launch
service and emergency response services.
OVERVIEW
In 2003, The Partnership integrated the major acquisitions completed in
2002 and focused on the performance of those operations, as well as its core
business, to generate increased cash flow. The Partnership's success in this
effort enabled it to increase cash distributions twice in 2003. On an annualized
basis, KPP raised its distribution $0.08 in May 2003 and then another $0.12 in
November 2003. The Partnership had a very strong year as revenues increased 48%,
operating income increased 22% and net income increased 13%.
In 2003, the Partnership completed the financing for the $600 million
of acquisitions it made in 2002, which were financed half with equity and half
with debt. In March 2003, KPP sold approximately three million units - the
largest and most successful equity offering in its history. The Partnership
completed the placement of its permanent financing in May 2003, and over 85% of
that debt is at favorable fixed rates, thereby limiting its exposure to rising
interest rates. The Partnership also completed a new revolving credit facility
of $400 million, with the ability to increase it to $450 million.
The Partnership has a very strong balance sheet and the financial
capacity for further expansion. The Partnership has integrated and assimilated
the substantial acquisitions it made in 2002 and has seen the contribution of
those operations to its results in 2003. The Partnership now actively seeks
opportunities for strategic and substantial growth.
CONSOLIDATED RESULTS OF OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 570,414 $ 386,630 $ 207,796
=========== =========== ===========
Operating income..................................... $ 128,501 $ 105,721 $ 82,091
=========== =========== ===========
Income before cumulative effect of change in
accounting principle............................. $ 84,782 $ 73,816 $ 64,789
Cumulative effect of change in accounting principle.. (1,593) - -
---------- ----------- -----------
Net income........................................... $ 83,189 $ 73,816 $ 64,789
=========== =========== ===========
Capital expenditures, excluding acquisitions......... $ 44,741 $ 31,101 $ 17,246
=========== =========== ===========
For the year ended December 31, 2003, revenues increased by $183.8
million, or 48%, compared to 2002, due to a $36.9 million increase in revenues
in the pipeline business, a $29.0 million increase in revenues in the
terminaling business and a $117.9 million increase in product sales revenues.
See "Liquidity and Capital Resources" regarding 2002 acquisitions. Operating
income for the year ended December 31, 2003 increased by $22.8 million, or 22%,
when compared to 2002, due to a $13.2 million increase in pipeline operating
income, a $1.5 million increase in terminaling operating income and a $8.1
million increase in product sales operating income. Income before cumulative
effect of change in accounting principle increased by $11.0 million, or 15%,
when compared to 2002. Overall, 2003 net income, including a charge of $1.6
million for the cumulative effect of change in accounting principle - adoption
of new accounting standard for asset retirement obligations, increased by $9.4
million, or 13%, when compared to 2002.
For the year ended December 31, 2002, revenues increased by $178.8
million, or 86%, compared to 2001, due to a $73.2 million increase in revenues
in the terminaling business and a $7.7 million increase in revenues in the
pipeline business. 2002 revenues also include $97.9 million in product sales
revenues from a business acquired with Statia in February of 2002. See
"Liquidity and Capital Resources". Operating income for the year ended December
31, 2002 increased by $23.6 million, or 29%, when compared to 2001, due to a
$19.7 million increase in terminaling business operating income, a $1.9 million
increase in pipeline operating income and 2002 product sales operating income of
$2.1 million. Overall, net income for the year ended December 31, 2002 increased
by $9.0 million, or 14%, when compared to 2001.
PIPELINE OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 119,633 $ 82,698 $ 74,976
Operating costs...................................... 46,379 33,744 28,844
Depreciation and amortization........................ 14,117 6,408 5,478
General and administrative........................... 7,277 3,923 3,881
----------- ----------- -----------
Operating income..................................... $ 51,860 $ 38,623 $ 36,773
=========== =========== ===========
The Partnership's pipeline revenues are based on volumes shipped and
the distances over which such volumes are transported. Because tariff rates are
regulated by the FERC or STB, the pipelines compete on the basis of quality of
service, including delivering products at convenient locations on a timely basis
to meet the needs of its customers. For the year ended December 31, 2003,
revenues increased by $36.9 million, or 45%, compared to 2002, due entirely to
the November and December 2002 pipeline acquisitions (see "Liquidity and Capital
Resources"). For the year ended December 31, 2002, revenues increased by $7.7
million, or 10%, compared to 2001, due to higher per barrel rates realized on
volumes shipped on existing pipelines and as a result of the 2002 pipeline
acquisitions. Approximately $4.5 million of the 2002 revenue increase was a
result of the pipeline acquisitions. Barrel miles on petroleum pipelines totaled
21.3 billion (including 4.7 billion for the petroleum pipeline acquired in
December of 2002), 18.3 billion and 18.6 billion for the years ended December
31, 2003, 2002 and 2001, respectively.
Operating costs, which include fuel and power costs, materials and
supplies, maintenance and repair costs, salaries, wages and employee benefits,
and property and other taxes, increased by $12.6 million in 2003 and $4.9
million in 2002. The increase in 2003 was due to the 2002 pipeline acquisitions
and increases in planned maintenance. The increase in 2002 was due to the
pipeline acquisitions and increases in expenditures for routine repairs and
maintenance. For the years ended December 31, 2003 and 2002, depreciation and
amortization increased by $7.7 million and $0.9 million, respectively, when
compared to the respective prior year, due to the pipeline acquisitions. General
and administrative costs which includes managerial, accounting and
administrative personnel costs, office rental expense, legal and professional
costs and other non-operating costs increased by $3.4 million in 2003, when
compared to 2002, due primarily to the pipeline acquisitions and increases in
personnel-related costs.
TERMINALING OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 234,958 $ 205,971 $ 132,820
Operating costs...................................... 114,030 94,480 61,788
Depreciation and amortization........................ 38,089 32,368 17,706
Gain on sale of assets............................... - (609) -
General and administrative........................... 16,307 14,692 8,008
----------- ----------- -----------
Operating income..................................... $ 66,532 $ 65,040 $ 45,318
=========== =========== ===========
For the year ended December 31, 2003, the Partnership's terminaling
revenues increased by $29.0 million, or 14%, when compared to 2002, due to the
2002 terminal acquisitions (see "Liquidity and Capital Resources") and overall
increases in the average price realized per barrel of tankage utilized. For the
year ended December 31, 2002, revenues increased by $73.2 million, or 55%,
compared to 2001, due to the terminal acquisitions and overall increases in
utilizations at existing locations. Approximately $25 million of the 2003
revenue increase and $63 million of the 2002 revenue increase was a result of
the terminal acquisitions. Average annual tankage utilized for the years ended
December 31, 2003, 2002 and 2001 aggregated 46.7 million barrels, 46.5 million
barrels and 30.1 million barrels, respectively. Average revenues per barrel of
tankage utilized for the years ended December 31, 2003, 2002 and 2001 was $5.02,
$4.43 and $4.41, respectively. The increase in 2003 average revenues per barrel
of tankage utilized was the result of changes in product mix resulting from the
2002 terminals acquisitions and foreign currency exchange differences. The
increase in 2002 average revenues per barrel of tankage utilized was due to more
favorable domestic market conditions, when compared to 2001.
In 2003, operating costs increased by $19.6 million, when compared to
2002, due to the 2002 terminal acquisitions, repair costs associated with
hurricane Isabel and increases in planned maintenance. In 2002, operating costs
increased by $32.7 million, when compared to 2001, due to the 2002 terminal
acquisitions and increases in volumes stored at existing locations. For the
years ended December 31, 2003 and 2002, depreciation and amortization increased
by $5.7 million and $14.7 million, respectively, due to the terminal
acquisitions. In 2002, KPP sold land and other terminaling business assets for
net proceeds of approximately $1.1 million, recognizing a gain on disposition of
assets of $0.6 million. General and administrative expense increased by $1.6
million in 2003 and by $6.7 million in 2002, due to the terminal acquisitions
and increases in personnel-related costs.
PRODUCT SALES OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 215,823 $ 97,961 $ -
Cost of products sold................................ 195,100 90,898 -
----------- ----------- -----------
Gross margin......................................... $ 20,723 $ 7,063 $ -
=========== =========== ===========
Operating income..................................... $ 10,109 $ 2,058 $ -
=========== =========== ===========
The product sales business, which was acquired with Statia (see
"Liquidity and Capital Resources"), delivers bunker fuels to ships in the
Caribbean and Nova Scotia, Canada and sells bulk petroleum products to various
commercial interests. For the year ended December 31, 2003, product sales
revenues, gross margin and operating income increased by $117.9 million, $13.7
million and $8.1 million, respectively, when compared to 2002, due to increases
in both sales price and volumes. Approximately $95.8 of the 2003 revenue
increase was due to volume increases and $22.1 million was due to price
increases, when compared to 2002. The results of operations for the year ended
December 31, 2002 include the operations of the product sales business since the
date of acquisition, February 28, 2002.
Product inventories are maintained at minimum levels to meet customers'
needs; however, market prices for petroleum products can fluctuate significantly
in short periods of time.
INTEREST AND OTHER INCOME
In September of 2002, the Partnership entered into a treasury lock
contract, maturing on November 4, 2002, for the purpose of locking in the US
Treasury interest rate component on $150 million of anticipated thirty-year
public debt offerings. The treasury lock contract originally qualified as a cash
flow hedging instrument under Statement of Financial Accounting Standards
("SFAS") No. 133. In October of 2002, the Partnership, due to various market
factors, elected to defer issuance of the public debt securities, effectively
eliminating the cash flow hedging designation for the treasury lock contract. On
October 29, 2002, the contract was settled resulting in a net realized gain of
$3.0 million, which was recognized as a component of interest and other income.
In March of 2001, the Partnership entered into two contracts for the
purpose of locking in interest rates on $100 million of anticipated ten-year
public debt offerings. As the interest rate locks were not designated as hedging
instruments pursuant to the requirements of SFAS No. 133, increases or decreases
in the fair value of the contracts are included as a component of interest and
other income. On May 22, 2001, the contracts were settled resulting in a gain of
$3.8 million, which is included in interest and other income in 2001.
INTEREST EXPENSE
For the year ended December 31, 2003, interest expense increased by
$10.6 million, when compared to 2002, due to increases in fixed rate debt
resulting from the 2002 pipeline and terminal acquisitions (see "Liquidity and
Capital Resources"), partially offset by overall declines in interest rates on
variable rate debt.
For the year ended December 31, 2002, interest expense increased by
$13.3 million, when compared to 2001, due to overall increases in debt levels
resulting from the 2002 acquisitions (see "Liquidity and Capital Resources"),
partially offset by declines in interest rates on variable rate debt.
INCOME TAXES
Partnership operations are not subject to federal or state income
taxes. However, certain operations are conducted through separate taxable
wholly-owned U.S. and foreign corporate subsidiaries. The income tax expense for
these subsidiaries was $5.2 million, $4.1 million and $0.3 million for the years
ended December 31, 2003, 2002 and 2001, respectively. The 2003 and 2002
increases in income taxes, compared to the respective prior year, was primarily
due to foreign taxes on terminaling operations acquired in 2002 (see "Liquidity
and Capital Resources").
On June 1, 1989, the governments of the Netherlands Antilles and St.
Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January
1, 1989, which expired on December 31, 2000. This agreement requires a
subsidiary of the Partnership, which was acquired with Statia on February 28,
2002, to pay a 2% rate on taxable income, as defined therein, or a minimum
payment of 500,000 Netherlands Antilles guilders ($0.3 million) per year. The
agreement further provides that any amounts paid in order to meet the minimum
annual payment will be available to offset future tax liabilities under the
agreement to the extent that the minimum annual payment is greater than 2% of
taxable income. The subsidiary is currently engaged in discussions with
representatives appointed by the Island Territory of St. Eustatius regarding the
renewal or modification of the agreement, but the ultimate outcome cannot be
predicted at this time. The subsidiary has accrued amounts assuming a new
agreement becomes effective, and continues to make payments, as required, under
the previous agreement.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities was $142.0 million, $91.8 million
and $95.7 million for the years 2003, 2002 and 2001, respectively. The increase
in 2003, compared to 2002, was due to increases in pipeline, terminaling and
product sales revenues and operating income, primarily a result of the 2002
acquisitions, and changes in working capital components from the timing of cash
receipts and disbursements. The 2002 decrease in cash provided by operating
activities, when compared to 2001, was due to the payment of personnel-related
costs assumed with the Statia acquisition, initial working capital requirements
of the pipeline businesses acquired in 2002 and changes in working capital
components resulting from the timing of cash receipts and disbursements,
partially offset by overall increases in revenues and operating income.
Capital expenditures, including routine maintenance and expansion
expenditures, but excluding acquisitions, were $44.7 million, $31.1 million and
$17.2 million for 2003, 2002 and 2001, respectively. The increase in 2003 and
2002 capital expenditures, when compared to the respective prior year, is the
result of planned maintenance and expansion capital expenditures related to the
pipeline and terminaling operations acquired in 2002 and higher maintenance
capital expenditures in the existing pipeline and terminaling businesses. During
all periods, adequate pipeline capacity existed to accommodate volume growth,
and the expenditures required for environmental and safety improvements were
not, and are not expected in the future to be, significant. Environmental
damages are included under the Partnership's insurance coverages (subject to
deductibles and limits). The Partnership anticipates that capital expenditures
(including routine maintenance and expansion expenditures, but excluding
acquisitions) will total approximately $28 million to $32 million in 2004. Such
future expenditures, however, will depend on many factors beyond the
Partnership's control, including, without limitation, demand for refined
petroleum products and terminaling services in the Partnership's market areas,
local, state and federal government regulations, fuel conservation efforts and
the availability of financing on acceptable terms. No assurance can be given
that required capital expenditures will not exceed anticipated amounts during
the year or thereafter or that the Partnership will have the ability to finance
such expenditures through borrowings, or choose to do so.
The Partnership makes regular cash distributions in accordance with its
Partnership agreement within 45 days after the end of each quarter to limited
partner and general partner interests. Aggregate distributions of $98.2 million,
$74.4 million and $62.2 million, were paid to limited partner interests and
general partner interests in 2003, 2002 and 2001, respectively.
The Partnership expects to fund future cash distributions and routine
maintenance capital expenditures with existing cash and anticipated cash flows
from operations. Expansionary capital expenditures are expected to be funded
through additional Partnership bank borrowings and/or future public debt
offerings or KPP public equity offerings.
In January of 2001, the Partnership used proceeds from its revolving
credit agreement to repay in full its $128 million of mortgage notes. Under the
provisions of the mortgage notes, the Partnership incurred a $6.5 million
prepayment penalty which was recognized as loss on debt extinguishment in 2001.
In January of 2001, the Partnership acquired Shore Terminals LLC
("Shore") for $107 million in cash and 1,975,090 KPP limited partnership units
(valued at $56.5 million on the date of agreement and its announcement).
Financing for the cash portion of the purchase price was initially supplied by
the Partnership's revolving credit facility.
In January of 2002, KPP issued 1,250,000 limited partnership units in a
public offering at $41.65 per unit, generating approximately $49.7 million in
net proceeds. The proceeds were used to reduce borrowings under the
Partnership's revolving credit agreement.
In February of 2002, the Partnership issued $250 million of 7.75%
senior unsecured notes due February 15, 2012. The net proceeds from the public
offering, $248.2 million, were used to repay the Partnership's revolving credit
agreement and to partially fund the acquisition of all of the liquids
terminaling subsidiaries of Statia Terminals Group NV ("Statia"). Under the note
indenture, interest is payable semi-annually in arrears on February 15 and
August 15 of each year. The notes are redeemable, as a whole or in part, at the
option of the Partnership, at any time, at a redemption price equal to the
greater of 100% of the principal amount of the notes, or the sum of the present
value of the remaining scheduled payments of principal and interest, discounted
to the redemption date at the applicable U.S. Treasury rate, as defined in the
indenture, plus 30 basis points. The note indenture contains certain financial
and operational covenants, including certain limitations on investments, sales
of assets and transactions with affiliates and, absent an event of default, such
covenants do not restrict distributions to partners. At December 31, 2003, the
Partnership was in compliance with all covenants.
On February 28, 2002, the Partnership acquired Statia for approximately
$178 million in cash (net of acquired cash). The acquired Statia subsidiaries
had approximately $107 million in outstanding debt, including $101 million of
11.75% notes due in November 2003. The cash portion of the purchase price was
initially funded by the Partnership's revolving credit agreement and proceeds
from the Partnership's February 2002 public debt offering. In April of 2002, the
Partnership redeemed all of Statia's 11.75% notes at 102.938% of the principal
amount, plus accrued interest. The redemption was funded by the Partnership's
revolving credit facility. Under the provisions of the 11.75% notes, the
Partnership incurred a $3.0 million prepayment penalty, of which $2.0 million
was recognized as loss on debt extinguishment in 2002.
In May of 2002, KPP issued 1,565,000 limited partnership units in a
public offering at a price of $39.60 per unit, generating approximately $59.1
million in net proceeds. A portion of the offering proceeds were used to fund
the Partnership's September 2002 acquisition of the Australia and New Zealand
terminals.
On September 18, 2002, the Partnership acquired eight bulk liquid
storage terminals in Australia and New Zealand from Burns Philp & Co. Ltd. for
approximately $47 million in cash.
On November 1, 2002, the Partnership acquired an approximately
2,000-mile anhydrous ammonia pipeline system from Koch Pipeline Company, L.P.
for approximately $139 million in cash. This fertilizer pipeline system
originates in southern Louisiana, proceeds north through Arkansas and Missouri,
and then branches east into Illinois and Indiana and north and west into Iowa
and Nebraska. The acquisition was initially financed with bank debt.
In November of 2002, KPP issued 2,095,000 limited partnership units in
a public offering at $33.36 per unit, generating approximately $66.7 million in
net proceeds. The offering proceeds were used to reduce bank borrowings for the
fertilizer pipeline acquisition.
On December 24, 2002, the Partnership acquired a 400-mile petroleum
products pipeline and four terminals in North Dakota and Minnesota from Tesoro
Refining and Marketing Company for approximately $100 million in cash, subject
to normal post-closing adjustments. The acquisition was initially funded with
bank debt.
In March of 2003, KPP issued 3,122,500 limited partnership units in a
public offering at $36.54 per unit, generating approximately $109.1 million in
net proceeds. The proceeds were used to reduce bank borrowings.
In April of 2003, the Partnership entered into a new credit agreement
with a group of banks that provides for a $400 million unsecured revolving
credit facility through April of 2006. The credit facility, which provides for
an increase in the commitment up to an aggregate of $450 million by mutual
agreement between the Partnership and the banks, bears interest at variable
rates and has a variable commitment fee on unused amounts. The credit facility
contains certain financial and operating covenants, including limitations on
investments, sales of assets and transactions with affiliates and, absent an
event of default, does not restrict distributions to partners. At December 31,
2003, the Partnership was in compliance with all covenants. Initial borrowings
on the credit agreement ($324.2 million) were used to repay all amounts
outstanding under the Partnership's $275 million credit agreement and $175
million bridge loan agreement. At December 31, 2003, $54.2 million was
outstanding under the new credit agreement.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior
unsecured notes due June 1, 2013. The net proceeds from the public offering,
$247.6 million, were used to reduce amounts due under the 2003 revolving credit
agreement. Under the note indenture, interest is payable semi-annually in
arrears on June 1 and December 1 of each year. The notes are redeemable, as a
whole or in part, at the option of the Partnership, at any time, at a redemption
price equal to the greater of 100% of the principal amount of the notes, or the
sum of the present value of the remaining scheduled payments of principal and
interest, discounted to the redemption date at the applicable U.S. Treasury
rate, as defined in the indenture, plus 30 basis points. The note indenture
contains certain financial and operational covenants, including certain
limitations on investments, sales of assets and transactions with affiliates
and, absent an event of default, such covenants do not restrict distributions to
partners. At December 31, 2003, the Partnership was in compliance with all
covenants. In connection with the offering, on May 8, 2003, the Partnership
entered into a treasury lock contract for the purpose of locking in the US
Treasury interest rate component on $100 million of the debt. The treasury lock
contract, which qualified as a cash flow hedging instrument under SFAS No. 133,
was settled on May 19, 2003 with a cash payment by the Partnership of $1.8
million. The settlement cost of the contract has been recorded as a component of
accumulated other comprehensive income and is being amortized, as interest
expense, over the life of the debt.
The following is a schedule by period of the Partnership's debt
repayment obligations and material contractual commitments as of December 31,
2003:
Less than After
Total 1 year 1 -3 years 4 -5 years 5 years
----------- ----------- ---------- ----------- ----------
(in thousands)
Debt:
Revolving credit facility......... $ 54,169 $ - $ 54,169 $ - $ -
7.75% senior unsecured notes...... 250,000 - - - 250,000
5.875% senior unsecured notes..... 250,000 - - - 250,000
Other bank debt................... 63,527 - 63,527 - -
----------- ----------- --------- ---------- ----------
Debt subtotal.................. 617,696 - 117,696 - 500,000
----------- ----------- --------- ---------- ----------
Contractual commitments:
Operating leases.................. 10,723 4,325 3,706 2,350 342
----------- ----------- --------- ---------- ----------
Contractual commitments
subtotal.................... 10,723 4,325 3,706 2,350 342
----------- ----------- --------- ---------- ----------
Total.......................... $ 628,419 $ 4,325 $ 121,402 $ 2,350 $ 500,342
=========== =========== ========= ========== ==========
See also "Item 1 - Environmental Matters" and "Item 3 - Legal
Proceedings".
OFF-BALANCE SHEET TRANSACTIONS
The Partnership was not a party to any off-balance sheet transactions
at December 31, 2003, or for any of the years ended December 31, 2003, 2002 and
2001.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the Partnership's financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates. Significant accounting policies are included in the Notes
to the Consolidated Financial Statements.
Critical accounting policies are those that are most important to the
portrayal to the Partnership's financial position and results of operations.
These policies require management's most difficult, subjective or complex
judgments, often employing the use of estimates about the effect of matters that
are inherently uncertain. The Partnership's most critical accounting policies
pertain to impairment of property and equipment and environmental costs.
The carrying value of property and equipment is periodically evaluated
using management's estimates of undiscounted future cash flows, or, in some
cases, third-party appraisals, as the basis of determining if impairment exists
under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets", which was adopted effective January 1, 2002. To the
extent that impairment is indicated to exist, an impairment loss is recognized
under SFAS No. 144 based on fair value. The application of SFAS No. 144 did not
have a material impact on the results of operations of the Partnership for the
years ended December 31, 2003 or 2002. However, future evaluations of carrying
value are dependent on many factors, several of which are out of the
Partnership's control, including demand for refined petroleum products and
terminaling services in the Partnership's market areas, and local, state and
federal governmental regulations. To the extent that such factors or conditions
change, it is possible that future impairments might occur, which could have a
material effect on the results of operations of the Partnership.
Environmental expenditures that relate to current operations are
expensed or capitalized, as appropriate. Expenditures that relate to an existing
condition caused by past operations, and which do not contribute to current or
future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or remedial efforts are probable, and the costs
can be reasonably estimated. Generally, the timing of these accruals coincides
with the completion of a feasibility study or the Partnership's commitment to a
formal plan of action. The application of the Partnership's environmental
accounting policies did not have a material impact on the results of operations
of the Partnership for the years ended December 31, 2003, 2002 or 2001. Although
the Partnership believes that its operations are in general compliance with
applicable environmental regulations, risks of substantial costs and liabilities
are inherent in pipeline and terminaling operations. Moreover, it is possible
that other developments, such as increasingly strict environmental laws,
regulations and enforcement policies thereunder, and legal claims for damages to
property or persons resulting from the operations of the Partnership could
result in substantial costs and liabilities, any of which could have a material
effect on the results of operations of the Partnership.
RECENT ACCOUNTING PRONOUNCEMENT
In December 2003, the FASB issued Interpretation No. 46 (Revised
December 2003), "Consolidation of Variable Interest Entities (FIN 46R),
primarily to clarify the required accounting for interests in variable interest
entities (VIEs). This standard replaces FASB Interpretation No. 46,
Consolidation of Variable Interest Entities, that was issued in January 2003 to
address certain situations in which a company should include in its financial
statements the assets, liabilities and activities of another entity. For the
Partnership, application of FIN 46R is required for interests in certain VIEs
that are commonly referred to as special-purpose entities, or SPEs, as of
December 31, 2003 and for interests in all other types of VIEs as of March 31,
2004. The application of FIN 46R has not and is not expected to have a material
impact on the consolidated financial statements of the Partnership.
Item 7(a). Quantitative and Qualitative Disclosures About Market Risk
The principal market risks (i.e., the risk of loss arising from the
adverse changes in market rates and prices) to which the Partnership is exposed
are interest rates on the Partnership's debt and investment portfolios,
fluctuations of petroleum product prices on inventories held for resale, and
fluctuations in foreign currency.
The Partnership's investment portfolio consists of cash equivalents;
accordingly, the carrying amounts approximate fair value. The Partnership's
investments are not material to its financial position or performance. Assuming
variable rate debt of $117.7 million at December 31, 2003, a one percent
increase in interest rates would increase annual net interest expense by
approximately $1.2 million. Information regarding the Partnership's interest
rate hedging transactions are included in "Item 7 -Interest and Other Income"
and "Item 7 - Liquidity and Capital Resources".
The product sales business periodically purchases refined petroleum
products for resale as bunker fuel and sales to commercial interests. Petroleum
inventories are generally held for short periods of time, not exceeding 90 days.
As the Partnership does not engage in derivative transactions to hedge the value
of the inventory, it is subject to market risk from changes in global oil
markets.
A significant portion of the terminaling business is exposed to
fluctuations in foreign currency exchange rates. (See "Item 7 - Terminaling
Operations".)
Item 8. Financial Statements and Supplementary Data
The financial statements and supplementary data of the Partnership
begin on page F-1 of this report. Such information is hereby incorporated by
reference into this Item 8.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
Item 9(a). Controls and Procedures
Kaneb Pipe Line Company LLC's principal executive officer and principal
financial officer, after evaluating as of December 31, 2003, the effectiveness
of the Partnership's disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934), have concluded
that, as of such date, the Partnership's disclosure controls and procedures are
adequate and effective to ensure that material information relating to the
Partnership and its consolidated subsidiaries would be made known to them by
others within those entities.
During the fourth quarter of 2003, there have been no changes in the
Partnership's internal controls over financial reporting that have materially
affected, or are reasonably likely to materially affect, those internal controls
subsequent to the date of the evaluation. As a result, no corrective actions
were required or undertaken.
PART III
Item 10. Directors and Executive Officers of the Registrant
The Partnership does not have directors or officers. All directors of
the general partner are elected annually by KPL. All officers serve at the
discretion of the directors. The information contained in Item 10 of KPP's Form
10-K, for the year ended December 31, 2003, is incorporated by reference in this
report.
CODE OF ETHICS
The Partnership has adopted a Code of Ethics applicable to all
employees, including the principal executive officer, principal financial
officer and directors of the General Partner. A copy of the Code of Ethics will
be provided without charge by written request to Investor Relations, 2435 North
Central Expressway, Richardson, Texas 75080.
Item 11. Executive Compensation
The officers of the general partner manage and operate the
Partnership's business. The Partnership does not directly employ any of the
persons responsible for managing or operating the Partnership's operations, but
instead reimburses the general partner for the services of such persons. The
information contained in Item 11 of KPP's Form 10-K for the year ended December
31, 2003, is incorporated by reference in this report.
Item 12. Security Ownership of Certain Beneficial Owners and Management
KPP owns a 99% interest as the sole limited partner interest and KPL
owns a 1% general partner interest in the Partnership. Information identifying
security ownership by the Directors and Officers of KPL is contained in Item 12
of KPP's Form 10-K, for the year ended December 31, 2003, and is incorporated by
reference in this report.
Item 13. Certain Relationships and Related Transactions
KPL is entitled to certain reimbursements under the Partnership
Agreement. For additional information regarding the nature and amount of such
reimbursements, see Note 7 to the Partnership's consolidated financial
statements.
Item 14. Principal Accounting Fees and Services
The information contained in Item 14 of KPP's Form 10-K for the year
ended December 31, 2003 is incorporated by reference in this report.
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, 2003................... F - 2
Consolidated Balance Sheets - December 31, 2003 and 2002.................................. F - 3
Consolidated Statements of Cash Flows - Three Years Ended December 31, 2003............... F - 4
Consolidated Statements of Partners' Capital - Three Years ended December 31, 2003........ F - 5
Notes to Consolidated Financial Statements................................................ F - 6
(a)(2) Financial Statement Schedules
Set forth below is the financial statement schedule appearing in this
report.
Schedule II - Kaneb Pipe Line Operating Partnership, L.P. Valuation and Qualifying Accounts -
Years Ended December 31, 2003, 2002 and 2001.............................................. F - 21
Schedules, other than the one listed above, have been omitted because
of the absence of the conditions under which they are required or
because the required information is included in the consolidated
financial statements or related notes thereto.
(a)(3) List of Exhibits
3.1 Amended and Restated Agreement of Limited Partnership, dated
September 27, 1989, filed as Exhibit 3.1 to the Registrant's
Form 10-K for the year ended December 31, 2001, which exhibit
is hereby incorporated by reference.
3.2 Amendment to Amended and Restated Agreement of Limited
Partnership dated October 27, 2003, filed herewith.
10.1 ST Agreement and Plan of Merger dated December 21, 1992 by and
between Grace Energy Corporation, Support Terminal Services,
Inc., Standard Transpipe Corp., and Kaneb Pipe Line Operating
Partnership, NSTS, Inc. and NSTI, Inc. as amended by Amendment
of STS Merger Agreement dated March 2, 1993, filed as Exhibit
10.1 of the exhibits to KPP's Current Report on Form 8-K
("Form 8-K"), dated March 16, 993, which exhibit is hereby
incorporated by reference.
10.2 Agreement for Sale and Purchase of Assets between Wyco Pipe
Line Company and the Partnership, dated February 19, 1995,
filed as Exhibit 10.1 of the exhibits to KPP's March 1995 Form
8-K, which exhibit is hereby incorporated by reference.
10.3 Asset Purchase Agreements between and among Steuart Petroleum
Company, SPC Terminals, Inc., Piney Point Industries, Inc.,
Steuart Investment Company, Support Terminals Operating
Partnership, L.P. and the Partnership, as amended, dated
August 27, 1995, filed as Exhibits 10.1, 10.2, 10.3, and 10.4
of the exhibits to KPP's Current Report on Form 8-K dated
January 3, 1996, which exhibits are hereby incorporated by
reference.
10.4 Formation and Purchase Agreement, between and among Support
Terminal Operating Partnership, L.P., Northville Industries
Corp. and AFFCO, Corp., dated October 30, 1998, filed as
exhibit 10.9 to KPP's Form 10-K for the year ended December
31, 1998, which exhibit is hereby incorporated by reference.
10.5 Agreement, between and among, GATX Terminals Limited, ST
Services, Ltd., ST Eastham, Ltd., GATX Terminals Corporation,
Support Terminals Operating Partnership, L.P. and Kaneb Pipe
Line Partners, L.P., dated January 26, 1999, filed as Exhibit
10.10 to KPP's Form 10-K for the year ended December 31, 1998,
which exhibit is hereby incorporated by reference.
10.6 Credit Agreement, between and among, Kaneb Pipe Line Operating
Partnership, L.P., ST Services, Ltd. and SunTrust Bank,
Atlanta, dated January 27, 1999, filed as Exhibit 10.11 to
KPP's Form 10-K for the year ended December 31, 1998, which
exhibit is hereby incorporated by reference.
10.7 Revolving Credit Agreement, dated as of April 24, 2003 among
Kaneb Pipe Line Operating Partnership, L.P., Kaneb Pipe Line
Partners, L.P., The Lenders From Time To Time Party Hereto,
and SunTrust Bank, as Administrative Agent, filed as Exhibit
10.11 to the Registrant's Form 10-Q for the period ended March
31, 2003, which exhibit is hereby incorporated by reference.
10.8 Securities Purchase Agreement Among Shore Terminals LLC, Kaneb
Pipe Line Partners, L.P. and the Sellers Named Therein, dated
as of September 22, 2000, Amendment No. 1 To Securities
Purchase Agreement, dated as of November 28, 2000 and
Registration Rights Agreement, dated as of January 3, 2001,
filed as Exhibits 10.1, 10.2 and 10.3 of the exhibits to KPP's
Current Report on Form 8-K dated January 3, 2001, which
exhibits are hereby incorporated by reference.
10.9 Stock Purchase Agreement, dated as of November 12, 2001, by
and between Kaneb Pipe Line Operating Partnership, L.P., and
Statia Terminals Group NV, a public company with limited
liability organized under the laws of the Netherlands
Antilles, filed as Exhibit 10.1 to the exhibits to KPP's
Current Report on Form 8-K, dated January 11, 2002, and
incorporated herein by reference.
10.10 Voting and Option Agreement dated as of November 12, 2001, by
and between Kaneb Pipe Line Operating Partnership, L.P., and
Statia Terminals Holdings N.V., a Netherlands Antilles company
and a shareholder of Statia Terminals Group NV, a Netherlands
Antilles company filed as Exhibit 10.1 to the exhibits to
Registrant's Current Report on Form 8-K, dated January 11,
2002, and incorporated herein by reference.
10.11* Amended and Restated Kaneb LLC 2002 Long Term Incentive Plan,
dated June 30, 2003, filed as Exhibit 10.1 to the exhibits to
Registrant's Form 10-Q for the period ended June 30, 2003, and
incorporated herein by reference.
21 List of Subsidiaries, filed herewith.
23 Consent of KPMG LLP, filed herewith.
31.1 Certification of Chief Executive Officer, Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002, dated as of March 12,
2004.
31.2 Certification of Chief Financial Officer, Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002, dated as of March 12,
2004.
32.1 Certification of Chief Executive Officer, Pursuant to Section
906(a) of the Sarbanes-Oxley Act of 2002, dated as of March
12, 2004.
32.2 Certification of Chief Financial Officer, Pursuant to Section
906(a) of the Sarbanes-Oxley Act of 2002, dated as of March
12, 2004.
* Denotes management contract.
(b) Reports on Form 8-K
Current Report on Form 8-K filed with the SEC on October 30, 2003.
INDEPENDENT AUDITORS' REPORT
To the Partners of
Kaneb Pipe Line Operating Partnership, L.P.
We have audited the consolidated financial statements of Kaneb Pipe Line
Operating Partnership, L.P. and its subsidiaries (the "Partnership") as listed
in the index appearing under Item 15(a)(1). In connection with our audits of the
consolidated financial statements, we have also audited the financial statement
schedule as listed in the index appearing under Item 15(a)(2). These
consolidated financial statements and financial statement schedule are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on the consolidated financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Partnership and
its subsidiaries as of December 31, 2003 and 2002, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2003, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, the related
financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects the information set forth therein.
As described in Note 2, the Partnership adopted Statement of Financial
Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" in
2003.
KPMG LLP
Dallas, Texas
February 20, 2004
F - 1
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
-----------------------------------------------------------
2003 2002 2001
----------------- ----------------- -----------------
Revenues:
Services........................................... $ 354,591,000 $ 288,669,000 $ 207,796,000
Products........................................... 215,823,000 97,961,000 -
------------- ------------- --------------
Total revenues.................................. 570,414,000 386,630,000 207,796,000
------------- ------------- --------------
Costs and expenses:
Cost of products sold.............................. 195,100,000 90,898,000 -
Operating costs.................................... 168,537,000 131,326,000 90,632,000
Depreciation and amortization...................... 53,155,000 39,425,000 23,184,000
Gain on sale of assets............................. - (609,000) -
General and administrative......................... 25,121,000 19,869,000 11,889,000
------------- ------------- --------------
Total costs and expenses........................ 441,913,000 280,909,000 125,705,000
------------- ------------- --------------
Operating income...................................... 128,501,000 105,721,000 82,091,000
Interest and other income............................. 261,000 3,570,000 4,277,000
Interest expense...................................... (38,757,000) (28,110,000) (14,783,000)
Loss on debt extinguishment........................... - (3,282,000) (6,540,000)
------------- ------------- --------------
Income before income taxes and cumulative effect of
change in accounting principle..................... 90,005,000 77,899,000 65,045,000
Income tax expense.................................... (5,223,000) (4,083,000) (256,000)
------------- -------------- --------------
Income before cumulative effect of change in
accounting principle............................... 84,782,000 73,816,000 64,789,000
Cumulative effect of change in accounting principle -
adoption of new accounting standard for asset
retirement obligations............................. (1,593,000) - -
------------- ------------- --------------
Net income ........................................... $ 83,189,000 $ 73,816,000 $ 64,789,000
============= ============= ==============
See notes to consolidated financial statements.
F - 2
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------------------------
2003 2002
---------------- ----------------
ASSETS
Current assets:
Cash and cash equivalents............................................... $ 38,626,000 $ 22,028,000
Accounts receivable (net of allowance for doubtful accounts
of $1,693,000 in 2003 and $1,765,000 in 2002)........................ 51,864,000 48,926,000
Inventories............................................................. 9,324,000 4,922,000
Prepaid expenses and other.............................................. 9,205,000 8,498,000
---------------- ----------------
Total current assets................................................. 109,019,000 84,374,000
---------------- ----------------
Property and equipment..................................................... 1,360,319,000 1,288,762,000
Less accumulated depreciation.............................................. 247,349,000 196,570,000
---------------- ----------------
Net property and equipment........................................... 1,112,970,000 1,092,192,000
---------------- ----------------
Investment in affiliates................................................... 25,456,000 25,604,000
Excess of cost over fair value of net assets of acquired business and
other assets............................................................ 17,237,000 13,240,000
---------------- ----------------
$ 1,264,682,000 $ 1,215,410,000
================ ================
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable........................................................ $ 27,941,000 $ 22,064,000
Accrued expenses........................................................ 31,642,000 29,339,000
Accrued distributions payable........................................... 26,344,000 21,639,000
Accrued interest payable................................................ 9,297,000 7,896,000
Accrued taxes, other than income taxes.................................. 4,031,000 3,598,000
Deferred terminaling fees............................................... 7,061,000 6,246,000
Payable to general partner.............................................. 3,630,000 5,403,000
---------------- ----------------
Total current liabilities............................................ 109,946,000 96,185,000
---------------- ----------------
Long-term debt............................................................. 617,696,000 694,330,000
Other liabilities and deferred taxes....................................... 43,451,000 31,581,000
Commitments and contingencies
Partners' capital:
Limited partners........................................................ 480,323,000 390,904,000
General partner......................................................... 894,000 1,016,000
Accumulated other comprehensive income.................................. 12,372,000 1,394,000
---------------- ----------------
Total partners' capital.............................................. 493,589,000 393,314,000
---------------- ----------------
$ 1,264,682,000 $ 1,215,410,000
================ ================
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,
---------------------------------------------------------
2003 2002 2001
------------- ------------- --------------
Operating activities:
Net income ........................................ $ 83,189,000 $ 73,816,000 $ 64,789,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization................... 53,155,000 39,425,000 23,184,000
Equity in earnings of affiliates, net of
distributions................................. 148,000 (3,164,000) (5,000)
Gain on sale of assets.......................... - (609,000) -
Deferred income taxes........................... 1,683,000 3,105,000 256,000
Cumulative effect of change in accounting
principle..................................... 1,593,000 - -
Other liabilities............................... 1,190,000 (1,341,000) (5,422,000)
Changes in working capital components:
Accounts receivable........................... (2,938,000) (12,379,000) (824,000)
Inventories, prepaid expenses and other....... (5,109,000) (6,601,000) 1,601,000
Accounts payable and accrued expenses......... 10,829,000 (1,192,000) 9,298,000
Payable to general partner.................... (1,773,000) 702,000 2,812,000
-------------- ------------- --------------
Net cash provided by operating activities.. 141,967,000 91,762,000 95,689,000
-------------- ------------- --------------
Investing activities:
Acquisitions, net of cash acquired................. (1,644,000) (468,477,000) (111,562,000)
Capital expenditures............................... (44,741,000) (31,101,000) (17,246,000)
Proceeds from sale of assets....................... - 1,107,000 2,807,000
Other, net......................................... (1,109,000) 306,000 (111,000)
-------------- ------------- --------------
Net cash used in investing activities...... (47,494,000) (498,165,000) (126,112,000)
-------------- -------------- --------------
Financing activities:
Issuance of debt................................... 291,377,000 746,087,000 260,500,000
Payments of debt................................... (382,831,000) (426,647,000) (164,776,000)
Distributions...................................... (98,243,000) (74,439,000) (62,156,000)
Net proceeds from issuance of units by KPP......... 109,056,000 175,527,000 -
-------------- ------------- --------------
Net cash provided by (used in) financing
activities............................. (80,641,000) 420,528,000 33,568,000
-------------- ------------- --------------
Effect of exchange rate changes on cash............... 2,766,000 - -
-------------- ------------- --------------
Increase in cash and cash equivalents................. 16,598,000 14,125,000 3,145,000
Cash and cash equivalents at beginning of period...... 22,028,000 7,903,000 4,758,000
-------------- ------------- --------------
Cash and cash equivalents at end of period............ $ 38,626,000 $ 22,028,000 $ 7,903,000
============== ============= ==============
Supplemental cash flow information:
Cash paid for interest............................. $ 34,818,000 $ 25,942,000 $ 14,028,000
============== ============= ==============
Non-cash investing and financing activities -
Issuance of units by KPP in connection with
acquisition of terminals........................ $ - $ - $ 56,488,000
============== ============= ==============
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 31, 2001.... $ 162,288,000 $ 984,000 $ (1,537,000) $ 161,735,000
2001 income allocation................. 64,141,000 648,000 - 64,789,000 $ 64,789,000
Distributions declared................. (61,554,000) (602,000) - (62,156,000) -
Issuance of units by KPP, net of
offering costs....................... 56,488,000 - - 56,488,000 -
Foreign currency translation
adjustment........................... - - (329,000) (329,000) (329,000)
-------------- ----------- ----------- -------------- ---------------
Comprehensive income for the year...... $ 64,460,000
===============
Partners' capital at December 31, 2001... 221,363,000 1,030,000 (1,866,000) 220,527,000
2002 income allocation................. 73,078,000 738,000 - 73,816,000 $ 73,816,000
Distributions declared................. (79,064,000) (752,000) - (79,816,000) -
Issuance of units by KPP, net of
offering costs....................... 175,527,000 - - 175,527,000 -
Foreign currency translation
adjustment........................... - - 3,260,000 3,260,000 3,260,000
-------------- ----------- ----------- -------------- ---------------
Comprehensive income for the year...... $ 77,076,000
===============
Partners' capital at December 31, 2002... 390,904,000 1,016,000 1,394,000 393,314,000
2003 income allocation................. 82,357,000 832,000 - 83,189,000 $ 83,189,000
Distributions declared................. (101,994,000) (954,000) - (102,948,000) -
Issuance of units by KPP, net of
offering costs....................... 109,056,000 - - 109,056,000 -
Foreign currency translation
adjustment........................... - - 12,662,000 12,662,000 12,662,000
Interest rate hedging transaction...... - - (1,684,000) (1,684,000) (1,684,000)
-------------- ------------ ----------- -------------- ---------------
Comprehensive income for the year...... $ 94,167,000
===============
Partners' capital at December 31, 2003... $ 480,323,000 $ 894,000 $12,372,000 $ 493,589,000
============== =========== =========== ==============
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 18% (at December 31, 2003) limited partnership
interest. KPL owns a 1% interest as general partner of the Partnership and a 1%
interest as general partner of KPP.
In March of 2003, KPP issued 3,122,500 limited partnership units in a
public offering at $36.54 per unit, generating approximately $109.1 million in
net proceeds. The proceeds were used to reduce bank borrowings (See Note 5).
In November of 2002, KPP issued 2,095,000 limited partnership units in a
public offering at $33.36 per unit, generating approximately $66.7 million in
net proceeds. The offering proceeds were used to reduce bank borrowings for the
November 2002 fertilizer pipeline acquisition (see Notes 3 and 5).
In May of 2002, KPP issued 1,565,000 limited partnership units in a
public offering at a price of $39.60 per unit, generating approximately $59.1
million in net proceeds. A portion of the offering proceeds were used to fund
the Partnership's September 2002 acquisition of the Australia and New Zealand
terminals (see Note 3).
In January of 2002, KPP issued 1,250,000 limited partnership units in a
public offering at $41.65 per unit, generating approximately $49.7 million in
net proceeds. The proceeds were used to reduce borrowings under the
Partnership's revolving credit agreement (see Note 5).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following significant accounting policies are followed by the
Partnership in the preparation of the consolidated financial statements.
Cash and Cash Equivalents
The Partnership's policy is to invest cash in highly liquid investments
with original maturities of three months or less. Accordingly, uninvested cash
balances are kept at minimum levels. Such investments are valued at cost, which
approximates market, and are classified as cash equivalents.
Inventories
Inventories consist primarily of petroleum products purchased for resale
in the product sales operations and are valued at the lower of cost or market.
Cost is determined by using the weighted-average cost method.
Property and Equipment
Property and equipment are carried at historical cost. Additions of new
equipment and major renewals and replacements of existing equipment are
capitalized. Repairs and minor replacements that do not materially increase
values or extend useful lives are expensed. Depreciation of property and
equipment is provided on a straight-line basis at rates based upon expected
useful lives of various classes of assets, as disclosed in Note 4. The rates
used for pipeline and storage facilities are the same as those which have been
promulgated by the Federal Energy Regulatory Commission. Upon disposal of assets
depreciated on an individual basis, the gains and losses are included in current
operating income. Upon disposal of assets depreciated on a group basis, unless
unusual in nature or amount, residual cost, less salvage, is charged against
accumulated depreciation.
Effective January 1, 2002, the Partnership adopted Statement of Financial
Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", which addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. The adoption of
SFAS No. 144 did not have a material impact on the consolidated financial
statements of the Partnership. Under SFAS No. 144, the carrying value of
property and equipment is periodically evaluated using undiscounted future cash
flows as the basis for determining if impairment exists. To the extent
impairment is indicated to exist, an impairment loss will be recognized based on
fair value.
Revenue and Income Recognition
The pipeline business provides pipeline transportation of refined
petroleum products, liquified petroleum gases, and anhydrous ammonia fertilizer.
Pipeline revenues are recognized as services are provided. The Partnership's
terminaling services business provides terminaling and other ancillary services.
Storage fees are generally billed one month in advance and are reported as
deferred income. Terminaling revenues are recognized in the month services are
provided. Revenues for the product sales business are recognized when product is
sold and title and risk pass to the customer.
Foreign Currency Translation
The Partnership translates the balance sheet of its foreign subsidiaries
using year-end exchange rates and translates income statement amounts using the
average exchange rates in effect during the year. The gains and losses resulting
from the change in exchange rates from year to year have been reported
separately as a component of accumulated other comprehensive income (loss) in
Partners' Capital. Gains and losses resulting from foreign currency transactions
are included in the consolidated statements of income. The local currency is
considered to be the functional currency, except in the Netherland Antilles and
Canada, where the U.S. dollar is the functional currency.
Excess of Cost Over Fair Value of Net Assets of Acquired Business
Effective January 1, 2002, the Partnership adopted SFAS No. 142,
"Goodwill and Other Intangible Assets," which eliminates the amortization of
goodwill (excess of cost over fair value of net assets of acquired business) and
other intangible assets with indefinite lives. Under SFAS No. 142, intangible
assets with lives restricted by contractual, legal, or other means will continue
to be amortized over their useful lives. At December 31, 2003, the Partnership
had no intangible assets subject to amortization under SFAS No. 142. Goodwill
and other intangible assets not subject to amortization are tested for
impairment annually or more frequently if events or changes in circumstances
indicate that the assets might be impaired. SFAS No. 142 requires a two-step
process for testing impairment. First, the fair value of each reporting unit is
compared to its carrying value to determine whether an indication of impairment
exists. If an impairment is indicated, then the fair value of the reporting
unit's goodwill is determined by allocating the unit's fair value to its assets
and liabilities (including any unrecognized intangible assets) as if the
reporting unit had been acquired in a business combination. The amount of
impairment for goodwill is measured as the excess of its carrying value over its
fair value. Based on valuations and analysis performed by the Partnership at
initial adoption date and at December 31, 2003, the Partnership determined that
the implied fair value of its goodwill exceeded carrying value and, therefore,
no impairment charge was necessary. Goodwill amortization included in the
results of operations of the Partnership for the year ended December 31, 2001
was not material.
Environmental Matters
Environmental expenditures that relate to current operations are expensed
or capitalized, as appropriate. Expenditures that relate to an existing
condition caused by past operations, and which do not contribute to current or
future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or remedial efforts are probable, and the costs
can be reasonably estimated. Generally, the timing of these accruals coincides
with the completion of a feasibility study or the Partnership's commitment to a
formal plan of action.
Asset Retirement Obligations
Effective January 1, 2003, the Partnership adopted SFAS No. 143
"Accounting for Asset Retirement Obligations", which establishes requirements
for the removal-type costs associated with asset retirements. At the initial
adoption date of SFAS No. 143, the Partnership recorded an asset retirement
obligation of approximately $5.5 million and recognized a cumulative effect of
change in accounting principle of $1.6 million for its legal obligations to
dismantle, dispose of, and restore certain leased pipeline and terminaling
facilities, including petroleum and chemical storage tanks, terminaling
facilities and barges. The Partnership did not record a retirement obligation
for certain of its pipeline and terminaling assets because sufficient
information is presently not available to estimate a range of potential
settlement dates for the obligation. In these cases, the obligation will be
initially recognized in the period in which sufficient information exists to
estimate the obligation. At December 31, 2003, the Partnership had no assets
which were legally restricted for purposes of settling asset retirement
obligations. The effect of SFAS No. 143, assuming adoption on January 1, 2001,
was not material to the results of operations of the Partnership for the years
ended December 31, 2003, 2002 and 2001. In 2003, accretion expense of $0.4
million was included in operating costs.
Comprehensive Income
The Partnership follows the provisions of SFAS No. 130, "Reporting
Comprehensive Income", for the reporting and display of comprehensive income and
its components in a full set of general purpose financial statements. SFAS No.
130 requires additional disclosure and does not affect the Partnership's
financial position or results of operations.
Income Taxes
Income (loss) before income tax expense and extraordinary items, is made
up of the following components:
Year Ended December 31,
---------------------------------------------------------
2003 2002 2001
------------- ------------- --------------
Partnership operations........................ $ 71,104,000 $ 71,614,000 $ 62,650,000
Corporate operations:
Domestic................................. (3,055,000) 2,046,000 (1,594,000)
Foreign.................................. 21,956,000 4,239,000 3,989,000
------------- ------------- --------------
$ 90,005,000 $ 77,899,000 $ 65,045,000
============= ============= ==============
Partnership operations are not subject to federal or state income taxes.
However, certain operations of terminaling operations are conducted through
wholly-owned corporate subsidiaries which are taxable entities. The provision
for income taxes for the periods ended December 31, 2003, 2002 and 2001
primarily consists of U.S. and foreign income taxes of $5.2 million, $4.1
million and $0.3 million, respectively. The net deferred tax liability of $20.6
million and $17.8 million at December 31, 2003 and 2002, respectively, consists
of deferred tax liabilities of $48.8 million and $41.7 million, respectively,
and deferred tax assets of $28.2 million and $23.9 million, respectively. The
deferred tax liabilities consist primarily of tax depreciation in excess of book
depreciation and the deferred tax assets consist primarily of net operating loss
carryforwards. The U.S. corporate operations have net operating loss
carryforwards for tax purposes totaling approximately $43.1 million which are
subject to various limitations on use and expire in years 2008 through 2023.
On June 1, 1989, the governments of the Netherlands Antilles and St.
Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January
1, 1989, which expired on December 31, 2000. This agreement requires a
subsidiary of the Partnership, which was acquired with Statia on February 28,
2002 (see Note 3), to pay a 2% rate on taxable income, as defined therein, or a
minimum payment of 500,000 Netherlands Antilles guilders ($0.3 million) per
year. The agreement further provides that any amounts paid in order to meet the
minimum annual payment will be available to offset future tax liabilities under
the agreement to the extent that the minimum annual payment is greater than 2%
of taxable income. The subsidiary is currently engaged in discussions with
representatives appointed by the Island Territory of St. Eustatius regarding the
renewal or modification of the agreement, but the ultimate outcome cannot be
predicted at this time. The subsidiary has accrued amounts assuming a new
agreement becomes effective, and continues to make payments, as required, under
the previous agreement.
Since the income or loss of the operations which are conducted through
limited partnerships will be included in the tax returns of the individual
partners of the Partnership, no provision for income taxes has been recorded in
the accompanying financial statements on these earnings. The tax returns of the
Partnership are subject to examination by federal and state taxing authorities.
If any such examination results in adjustments to distributive shares of taxable
income or loss, the tax liability of the partners would be adjusted accordingly.
The tax attributes of the Partnership's net assets flow directly to each
individual partner. Individual partners will have different investment bases
depending upon the timing and prices of acquisition of Partnership units.
Further, each partner's tax accounting, which is partially dependent upon their
individual tax position, may differ from the accounting followed in the
financial statements. Accordingly, there could be significant differences
between each individual partner's tax basis and their proportionate share of the
net assets reported in the financial statements. SFAS No. 109, "Accounting for
Income Taxes," requires disclosure of the aggregate difference in the basis of
its net assets for financial and tax reporting purposes. Management of the
Partnership does not believe that, in the Partnership's circumstances, the
aggregate difference would be meaningful information.
Cash Distributions
The Partnership makes regular cash distributions in accordance with its
Partnership agreement within 45 days after the end of each quarter to limited
partner and general partner interests. Aggregate distributions of $98.2 million,
$74.4 million and $62.2 million, were paid to limited partner interests and
general partner interests in 2003, 2002 and 2001, respectively.
Derivative Instruments
Effective January 1, 2001, the Partnership adopted the provisions of SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities", which
establishes the accounting and reporting standards for such activities. Under
SFAS No. 133, companies must recognize all derivative instruments on their
balance sheet at fair value. Changes in the value of derivative instruments,
which are considered hedges, are offset against the change in fair value of the
hedged item through earnings, or recognized in other comprehensive income until
the hedged item is recognized in earnings, depending on the nature of the hedge.
SFAS No. 133 requires that unrealized gains and losses on derivatives not
qualifying for hedge accounting be recognized currently in earnings. On January
1, 2001, the Partnership was not a party to any derivative contracts and,
accordingly, initial adoption of SFAS No. 133 at that date did not have any
effect on the Partnership's result of operations or financial position.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior
unsecured notes due June 1, 2013 (see Note 5.) In connection with the offering,
on May 8, 2003, the Partnership entered into a treasury lock contract for the
purpose of locking in the US Treasury interest rate component on $100 million of
the debt. The treasury lock contract, which qualified as a cash flow hedging
instrument under SFAS No. 133, was settled on May 19, 2003 with a cash payment
by the Partnership of $1.8 million. The settlement cost of the contract has been
recorded as a component of accumulated other comprehensive income and is being
amortized, as interest expense, over the life of the debt. For the year ended
December 31, 2003, $0.1 million of amortization is included in interest expense.
In September of 2002, the Partnership entered into a treasury lock
contract, maturing on November 4, 2002, for the purpose of locking in the US
Treasury interest rate component on $150 million of anticipated thirty-year
public debt offerings. The treasury lock contract originally qualified as a cash
flow hedging instrument under SFAS No. 133. In October of 2002, the Partnership,
due to various market factors, elected to defer issuance of the public debt
securities, effectively eliminating the cash flow hedging designation for the
treasury lock contract. On October 29, 2002, the contract was settled resulting
in a net realized gain of $3.0 million, which was recognized as a component of
interest and other income.
In March of 2001, the Partnership entered into two contracts for the
purpose of locking in interest rates on $100 million of anticipated ten-year
public debt offerings. As the interest rate locks were not designated as hedging
instruments pursuant to the requirements of SFAS No. 133, increases or decreases
in the fair value of the contracts were included as a component of interest and
other income. On May 22, 2001, the contracts were settled resulting in a gain of
$3.8 million, which is included in interest and other income in 2001.
Estimates
The preparation of the Partnership's financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
Recent Accounting Pronouncements
Effective January 1, 2003, the Partnership adopted SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities", which
requires that all restructurings initiated after December 31, 2002 be recorded
when they are incurred and can be measured at fair value. The initial adoption
of SFAS No. 146 had no effect on the consolidated financial statements of the
Partnership.
The Partnership has adopted the provisions of FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements of Guarantees, Including
Indirect Guarantees of Indebtedness to Others, an interpretation of FASB
Statements No. 5, 57, and 107, and a rescission of FASB Interpretation No. 34."
This interpretation elaborates on the disclosures to be made by a guarantor in
its interim and annual financial statements about its obligations under
guarantees issued. The interpretation also clarifies that a guarantor is
required to recognize, at inception of a guarantee, a liability for the fair
value of the obligation undertaken. The initial recognition and measurement
provisions of the interpretation are applicable to guarantees issued or modified
after December 31, 2002. The initial application of this interpretation had no
effect on the consolidated financial statements of the Partnership.
In December 2003, the FASB issued Interpretation No. 46 (Revised December
2003), "Consolidation of Variable Interest Entities (FIN 46R), primarily to
clarify the required accounting for interests in variable interest entities
(VIEs). This standard replaces FASB Interpretation No. 46, Consolidation of
Variable Interest Entities, that was issued in January 2003 to address certain
situations in which a company should include in its financial statements the
assets, liabilities and activities of another entity. For the Partnership,
application of FIN 46R is required for interests in certain VIEs that are
commonly referred to as special-purpose entities, or SPEs, as of December 31,
2003 and for interests in all other types of VIEs as of March 31, 2004. The
application of FIN 46R has not and is not expected to have a material impact on
the consolidated financial statements of the Partnership.
The Partnership has adopted the provisions of SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities", which amends
and clarifies financial accounting and reporting for derivative instruments and
hedging activities. The adoption of SFAS No. 149, which was effective for
derivative contracts and hedging relationships entered into or modified after
June 30, 2003, had no impact on the Partnership's consolidated financial
statements.
On July 1, 2003, the Partnership adopted SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity", which requires certain financial instruments, which were previously
accounted for as equity, to be classified as liabilities. The adoption of SFAS
No. 150 had no effect on the consolidated financial statements of the
Partnership.
3. ACQUISITIONS
On December 24, 2002, the Partnership acquired a 400-mile petroleum
products pipeline and four terminals in North Dakota and Minnesota from Tesoro
Refining and Marketing Company for approximately $100 million in cash, subject
to normal post-closing adjustments. The acquisition was initially funded with
bank debt (see Note 5). Based on the evaluations performed, no amounts were
assigned to goodwill or to other intangible assets in the purchase price
allocation.
On November 1, 2002, the Partnership acquired an approximately 2,000-mile
anhydrous ammonia pipeline system from Koch Pipeline Company, L.P. for
approximately $139 million in cash. This fertilizer pipeline system originates
in southern Louisiana, proceeds north through Arkansas and Missouri, and then
branches east into Illinois and Indiana and north and west into Iowa and
Nebraska. The acquisition was initially funded with bank debt (see Note 5). The
results of operations and cash flows of the acquired business are included in
the consolidated financial statements of the Partnership since the date of
acquisition. Based on the evaluations performed, no amounts were assigned to
goodwill or to other intangible assets in the purchase price allocation.
On September 18, 2002, the Partnership acquired eight bulk liquid storage
terminals in Australia and New Zealand from Burns Philp & Co. Ltd. for
approximately $47 million in cash. The results of operations and cash flows of
the acquired business are included in the consolidated financial statements of
the Partnership since the date of acquisition. Based on the evaluations
performed, no amounts were assigned to goodwill or to other intangible assets in
the purchase price allocation.
On February 28, 2002, the Partnership acquired all of the liquids
terminaling subsidiaries of Statia Terminals Group NV ("Statia") for
approximately $178 million in cash (net of acquired cash). The acquired Statia
subsidiaries had approximately $107 million in outstanding debt, including $101
million of 11.75% notes due in November 2003. The cash portion of the purchase
price was initially funded by the Partnership's revolving credit agreement and
proceeds from the Partnership's February 2002 public debt offering (see Note 5).
In April of 2002, the Partnership redeemed all of Statia's 11.75% notes at
102.938% of the principal amount, plus accrued interest. The redemption was
funded by the Partnership's revolving credit facility (see Note 5). Under the
provisions of the 11.75% notes, the Partnership incurred a $3.0 million
prepayment penalty, of which $2.0 million was recognized as loss on debt
extinguishment in 2002.
The results of operations and cash flows of Statia are included in the
consolidated financial statements of the Partnership since the date of
acquisition. Based on the valuations performed, no amounts were assigned to
goodwill or to other tangible assets. A summary of the allocation of the Statia
purchase price, net of cash acquired, is as follows:
Current assets......................................... $ 10,898,000
Property and equipment................................. 320,008,000
Other assets........................................... 53,000
Current liabilities.................................... (39,052,000)
Long-term debt......................................... (107,746,000)
Other liabilities...................................... (5,957,000)
-------------
Purchase price..................................... $ 178,204,000
=============
Assuming the Statia acquisition occurred on January 1, 2001, unaudited
pro forma revenues and net income would have been $411.3 million and $72.8
million, respectively, for the year ended December 31, 2002, and $410.0 million
and $63.9 million, respectively, for the year ended December 31, 2001.
On January 3, 2001, the Partnership acquired Shore Terminals LLC
("Shore") for $107 million in cash and 1,975,090 KPP limited partnership units
(valued at $56.5 million on the date of agreement and its announcement).
Financing for the cash portion of the purchase price was initially supplied by
the Partnership's revolving credit facility (see Note 5). The acquisition was
accounted for using the purchase method of accounting.
4. PROPERTY AND EQUIPMENT
The cost of property and equipment is summarized as follows:
Estimated
Useful December 31,
Life --------------------------------------
(Years) 2003 2002
-------------- ------------------ -----------------
Land...................................... - $ 75,912,000 $ 72,152,000
Buildings................................. 25 - 35 36,229,000 27,559,000
Pipeline and terminaling equipment........ 15 - 40 1,115,458,000 1,067,794,000
Marine equipment.......................... 15 - 30 87,204,000 84,641,000
Furniture and fixtures.................... 5 - 15 11,388,000 7,892,000
Transportation equipment.................. 3 - 6 7,360,000 5,414,000
Construction work-in-progress............. - 26,768,000 23,310,000
------------------ -----------------
Total property and equipment.............. 1,360,319,000 1,288,762,000
Less accumulated depreciation............. 247,349,000 196,570,000
------------------ -----------------
Net property and equipment................ $ 1,112,970,000 $ 1,092,192,000
================== =================
5. LONG-TERM DEBT
Long-term debt is summarized as follows:
December 31,
-------------------------------------
2003 2002
--------------- --------------
$400 million revolving credit facility, due in April of 2006........ $ 54,169,000 $ -
$250 million 5.875% senior unsecured notes, due in June of 2013..... 250,000,000 -
$250 million 7.75% senior unsecured notes, due in February of 2012.. 250,000,000 250,000,000
$275 million revolving credit facility, repaid in April of 2003..... - 243,000,000
Bank bridge facility, repaid in April of 2003....................... - 175,000,000
Term loans, due in April of 2006.................................... 29,243,000 26,330,000
Australian bank facility, due in April of 2006...................... 34,284,000 -
--------------- --------------
Total long-term debt................................................ $ 617,696,000 $ 694,330,000
=============== ==============
In April of 2003, the Partnership entered into a new credit agreement
with a group of banks that provides for a $400 million unsecured revolving
credit facility through April of 2006. The credit facility, which provides for
an increase in the commitment up to an aggregate of $450 million by mutual
agreement between the Partnership and the banks, bears interest at variable
rates and has a variable commitment fee on unused amounts. The credit facility
contains certain financial and operating covenants, including limitations on
investments, sales of assets and transactions with affiliates and, absent an
event of default, does not restrict distributions to partners. At December 31,
2003, the Partnership was in compliance with all covenants. Initial borrowings
on the credit agreement ($324.2 million) were used to repay all amounts
outstanding under the Partnership's $275 million credit agreement and $175
million bridge loan agreement. At December 31, 2003, $54.2 million was
outstanding under the new credit agreement.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior
unsecured notes due June 1, 2013. The net proceeds from the public offering,
$247.6 million, were used to reduce amounts due under the revolving credit
agreement. Under the note indenture, interest is payable semi-annually in
arrears on June 1 and December 1 of each year. The notes are redeemable, as a
whole or in part, at the option of the Partnership, at any time, at a redemption
price equal to the greater of 100% of the principal amount of the notes, or the
sum of the present value of the remaining scheduled payments of principal and
interest, discounted to the redemption date at the applicable U.S. Treasury
rate, as defined in the indenture, plus 30 basis points. The note indenture
contains certain financial and operational covenants, including certain
limitations on investments, sales of assets and transactions with affiliates
and, absent an event of default, such covenants do not restrict distributions to
partners. At December 31, 2003, the Partnership was in compliance with all
covenants.
In February of 2002, the Partnership issued $250 million of 7.75% senior
unsecured notes due February 15, 2012. The net proceeds from the public
offering, $248.2 million, were used to repay the Partnership's revolving credit
agreement and to partially fund the Statia acquisition (see Note 3). Under the
note indenture, interest is payable semi-annually in arrears on February 15 and
August 15 of each year. The notes are redeemable, as a whole or in part, at the
option of the Partnership, at any time, at a redemption price equal to the
greater of 100% of the principal amount of the notes, or the sum of the present
value of the remaining scheduled payments of principal and interest, discounted
to the redemption date at the applicable U.S. Treasury rate, as defined in the
indenture, plus 30 basis points. The note indenture contains certain financial
and operational covenants, including certain limitations on investments, sales
of assets and transactions with affiliates and, absent an event of default, such
covenants do not restrict distributions to partners. At December 31, 2003, the
Partnership was in compliance with all covenants.
In January of 2001, the Partnership used proceeds from its revolving
credit agreement to repay in full its $128 million of mortgage notes. Under the
provisions of the mortgage notes, the Partnership incurred a $6.5 million
prepayment penalty, which was recognized as loss on debt extinguishment in 2001.
6. COMMITMENTS AND CONTINGENCIES
The following is a schedule by years of future minimum lease payments
under operating leases as of December 31, 2003:
Year ending December 31:
2004...................................... $ 4,325,000
2005...................................... 2,028,000
2006...................................... 1,678,000
2007...................................... 1,416,000
2008...................................... 934,000
Thereafter................................ 342,000
--------------
Total minimum lease payments.................... $ 10,723,000
==============
Total rent expense under operating leases amounted to $14.5 million, $9.4
million and $4.2 million for the years ended December 31, 2003, 2002 and 2001,
respectively.
The operations of the Partnership are subject to federal, state and local
laws and regulations in the United States and the various foreign locations
relating to protection of the environment. Although the Partnership believes its
operations are in general compliance with applicable environmental regulations,
risks of additional costs and liabilities are inherent in pipeline and terminal
operations, and there can be no assurance that significant costs and liabilities
will not be incurred by the Partnership. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property or persons
resulting from the operations of the Partnership, could result in substantial
costs and liabilities to the Partnership. The Partnership has recorded an
undiscounted reserve for environmental claims in the amount of $28.6 million at
December 31, 2003, including $25.5 million related to acquisitions of pipelines
and terminals. During 2003, 2002 and 2001, respectively, the Partnership
incurred $2.1 million, $2.4 million and $5.2 million of costs related to such
acquisition reserves and reduced the liability accordingly.
KPL has indemnified the Partnership against liabilities for damage to the
environment resulting from operations of the pipeline prior to October 3, 1989
(the date of formation of the Partnership). The indemnification does not extend
to any liabilities that arise after such date to the extent that the liabilities
result from changes in environmental laws and regulations.
Certain subsidiaries of the Partnership were sued in a Texas state court
in 1997 by Grace Energy Corporation ("Grace"), the entity from which the
Partnership acquired ST Services in 1993. The lawsuit involves environmental
response and remediation costs allegedly resulting from jet fuel leaks in the
early 1970's from a pipeline. The pipeline, which connected a former Grace
terminal with Otis Air Force Base in Massachusetts (the "Otis pipeline" or the
"pipeline"), ceased operations in 1973 and was abandoned before 1978, when the
connecting terminal was sold to an unrelated entity. Grace alleged that
subsidiaries of the Partnership acquired the abandoned pipeline, as part of the
acquisition of ST Services in 1993 and assumed responsibility for environmental
damages allegedly caused by the jet fuel leaks. Grace sought a ruling from the
Texas court that these subsidiaries are responsible for all liabilities,
including all present and future remediation expenses, associated with these
leaks and that Grace has no obligation to indemnify these subsidiaries for these
expenses. In the lawsuit, Grace also sought indemnification for expenses of
approximately $3.5 million that it incurred since 1996 for response and
remediation required by the State of Massachusetts and for additional expenses
that it expects to incur in the future. The consistent position of the
Partnership's subsidiaries has been that they did not acquire the abandoned
pipeline as part of the 1993 ST Services transaction, and therefore did not
assume any responsibility for the environmental damage nor any liability to
Grace for the pipeline.
At the end of the trial, the jury returned a verdict including findings
that (1) Grace had breached a provision of the 1993 acquisition agreement by
failing to disclose matters related to the pipeline, and (2) the pipeline was
abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired
ST Services. On August 30, 2000, the Judge entered final judgment in the case
that Grace take nothing from the subsidiaries on its claims seeking recovery of
remediation costs. Although the Partnership's subsidiaries have not incurred any
expenses in connection with the remediation, the court also ruled, in effect,
that the subsidiaries would not be entitled to indemnification from Grace if any
such expenses were incurred in the future. Moreover, the Judge let stand a prior
summary judgment ruling that the pipeline was an asset acquired by the
Partnership's subsidiaries as part of the 1993 ST Services transaction and that
any liabilities associated with the pipeline would have become liabilities of
the subsidiaries. Based on that ruling, the Massachusetts Department of
Environmental Protection and Samson Hydrocarbons Company (successor to Grace
Petroleum Company) wrote letters to ST Services alleging its responsibility for
the remediation, and ST Services responded denying any liability in connection
with this matter. The Judge also awarded attorney fees to Grace of more than
$1.5 million. Both the Partnership's subsidiaries and Grace have appealed the
trial court's final judgment to the Texas Court of Appeals in Dallas. In
particular, the subsidiaries have filed an appeal of the judgment finding that
the Otis pipeline and any liabilities associated with the pipeline were
transferred to them as well as the award of attorney fees to Grace.
On April 2, 2001, Grace filed a petition in bankruptcy, which created an
automatic stay against actions against Grace. This automatic stay covers the
appeal of the Dallas litigation, and the Texas Court of Appeals has issued an
order staying all proceedings of the appeal because of the bankruptcy. Once that
stay is lifted, the Partnership's subsidiaries that are party to the lawsuit
intend to resume vigorous prosecution of the appeal.
The Otis Air Force Base is a part of the Massachusetts Military
Reservation ("MMR Site"), which has been declared a Superfund Site pursuant to
CERCLA. The MMR Site contains a number of groundwater contamination plumes, two
of which are allegedly associated with the Otis pipeline, and various other
waste management areas of concern, such as landfills. The United States
Department of Defense, pursuant to a Federal Facilities Agreement, has been
responding to the Government remediation demand for most of the contamination
problems at the MMR Site. Grace and others have also received and responded to
formal inquiries from the United States Government in connection with the
environmental damages allegedly resulting from the jet fuel leaks. The
Partnership's subsidiaries voluntarily responded to an invitation from the
Government to provide information indicating that they do not own the pipeline.
In connection with a court-ordered mediation between Grace and the Partnership's
subsidiaries, the Government advised the parties in April 1999 that it has
identified two spill areas that it believes to be related to the pipeline that
is the subject of the Grace suit. The Government at that time advised the
parties that it believed it had incurred costs of approximately $34 million, and
expected in the future to incur costs of approximately $55 million, for
remediation of one of the spill areas. This amount was not intended to be a
final accounting of costs or to include all categories of costs. The Government
also advised the parties that it could not at that time allocate its costs
attributable to the second spill area.
By letter dated July 26, 2001, the United States Department of Justice
("DOJ") advised ST Services that the Government intends to seek reimbursement
from ST Services under the Massachusetts Oil and Hazardous Material Release
Prevention and Response Act and the Declaratory Judgment Act for the
Government's response costs at the two spill areas discussed above. The DOJ
relied in part on the Texas state court judgment, which in the DOJ's view, held
that ST Services was the current owner of the pipeline and the
successor-in-interest of the prior owner and operator. The Government advised ST
Services that it believes it has incurred costs exceeding $40 million, and
expects to incur future costs exceeding an additional $22 million, for
remediation of the two spill areas. The Partnership believes that its
subsidiaries have substantial defenses. ST Services responded to the DOJ on
September 6, 2001, contesting the Government's positions and declining to
reimburse any response costs. The DOJ has not filed a lawsuit against ST
Services seeking cost recovery for its environmental investigation and response
costs. Representatives of ST Services have met with representatives of the
Government on several occasions since September 6, 2001 to discuss the
Government's claims and to exchange information related to such claims.
Additional exchanges of information are expected to occur in the future and
additional meetings may be held to discuss possible resolution of the
Government's claims without litigation. The Partnership does not believe this
matter will have a materially adverse effect on its financial condition,
although there can be no assurances as to the ultimate outcome.
On April 7, 2000, a fuel oil pipeline in Maryland owned by Potomac
Electric Power Company ("PEPCO") ruptured. Work performed with regard to the
pipeline was conducted by a partnership of which ST Services is general partner.
PEPCO has reported that it has incurred total cleanup costs of $70 million to
$75 million. PEPCO probably will continue to incur some cleanup related costs
for the foreseeable future, primarily in connection with EPA requirements for
monitoring the condition of some of the impacted areas. Since May 2000, ST
Services has provisionally contributed a minority share of the cleanup expense,
which has been funded by ST Services' insurance carriers. ST Services and PEPCO
have not, however, reached a final agreement regarding ST Services'
proportionate responsibility for this cleanup effort, if any, and cannot predict
the amount, if any, that ultimately may be determined to be ST Services' share
of the remediation expense, but ST believes that such amount will be covered by
insurance and therefore will not materially adversely affect the Partnership's
financial condition.
As a result of the rupture, purported class actions were filed against
PEPCO and ST Services in federal and state court in Maryland by property and
business owners alleging damages in unspecified amounts under various theories,
including under the Oil Pollution Act ("OPA") and Maryland common law. The
federal court consolidated all of the federal cases in a case styled as In re
Swanson Creek Oil Spill Litigation. A settlement of the consolidated class
action, and a companion state-court class action, was reached and approved by
the federal judge. The settlement involved creation and funding by PEPCO and ST
Services of a $2,250,000 class settlement fund, from which all participating
claimants would be paid according to a court-approved formula, as well as a
court-approved payment to plaintiffs' attorneys. The settlement has been
consummated and the fund, to which PEPCO and ST Services contributed equal
amounts, has been distributed. Participating claimants' claims have been settled
and dismissed with prejudice. A number of class members elected not to
participate in the settlement, i.e., to "opt out," thereby preserving their
claims against PEPCO and ST Services. All non-participant claims have been
settled for immaterial amounts with ST Services' portion of such settlements
provided by its insurance carrier.
PEPCO and ST Services agreed with the federal government and the State of
Maryland to pay costs of assessing natural resource damages arising from the
Swanson Creek oil spill under OPA and of selecting restoration projects. This
process was completed in mid-2002. ST Services' insurer has paid ST Services'
agreed 50 percent share of these assessment costs. In late November 2002, PEPCO
and ST Services entered into a Consent Decree resolving the federal and state
trustees' claims for natural resource damages. The decree required payments by
ST Services and PEPCO of a total of approximately $3 million to fund the
restoration projects and for remaining damage assessment costs. The federal
court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO
and ST have each paid their 50% share and thus fully performed their payment
obligations under the Consent Decree. ST Services' insurance carrier funded ST
Services' payment.
The U.S. Department of Transportation ("DOT") has issued a Notice of
Proposed Violation to PEPCO and ST Services alleging violations over several
years of pipeline safety regulations and proposing a civil penalty of $647,000
jointly against the two companies. ST Services and PEPCO have contested the DOT
allegations and the proposed penalty. A hearing was held before the Office of
Pipeline Safety at the DOT in late 2001. ST Services does not anticipate any
further hearings on the subject and is still awaiting the DOT's ruling.
By letter dated January 4, 2002, the Attorney General's Office for the
State of Maryland advised ST Services that it intended to seek penalties from ST
Services in connection with the April 7, 2000 spill. The State of Maryland
subsequently asserted that it would seek penalties against ST Services and PEPCO
totaling up to $12 million. A settlement of this claim was reached in mid-2002
under which ST Services' insurer will pay a total of slightly more than $1
million in installments over a five year period. PEPCO has also reached a
settlement of these claims with the State of Maryland. Accordingly, the
Partnership believes that this matter will not have a material adverse effect on
its financial condition.
On December 13, 2002, ST Services sued PEPCO in the Superior Court,
District of Columbia, seeking, among other things, a declaratory judgment as to
ST Services' legal obligations, if any, to reimburse PEPCO for costs of the oil
spill. On December 16, 2002, PEPCO sued ST Services in the United States
District Court for the District of Maryland, seeking recovery of all its costs
for remediation of and response to the oil spill. Pursuant to an agreement
between ST Services and PEPCO, ST Services' suit was dismissed, subject to
refiling. ST Services has moved to dismiss PEPCO's suit. ST Services is
vigorously defending against PEPCO's claims and is pursuing its own
counterclaims for return of monies ST Services has advanced to PEPCO for
settlements and cleanup costs. The Partnership believes that any costs or
damages resulting from these lawsuits will be covered by insurance and therefore
will not materially adversely affect the Partnership's financial condition. The
amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy
which has a $600,000 retention, but the Partnership does not believe that such
retention, if incurred, would materially adversely affect the Partnership's
financial condition.
The Partnership has other contingent liabilities resulting from
litigation, claims and commitments incident to the ordinary course of business.
Management of the Partnership believes, based on the advice of counsel, that the
ultimate resolution of such contingencies will not have a materially adverse
effect on the financial position, results of operations or liquidity of the
Partnership.
7. RELATED PARTY TRANSACTIONS
The Partnership has no employees and is managed and controlled by KPL.
KPL and KSL are entitled to reimbursement of all direct and indirect costs
related to the business activities of the Partnership. These costs, which
totaled $36.3 million, $27.3 million and $18.1 million for the years ended
December 31, 2003, 2002 and 2001, respectively, include compensation and
benefits paid to officers and employees of KPL and KSL, insurance premiums,
general and administrative costs, tax information and reporting costs, legal and
audit fees. Included in this amount is $26.6 million, $17.7 million and $14.3
million of compensation and benefits, paid to officers and employees of KPL and
KSL for the years ended December 31, 2003, 2002 and 2001, respectively. In
addition, the Partnership paid $0.6 million in 2003, $0.6 million in 2002 and
$0.5 million in 2001 for an allocable portion of KPL's overhead expenses. At
December 31, 2003 and 2002, the Partnership owed KPL and KSL $3.6 million and
$5.4 million, respectively, for these expenses which are due under normal
invoice terms.
8. BUSINESS SEGMENT DATA
The Partnership conducts business through three principal segments; the
"Pipeline Operations," which consists primarily of the transportation of refined
petroleum products and fertilizer in the Midwestern states as a common carrier,
the "Terminaling Operations," which provides storage for petroleum products,
specialty chemicals and other liquids, and the "Product Sales Operations", which
delivers bunker fuel to ships in the Caribbean and Nova Scotia, Canada and sells
bulk petroleum products to various commercial interests.
The Partnership measures segment profit as operating income. Total assets
are those assets controlled by each reportable segment. Business segment data is
as follows:
Year Ended December 31,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Business segment revenues:
Pipeline operations.................................. $ 119,633,000 $ 82,698,000 $ 74,976,000
Terminaling operations............................... 234,958,000 205,971,000 132,820,000
Product sales operations............................. 215,823,000 97,961,000 -
---------------- --------------- --------------
$ 570,414,000 $ 386,630,000 $ 207,796,000
================ =============== ==============
Business segment profit:
Pipeline operations.................................. $ 51,860,000 $ 38,623,000 $ 36,773,000
Terminaling operations............................... 66,532,000 65,040,000 45,318,000
Product sales operations............................. 10,109,000 2,058,000 -
---------------- --------------- --------------
Operating income.................................. 128,501,000 105,721,000 82,091,000
Interest and other income ........................... 261,000 3,570,000 4,277,000
Interest expense..................................... (38,757,000) (28,110,000) (14,783,000)
Loss on debt extinguishment.......................... - (3,282,000) (6,540,000)
---------------- --------------- --------------
Income before income taxes and cumulative effect
of change in accounting principle............... $ 90,005,000 $ 77,899,000 $ 65,045,000
================ =============== ==============
Business segment assets:
Depreciation and amortization:
Pipeline operations............................... $ 14,117,000 $ 6,408,000 $ 5,478,000
Terminaling operations............................ 38,089,000 32,368,000 17,706,000
Product sales operations.......................... 949,000 649,000 -
---------------- --------------- --------------
$ 53,155,000 $ 39,425,000 $ 23,184,000
================ =============== ==============
Capital expenditures (excluding acquisitions):
Pipeline operations............................... $ 9,584,000 $ 9,469,000 $ 4,309,000
Terminaling operations............................ 34,572,000 20,953,000 12,937,000
Product sales operations.......................... 585,000 679,000 -
---------------- --------------- --------------
$ 44,741,000 $ 31,101,000 $ 17,246,000
================ =============== ==============
December 31,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Total assets:
Pipeline operations................................ $ 352,901,000 $ 352,657,000 $ 105,156,000
Terminaling operations............................. 874,185,000 844,321,000 443,215,000
Product sales operations........................... 37,596,000 18,432,000 -
---------------- --------------- --------------
$ 1,264,682,000 $ 1,215,410,000 $ 548,371,000
================ =============== ==============
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,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Geographical area revenues:
United States........................................ $ 240,518,000 $ 202,124,000 $ 186,734,000
United Kingdom....................................... 26,392,000 23,937,000 21,062,000
Netherlands Antilles................................. 241,693,000 132,387,000 -
Canada............................................... 41,689,000 23,207,000 -
Australia and New Zealand............................ 20,122,000 4,975,000 -
---------------- --------------- --------------
$ 570,414,000 $ 386,630,000 $ 207,796,000
================ =============== ==============
Geographical area operating income:
United States........................................ $ 87,962,000 $ 82,906,000 $ 76,575,000
United Kingdom....................................... 8,583,000 7,318,000 5,516,000
Netherlands Antilles................................. 19,223,000 9,616,000 -
Canada............................................... 6,777,000 4,398,000 -
Australia and New Zealand............................ 5,956,000 1,483,000 -
---------------- --------------- --------------
$ 128,501,000 $ 105,721,000 $ 82,091,000
================ =============== ==============
December 31,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Geographical area net property and equipment:
United States........................................ $ 693,295,000 $ 690,178,000 $ 440,104,000
United Kingdom....................................... 51,392,000 46,543,000 41,170,000
Netherlands Antilles................................. 217,143,000 224,810,000 -
Canada............................................... 74,995,000 78,789,000 -
Australia and New Zealand............................ 76,145,000 51,872,000 -
---------------- --------------- --------------
$ 1,112,970,000 $ 1,092,192,000 $ 481,274,000
================ =============== ==============
9. FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK
The estimated fair value of all debt as of December 31, 2003 and 2002 was
approximately $630 million and $709 million, as compared to the carrying value
of $618 million and $694 million, respectively. These fair values were estimated
using discounted cash flow analysis, based on the Partnership's current
incremental borrowing rates for similar types of borrowing arrangements. These
estimates are not necessarily indicative of the amounts that would be realized
in a current market exchange. See Note 2 regarding derivative instruments.
The Partnership markets and sells its services to a broad base of
customers and performs ongoing credit evaluations of its customers. The
Partnership does not believe it has a significant concentration of credit risk
at December 31, 2003. No customer constituted 10 percent or more of consolidated
revenues in 2003, 2002 or 2001.
10. QUARTERLY FINANCIAL DATA (unaudited)
Quarterly operating results for 2003 and 2002 are summarized as follows:
Quarter Ended
--------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
---------------- ---------------- --------------- --------------
2003:
Revenues....................... $ 140,757,000 $ 146,948,000 $ 140,404,000 $ 142,305,000
================ ================ =============== ==============
Operating income............... $ 33,598,000 $ 33,041,000 $ 32,016,000 $ 29,846,000
================ ================ =============== ==============
Net income..................... $ 22,049,000(a) $ 22,829,000 $ 20,323,000 $ 17,988,000
================ ================ =============== ==============
2002:
Revenues....................... $ 67,642,000 $ 100,702,000 $ 103,304,000 $ 114,982,000
================ ================ =============== ==============
Operating income............... $ 23,225,000 $ 27,756,000 $ 27,870,000 $ 26,870,000
================ ================ =============== ==============
Net income..................... $ 17,416,000 $ 17,133,000(b) $ 19,491,000 $ 19,776,000(c)
================ ================ =============== ==============
(a) Includes cumulative effect of change in accounting principle - adoption
of new accounting standard for asset retirement obligations of
approximately $1.6 million in expense.
(b) Includes loss on debt extinguishment of approximately $1.9 million.
(c) Includes loss on debt extinguishment of approximately $1.2 million and
gain on interest rate lock transaction at approximately $3.0 million.
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, 2003:
For doubtful receivables
classified as current assets... $ 1,765 $ 401 $ - $ (473)(b) $ 1,693
============= =========== ============= ======== ==========
Year Ended December 31, 2002:
For doubtful receivables
classified as current assets... $ 278 $ 925 $ 841(a) $ (279)(b) $ 1,765
============= =========== ============= ======== ==========
Year Ended December 31, 2001:
For doubtful receivables
classified as current assets... $ 250 $ 124 $ - $ (96)(b) $ 278
============= =========== ============= ======== ==========
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 12, 2004
Pursuant to the requirements of the Securities and Exchange Act of
1934, this report has been signed below by the following persons on behalf of
Kaneb Pipe Line Operating Partnership, L.P. and in the capacities with Kaneb
Pipe Line Company LLC and on the date indicated.
Signature Title Date
- ---------------------------------------- --------------------------- --------------
Principal Executive Officer
//s// EDWARD D. DOHERTY Chairman of the Board March 12, 2004
- ---------------------------------------- and Chief Executive Officer
Principal Accounting Officer
//s// HOWARD C. WADSWORTH Vice President March 12, 2004
- ---------------------------------------- Treasurer & Secretary
Directors
//s// SANGWOO AHN Director March 12, 2004
- ----------------------------------------
//s// JOHN R. BARNES Director March 12, 2004
- ----------------------------------------
//s// MURRAY R. BILES Director March 12, 2004
- ----------------------------------------
//s// FRANK M. BURKE, JR. Director March 12, 2004
- ----------------------------------------
//s// CHARLES R. COX Director March 12, 2004
- ----------------------------------------
//s// HANS KESSLER Director March 12, 2004
- ----------------------------------------
//s// JAMES R. WHATLEY Director March 12, 2004
- ----------------------------------------
Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
----------------------------------------
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
---------------------------------------------------------
I, Edward D. Doherty, Chief Executive Officer of Kaneb Pipe Line Company LLC, as
General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:
1. I have reviewed this annual report on Form 10-K of Kaneb Pipe Line
Operating Partnership, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a) designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this annual report is being
prepared;
b) [intentionally omitted pursuant to SEC Release No. 34-47986];
c) evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this annual report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this annual report, based on such evaluation; and
d) disclosed in this annual report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting; and
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies and material weaknesses in the
design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal control over financial reporting.
Date: March 12, 2004
//s// EDWARD D. DOHERTY
--------------------------------------------
Edward D. Doherty
Chief Executive Officer
Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
----------------------------------------
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
---------------------------------------------------------
I, Howard C. Wadsworth, Chief Financial Officer of Kaneb Pipe Line Company LLC,
as General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:
1. I have reviewed this annual report on Form 10-K of Kaneb Pipe Line
Operating Partnership, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a) designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this annual report is being
prepared;
b) [intentionally omitted pursuant to SEC Release No. 34-47986];
c) evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this annual report
our conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this annual report, based on such evaluation; and
d) disclosed in this annual report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting; and
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies and material weaknesses in the
design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal control over financial reporting.
Date: March 12, 2004
//s// HOWARD C. WADSWORTH
-----------------------------------
Howard C. Wadsworth
Chief Financial Officer
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
----------------------------------------
PURSUANT TO SECTION 906(A) OF THE SARBANES-OXLEY ACT OF 2002
------------------------------------------------------------
The undersigned, being the Chief Executive Officer of Kaneb Pipe Line Company
LLC, as General Partner of Kaneb Pipe Line Operating Partnership, L.P. (the
"Partnership"), hereby certifies that, to his knowledge, the Partnership's
Annual Report on Form 10-K for the year ended December 31, 2003, filed with the
United States Securities and Exchange Commission pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully
complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and that information contained in such Annual Report fairly
presents, in all material respects, the financial condition and results of
operations of the Partnership.
This written statement is being furnished to the Securities and Exchange
Commission as an exhibit to such Form 10-K. A signed original of this written
statement required by Section 906 has been provided to Kaneb Pipe Line Operating
Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership,
L.P. and furnished to the Securities and Exchange Commission or its staff upon
request.
Date: March 12, 2004
//s// EDWARD D. DOHERTY
--------------------------------------------
Edward D. Doherty
Chief Executive Officer
Exhibit 32.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
----------------------------------------
PURSUANT TO SECTION 906(A) OF THE SARBANES-OXLEY ACT OF 2002
------------------------------------------------------------
The undersigned, being the Chief Financial Officer of Kaneb Pipe Line Company
LLC, as General Partner of Kaneb Pipe Line Operating Partnership, L.P. (the
"Partnership"), hereby certifies that, to his knowledge, the Partnership's
Annual Report on Form 10-K for the year ended December 31, 2003, filed with the
United States Securities and Exchange Commission pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully
complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and that information contained in such Annual Report fairly
presents, in all material respects, the financial condition and results of
operations of the Partnership.
This written statement is being furnished to the Securities and Exchange
Commission as an exhibit to such Form 10-K. A signed original of this written
statement required by Section 906 has been provided to Kaneb Pipe Line Operating
Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership,
L.P. and furnished to the Securities and Exchange Commission or its staff upon
request.
Date: March 12, 2004
//s// HOWARD C. WADSWORTH
-----------------------------------
Howard C. Wadsworth
Chief Financial Officer