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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, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number 333-44634
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
(Exact name of Registrant as specified in its Charter)
Delaware 75-2287683
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
2435 North Central Expressway
Richardson, Texas 75080
- --------------------------------------- --------------------------
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (972) 699-4062
Title of each class
7.75% Senior Unsecured Notes due 2012
5.875% Senior Unsecured Notes due 2013
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
------- ------
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Subsection 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. N/A
-----
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
Yes No X
------- -------
PART I
Item 1. Business
GENERAL
Kaneb Pipe Line Operating Partnership, L.P., a Delaware limited partnership
(the "Partnership"), is engaged in the refined petroleum products and anhydrous
ammonia pipeline business and the terminaling of petroleum products and
specialty liquids. Kaneb Pipe Line Partners, L.P. ("KPP") (NYSE: KPP), a master
limited partnership, holds a 99% interest as a limited partner in the
Partnership. Kaneb Pipe Line Company LLC, a Delaware limited liability company
("KPL"), a wholly-owned subsidiary of Kaneb Services LLC, a Delaware limited
liability company ("KSL") (NYSE: KSL), holds a 1% interest as general partner of
the Partnership and a 1% interest as general partner of KPP. The terminaling
business of the Partnership is conducted through Support Terminals Operating
Partnership, L.P. ("STOP"), and its affiliated partnerships and corporate
entities, which operate under the trade names "ST Services" and "StanTrans,"
among others; and Statia Terminals Holdings Company LLC and its subsidiary
entities ("Statia").
On October 31, 2004, Valero L.P. and KPP entered into a definitive
agreement to merge (the "KPP Merger") Valero L.P. and KPP. Under the terms of
the agreement, each holder of units of limited partnership interests in KPP will
receive a number of Valero L.P. common units based on an exchange ratio that
fluctuates within a fixed range to provide $61.50 in value of Valero L.P. units
for each unit of KPP. The actual exchange ratio will be determined at the time
of the closing of the proposed merger and is subject to a fixed value collar of
plus or minus five percent of Valero L.P.'s per unit price of $57.25 as of
October 7, 2004. Should Valero L.P.'s per unit price fall below $54.39 per unit,
the exchange ratio will remain fixed at 1.1307 Valero L.P. units for each unit
of KPP. Likewise, should Valero L.P.'s per unit price exceed $60.11 per unit of
KPP, the exchange ratio will remain fixed at 1.0231 Valero L.P. units for each
unit of KPP.
In a separate definitive agreement, on October 31, 2004, Valero L.P. agreed
to acquire by merger (the "KSL Merger") all of the outstanding common shares of
KSL for cash. Under the terms of that agreement, Valero L.P. is offering to
purchase all of the outstanding shares of KSL at $43.31 per share.
The completion of the KPP Merger is subject to the customary regulatory
approvals including those under the Hart-Scott-Rodino Antitrust Improvements
Act. The completion of the KPP Merger is also subject to completion of the KSL
Merger. All required unitholder and shareholder approvals have been obtained.
Upon completion of the mergers, the general partner of the combined partnership
will be owned by affiliates of Valero Energy Corporation and KPP and KSL will
become wholly owned subsidiaries of Valero L.P.
PIPELINE BUSINESS
Introduction
The Partnership's pipeline business consists primarily of the
transportation of refined petroleum products as a common carrier in Kansas,
Nebraska, Iowa, South Dakota, North Dakota, Colorado, Wyoming and Minnesota. On
December 24, 2002, the Partnership acquired the Northern Great Plains Product
System from Tesoro Refining and Marketing Company for approximately $100
million. This product pipeline system is now referred to as the Partnership's
North Pipeline. On November 1, 2002, the Partnership acquired a 2,000 mile
anhydrous ammonia pipeline from Koch Pipeline Company, LP and Koch Fertilizer
Storage and Terminal Company for approximately $139 million. The Partnership's
three refined petroleum products pipelines and the anhydrous ammonia pipeline
are described below.
East Pipeline
Construction of the East Pipeline commenced in 1953 with a line from
southern Kansas to Geneva, Nebraska. During subsequent years, the East Pipeline
was extended northward to its present terminus at Jamestown, North Dakota, west
to North Platte, Nebraska and east into the State of Iowa. The East Pipeline,
which moves refined products from south to north, now consists of 2,090 miles of
pipeline ranging in size from 6 inches to 16 inches.
The East Pipeline system also includes 17 product terminals in Kansas,
Nebraska, Iowa, South Dakota and North Dakota with total storage capacity of
approximately 3.5 million barrels and an additional 23 product tanks with total
storage capacity of approximately 1,082,555 barrels at its tank farm
installations at McPherson and El Dorado, Kansas. The system also has six origin
pump stations in Kansas and 38 booster pump stations throughout the system.
Additionally, the system maintains various office and warehouse facilities, and
an extensive quality control laboratory.
The East Pipeline transports refined petroleum products, including propane,
received from refineries in southeast Kansas and other connecting pipelines to
its terminals along the system and to receiving pipeline connections in Kansas.
Shippers on the East Pipeline obtain refined petroleum products from refineries
connected to the East Pipeline or through other pipelines directly connected to
the pipeline system. Five connecting pipelines can deliver propane for shipment
through the East Pipeline from gas processing plants in Texas, New Mexico,
Oklahoma and Kansas.
Much of the refined petroleum products delivered through the East Pipeline
are ultimately used as fuel for railroads or in agricultural operations,
including fuel for farm equipment, irrigation systems, trucks used for
transporting crops and crop drying facilities. Demand for refined petroleum
products for agricultural use, and the relative mix of products required, is
affected by weather conditions in the markets served by the East Pipeline.
Government agricultural policies and crop prices also affect the agricultural
sector. Although periods of drought suppress agricultural demand for some
refined petroleum products, particularly those used for fueling farm equipment,
the demand for fuel for irrigation systems often increases during such times.
The mix of refined petroleum products delivered varies seasonally, with
gasoline demand peaking in early summer, diesel fuel demand peaking in late
summer and propane demand higher in the fall. In addition, weather conditions in
the areas served by the East Pipeline affect both the demand for and the mix of
the refined petroleum products delivered through the East Pipeline, although
historically any impact on total volumes shipped has been short-term. Tariffs
charged to shippers for transportation of products do not vary according to the
type of product delivered.
West Pipeline
The Partnership acquired the West Pipeline in February 1995, increasing the
Partnership's pipeline business in South Dakota and expanding it into Wyoming
and Colorado. The West Pipeline system includes approximately 550 miles of
pipeline in Wyoming, Colorado and South Dakota, four truck-loading terminals and
numerous pump stations situated along the system. The system's four product
terminals have a total storage capacity of over 1.7 million barrels.
The West Pipeline originates near Casper, Wyoming, where it serves as a
connecting point with Sinclair's Little America Refinery and the Seminoe
Pipeline which transports product from Billings, Montana area refineries. At
Douglas, Wyoming, a 6 inch pipeline branches off to serve the Partnership's
Rapid City, South Dakota terminal approximately 190 miles away. The 6 inch
pipeline also receives product from Wyoming Refining's pipeline at a connection
located near the Wyoming/South Dakota border. From Douglas, the Partnership's
pipeline continues southward through a delivery point at the Burlington Northern
junction to terminals at Cheyenne, Wyoming, the Denver metropolitan area and
Fountain, Colorado.
The West Pipeline system parallels the Partnership's East Pipeline to the
west. The East Pipeline's North Platte line terminates in western Nebraska,
approximately 200 miles east of the West Pipeline's Cheyenne, Wyoming terminal.
The West Pipeline serves Denver and other eastern Colorado markets and supplies
jet fuel to Ellsworth Air Force Base at Rapid City, South Dakota, as compared to
the East Pipeline's largely agricultural service area. The West Pipeline has a
relatively small number of shippers who, with few exceptions, are also shippers
on the Partnership's East Pipeline system.
North Pipeline
The North Pipeline, acquired in December 2002, runs from west to east
approximately 440 miles from its origin at the Tesoro Refining and Marketing
Company's Mandan, North Dakota refinery to the Minneapolis, Minnesota area. It
has four product terminals, one in North Dakota and three in Minnesota, with a
total tankage capacity of 1.3 million barrels. The North Pipeline crosses the
Partnership's East Pipeline near Jamestown, North Dakota where the two pipelines
are connected. The North Pipeline is currently supplied exclusively by the
Mandan refinery, however, it is capable of delivering or receiving products to
or from the East Pipeline.
Ammonia Pipeline
In November 2002, the Partnership acquired the anhydrous ammonia pipeline
(the "Ammonia Pipeline") from two Koch companies. Anhydrous ammonia is primarily
used as agricultural fertilizer through direct application. Other uses are as a
component of various types of dry fertilizer as well as use as a cleaning agent
in power plant scrubbers. The 2,000 mile pipeline originates in the Louisiana
delta area where it has access to three marine terminals on the Mississippi
River. It moves north through Louisiana and Arkansas into Missouri, where at
Hermann, Missouri, one branch splits going east into Illinois and Indiana, and
the other branch continues north into Iowa and then turning west into Nebraska.
The Partnership acquired a storage and loading terminal near Hermann, Missouri a
portion of which is leased back to Koch Nitrogen. The Ammonia Pipeline is
connected to twenty-two other third party owned terminals and also has several
industrial facility delivery locations. Product is supplied to the pipeline from
plants in Louisiana and foreign-source product delivered through the marine
terminals.
Other Systems
The Partnership also owns three single-use pipelines, located near
Umatilla, Oregon; Rawlins, Wyoming and Pasco, Washington, each of which supplies
diesel fuel to a railroad fueling facility. The Oregon and Washington lines are
fully automated, however the Wyoming line utilizes a coordinated startup
procedure between the refinery and the railroad. For the year ended December 31,
2004, these three systems combined transported a total of 3.8 million barrels of
diesel fuel, representing an aggregate of $1.55 million in revenues.
Pipelines Products and Activities
The revenues for the East Pipeline, West Pipeline, North Pipeline, Ammonia
Pipeline and Other Pipelines (collectively, the "Pipelines") are based upon
volumes and distances of product shipped. The following table reflects the total
volume, barrel miles of refined petroleum products shipped and total operating
revenues earned by the Pipelines for each of the periods indicated, but does not
include any information on the Ammonia Pipeline. During 2004 and 2003, the
Ammonia Pipeline shipped 1,122,618 tons and 1,156,549 tons, respectively, of
ammonia generating $19.6 million and $21.3 million, respectively, of revenue.
Year Ended December 31,
------------------------------------------------------------------------------------
2004 2003 2002 2001 2000
------------- ------------- -------------- ------------- --------------
Volume (1).................. 104,344 102,928 89,780 92,116 89,192
Barrel miles (2)............ 22,243 21,327 18,275 18,567 17,843
Revenues (3)................ $100,241 $98,329 $78,240 $74,976 $70,685
(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)
------------------------------------------------------------------------------------
2004 2003 2002 2001 2000
------------- ------------- -------------- ------------- --------------
Gasoline.................... 54,745 53,205 45,106 46,268 44,215
Diesel and fuel oil......... 46,223 46,072 40,450 42,354 41,087
Propane..................... 3,376 3,651 4,224 3,494 3,890
------------- ------------- -------------- ------------- --------------
Total....................... 104,344 102,928 89,780 92,116 89,192
============= ============= ============== ============= ==============
Diesel and fuel oil are used in farm machinery and equipment, over-the-road
transportation, railroad fueling and residential fuel oil. Gasoline is primarily
used in over-the-road transportation and propane is used for crop drying,
residential heating and to power irrigation equipment. The mix of refined
petroleum products delivered varies seasonally, with gasoline demand peaking in
early summer, diesel fuel demand peaking in late summer and propane demand
higher in the fall. In addition, weather conditions in the areas served by the
East Pipeline affect both the demand for and the mix of the refined petroleum
products delivered through the East Pipeline, although historically any overall
impact on the total volumes shipped has been short-term. Tariffs charged to
shippers for transportation of products do not vary according to the type of
product delivered. Demand on the North Pipeline is mainly of the same
agricultural nature as that of the East Pipeline except for the Minneapolis
terminal area which is more metropolitan.
Maintenance and Monitoring
The Pipelines have been constructed and are maintained in a manner
consistent with applicable federal, state and local laws and regulations,
standards prescribed by the American Petroleum Institute and accepted industry
practice. Further, protective measures are taken and routine preventive
maintenance is performed on the Pipelines in order to prolong their useful
lives. Such measures include cathodic protection to prevent external corrosion,
inhibitors to prevent internal corrosion and periodic inspection of the
Pipelines. Additionally, the Pipelines are patrolled at regular intervals to
identify equipment or activities by third parties that, if left unchecked, could
result in encroachment upon the Pipelines' rights-of-way and possible damage to
the Pipelines.
The Partnership uses Supervisory Control and Data Acquisition remote
supervisory control software programs to continuously monitor and control the
Pipelines from the Wichita, Kansas headquarters and from the Roseville,
Minnesota terminal for the North Pipeline. The system monitors quantities of
products injected in and delivered through the Pipelines and automatically
signals the Wichita or Roseville personnel upon deviations from normal
operations that requires attention.
Pipeline Operations
For pipeline operations, integrity management and public safety, the East
Pipeline, the West Pipeline, the North Pipeline and the Ammonia Pipeline are
subject to federal regulation by one or more of the following governmental
agencies or laws: the Federal Energy Regulatory Commission ("FERC"), the Surface
Transportation Board (the "STB"), the Department of Transportation, the
Environmental Protection Agency, and the Homeland Security Act. Additionally,
the operations and integrity of the Pipelines are subject to the respective
state jurisdictions along the route of the systems. See "Regulation."
Except for the three single-use pipelines and certain ethanol facilities,
all of the Partnership's pipeline operations constitute common carrier
operations and are subject to federal tariff regulation. In May 1998, the
Partnership was authorized by the FERC to adopt market-based rates in
approximately one-half of its markets on the East and West systems. Common
carrier activities are those for which transportation through the Partnership's
Pipelines is available at published tariffs filed, in the case of interstate
petroleum product shipments, with the FERC or, in the case of intrastate
petroleum product shipments in Kansas, Colorado, Wyoming and North Dakota, with
the relevant state authority, to any shipper of refined petroleum products who
requests such services and satisfies the conditions and specifications for
transportation. The Ammonia Pipeline is subject to federal regulation by the
STB, rather than the FERC.
In general, a shipper on one of the Partnership's refined petroleum
products pipelines delivers products to the pipeline from refineries or third
party pipelines that connect to the Pipelines. The Pipelines' refined petroleum
products operations also include 25 truck-loading terminals through which
refined petroleum products are delivered to storage tanks and then loaded into
petroleum transport trucks. Five of the 25 terminals also receive propane into
storage tanks and then load it into transport trucks. The Ammonia Pipeline
receives product from anhydrous ammonia plants or from the marine terminals for
imported product. Tariffs for transportation are charged to shippers based upon
transportation from the origination point on the pipeline to the point of
delivery. Such tariffs also include charges for terminaling and storage of
product at the Pipeline's terminals. Pipelines are generally the lowest cost
method for intermediate and long-haul overland transportation of refined
petroleum products.
Each shipper transporting product on a pipeline is required to supply the
Partnership with a notice of shipment indicating sources of products and
destinations. All shipments are tested or receive refinery certifications to
ensure compliance with the Partnership's specifications. Petroleum shippers are
generally invoiced by the Partnership immediately upon the product entering one
of the Petroleum Pipelines.
The following table shows the number of tanks owned by the Partnership at
each refined petroleum product terminal location at December 31, 2004, the
storage capacity in barrels and truck capacity of each terminal location.
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 12
storage tanks at El Dorado, Kansas and 10 storage tanks at McPherson, Kansas,
with aggregate capacities of approximately 548,555 and 534,000 barrels,
respectively. During 2004, approximately 57.3%, 87.6% and 90.0% of the
deliveries of the East, the West and the North Pipelines, respectively, were
made through their terminals, and the remainder of the respective deliveries of
such lines were made to other pipelines and customer owned storage tanks.
Storage of product at terminals pending delivery is considered by the
Partnership to be an integral part of the petroleum product delivery service of
the pipelines. Shippers generally store refined petroleum products for less than
one week. Ancillary services, including injection of shipper-furnished and
generic additives, are available at each terminal.
The Partnership owns 1,500 tons of ammonia storage at the terminal near
Hermann, Missouri. One half of the capacity is leased to Koch Nitrogen.
Demand for and Sources of Refined Petroleum Products
The Partnership's pipeline business depends in large part on the level of
demand for refined petroleum products in the markets served by the pipelines and
the ability and willingness of refiners and marketers having access to the
pipelines to supply such demand by deliveries through the pipelines.
Much of the refined petroleum products delivered through the East Pipeline
and the western three terminals on the North Pipeline is ultimately used as fuel
for railroads or in agricultural operations, including fuel for farm equipment,
irrigation systems, trucks used for transporting crops and crop drying
facilities. Demand for refined petroleum products for agricultural use, and the
relative mix of products required, is affected by weather conditions in the
markets served by the East and North Pipelines. The agricultural sector is also
affected by government agricultural policies and crop prices. Although periods
of drought suppress agricultural demand for some refined petroleum products,
particularly those used for fueling farm equipment, the demand for fuel for
irrigation systems often increases during such times.
While there is some agricultural demand for the refined petroleum products
delivered through the West Pipeline, as well as military jet fuel volumes, most
of the demand is centered in the Denver and Colorado Springs area. Because
demand on the West Pipeline and the Minneapolis area terminal of the North
Pipeline is significantly weighted toward urban and suburban areas, the product
mix on the West Pipeline and that terminal includes a substantially higher
percentage of gasoline than the product mix on the East Pipeline.
The Partnership's refined petroleum products pipelines are also dependent
upon adequate levels of production of refined petroleum products by refineries
connected to the Pipelines, directly or through connecting pipelines. The
refineries are, in turn, dependent upon adequate supplies of suitable grades of
crude oil. The refineries connected directly to the East Pipeline obtain crude
oil from producing fields located primarily in Kansas, Oklahoma and Texas, and,
to a much lesser extent, from other domestic or foreign sources. In addition,
refineries in Kansas, Oklahoma and Texas are also connected to the East Pipeline
through other pipelines. These refineries obtain their supplies of crude oil
from a variety of sources. The refineries connected directly to the West
Pipeline are located in Casper and Cheyenne, Wyoming and Denver, Colorado.
Refineries in Billings and Laurel, Montana are connected to the West Pipeline
through other pipelines. These refineries obtain their supplies of crude oil
primarily from Rocky Mountain sources. The North Pipeline is heavily dependent
on the Tesoro Mandan refinery which primarily operates on North Dakota crude oil
although it has the ability to access other crude oils. If operations at any one
refinery were discontinued, the Partnership believes (assuming unchanged demand
for refined petroleum products in markets served by the refined petroleum
products pipelines) that the effects thereof would be short-term in nature and
the Partnership's business would not be materially adversely affected over the
long term because such discontinued production could be replaced by other
refineries or by other sources.
The majority of the refined petroleum product transported through the East
Pipeline in 2004 was produced at three refineries located at McPherson and El
Dorado, Kansas and Ponca City, Oklahoma, and operated by the National
Cooperative Refining Association ("NCRA"), Frontier Refining and ConocoPhillips
Company, respectively. The NCRA and Frontier Refining refineries are connected
directly to the East Pipeline. The McPherson, Kansas refinery operated by NCRA
accounted for approximately 31.8% of the total amount of product shipped over
the East Pipeline in 2004. The East Pipeline also has direct access by third
party pipelines to four other refineries in Kansas, Oklahoma and Texas and to
Gulf Coast supplies of products through connecting pipelines that receive
products from pipelines originating on the Gulf Coast. Five connecting pipelines
can deliver propane from gas processing plants in Texas, New Mexico, Oklahoma
and Kansas to the East Pipeline for shipment.
The majority of the refined petroleum products transported through the West
Pipeline is produced at the Frontier Refinery located at Cheyenne, Wyoming, the
Valero Energy Corporation and Suncor Refineries located at Denver, Colorado, and
Sinclair's Little America Refinery located at Casper, Wyoming, all of which are
connected directly to the West Pipeline. The West Pipeline also has access to
three Billings, Montana, area refineries through a connecting pipeline.
Demand for and Sources of Anhydrous Ammonia
The Partnership's Ammonia Pipeline business depends on the overall nitrogen
fertilizer use, management practice, level of demand for direct application of
anhydrous ammonia as a fertilizer for crop production ("Direct Application" or
"DA"), the weather (DA is not effective if the ground is too wet or too dry) and
the price of natural gas (the primary component of anhydrous ammonia).
The Ammonia Pipeline is the largest of three anhydrous ammonia pipelines in
the United States and the only one that has the capability of receiving foreign
production directly into the system and transporting anhydrous ammonia into the
nation's corn belt. This ability to receive either domestic or foreign anhydrous
ammonia is a competitive advantage over the next largest ammonia system which
originates in Oklahoma and Texas, then extends into Iowa.
Corn producers have several fertilizer alternatives such as liquid, dry or
Direct Application. Liquid and dry fertilizers are both upgrades of anhydrous
ammonia and therefore are generally more costly but are less sensitive to
weather conditions during application. DA is the cheapest method of fertilizer
application but cannot be applied if the ground is too wet or extremely dry.
Principal Customers
The Partnership had a total of approximately 48 shippers in 2004. The
principal shippers include integrated oil companies, refining companies, farm
cooperatives and a railroad. Transportation revenues attributable to the top 10
shippers were $90.4 million, $86.6 million and $61.5 million, which accounted
for 75%, 72% and 74% of total Pipeline revenues shipped for each of the years
2004, 2003 and 2002, respectively.
Competition and Business Considerations
The East and North Pipelines' major competitor is an independent, regulated
common carrier pipeline system owned by Magellan Midstream Partners, L.P.
("Magellan"), formerly the Williams Companies, Inc., that operates approximately
100 miles east of and parallel to the East Pipeline and in close proximity to
the North Pipeline. The Magellan system is a substantially more extensive system
than the East and North Pipelines. Competition with Magellan is based primarily
on transportation charges, quality of customer service and proximity to end
users, although refined product pricing at either the origin or terminal point
on a pipeline may outweigh transportation costs. Seventeen of the East
Pipeline's and all four of the North Pipeline's delivery terminals are located
within 2 to 145 miles of, and in direct competition with Magellan's terminals.
The West Pipeline competes with the truck-loading racks of the Cheyenne and
Denver refineries and the Denver terminals of the Chase Terminal Company and
ConocoPhillips. Valero L.P. terminals in Denver and Colorado Springs, connected
to a Valero L.P. pipeline from their Texas Panhandle Refinery, are major
competitors to the West Pipeline's Denver and Fountain Terminals, respectively.
Because pipelines are generally the lowest cost method for intermediate and
long-haul movement of refined petroleum products, the Partnership's more
significant competitors are common carrier and proprietary pipelines owned and
operated by major integrated and large independent oil companies and other
companies in the areas where the Partnership delivers products. Competition
between common carrier pipelines is based primarily on transportation charges,
quality of customer service and proximity to end users. The Partnership believes
high capital costs, tariff regulation, environmental considerations and problems
in acquiring rights-of-way make it unlikely that other competing pipeline
systems comparable in size and scope to its pipelines will be built in the near
future, provided its pipelines have available capacity to satisfy demand and its
tariffs remain at reasonable levels.
The costs associated with transporting products from a loading terminal to
end users limit the geographic size of the market that can be served
economically by any terminal. Transportation to end users from the loading
terminals of the Partnership is conducted principally by trucking operations of
unrelated third parties. Trucks may competitively deliver products in some of
the areas served by the Partnership's pipelines. However, trucking costs render
that mode of transportation not competitive for longer hauls or larger volumes.
The Partnership does not believe that trucks are, or will be, effective
competition to its long-haul volumes over the long term.
Competitors of the Ammonia Pipeline include another anhydrous ammonia
pipeline which originates in Oklahoma and Texas, and terminates in Iowa. The
competitor pipeline has the same DA demand and weather issues as the Ammonia
Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest
production barges and railroads represent other forms of direct competition to
the pipeline under certain market conditions.
LIQUIDS TERMINALING BUSINESS
Introduction
The Partnership's terminaling business is conducted through the Support
Terminal Services operation ("ST Services" or "ST") and Statia Terminals
International N.V. ("Statia"). ST Services is one of the largest independent
petroleum products and specialty liquids terminaling companies in the United
States. Statia, acquired on February 28, 2002 for a purchase price of $178
million (net of cash acquired), plus the assumption of $107 million of debt,
owns and operates the Partnership's two largest terminals and provides related
value-added services, including crude oil and petroleum product blending and
processing, berthing of vessels at their marine facilities, and emergency and
spill response services. In addition to its terminaling services, Statia sells
bunkers, which is the fuel marine vessels consume, and bulk petroleum products
to various commercial interests.
For the year ended December 31, 2004, the Partnership's terminaling
business accounted for approximately 40% of the Partnership's revenues. As of
December 31, 2004, ST operated 41 facilities in 20 states, with a total storage
capacity of approximately 34.9 million barrels. ST also owns and operates seven
terminals located in the United Kingdom, having a total capacity of
approximately 6.0 million barrels. In May and September 2004, ST acquired
terminals in Philadelphia, Pennsylvania and Linden, New Jersey from ExxonMobil.
In September 2004, ST acquired a chemical and petroleum terminal in Grangemouth,
Scotland. In September 2002, ST acquired eight terminals in Australia and New
Zealand with a total capacity of approximately 1.2 million barrels for
approximately $47 million in cash. ST Services and its predecessors have a long
history in the terminaling business and handle a wide variety of liquids from
petroleum products to specialty chemicals to edible liquids. At the end of 2004,
Statia's tank capacity was 18.8 million barrels, including an 11.3 million
barrel storage and transshipment facility located on the Netherlands Antilles
island of St. Eustatius, and a 7.5 million barrel storage and transshipment
facility located at Point Tupper, Nova Scotia, Canada.
The Partnership's terminal facilities provide storage and handling services
on a fee basis for petroleum products, specialty chemicals and other liquids.
The Partnership's six largest terminal facilities are located on the Island of
St. Eustatius, Netherlands Antilles; in Point Tupper, Nova Scotia, Canada; in
Piney Point, Maryland; in Linden, New Jersey (50% owned joint venture); in
Crockett, California; and in Martinez, California.
Description of Largest Terminal Facilities
St. Eustatius, Netherlands Antilles
Statia owns and operates an 11.3 million barrel petroleum terminaling
facility located on the Netherlands Antilles island of St. Eustatius, which is
located at a point of minimal deviation from major shipping routes. This
facility is capable of handling a wide range of petroleum products, including
crude oil and refined products, and can accommodate the world's largest tankers
for loading and discharging crude oil. A two-berth jetty, a two-berth monopile
with platform and buoy systems, a floating hose station, and an offshore single
point mooring buoy with loading and unloading capabilities serve the terminal's
customers' vessels. The St. Eustatius facility has a total of 51 tanks. The fuel
oil and petroleum product facilities have in-tank and in-line blending
capabilities, while the crude tanks have tank-to-tank blending capability as
well as in-tank mixers. In addition to the storage and blending services at St.
Eustatius, the facility has the flexibility to utilize certain storage capacity
for both feedstock and refined products to support its atmospheric distillation
unit, which is capable of processing up to 15,000 barrels per day of feedstock,
ranging from condensates to heavy crude oil. Statia owns and operates all of the
berthing facilities at its St. Eustatius terminal and charges vessels a fee for
their use. Vessel owners or charterers may incur separate fees for associated
services such as pilotage, tug assistance, line handling, launch service,
emergency response services and other ship services.
Point Tupper, Nova Scotia, Canada
Statia owns and operates a 7.5 million barrel terminaling facility located
at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia,
Canada, which is located approximately 700 miles from New York City, 850 miles
from Philadelphia and 2,500 miles from Mongstad, Norway. This facility is the
deepest independent, ice-free marine terminal on the North American Atlantic
coast, with access to the East Coast and Canada as well as the Midwestern United
States via the St. Lawrence Seaway and the Great Lakes system. With one of the
premier jetty facilities in North America, the Point Tupper facility can
accommodate substantially all of the world's largest, fully-laden very large
crude carriers and ultra large crude carriers for loading and discharging crude
oil, petroleum products, and petrochemicals. The Point Tupper facility has a
total of 37 tanks. Its butane sphere is one of the largest of its kind in North
America. The facility's tanks were renovated in 1994 to comply with construction
standards that meet or exceed American Petroleum Institute, NFPA, and other
material industry standards. Crude oil and petroleum product movements at the
terminal are fully automated. Separate Statia fees apply for the use of the
jetty facility as well as associated services, including pilotage, tug
assistance, line handling, launch service, spill response services and other
ship services. Statia also charters tugs, mooring launches, and other vessels to
assist with the movement of vessels through the Strait of Canso and the safe
berthing of vessels at Point Tupper and to provide other services to vessels.
Piney Point, Maryland
The largest domestic terminal currently owned by ST is located on
approximately 400 acres on the Potomac River. The facility was acquired as part
of the purchase of the liquids terminaling assets of Steuart Petroleum Company
and certain of its affiliates in December 1995. The Piney Point terminal has
approximately 5.4 million barrels of storage capacity in 28 tanks and is the
closest deep-water facility to Washington, D.C. This terminal competes with
other large petroleum terminals in the East Coast water-borne market extending
from New York Harbor to Norfolk, Virginia. The terminal currently stores
petroleum products consisting primarily of fuel oils and asphalt. The terminal
has a dock with a 36-foot draft for tankers and four berths for barges. It also
has truck-loading facilities, product-blending capabilities and is connected to
a pipeline which supplies residual fuel oil to two power generating stations.
Linden, New Jersey
In October 1998, ST entered into a joint venture relationship with
Northville Industries Corp. ("Northville") to acquire a 50% ownership interest
in and the management of the terminal facility at Linden, New Jersey that was
previously owned by Northville. The 44-acre facility provides ST with deep-water
terminaling capabilities at New York Harbor and primarily stores petroleum
products, including gasoline, jet fuel and fuel oils. The facility has a total
capacity of approximately 3.9 million barrels in 22 tanks, can receive products
via ship, barge and pipeline and delivers product by ship, barge, pipeline and
truck. The terminal owns two docks and leases a third with draft limits of 35,
24 and 24 feet, respectively. In September 2004, ST, outside of the joint
venture, acquired an adjacent 375,000 barrel terminal from Exxon-Mobil.
Crockett, California
The Crockett Terminal was acquired in January 2001 as a part of the Shore
acquisition. The terminal has approximately 3 million barrels of tankage and is
located in the San Francisco Bay area. The facility provides deep-water access
for handling petroleum products and gasoline additives such as ethanol. The
terminal offers pipeline connections to various refineries and pipelines. It
receives and delivers product by vessel, barge, pipeline and truck-loading
facilities. The terminal also has railroad tank car unloading capability.
Martinez, California
The Martinez Terminal, also acquired in January 2001 as a part of the Shore
acquisition, is located in the refinery area of San Francisco Bay. It has
approximately 3.1 million barrels of tankage and handles refined petroleum
products as well as crude oil. The terminal is connected to a pipeline and to
area refineries by pipelines and can also receive and deliver products by vessel
or barge. It also has a truck rack for product delivery.
The Partnership's facilities have been designed with engineered structural
measures to minimize the possibility of the occurrence and the level of damage
in the event of a spill or fire. All loading areas, tanks, pipes and pumping
areas are "contained" to collect any spillage and insure that only properly
treated water is discharged from the site.
Other Terminal Sites
In addition to the four major domestic facilities described above, ST
Services has 37 other terminal facilities located throughout the United States,
seven facilities in the United Kingdom, four facilities in Australia and four
facilities in New Zealand. These other facilities primarily store petroleum
products for a variety of customers, with the exception of the facilities in
Texas City, Texas, which handles specialty chemicals; Columbus, Georgia, which
handles aviation gasoline and specialty chemicals; Winona, Minnesota, which
handles nitrogen fertilizer solutions; Savannah, Georgia, which handles
chemicals, lube oils, potash and caustic solutions, as well as petroleum
products; Vancouver, Washington, which handles chemicals and fertilizer;
Eastham, United Kingdom, which handles chemicals and animal fats; Grangemouth,
United Kingdom, which handles chemicals and molasses as well as petroleum
products; and Runcorn, United Kingdom, which handles molten sulphur, and the
Australian and New Zealand terminals which handle chemicals and animal fats and
oil. Overall, these facilities provide ST Services with locations which are
diverse geographically, in products handled and in customers served.
The following table outlines the Partnership's terminal locations,
capacities, tanks and primary products handled:
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 2,008,000 124 Chemicals, petrochemicals,
petroleum
Other U. S. Terminals:
Montgomery, AL(b) 162,000 7 Petroleum, jet fuel
Moundville, AL 310,000 6 Jet Fuel
Tucson, AZ(a) 174,000 7 Petroleum
Los Angeles, CA 597,000 20 Petroleum
Richmond, CA 617,000 25 Petroleum, ethanol
Stockton, CA 706,000 32 Petroleum, ethanol, fertilizer,
caustic
Bremen, GA 182,000 9 Petroleum, jet fuel
Brunswick, GA 302,000 3 Fertilizer, pulp liquor
Columbus, GA 175,000 24 Petroleum, chemicals, fertilizers
Macon, GA(b) 307,000 10 Petroleum, jet fuel
Savannah, GA 903,000 28 Petroleum, chemicals
Blue Island, IL 752,000 19 Petroleum, ethanol
Chillicothe, IL(a) 270,000 6 Petroleum
Peru, IL 221,000 8 Fertilizer
Indianapolis, IN 410,000 18 Petroleum
Westwego, LA 849,000 53 Molasses, fertilizer, caustic,
chemicals, lube oil
Andrews AFB Pipeline, MD(b) 72,000 3 Jet fuel
Baltimore, MD 832,000 50 Chemicals, asphalt, jet fuel
Salisbury, MD 177,000 14 Petroleum
Winona, MN 267,000 8 Fertilizer
Reno, NV 107,000 7 Petroleum
Linden, NJ 375,000 11 Petroleum
Paulsboro, NJ 1,580,000 18 Petroleum
Alamogordo, NM(b) 120,000 5 Jet Fuel
Drumright, OK 315,000 4 Petroleum
Portland, OR 1,119,000 31 Petroleum
Philadelphia, PA 894,000 11 Petroleum
Philadelphia, PA 665,000 11 Petroleum
Texas City, TX 153,000 12 Chemicals, petrochemicals,
petroleum
Dumfries, VA 554,000 16 Petroleum, asphalt
Virginia Beach, VA(b) 40,000 2 Jet fuel
Tacoma, WA 377,000 15 Petroleum
Vancouver, WA 227,000 49 Chemicals, fertilizer, petroleum
Vancouver, WA 316,000 6 Petroleum, chemicals, fertilizer
Milwaukee, WI 308,000 7 Petroleum, ethanol
Foreign Terminals:
St. Eustatius, Netherlands
Antilles. 11,350,000 60 Petroleum, crude oil
Point Tupper, Canada 7,514,000 40 Petroleum, crude oil
Sydney, Australia 330,000 65 Chemicals, fats and oils
Melbourne, Australia 468,000 118 Specialty chemicals
Geelong, Australia 145,000 14 Specialty chemicals, petroleum
Adelaide, Australia 90,000 24 Chemicals, tallow, petroleum
Auckland, New Zealand (a) 74,000 44 Fats, oils and chemicals
New Plymouth, New Zealand 35,000 10 Fats, oils and chemicals
Mt. Maunganui, New Zealand 83,000 24 Fats, oils and chemicals
Wellington, New Zealand 50,000 13 Fats, oils and chemicals
Grays, England 1,945,000 53 Petroleum
Eastham, England 2,185,000 162 Chemicals, petroleum, animal fats
Runcorn, England 146,000 4 Molten sulfur
Grangemouth, Scotland 530,000 46 Petroleum, chemicals and molasses
Glasgow, Scotland 344,000 16 Petroleum
Leith, Scotland 459,000 34 Petroleum, chemicals
Belfast, Northern Ireland 407,000 41 Petroleum
--------------- --------------
61,108,000 1,570
=============== ==============
(a) The terminal is 50% owned by ST.
(b) Facility also includes pipelines to U.S. government military base
locations.
Customers
Statia provides terminaling services for crude oil and refined petroleum
products to many of the world's largest producers of crude oil, integrated oil
companies, oil traders and refiners. Statia's crude oil transshipment customers
include an oil producer that leases and utilizes 5.0 million barrels of storage
at St. Eustatius and a major international oil company which leases and utilizes
3.6 million barrels of storage at Point Tupper, both of which have long-term
contracts with Statia. In addition, two different international oil companies
each lease and utilize 1.0 million barrels of clean products storage at St.
Eustatius and Point Tupper, respectively. Also in Canada, a consortium
consisting of major oil companies sends natural gas liquids via pipeline to
certain processing facilities on land leased from Statia. After processing,
certain products are stored at the Point Tupper facility under a long-term
contract. In addition, Statia's blending capabilities have attracted customers
who have leased capacity primarily for blending purposes and who have
contributed to Statia's bunker fuel and bulk product sales.
The storage and transport of jet fuel for the U.S. Department of Defense is
an important part of ST's business. Eleven of ST's terminal sites are involved
in the terminaling or transport (via pipeline) of jet fuel for the Department of
Defense and four of the eleven locations have been utilized solely by the U.S.
Government. Of the eleven locations, five include pipelines which deliver jet
fuel directly to nearby military bases.
Competition and Business Considerations
In addition to the terminals owned by independent terminal operators, such
as the Partnership, many major energy and chemical companies own extensive
terminal storage facilities. Although such terminals often have the same
capabilities as terminals owned by independent operators, they generally do not
provide terminaling services to third parties. In many instances, major energy
and chemical companies that own storage and terminaling facilities are also
significant customers of independent terminal operators, such as the
Partnership. Such companies typically have strong demand for terminals owned by
independent operators when independent terminals have more cost effective
locations near key transportation links, such as deep-water ports. Major energy
and chemical companies also need independent terminal storage when their owned
storage facilities are inadequate, either because of size constraints, the
nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location
and versatility of terminals, service and price. A favorably located terminal
will have access to various cost effective transportation modes both to and from
the terminal. Transportation modes typically include waterways, railroads,
roadways and pipelines. Terminals located near deep-water port facilities are
referred to as "deep-water terminals" and terminals without such facilities are
referred to as "inland terminals"; although some inland facilities located on or
near navigable rivers are served by barges.
Terminal versatility is a function of the operator's ability to offer
handling for diverse products with complex handling requirements. The service
function typically provided by the terminal includes, among other things, the
safe storage of the product at specified temperature, moisture and other
conditions, as well as receipt at and delivery from the terminal, all of which
must be in compliance with applicable environmental regulations. A terminal
operator's ability to obtain attractive pricing is often dependent on the
quality, versatility and reputation of the facilities owned by the operator.
Although many products require modest terminal modification, operators with
versatile storage capabilities typically require less modification prior to
usage, ultimately making the storage cost to the customer more attractive.
A few companies offering liquid terminaling facilities have significantly
more capacity than the Partnership. However, much of the Partnership's tankage
can be described as "niche" facilities that are equipped to properly handle
"specialty" liquids or provide facilities or services where management believes
the Partnership enjoys an advantage over competitors. As a result, many of the
Partnership's terminals compete against other large petroleum products
terminals, rather than specialty liquids facilities. Such specialty or "niche"
tankage is less abundant in the U.S. and "specialty" liquids typically command
higher terminal fees than lower-price bulk terminaling for petroleum products.
The main competition to crude oil storage at Statia's facilities is from
"lightering" which is the process by which liquid cargo is transferred to
smaller vessels, usually while at sea. The price differential between lightering
and terminaling is primarily driven by the charter rates for vessels of various
sizes. Lightering generally takes significantly longer than discharging at a
terminal. Depending on charter rates, the longer charter period associated with
lightering is generally offset by various costs associated with terminaling,
including storage costs, dock charges and spill response fees. However,
terminaling is generally safer and reduces the risk of environmental damage
associated with lightering, provides more flexibility in the scheduling of
deliveries, and allows customers of Statia to deliver their products to multiple
locations. Lightering in U.S. territorial waters creates a risk of liability for
owners and shippers of oil under the U.S. Oil Pollution Act of 1990 and other
state and federal legislation. In Canada, similar liability exists under the
Canadian Shipping Act. Terminaling also provides customers with the ability to
access value-added terminal services.
In the bunkering business, Statia competes with ports offering bunker fuels
to which, or from which, each vessel travels or are along the route of travel of
the vessel. Statia also competes with bunker delivery locations around the
world. In the Western Hemisphere, alternative bunker locations include ports on
the U.S. East coast and Gulf coast and in Panama, Puerto Rico, the Bahamas,
Aruba, Curacao, and Halifax. In addition, Statia competes with Rotterdam and
various North Sea locations.
CAPITAL EXPENDITURES
Capital expenditures by the Pipelines, including routine maintenance and
expansion expenditures, but excluding acquisitions, were $10.3 million, $9.6
million and $9.5 million for 2004, 2003 and 2002, respectively. During these
periods, adequate capacity existed on these pipelines to accommodate volume
growth, and the expenditures required for environmental matters were not
material in amount. Capital expenditures, including routine maintenance and
expansion expenditures, but excluding acquisitions, for the Partnership's
terminaling operations were $29.5 million, $34.6 million and $21.0 million for
2004, 2003 and 2002, respectively.
Capital expenditures of the Partnership during 2005, including routine
maintenance and expansion expenditures, but excluding acquisitions, are expected
to be approximately $40 million to $44 million. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources." Additional expansion-related capital expenditures will
depend on future opportunities to expand the Partnership's operations. Such
future expenditures, however, will depend on many factors beyond the
Partnership's control, including, without limitation, demand for refined
petroleum products and terminaling services in the Partnership's market areas,
local, state and federal governmental regulations, fuel conservation efforts and
the availability of financing on acceptable terms. No assurance can be given
that required capital expenditures will not exceed anticipated amounts during
the year or thereafter or that the Partnership will have the ability to finance
such expenditures through borrowings or choose to do so.
REGULATION
Interstate Regulation
The interstate common carrier petroleum product pipeline operations of the
Partnership are subject to rate regulation by FERC under the Interstate Commerce
Act. The Interstate Commerce Act provides, among other things, that to be lawful
the rates of common carrier petroleum pipelines must be "just and reasonable"
and not unduly discriminatory. New and changed rates must be filed with the
FERC, which may investigate their lawfulness on protest or its own motion. The
FERC may suspend the effectiveness of such rates for up to seven months. If the
suspension expires before completion of the investigation, the rates go into
effect, but the pipeline can be required to refund to shippers, with interest,
any difference between the level the FERC determines to be lawful and the filed
rates under investigation. Rates that have become final and effective may be
challenged by a complaint to FERC filed by a shipper or on the FERC's own
initiative. Reparations may be recovered by the party filing the complaint for
the two-year period prior to the complaint, if FERC finds the rate to be
unlawful.
The FERC allows for a rate of return for petroleum products pipelines
determined by adding (i) the product of a rate of return equal to the nominal
cost of debt multiplied by the portion of the rate base that is deemed to be
financed with debt and (ii) the product of a rate of return equal to the real
(i.e., inflation-free) cost of equity multiplied by the portion of the rate base
that is deemed to be financed with equity. The appropriate rate of return for a
petroleum pipeline is determined on a case-by-case basis, taking into account
cost of capital, competitive factors and business and financial risks associated
with pipeline operations.
Under Title XVIII of the Energy Policy Act of 1992 (the "EP Act"), rates
that were in effect on October 24, 1991 that were not subject to a protest,
investigation or complaint are deemed to be just and reasonable. Such rates,
commonly referred to as grandfathered rates, are subject to challenge only for
limited reasons. Any relief granted pursuant to such challenges may be
prospective only. Because the Partnership's rates that were in effect on October
24, 1991, were not subject to investigation and protest at that time, those
rates could be deemed to be just and reasonable pursuant to the EP Act. The
Partnership's current rates became final and effective in July 2000, and the
Partnership believes that its currently effective tariffs are just and
reasonable and would withstand challenge under the FERC's cost-based rate
standards. Because of the complexity of rate making, however, the lawfulness of
any rate is never assured.
On October 22, 1993, the FERC issued Order No. 561 which adopted a
simplified rate making methodology for future oil pipeline rate changes in the
form of indexation. Indexation, which is also known as price cap regulation,
establishes ceiling prices on oil pipeline rates based on application of a
broad-based measure of inflation in the general economy to existing rates. Rate
increases up to the ceiling level are to be discretionary for the pipeline, and,
for such rate increases, there will be no need to file cost-of-service or
supporting data. Moreover, so long as the ceiling is not exceeded, a pipeline
may make a limitless number of rate change filings. This indexing mechanism
calculates a ceiling rate. Rate decreases are required if the indexing mechanism
operates to reduce the ceiling rate below a pipeline's existing rates. The
pipeline may increase its rates to this calculated ceiling rate without filing a
formal cost based justification and with limited risk of shipper protests.
The indexation method is to serve as the principal basis for the
establishment of oil pipeline rate changes in the future. However, the FERC
determined that a pipeline may utilize any one of the following alternative
methodologies to indexing: (i) a cost-of-service methodology may be utilized by
a pipeline to justify a change in a rate if a pipeline can demonstrate that its
increased costs are prudently incurred and that there is a substantial
divergence between such increased costs and the rate that would be produced by
application of the index; and (ii) a pipeline may base its rates upon a
"light-handed" market-based form of regulation if it is able to demonstrate a
lack of significant market power in the relevant markets.
On September 15, 1997, the Partnership filed an Application for Market
Power Determination with the FERC seeking market based rates for approximately
half of its markets. In May 1998, the FERC granted the Partnership's application
and approximately half of the markets served by the East and West Pipelines
subsequently became subject to market force regulation.
In the FERC's Lakehead decision issued June 15, 1995, the FERC partially
disallowed Lakehead's inclusion of income taxes in its cost of service.
Specifically, the FERC held that Lakehead was entitled to receive an income tax
allowance with respect to income attributable to its corporate partners, but was
not entitled to receive such an allowance for income attributable to partnership
interests held by individuals. Lakehead's motion for rehearing was denied by the
FERC and Lakehead appealed the decision to the U.S. Court of Appeals.
Subsequently, the case was settled by Lakehead and the appeal was withdrawn. In
another FERC proceeding involving a different oil pipeline limited partnership,
various shippers challenged such pipeline's inclusion of an income tax allowance
in its cost of service. The FERC decided this case on the same basis as its
holding in the Lakehead case. On July 20, 2004, the District of Columbia Court
of Appeals vacated the Commission's determination regarding the proper tax
allowance in that case and remanded the income tax allocation issue for further
FERC consideration. FERC has requested and received comments as to the issue. If
the FERC were to partially or completely disallow the income tax allowance in
the cost of service of the East and West pipelines on the basis set forth in the
Lakehead order, KPL believes that the Partnership's ability to pay distributions
to the holders of the Units would not be impaired; however, in view of the
uncertainties involved in this issue, there can be no assurance in this regard.
The Ammonia Pipeline rates are regulated by the STB. The STB was
established in 1996 when the Interstate Commerce Commission was terminated by
the ICC Termination Act of 1995. The STB is headed by Board Members appointed by
the President and confirmed by the Senate and is authorized to have three
members. The STB jurisdiction generally includes railroad rate and service
issues, rail restructuring transactions and labor matters related thereto;
certain trucking company, moving van, and non-contiguous ocean shipping company
rate matters; and certain pipeline matters not regulated by the FERC. In the
performance of its functions, the STB is charged with promoting, where
appropriate, substantive and procedural regulatory reform in the economic
regulation of surface transportation, and with providing an efficient and
effective forum for the resolution of disputes. The STB seeks to facilitate
commerce by providing an effective forum for efficient dispute resolution and
facilitation of appropriate market-based business transactions.
The Partnership issued a STB tariff that became effective April 1, 2003.
The tariff filing combined the STB interstate tariff and the Louisiana
intrastate tariff into one document and standardized the tariff regulation
between the two regulatory bodies. The tariff filing modified the capacity
allocation procedures and established a minimum tariff rate of $5.00 per ton.
The tariff filing implemented a 7% tariff increase across all tariff rates.
Another modification was the removal of the "Industrial User" classification
which effectively increases the tariff rates actually paid for transportation to
certain shippers by more than 7%. Dyno Nobel, an industrial user in Missouri,
and CF Industries filed protests against the tariff filing. See "Item 3. Legal
Proceedings, Ammonia Pipeline Matters" for a description of those matters.
Intrastate Regulation
The intrastate operations of the East Pipeline in Kansas are subject to
regulation by the Kansas Corporation Commission, the intrastate operations of
the West Pipeline in Colorado and Wyoming are subject to regulation by the
Colorado Public Utility Commission and the Wyoming Public Service Commission,
respectively, and the intrastate operations of the North Pipeline are subject to
regulation by the North Dakota Public Utility Commission. Like the FERC, the
state regulatory authorities require that shippers be notified of proposed
intrastate tariff increases and have an opportunity to protest such increases.
The Partnership also files with such state authorities copies of interstate
tariff changes filed with the FERC. In addition to challenges to new or proposed
rates, challenges to intrastate rates that have already become effective are
permitted by complaint of an interested person or by independent action of the
appropriate regulatory authority.
The intrastate operations of the Ammonia Pipeline in Louisiana are subject
to regulation by the Louisiana Public Service Commission. Shippers under the
Louisiana intrastate tariff have rights similar to those mentioned in the
paragraph above.
ENVIRONMENTAL MATTERS
General
The operations of the Partnership are subject to federal, state and local
laws and regulations relating to the protection of the environment in the United
States and to the environmental laws and regulations of the host countries in
regard to the terminals acquired overseas. Although the Partnership believes
that its operations are in general compliance with applicable environmental
regulations, risks of substantial costs and liabilities are inherent in pipeline
and terminal operations, and there can be no assurance that significant costs
and liabilities will not be incurred by the Partnership. Moreover, it is
possible that other developments, such as increasingly strict environmental
laws, regulations and enforcement policies thereunder, and claims for damages to
property or persons resulting from the operations of the Partnership, past and
present, could result in substantial costs and liabilities to the Partnership.
See "Item 3 - Legal Proceedings" for information concerning several matters
pending against certain subsidiaries of the Partnership involving claims for
environmental damages.
Water
The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions of
the Federal Water Pollution Control Act of 1972 and other statutes as they
pertain to prevention and response to oil spills. The OPA subjects owners of
facilities to strict, joint and potentially unlimited liability for removal
costs and certain other consequences of an oil spill, where such spill is into
navigable waters, along shorelines or in the exclusive economic zone. In the
event of an oil spill into such waters, substantial liabilities could be imposed
upon the Partnership. Regulations concerning the environment are continually
being developed and revised in ways that may impose additional regulatory
burdens on the Partnership.
Contamination resulting from spills or releases of refined petroleum
products is not unusual within the petroleum pipeline and liquids terminaling
industries. The East Pipeline and ST Services have experienced limited
groundwater contamination at various terminal and pipeline sites resulting from
various causes including activities of previous owners. Remediation projects are
underway or under construction using various remediation techniques. The costs
to remediate contamination at several ST terminal locations are being borne by
the former owners under indemnification agreements. Although no assurances can
be made, the Partnership believes that the aggregate cost of these remediation
efforts will not be material.
The EPA has promulgated regulations that may require the Partnership to
apply for permits to discharge storm water runoff. Storm water discharge permits
also may be required in certain states in which the Partnership operates. Where
such requirements are applicable, the Partnership has applied for such permits
and, after the permits are received, will be required to sample storm water
effluent before releasing it. The Partnership believes that effluent limitations
could be met, if necessary, with minor modifications to existing facilities and
operations. Although no assurance in this regard can be given, the Partnership
believes that the changes will not have a material effect on the Partnership's
financial condition or results of operations.
Aboveground Storage Tank Acts
A number of the states in which the Partnership operates in the United
States have passed statutes regulating aboveground tanks containing liquid
substances. Generally, these statutes require that such tanks include secondary
containment systems or that the operators take certain alternative precautions
to ensure that no contamination results from any leaks or spills from the tanks.
Although there is not total federal regulation of all above ground tanks, the
DOT has adopted an industry standard that addresses tank inspection, repair,
alteration and reconstruction. This action requires pipeline companies to comply
with the standard for tank inspection and repair for all tanks regulated by the
DOT. The Partnership is in substantial compliance with all above ground storage
tank laws in the states with such laws. Although no assurance can be given, the
Partnership believes that the future implementation of above ground storage tank
laws by either additional states or by the federal government will not have a
material adverse effect on the Partnership's financial condition or results of
operations.
Air Emissions
The operations of the Partnership are subject to the Federal Clean Air Act
and comparable state and local statutes. The Partnership believes that the
operations of its pipelines and terminals are in substantial compliance with
such statutes in all states in which they operate.
Amendments to the Federal Clean Air Act enacted in 1990 require or will
require most industrial operations in the United States to incur future capital
expenditures in order to meet the air emission control standards that have been
and are to be developed and implemented by the EPA and state environmental
agencies. Pursuant to these Clean Air Act Amendments, those Partnership
facilities that emit volatile organic compounds ("VOC") or nitrogen oxides are
subject to increasingly stringent regulations, including requirements that
certain sources install maximum or reasonably available control technology. In
addition, the 1999 Federal Clean Air Act Amendments include a new operating
permit for major sources ("Title V Permits"), which applies to some of the
Partnership's facilities. Additionally, new dockside loading facilities owned or
operated by the Partnership in the United States will be subject to the New
Source Performance Standards that were proposed in May 1994. These regulations
require control of VOC emissions from the loading and unloading of tank vessels.
Although the Partnership is in substantial compliance with applicable air
pollution laws, in anticipation of the implementation of stricter air control
regulations, the Partnership is taking actions to substantially reduce its air
emissions.
Solid Waste
The Partnership generates non-hazardous solid waste that is subject to the
requirements of the Federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes in the United States. The EPA is considering the
adoption of stricter disposal standards for non-hazardous wastes. RCRA also
governs the disposal of hazardous wastes. At present, the Partnership is not
required to comply with a substantial portion of the RCRA requirements because
the Partnership's operations generate minimal quantities of hazardous wastes.
However, it is anticipated that additional wastes, which could include wastes
currently generated during pipeline operations, will in the future be designated
as "hazardous wastes". Hazardous wastes are subject to more rigorous and costly
disposal requirements than are non-hazardous wastes. Such changes in the
regulations may result in additional capital expenditures or operating expenses
by the Partnership.
At the terminal sites at which groundwater contamination is present, there
is also limited soil contamination as a result of the aforementioned spills. The
Partnership is under no present requirements to remove these contaminated soils,
but the Partnership may be required to do so in the future. Soil contamination
also may be present at other Partnership facilities at which spills or releases
have occurred. Under certain circumstances, the Partnership may be required to
clean up such contaminated soils. Although these costs should not have a
material adverse effect on the Partnership, no assurance can be given in this
regard.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA" or "Superfund") imposes liability, without regard to fault or the
legality of the original act, on certain classes of persons that contributed to
the release of a "hazardous substance" into the environment. These persons
include the owner or operator of the site and companies that disposed or
arranged for the disposal of the hazardous substances found at the site. CERCLA
also authorizes the EPA and, in some instances, third parties to act in response
to threats to the public health or the environment and to seek to recover from
the responsible classes of persons the costs they incur. In the course of its
ordinary operations, the Partnership may generate waste that may fall within
CERCLA's definition of a "hazardous substance". The Partnership may be
responsible under CERCLA for all or part of the costs required to clean up sites
at which such wastes have been disposed.
Environmental Impact Statement
The United States National Environmental Policy Act of 1969 (the "NEPA")
applies to certain extensions or additions to a pipeline system. Under NEPA, if
any project that would significantly affect the quality of the environment
requires a permit or approval from any United States federal agency, a detailed
environmental impact statement must be prepared. The effect of the NEPA may be
to delay or prevent construction of new facilities or to alter their location,
design or method of construction.
Indemnification
KPL has agreed to indemnify the Partnership against liabilities for damage
to the environment resulting from operations of the East Pipeline prior to
October 3, 1989. Such indemnification does not extend to any liabilities that
arise after such date to the extent such liabilities result from change in
environmental laws or regulations. Under such indemnity, KPL is presently liable
for the remediation of contamination at certain East Pipeline sites. In
addition, the Partnership was wholly or partially indemnified under certain
acquisition contracts for some environmental costs. Most of such contracts
contain time and amount limitations on the indemnities. To the extent that
environmental liabilities exceed the amount of such indemnity, the Partnership
has affirmatively assumed the excess environmental liabilities.
SAFETY REGULATION
The Partnership's pipelines are subject to regulation by the United States
Department of Transportation (the "DOT") under the Hazardous Liquid Pipeline
Safety Act of 1979 ("HLPSA") relating to the design, installation, testing,
construction, operation, replacement and management of their pipeline
facilities. The HLPSA covers anhydrous ammonia, petroleum and petroleum products
pipelines and requires any entity that owns or operates pipeline facilities to
comply with such safety regulations and to permit access to and copying of
records and to make certain reports and provide information as required by the
Secretary to Transportation. The Federal Pipeline Safety Act of 1992 amended the
HLPSA to include requirements of the future use of internal inspection devices.
The Partnership does not believe that it will be required to make any
substantial capital expenditures to comply with the requirements of HLPSA as so
amended.
On November 3, 2000, the DOT issued new regulations intended by the DOT to
assess the integrity of hazardous liquid pipeline segments that, in the event of
a leak or failure, could adversely affect highly populated areas, areas
unusually sensitive to environmental impact and commercially navigable
waterways. Under the regulations, an operator is required, among other things,
to conduct baseline integrity assessment tests (such as internal inspections)
within seven years, conduct future integrity tests at typically five-year
intervals and develop and follow a written risk-based integrity management
program covering the designated high consequence areas. The Partnership does not
believe that the increased costs of compliance with these regulations will
materially affect the Partnership's results of operations.
The Partnership is subject to the requirements of the United States Federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes that
regulate the protection of the health and safety of workers. In addition, the
OSHA hazard communication standard requires that certain information be
collected regarding hazardous materials used or produced in operations and that
this information be provided to employees, state and local authorities and
citizens. The Partnership believes that it is in general compliance with OSHA
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposure to benzene.
The OSHA hazard communication standard, the EPA community right-to-know
regulations under Title III of the Federal Superfund Amendment and
Reauthorization Act, and comparable state statutes require the Partnership to
organize information about the hazardous materials used in its operations.
Certain parts of this information must be reported to employees, state and local
governmental authorities, and local citizens upon request. In general, the
Partnership expects to increase its expenditures during the next decade to
comply with more stringent industry and regulatory safety standards such as
those described above. Such expenditures cannot be accurately estimated at this
time, although they are not expected to have a material adverse impact on the
Partnership.
EMPLOYEES
The Partnership has no employees. The business of the Partnership is
conducted by the general partner, KPL, and its affiliate, Kaneb LLC, which
employs all persons necessary for the operation of the Partnership's business.
At December 31, 2004, approximately 1,114 persons were employed. Approximately
154 of the persons at seven terminal locations in the United States and Canada
were subject to representation by labor unions and collective bargaining or
similar contracts at that date. KPL and Kaneb LLC consider relations with their
employees to be good.
AVAILABLE INFORMATION
The Partnership files annual, quarterly, and other reports and other
information with the Securities and Exchange Commission ("SEC") under the
Securities Exchange Act of 1934 (the "Exchange Act"). You may read and copy any
materials that the Partnership files with the SEC at the SEC's Public Reference
Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain additional
information about the Public Reference Room by calling the SEC at
1-800-SEC-0330. In addition, the SEC maintains an Internet site
(http://www.sec.gov) that contains reports, proxy information statements, and
other information regarding issuers that file electronically with the SEC.
The Partnership also makes available free of charge on or through the
Partnership's Internet site (http://www.kaneb.com) the Partnership's Annual
Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form
8-K, and other information statements and, if applicable, amendments to those
reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon
as reasonably practicable after the reports and other information is
electronically filed with, or furnished to, the SEC.
Item 2. Properties
The properties owned or utilized by the Partnership and its subsidiaries
are generally described in Item 1 of this Report. Additional information
concerning the obligations of the Partnership and its subsidiaries for lease and
rental commitments is presented under the caption "Commitments and
Contingencies" in Note 6 to the Partnership's consolidated financial statements.
Such descriptions and information are hereby incorporated by reference into this
Item 2.
The properties used in the operations of the Partnership's pipelines are
owned by the Partnership, through its subsidiary entities, except for KPL's
operational headquarters, located in Wichita, Kansas, which is held under a
lease that expires in 2009. Statia's facilities are owned through subsidiaries
and the majority of ST's facilities are owned, while the remainder, including
some of its terminal facilities located in port areas and its operational
headquarters, located in Richardson, Texas, are held pursuant to lease
agreements having various expiration dates, rental rates and other terms.
Item 3. Legal Proceedings
Grace Litigation. Certain subsidiaries of the Partnership were sued in a
Texas state court in 1997 by Grace Energy Corporation ("Grace"), the entity from
which the Partnership acquired ST Services in 1993. The lawsuit involves
environmental response and remediation costs allegedly resulting from jet fuel
leaks in the early 1970's from a pipeline. The pipeline, which connected a
former Grace terminal with Otis Air Force Base in Massachusetts (the "Otis
pipeline" or the "pipeline"), ceased operations in 1973 and was abandoned before
1978, when the connecting terminal was sold to an unrelated entity. Grace
alleged that subsidiaries of the Partnership acquired the abandoned pipeline as
part of the acquisition of ST Services in 1993 and assumed responsibility for
environmental damages allegedly caused by the jet fuel leaks. Grace sought a
ruling from the Texas court that these subsidiaries are responsible for all
liabilities, including all present and future remediation expenses, associated
with these leaks and that Grace has no obligation to indemnify these
subsidiaries for these expenses. In the lawsuit, Grace also sought
indemnification for expenses of approximately $3.5 million that it had incurred
since 1996 for response and remediation required by the State of Massachusetts
and for additional expenses that it expects to incur in the future. The
consistent position of the Partnership's subsidiaries has been that they did not
acquire the abandoned pipeline as part of the 1993 ST Services transaction, and
therefore did not assume any responsibility for the environmental damage nor any
liability to Grace for the pipeline.
At the end of the trial, the jury returned a verdict including findings
that (1) Grace had breached a provision of the 1993 acquisition agreement by
failing to disclose matters related to the pipeline, and (2) the pipeline was
abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired
ST Services. On August 30, 2000, the Judge entered final judgment in the case
that Grace take nothing from the subsidiaries on its claims seeking recovery of
remediation costs. Although the Partnership's subsidiaries have not incurred any
expenses in connection with the remediation, the court also ruled, in effect,
that the subsidiaries would not be entitled to indemnification from Grace if any
such expenses were incurred in the future. Moreover, the Judge let stand a prior
summary judgment ruling that the pipeline was an asset acquired by the
Partnership's subsidiaries as part of the 1993 ST Services transaction and that
any liabilities associated with the pipeline would have become liabilities of
the subsidiaries. Based on that ruling, the Massachusetts Department of
Environmental Protection and Samson Hydrocarbons Company (successor to Grace
Petroleum Company) wrote letters to ST Services alleging its responsibility for
the remediation, and ST Services responded denying any liability in connection
with this matter. The Judge also awarded attorney fees to Grace of more than
$1.5 million. Both the Partnership's subsidiaries and Grace have appealed the
trial court's final judgment to the Texas Court of Appeals in Dallas. In
particular, the subsidiaries have filed an appeal of the judgment finding that
the Otis pipeline and any liabilities associated with the pipeline were
transferred to them as well as the award of attorney fees to Grace.
On April 2, 2001, Grace filed a petition in bankruptcy, which created an
automatic stay of actions against Grace. This automatic stay covers the appeal
of the Dallas litigation, and the Texas Court of Appeals has issued an order
staying all proceedings of the appeal because of the bankruptcy. Once that stay
is lifted, the Partnership's subsidiaries that are party to the lawsuit intend
to resume vigorous prosecution of the appeal.
The Otis Air Force Base is a part of the Massachusetts Military Reservation
("MMR Site"), which has been declared a Superfund Site pursuant to CERCLA. The
MMR Site contains a number of groundwater contamination plumes, two of which are
allegedly associated with the Otis pipeline, and various other waste management
areas of concern, such as landfills. The United States Department of Defense,
pursuant to a Federal Facilities Agreement, has been responding to the
Government remediation demand for most of the contamination problems at the MMR
Site. Grace and others have also received and responded to formal inquiries from
the United States Government in connection with the environmental damages
allegedly resulting from the jet fuel leaks. The Partnership's subsidiaries
voluntarily responded to an invitation from the Government to provide
information indicating that they do not own the pipeline. In connection with a
court-ordered mediation between Grace and the Partnership's subsidiaries, the
Government advised the parties in April 1999 that it has identified two spill
areas that it believes to be related to the pipeline that is the subject of the
Grace suit. The Government at that time advised the parties that it believed it
had incurred costs of approximately $34 million, and expected in the future to
incur costs of approximately $55 million, for remediation of one of the spill
areas. This amount was not intended to be a final accounting of costs or to
include all categories of costs. The Government also advised the parties that it
could not at that time allocate its costs attributable to the second spill area.
By letter dated July 26, 2001, the United States Department of Justice
("DOJ") advised ST Services that the Government intends to seek reimbursement
from ST Services under the Massachusetts Oil and Hazardous Material Release
Prevention and Response Act and the Declaratory Judgment Act for the
Government's response costs at the two spill areas discussed above. The DOJ
relied in part on the Texas state court judgment, which in the DOJ's view, held
that ST Services was the current owner of the pipeline and the
successor-in-interest of the prior owner and operator. The Government advised ST
Services that it believes it has incurred costs exceeding $40 million, and
expects to incur future costs exceeding an additional $22 million, for
remediation of the two spill areas. The Partnership believes that its
subsidiaries have substantial defenses. ST Services responded to the DOJ on
September 6, 2001, contesting the Government's positions and declining to
reimburse any response costs. The DOJ has not filed a lawsuit against ST
Services seeking cost recovery for its environmental investigation and response
costs. Representatives of ST Services have met with representatives of the
Government on several occasions since September 6, 2001 to discuss the
Government's claims and to exchange information related to such claims.
Additional exchanges of information are expected to occur in the future and
additional meetings may be held to discuss possible resolution of the
Government's claims without litigation. The Partnership does not believe this
matter will have a materially adverse effect on its financial condition,
although there can be no assurances as to the ultimate outcome.
PEPCO Litigation. On April 7, 2000, a fuel oil pipeline in Maryland owned
by Potomac Electric Power Company ("PEPCO") ruptured. Work performed with regard
to the pipeline was conducted by a partnership of which ST Services is general
partner. PEPCO has reported that it has incurred total cleanup costs of $70
million to $75 million. PEPCO probably will continue to incur some cleanup
related costs for the foreseeable future, primarily in connection with EPA
requirements for monitoring the condition of some of the impacted areas. Since
May 2000, ST Services has provisionally contributed a minority share of the
cleanup expense, which has been funded by ST Services' insurance carriers. ST
Services and PEPCO have not, however, reached a final agreement regarding ST
Services' proportionate responsibility for this cleanup effort, if any, and
cannot predict the amount, if any, that ultimately may be determined to be ST
Services' share of the remediation expense, but ST Services believes that such
amount will be covered by insurance and therefore will not materially adversely
affect the Partnership's financial condition.
As a result of the rupture, purported class actions were filed against
PEPCO and ST Services in federal and state court in Maryland by property and
business owners alleging damages in unspecified amounts under various theories,
including under the Oil Pollution Act ("OPA") and Maryland common law. The
federal court consolidated all of the federal cases in a case styled as In re
Swanson Creek Oil Spill Litigation. A settlement of the consolidated class
action, and a companion state-court class action, was reached and approved by
the federal judge. The settlement involved creation and funding by PEPCO and ST
Services of a $2,250,000 class settlement fund, from which all participating
claimants would be paid according to a court-approved formula, as well as a
court-approved payment to plaintiffs' attorneys. The settlement has been
consummated and the fund, to which PEPCO and ST Services contributed equal
amounts, has been distributed. Participating claimants' claims have been settled
and dismissed with prejudice. A number of class members elected not to
participate in the settlement, i.e., to "opt out," thereby preserving their
claims against PEPCO and ST Services. All non-participant claims have been
settled for immaterial amounts with ST Services' portion of such settlements
provided by its insurance carrier.
PEPCO and ST Services agreed with the federal government and the State of
Maryland to pay costs of assessing natural resource damages arising from the
Swanson Creek oil spill under OPA and of selecting restoration projects. This
process was completed in mid-2002. ST Services' insurer has paid ST Services'
agreed 50 percent share of these assessment costs. In late November 2002, PEPCO
and ST Services entered into a Consent Decree resolving the federal and state
trustees' claims for natural resource damages. The decree required payments by
ST Services and PEPCO of a total of approximately $3 million to fund the
restoration projects and for remaining damage assessment costs. The federal
court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO
and ST Services have each paid their 50% share and thus fully performed their
payment obligations under the Consent Decree. ST Services' insurance carrier
funded ST Services' payment.
The U.S. Department of Transportation ("DOT") has issued a Notice of
Proposed Violation to PEPCO and ST Services alleging violations over several
years of pipeline safety regulations and proposing a civil penalty of $647,000
jointly against the two companies. ST Services and PEPCO have contested the DOT
allegations and the proposed penalty. A hearing was held before the Office of
Pipeline Safety at the DOT in late 2001. In June of 2004, the DOT issued a final
order reducing the penalty to $256,250 jointly against ST Services and PEPCO and
$74,000 against ST Services. On September 14, 2004, ST Services petitioned for
reconsideration of the order.
By letter dated January 4, 2002, the Attorney General's Office for the
State of Maryland advised ST Services that it intended to seek penalties from ST
Services in connection with the April 7, 2000 spill. The State of Maryland
subsequently asserted that it would seek penalties against ST Services and PEPCO
totaling up to $12 million. A settlement of this claim was reached in mid-2002
under which ST Services' insurer will pay a total of slightly more than $1
million in installments over a five year period. PEPCO has also reached a
settlement of these claims with the State of Maryland. Accordingly, the
Partnership believes that this matter will not have a material adverse effect on
its financial condition.
On December 13, 2002, ST Services sued PEPCO in the Superior Court,
District of Columbia, seeking, among other things, a declaratory judgment as to
ST Services' legal obligations, if any, to reimburse PEPCO for costs of the oil
spill. On December 16, 2002, PEPCO sued ST Services in the United States
District Court for the District of Maryland, seeking recovery of all its costs
for remediation of and response to the oil spill. Pursuant to an agreement
between ST Services and PEPCO, ST Services' suit was dismissed, subject to
refiling. ST Services has moved to dismiss PEPCO's suit. ST Services is
vigorously defending against PEPCO's claims and is pursuing its own
counterclaims for return of monies ST Services has advanced to PEPCO for
settlements and cleanup costs. The Partnership believes that any costs or
damages resulting from these lawsuits will be covered by insurance and therefore
will not materially adversely affect the Partnership's financial condition. The
amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy
which has a $600,000 retention, but the Partnership does not believe that such
retention, if incurred, would materially adversely affect the Partnership's
financial condition.
Paulsboro Litigation. In 2003, Exxon Mobil filed a lawsuit in a New Jersey
state court against GATX Corporation, Kinder Morgan Liquid Terminals ("Kinder
Morgan"), the successor in interest to GATX Terminals Corporation ("GATX"), and
a subsidiary of the Partnership, ST Services, seeking reimbursement for
remediation costs associated with the Paulsboro, New Jersey terminal. The
terminal was owned and operated by Exxon Mobil from the early 1950's until 1990
when purchased by GATX. ST Services purchased the terminal in 2000 from GATX.
GATX was subsequently acquired by Kinder Morgan. As a condition to the sale to
GATX in 1990, Exxon Mobil undertook certain remediation obligations with respect
to the site. In the lawsuit, Exxon Mobil is claiming that it has complied with
its remediation and contractual obligations and is entitled to reimbursement
from GATX Corporation, the parent company of GATX, Kinder Morgan, and ST
Services for costs in the amount of $400,000 that it claims are related to
releases at the site subsequent to its sale of the terminal to GATX. It is also
alleging that any remaining remediation requirements are the responsibility of
GATX Corporation, Kinder Morgan, or ST Services. Kinder Morgan has alleged that
it was relieved of any remediation obligations pursuant to the sale agreement
between its predecessor, GATX, and ST Services. ST Services believes that,
except for remediation involving immaterial amounts, GATX Corporation or Exxon
Mobil are responsible for the remaining remediation of the site. Costs of
completing the required remediation depend on a number of factors and cannot be
determined at the current time.
Ammonia Pipeline Matters. A subsidiary of the Partnership purchased the
approximately 2,000-mile ammonia pipeline system from Koch Pipeline Company,
L.P. and Koch Fertilizer Storage and Terminal Company in 2002. The rates of the
ammonia pipeline are subject to regulation by the Surface Transportation Board
(the "STB"). The STB had issued an order in May 2000, prescribing maximum
allowable rates the Partnership's predecessor could charge for transportation to
certain destination points on the pipeline system. In 2003, the Partnership
instituted a 7% general increase to pipeline rates. On August 1, 2003, CF
Industries, Inc. ("CFI") filed a complaint with the STB challenging these rate
increases. On August 11, 2004, STB ordered the Partnership to pay reparations to
CFI and to return CFI's rates to the levels permitted under the rate
prescription. The Partnership has complied with the order. The STB, however,
indicated in the order that it would lift the rate prescription in the event the
Partnership could show "materially changed circumstances." The Partnership has
submitted evidence of "materially changed circumstances," which specifically
includes its capital investment in the pipeline. CFI has argued that the
Partnership's acquisition costs should not be considered by the STB as a measure
of the Partnership's investment base. The STB is expected to decide the issue
within the second quarter of 2005.
Also, on June 16, 2003, Dyno Nobel Inc. ("Dyno") filed a complaint with the
STB challenging the 2003 rate increase on the basis that (i) the rate increase
constitutes a violation of a contract rate, (ii) rates are discriminatory and
(iii) the rates exceed permitted levels. Dyno also intervened in the CFI
proceeding described above. Unlike CFI, Dyno's rates are not subject to a rate
prescription. As of December 31, 2004, Dyno would be entitled to approximately
$2 million in rate refunds, should it be successful. The Partnership believes,
however, that Dyno's claims are without merit.
The Partnership has other contingent liabilities resulting from litigation,
claims and commitments incident to the ordinary course of business. Management
of the Partnership believes, after consulting with counsel, that the ultimate
resolution of such contingencies will not have a materially adverse effect on
the financial position, results of operations or liquidity of the Partnership.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for the Registrant's Partnership Interests and Related Partners
Matters
KPP owns a 99% interest as sole limited partner and KPL owns a 1% general
partner interest in the Partnership. There is no established public trading
market for the Partnership ownership interests.
The Partnership makes regular cash distributions, in accordance with its
partnership agreement, within 45 days after the end of each quarter to limited
partner and general partner interests.
The Partnership is a limited partnership that is not subject to federal
income tax. Instead, the partners are required to report their allocable share
of the Partnership income, gain, loss, deduction and credit, regardless of
whether the Partnership makes distributions.
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,
--------------------------------------------------------------------
2004 2003 2002 (a) 2001 (a) 2000
----------- ----------- ----------- ----------- -----------
Income Statement Data:
Revenues:
Services.......................... $ 379,155 $ 354,591 $ 288,669 $ 207,796 $ 156,232
Products.......................... 269,054 215,823 97,961 - -
----------- ----------- ----------- ----------- -----------
648,209 570,414 386,630 207,796 156,232
----------- ----------- ----------- ----------- -----------
Costs and expenses:
Cost of products sold............. 246,858 195,100 90,898 - -
Operating costs................... 176,976 168,537 131,326 90,632 69,653
Depreciation and amortization..... 56,648 53,155 39,425 23,184 16,253
Gain on sale of assets............ - - (609) - (1,126)
General and administrative........ 30,937 25,121 19,869 11,889 11,881
----------- ----------- ----------- ----------- -----------
511,419 441,913 280,909 125,705 96,661
----------- ----------- ----------- ----------- -----------
Operating income...................... 136,790 128,501 105,721 82,091 59,571
Interest and other income............. 267 261 3,570 4,277 316
Interest expense...................... (42,750) (38,757) (28,110) (14,783) (12,283)
Loss on debt extinguishment........... - - (3,282) (6,540) -
Income tax expense.................... (3,282) (5,223) (4,083) (256) (943)
----------- ----------- ----------- ----------- -----------
Income before cumulative effect of
change in accounting principle.... 91,025 84,782 73,816 64,789 46,661
Cumulative effect of change in
accounting principle - adoption of
new accounting standard for
asset retirement obligations...... - (1,593) - - -
----------- ----------- ----------- ----------- -----------
Net income ........................... $ 91,025 $ 83,189 $ 73,816 $ 64,789 $ 46,661
=========== =========== =========== =========== ===========
Cash distributions declared........... $ 107,214 $ 102,948 $ 79,816 $ 62,156 $ 53,485
=========== =========== =========== =========== ===========
Balance Sheet Data (at year end):
Property and equipment, net........... $ 1,148,591 $ 1,112,970 $ 1,092,192 $ 481,274 $ 321,355
Total assets.......................... 1,325,316 1,264,682 1,215,410 548,371 375,063
Long-term debt........................ 671,952 617,696 694,330 262,624 166,900
Partners' capital..................... 481,481 493,589 393,314 220,527 161,735
(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.
OVERVIEW
The Partnership, a limited partnership, is engaged in the refined petroleum
products and anhydrous ammonia pipeline business and the terminaling of
petroleum products and specialty liquids. Kaneb Pipe Line Partners, L.P.
("KPP"), a master limited partnership, holds a 99% interest as limited partner
in the Partnership. Kaneb Pipe Line Company LLC ("KPL"), now a wholly owned
subsidiary of Kaneb Services LLC ("KSL"), manages and controls the operations of
KPP through its general partner interest and an 18% (at December 31, 2004)
limited partner interest. KPL owns a 1% interest as general partner of the
Partnership and a 1% interest as general partner of KPP.
On October 31, 2004, Valero L.P. and KPP entered into a definitive
agreement to merge (the "KPP Merger") Valero L.P. and KPP. Under the terms of
the agreement, each holder of units of limited partnership interests in KPP will
receive a number of Valero L.P. common units based on an exchange ratio that
fluctuates within a fixed range to provide $61.50 in value of Valero L.P. units
for each unit of KPP. The actual exchange ratio will be determined at the time
of the closing of the proposed merger and is subject to a fixed value collar of
plus or minus five percent of Valero L.P.'s per unit price of $57.25 as of
October 7, 2004. Should Valero L.P.'s per unit price fall below $54.39 per unit,
the exchange ratio will remain fixed at 1.1307 Valero L.P. units for each unit
of KPP. Likewise, should Valero L.P.'s per unit price exceed $60.11 per unit of
KPP, the exchange ratio will remain fixed at 1.0231 Valero L.P. units for each
unit of KPP.
In a separate definitive agreement, on October 31, 2004, Valero L.P. agreed
to acquire by merger (the "KSL Merger") all of the outstanding common shares of
KSL for cash. Under the terms of that agreement, Valero L.P. is offering to
purchase all of the outstanding shares of KSL at $43.31 per share.
The completion of the KPP Merger is subject to the customary regulatory
approvals including those under the Hart-Scott-Rodino Antitrust Improvements
Act. The completion of the KPP Merger is also subject to completion of the KSL
Merger. All required unitholder and shareholder approvals have been obtained.
Upon completion of the mergers, the general partner of the combined partnership
will be owned by affiliates of Valero Energy Corporation and KPP and KSL will
become wholly owned subsidiaries of Valero L.P.
The Partnership's petroleum pipeline business consists primarily of the
transportation, as a common carrier, of refined petroleum products in Kansas,
Nebraska, Iowa, South Dakota, North Dakota, Colorado, Wyoming and Minnesota.
Common carrier activities are those under which transportation through the
pipelines is available at published tariffs filed, in the case of interstate
shipments with the Federal Energy Regulatory Commission (the "FERC"), or in the
case of intrastate shipments, with the relevant state authority, to any shipper
of refined petroleum products who requests such services and satisfies the
conditions and specifications for transportation. The petroleum pipelines
primarily transport gasoline, diesel oil, fuel oil and propane. Substantially
all of the petroleum pipeline operations constitute common carrier operations
that are subject to federal or state tariff regulations. The Partnership also
owns an approximately 2,000-mile anhydrous ammonia pipeline system acquired from
Koch Pipeline Company, L.P. in November of 2002 (see "Liquidity and Capital
Resources"). The fertilizer pipeline originates in southern Louisiana, proceeds
north through Arkansas and Missouri, and then branches east into Illinois and
Indiana and north and west into Iowa and Nebraska. The Partnership's petroleum
pipeline business depends on the level of demand for refined petroleum products
in the markets served by the pipelines and the ability and willingness of
refineries and marketers having access to the pipelines to supply such demand by
deliveries through the pipelines. The Partnership's pipeline revenues are based
on volumes shipped and the distance over which such volumes are transported.
The Partnership's terminaling business is one of the largest independent
petroleum products and specialty liquids terminaling companies in the United
States. In the United States, ST Services operates 41 facilities in 20 states.
ST Services also owns and operates seven terminals located in the United Kingdom
and eight terminals in Australia and New Zealand. ST Services and its
predecessors have a long history in the terminaling business and handle a wide
variety of liquids from petroleum products to specialty chemicals to edible
liquids. Statia, acquired on February 28, 2002 (see "Liquidity and Capital
Resources"), owns a terminal on the Island of St. Eustatius, Netherlands
Antilles and a terminal at Point Tupper, Nova Scotia, Canada. Independent
terminal owners generally compete on the basis of the location and versatility
of the terminals, service and price. Terminal versatility is a function of the
operator's ability to offer handling for diverse products with complex handling
requirements. The service function typically provided by the terminal includes
the safe storage of product at specified temperatures and other conditions, as
well as receipt and delivery from the terminal. The ability to obtain attractive
pricing is dependent largely on the quality, versatility and reputation of the
facility. Terminaling revenues are earned based on fees for the storage and
handling of products.
The Partnership's product sales business delivers bunker fuels to ships in
the Caribbean and Nova Scotia, Canada, and sells bulk petroleum products to
various commercial customers at those locations. In the bunkering business, the
Partnership competes with ports offering bunker fuels along the route of the
vessel. Vessel owners or charterers are charged berthing and other fees for
associated services such as pilotage, tug assistance, line handling, launch
service and emergency response services.
CONSOLIDATED RESULTS OF OPERATIONS
Year Ended December 31,
---------------------------------------------------
2004 2003 2002
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 648,209 $ 570,414 $ 386,630
=========== =========== ===========
Operating income..................................... $ 136,790 $ 128,501 $ 105,721
=========== =========== ===========
Income before cumulative effect of change in
accounting principle............................. $ 91,025 $ 84,782 $ 73,816
Cumulative effect of change in accounting principle.. - (1,593) -
----------- ---------- -----------
Net income........................................... $ 91,025 $ 83,189 $ 73,816
=========== =========== ===========
Capital expenditures, excluding acquisitions......... $ 42,214 $ 44,741 $ 31,101
=========== =========== ===========
For the year ended December 31, 2004, revenues increased by $77.8 million,
or 14%, when compared to 2003, due to a $53.2 million increase in revenues in
the product sales business (see "Product Sales Operations" below), a $24.4
million increase in revenues in the terminaling business (see "Terminaling
Operations" below) and a $0.2 million increase in pipeline revenues (see
"Pipeline Operations" below). Operating income for the year ended December 31,
2004 increased by $8.3 million, or 6%, when compared to 2003, due to an $8.1
million increase in terminaling operating income and a $3.2 million increase in
product sales operating income, partially offset by a $3.0 million decrease in
pipeline operating income. 2004 operating income is after $2.2 million of costs
associated with the Valero L.P. merger agreement and compliance with the
Sarbanes-Oxley Act of 2002. Income before cumulative effect of change in
accounting principle increased by $6.2 million, or 7%, when compared to 2003.
Overall, 2004 net income increased by $7.8 million, or 9%, when compared to
2003, which included a change of $1.6 million for the cumulative effect of
change in accounting principle - adoption of new accounting standard for asset
retirement obligations.
For the year ended December 31, 2003, revenues increased by $183.8 million,
or 48%, when compared to 2002, due to a $36.9 million increase in revenues in
the pipeline business, a $29.0 million increase in revenues in the terminaling
business and a $117.9 million increase in product sales revenues. See "Liquidity
and Capital Resources" regarding 2002 acquisitions. Operating income for the
year ended December 31, 2003 increased by $22.8 million, or 22%, when compared
to 2002, due to a $13.2 million increase in pipeline operating income, a $1.5
million increase in terminaling operating income and an $8.1 million increase in
product sales operating income. Income before cumulative effect of change in
accounting principle increased by $11.0 million, or 15%, when compared to 2002.
Overall, 2003 net income, including a charge of $1.6 million for the cumulative
effect of change in accounting principle - adoption of new accounting standard
for asset retirement obligations, increased by $9.4 million, or 13%, when
compared to 2002.
PIPELINE OPERATIONS
Year Ended December 31,
---------------------------------------------------
2004 2003 2002
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 119,803 $ 119,633 $ 82,698
Operating costs...................................... 48,306 46,379 33,744
Depreciation and amortization........................ 14,538 14,117 6,408
General and administrative........................... 8,106 7,277 3,923
----------- ----------- -----------
Operating income..................................... $ 48,853 $ 51,860 $ 38,623
=========== =========== ===========
The Partnership's pipeline revenues are based on volumes shipped and the
distances over which such volumes are transported. Because tariff rates are
regulated by the FERC or STB, the pipelines compete on the basis of quality of
service, including delivering products at convenient locations on a timely basis
to meet the needs of its customers. For the year ended December 31, 2004,
revenues increased by $0.2 million, when compared to 2003, due to increases in
barrel miles of products shipped on petroleum pipelines, substantially offset by
lower prices received for products shipped on the anhydrous ammonia pipeline.
For the year ended December 31, 2003, revenues increased by $36.9 million, or
45%, when compared to 2002, due entirely to the November and December 2002
pipeline acquisitions (see "Liquidity and Capital Resources"). Barrel miles on
petroleum pipelines totaled 22.2 billion, 21.3 billion (including 4.7 billion
for the petroleum pipeline acquired in December 2002) and 18.3 billion for the
years ended December 31, 2004, 2003 and 2002, respectively. Total volumes
shipped on the anhydrous ammonia pipeline aggregated 1,123 thousand tons in 2004
and 1,157 thousand tons in 2003.
Operating costs, which include fuel and power costs, materials and
supplies, maintenance and repair costs, salaries, wages and employee benefits,
and property and other taxes, increased by $1.9 million in 2004 and $12.6
million in 2003. The increase in 2004, when compared to 2003, was due to
unusually high expenses relating to preventive and other maintenance and
repairs, including those required by government regulation, and increases in
power and fuel costs. The increase in 2003, when compared to 2002, was due to
the pipeline acquisitions and increases in expenditures for routine repairs and
maintenance. For the year ended December 31, 2004, depreciation and amortization
increased by $0.4 million, when compared to 2003, due primarily to routine
maintenance capital expenditures. For the year ended December 31, 2003,
depreciation and amortization increased by $7.7 million, when compared to 2002,
due to the pipeline acquisitions and routine maintenance capital expenditures.
General and administrative costs, which includes managerial, accounting and
administrative personnel costs, office rental expense, legal and professional
costs and other non-operating costs increased by $0.8 million in 2004, when
compared to 2003, due primarily to costs associated with the Valero L.P. merger
agreement, compliance with the Sarbanes-Oxley Act of 2002 and increases in
personnel-related costs. General and administrative costs for the year ended
December 31, 2003 increased by $3.4 million, when compared to 2002, due to the
pipeline acquisitions and increases in personnel-related costs.
TERMINALING OPERATIONS
Year Ended December 31,
---------------------------------------------------
2004 2003 2002
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 259,352 $ 234,958 $ 205,971
Operating costs...................................... 122,791 114,030 94,480
Depreciation and amortization........................ 41,232 38,089 32,368
Gain on sale of assets............................... - - (609)
General and administrative........................... 20,666 16,307 14,692
----------- ----------- -----------
Operating income..................................... $ 74,663 $ 66,532 $ 65,040
=========== =========== ===========
For the year ended December 31, 2004, the Partnership's terminaling
revenues increased by $24.4 million, or 10%, when compared to 2003, due to
increases in both tankage utilization and the average price realized per barrel
of tankage utilized. For the year ended December 31, 2003, the Partnership's
terminaling revenues increased by $29.0 million, or 14%, when compared to 2002,
due to the 2002 terminal acquisitions (see "Liquidity and Capital Resources")
and overall increases in the average price realized per barrel of tankage
utilized. Approximately $25 million of the 2003 revenue increase was a result of
the terminal acquisitions. Average annual tankage utilized for the years ended
December 31, 2004, 2003 and 2002 aggregated 48.9 million barrels, 46.7 million
barrels and 46.5 million barrels, respectively. Average revenues per barrel of
tankage utilized for the years ended December 31, 2004, 2003 and 2002 was $5.30,
$5.02 and $4.43, respectively. The increase in 2004 average revenues per barrel
of tankage utilized was primarily the result of favorable market conditions
domestically and in Australia and New Zealand and favorable foreign currency
exchange differences. The increase in 2003 average revenues per barrel of
tankage utilized was the result of changes in product mix resulting from the
2002 terminals acquisitions and favorable foreign currency exchange differences.
For year ended December 31, 2004, operating costs increased by $8.8
million, when compared to 2003, due to an overall increase in planned terminal
maintenance. In 2003, operating costs increased by $19.6 million, when compared
to 2002, due to the 2002 terminal acquisitions, repair costs associated with
hurricane Isabel and increases in planned maintenance. For the year ended
December 31, 2004, depreciation and amortization increased by $3.1 million, when
compared to 2003, due to expansion and routine maintenance capital expenditures.
For the year ended December 31, 2003, depreciation and amortization increased by
$5.7 million, when compared to 2002, due to the 2002 terminal acquisitions. In
2002, KPP sold land and other terminaling business assets for net proceeds of
approximately $1.1 million, recognizing a gain on disposition of assets of $0.6
million. General and administrative expenses increased by $4.4 million in 2004,
when compared to 2003, due to increases in personnel-related costs and costs
associated with the Valero L.P. merger agreement and compliance with the
Sarbanes-Oxley Act of 2002. General and administrative expenses increased by
$1.6 million in 2003, when compared to 2002, due to the terminal acquisitions
and increases in personnel-related costs.
PRODUCT SALES OPERATIONS
Year Ended December 31,
---------------------------------------------------
2004 2003 2002
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 269,054 $ 215,823 $ 97,961
Cost of products sold................................ 246,858 195,100 90,898
----------- ----------- -----------
Gross margin......................................... $ 22,196 $ 20,723 $ 7,063
=========== =========== ===========
Operating income..................................... $ 13,274 $ 10,109 $ 2,058
=========== =========== ===========
The product sales business, which was acquired with Statia (see "Liquidity
and Capital Resources"), delivers bunker fuels to ships in the Caribbean and
Nova Scotia, Canada and sells bulk petroleum products to various commercial
interests. For the year ended December 31, 2004, product sales revenues
increased by $53.2 million, or 25%, when compared to 2003, due to an overall
increase in volumes sold and a general increase in prices. Approximately $44.9
million of the revenue increase was due to volume increases and $8.3 million was
due to price increases, when compared to 2003. Gross margin for the year ended
December 31, 2004, increased by $1.5 million, when compared to 2003, due to the
increase in volumes sold and favorable variations in prices resulting from the
timing of purchases and sales. Operating income for 2004 increased $3.2 million,
when compared to 2003, due to higher sales volumes.
For the year ended December 31, 2003, product sales revenues, gross margin
and operating income increased by $117.9 million, $13.7 million and $8.1
million, respectively, when compared to 2002, due to increases in both sales
price and volumes. Approximately $95.8 million of the 2003 revenue increase was
due to volume increases and $22.1 million was due to price increases, when
compared to 2002. The results of operations for the year ended December 31, 2002
include the operations of the product sales business since the date of
acquisition, February 28, 2002.
Product inventories are maintained at minimum levels to meet customers'
needs; however, market prices for petroleum products can fluctuate significantly
in short periods of time.
INTEREST AND OTHER INCOME
In September of 2002, the Partnership entered into a treasury lock
contract, maturing on November 4, 2002, for the purpose of locking in the US
Treasury interest rate component on $150 million of anticipated thirty-year
public debt offerings. The treasury lock contract originally qualified as a cash
flow hedging instrument under Statement of Financial Accounting Standards
("SFAS") No. 133. In October of 2002, the Partnership, due to various market
factors, elected to defer issuance of the public debt securities, effectively
eliminating the cash flow hedging designation for the treasury lock contract. On
October 29, 2002, the contract was settled resulting in a net realized gain of
$3.0 million, which was recognized as a component of interest and other income.
INTEREST EXPENSE
For the year ended December 31, 2004, interest expense increased by $4.0
million, when compared to 2003, due to the May 2003 refinancing of variable rate
debt with $250 million of 5.875% senior unsecured notes (see "Liquidity and
Capital Resources") and overall increases in interest rates on remaining
variable rate debt.
For the year ended December 31, 2003, interest expense increased by $10.6
million, when compared to 2002, due to increases in fixed rate debt resulting
from the 2002 pipeline and terminal acquisitions (see "Liquidity and Capital
Resources"), partially offset by overall declines in interest rates on variable
rate debt.
INCOME TAXES
Partnership operations are not subject to federal or state income taxes.
However, certain operations are conducted through separate taxable wholly-owned
U.S. and foreign corporate subsidiaries. The income tax expense for these
subsidiaries was $3.3 million, $5.2 million and $4.1 million for the years ended
December 31, 2004, 2003 and 2002, respectively.
On June 1, 1989, the governments of the Netherlands Antilles and St.
Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January
1, 1989, which expired on December 31, 2000. This agreement required a
subsidiary of the Partnership, which was acquired with Statia on February 28,
2002, to pay a 2% rate on taxable income, as defined therein, or a minimum
payment of 500,000 Netherlands Antilles guilders ($0.3 million) per year. The
agreement further provided that any amounts paid in order to meet the minimum
annual payment were available to offset future tax liabilities under the
agreement to the extent that the minimum annual payment is greater than 2% of
taxable income. The subsidiary is currently engaged in discussions with
representatives appointed by the Island Territory of St. Eustatius regarding the
renewal or modification of the agreement, but the ultimate outcome cannot be
predicted at this time. The subsidiary has accrued amounts assuming a new
agreement becomes effective, and continues to make payments, as required, under
the previous agreement.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities was $132.3 million, $142.0 million
and $91.8 million for the years ended December 31, 2004, 2003 and 2002,
respectively. The decrease in 2004 operating cash flows, when compared to 2003,
was due primarily to changes in working capital and other liabilities resulting
from the timing of cash receipts and disbursements and costs associated with the
Valero L.P. merger agreement and compliance with the Sarbanes-Oxley Act of 2002,
partially offset by an overall increase in net income. The increase in 2003,
when compared to 2002, was due to increases in pipeline, terminaling and product
sales revenues and operating income, primarily a result of the 2002
acquisitions, and changes in working capital components from the timing of cash
receipts and disbursements.
Capital expenditures, including routine maintenance and expansion
expenditures, but excluding acquisitions, were $42.2 million, $44.7 million and
$31.1 million for the years ended 2004, 2003 and 2002, respectively. Such
expenditures included $30.8 million and $20.3 million in maintenance and
environmental expenditures and $11.4 million and $24.4 million in expansion
expenditures for the years ended December 31, 2004 and 2003, respectively. The
decrease in 2004 capital expenditures, when compared to 2003, is primarily the
result of decreases in planned expansion capital expenditures related to the
terminaling business. The increase in 2003 capital expenditures, when compared
to 2002, is the result of planned maintenance and expansion capital expenditures
related to the pipeline and terminaling operations acquired in 2002 and planned
maintenance capital expenditures in the existing pipeline and terminaling
businesses. During all periods, adequate pipeline capacity existed to
accommodate volume growth, and the expenditures required for environmental and
safety improvements were not, and are not expected in the future to be,
significant. Environmental damages are included under the Partnership's
insurance coverages (subject to deductibles and limits). The Partnership
anticipates that capital expenditures (including routine maintenance and
expansion expenditures, but excluding acquisitions) will total approximately $40
million to $44 million in 2005. Such future expenditures, however, will depend
on many factors beyond the Partnership's control, including, without limitation,
demand for refined petroleum products and terminaling services in the
Partnership's market areas, local, state and federal government regulations,
fuel conservation efforts and the availability of financing on acceptable terms.
No assurance can be given that required capital expenditures will not exceed
anticipated amounts during the year or thereafter or that the Partnership will
have the ability to finance such expenditures through borrowings, or choose to
do so.
The Partnership makes regular cash distributions in accordance with its
Partnership agreement within 45 days after the end of each quarter to limited
partner and general partner interests. Aggregate distributions of $106.6
million, $98.2 million and $74.4 million, were paid to limited partner interests
and general partner interests in 2004, 2003 and 2002, respectively.
The Partnership expects to fund future cash distributions and routine
maintenance capital expenditures with existing cash and anticipated cash flows
from operations. Expansionary capital expenditures are expected to be funded
through additional Partnership bank borrowings and/or future public debt
offerings or KPP public equity offerings.
In January of 2002, KPP issued 1,250,000 limited partnership units in a
public offering at $41.65 per unit, generating approximately $49.7 million in
net proceeds. The proceeds were used to reduce borrowings under the
Partnership's revolving credit agreement.
In February of 2002, the Partnership issued $250 million of 7.75% senior
unsecured notes due February 15, 2012. The net proceeds from the public
offering, $248.2 million, were used to repay the Partnership's revolving credit
agreement and to partially fund the acquisition of all of the liquids
terminaling subsidiaries of Statia Terminals Group NV ("Statia"). Under the note
indenture, interest is payable semi-annually in arrears on February 15 and
August 15 of each year. The notes are redeemable, as a whole or in part, at the
option of the Partnership, at any time, at a redemption price equal to the
greater of 100% of the principal amount of the notes, or the sum of the present
value of the remaining scheduled payments of principal and interest, discounted
to the redemption date at the applicable U.S. Treasury rate, as defined in the
indenture, plus 30 basis points. The note indenture contains certain financial
and operational covenants, including certain limitations on investments, sales
of assets and transactions with affiliates and, absent anevent of default, such
covenants do not restrict distributions to partners. At December 31, 2004, the
Partnership was in compliance with all covenants.
On February 28, 2002, the Partnership acquired Statia for approximately
$178 million in cash (net of acquired cash). The acquired Statia subsidiaries
had approximately $107 million in outstanding debt, including $101 million of
11.75% notes due in November 2003. The cash portion of the purchase price was
initially funded by the Partnership's revolving credit agreement and proceeds
from the Partnership's February 2002 public debt offering. In April of 2002, the
Partnership redeemed all of Statia's 11.75% notes at 102.938% of the principal
amount, plus accrued interest. The redemption was funded by the Partnership's
revolving credit facility. Under the provisions of the 11.75% notes, the
Partnership incurred a $3.0 million prepayment penalty, of which $2.0 million
was recognized as loss on debt extinguishment in 2002.
In May of 2002, KPP issued 1,565,000 limited partnership units in a public
offering at a price of $39.60 per unit, generating approximately $59.1 million
in net proceeds. A portion of the offering proceeds were used to fund its
September 2002 acquisition of the Australia and New Zealand terminals.
On September 18, 2002, the Partnership acquired eight bulk liquid storage
terminals in Australia and New Zealand from Burns Philp & Co. Ltd. for
approximately $47 million in cash.
On November 1, 2002, the Partnership acquired an approximately 2,000-mile
anhydrous ammonia pipeline system from Koch Pipeline Company, L.P. for
approximately $139 million in cash. This fertilizer pipeline system originates
in southern Louisiana, proceeds north through Arkansas and Missouri, and then
branches east into Illinois and Indiana and north and west into Iowa and
Nebraska. The acquisition was initially financed with bank debt.
In November of 2002, KPP issued 2,095,000 limited partnership units in a
public offering at $33.36 per unit, generating approximately $66.7 million in
net proceeds. The offering proceeds were used to reduce bank borrowings for the
fertilizer pipeline acquisition.
On December 24, 2002, the Partnership acquired a 400-mile petroleum
products pipeline and four terminals in North Dakota and Minnesota from Tesoro
Refining and Marketing Company for approximately $100 million in cash, subject
to normal post-closing adjustments. The acquisition was initially funded with
bank debt.
In March of 2003, KPP issued 3,122,500 limited partnership units in a
public offering at $36.54 per unit, generating approximately $109.1 million in
net proceeds. The proceeds were used to reduce bank borrowings.
In April of 2003, the Partnership entered into a credit agreement with a
group of banks that provides for a $400 million unsecured revolving credit
facility through April of 2006. The credit facility, which provides for an
increase in the commitment up to an aggregate of $450 million by mutual
agreement between the Partnership and the banks, bears interest at variable
rates and has a variable commitment fee on unused amounts. The credit facility
contains certain financial and operating covenants, including limitations on
investments, sales of assets and transactions with affiliates and, absent an
event of default, does not restrict distributions to partners. At December 31,
2004, the Partnership was in compliance with all covenants. Initial borrowings
on the credit agreement ($324.2 million) were used to repay all amounts
outstanding under the Partnership's $275 million credit agreement and $175
million bridge loan agreement. At December 31, 2004, $95.7 million was
outstanding under the credit agreement.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior
unsecured notes due June 1, 2013. The net proceeds from the public offering,
$247.6 million, were used to reduce amounts due under the 2003 revolving credit
agreement. Under the note indenture, interest is payable semi-annually in
arrears on June 1 and December 1 of each year. The notes are redeemable, as a
whole or in part, at the option of the Partnership, at any time, at a redemption
price equal to the greater of 100% of the principal amount of the notes, or the
sum of the present value of the remaining scheduled payments of principal and
interest, discounted to the redemption date at the applicable U.S. Treasury
rate, as defined in the indenture, plus 30 basis points. The note indenture
contains certain financial and operational covenants, including certain
limitations on investments, sales of assets and transactions with affiliates
and, absent an event of default, such covenants do not restrict distributions to
partners. At December 31, 2004, the Partnership was in compliance with all
covenants. In connection with the offering, on May 8, 2003, the Partnership
entered into a treasury lock contract for the purpose of locking in the US
Treasury interest rate component on $100 million of the debt. The treasury lock
contract, which qualified as a cash flow hedging instrument under SFAS No. 133,
was settled on May 19, 2003 with a cash payment by the Partnership of $1.8
million. The settlement cost of the contract has been recorded as a component of
accumulated other comprehensive income and is being amortized, as interest
expense, over the life of the debt.
The following is a schedule by period of the Partnership's debt repayment
obligations and material contractual commitments at December 31, 2004:
Less than After
Total 1 year 1 -3 years 4 -5 years 5 years
---------- ---------- ---------- ----------- -----------
(in thousands)
Debt:
Revolving credit facility......... $ 95,669 $ - $ 95,669 $ - $ -
7.75% senior unsecured notes...... 250,000 - - - 250,000
5.875% senior unsecured notes..... 250,000 - - - 250,000
Other bank debt................... 76,283 - 76,283 - -
----------- ----------- --------- ---------- ----------
Debt subtotal.................. 671,952 - 171,952 - 500,000
----------- ----------- --------- ---------- ----------
Contractual commitment -
Operating leases.................. 51,905 9,756 14,717 9,292 18,140
----------- ----------- --------- ---------- ----------
Total.......................... $ 723,857 $ 9,756 $ 186,669 $ 9,292 $ 518,140
=========== =========== ========= ========== ==========
See also "Item 1 - Environmental Matters" and "Item 3 - Legal Proceedings".
OFF-BALANCE SHEET TRANSACTIONS
The Partnership was not a party to any off-balance sheet transactions at
December 31, 2004, or for any of the years ended December 31, 2004, 2003 or
2002.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the Partnership's financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates. Significant accounting policies are included in the Notes
to the Consolidated Financial Statements of the Partnership.
Critical accounting policies are those that are most important to the
portrayal of the Partnership's financial position and results of operations.
These policies require management's most difficult, subjective or complex
judgments, often employing the use of estimates about the effect of matters that
are inherently uncertain. The Partnership's most critical accounting policies
pertain to impairment of property and equipment and environmental costs.
The carrying value of property and equipment is periodically evaluated
using management's estimates of undiscounted future cash flows, or, in some
cases, third-party appraisals, as the basis of determining if impairment exists
under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets", which was adopted effective January 1, 2002. To the
extent that impairment is indicated to exist, an impairment loss is recognized
under SFAS No. 144 based on fair value. The application of SFAS No. 144 did not
have a material impact on the results of operations of the Partnership for the
years ended December 31, 2004, 2003 or 2002. However, future evaluations of
carrying value are dependent on many factors, several of which are out of the
Partnership's control, including demand for refined petroleum products and
terminaling services in the Partnership's market areas, and local, state and
federal governmental regulations. To the extent that such factors or conditions
change, it is possible that future impairments might occur, which could have a
material effect on the results of operations of the Partnership.
Environmental expenditures that relate to current operations are expensed
or capitalized, as appropriate. Expenditures that relate to an existing
condition caused by past operations, and which do not contribute to current or
future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or remedial efforts are probable, and the costs
can be reasonably estimated. Generally, the timing of these accruals coincides
with the completion of a feasibility study or the Partnership's commitment to a
formal plan of action. The application of the Partnership's environmental
accounting policies did not have a material impact on the results of operations
of the Partnership for the years ended December 31, 2004, 2003 or 2002. Although
the Partnership believes that its operations are in general compliance with
applicable environmental regulations, risks of substantial costs and liabilities
are inherent in pipeline and terminaling operations. Moreover, it is possible
that other developments, such as increasingly strict environmental laws,
regulations and enforcement policies thereunder, and legal claims for damages to
property or persons resulting from the operations of the Partnership could
result in substantial costs and liabilities, any of which could have a material
effect on the results of operations of the Partnership.
Item 7(a). Quantitative and Qualitative Disclosures About Market Risk
The principal market risks pursuant to this Item (i.e., the risk of loss
arising from the adverse changes in market rates and prices) to which the
Partnership is exposed are interest rates on the Partnership's debt and
investment portfolios, fluctuations of petroleum product prices on inventories
held for resale, and fluctuations in foreign currency.
The Partnership's investment portfolio consists of cash equivalents;
accordingly, the carrying amounts approximate fair value. The Partnership's
investments are not material to its financial position or performance. Assuming
variable rate debt of $131.2 million at December 31, 2004, a one percent
increase in interest rates would increase annual net interest expense by
approximately $1.3 million. Information regarding the Partnership's interest
rate hedging transactions are included in "Item 7 -Interest and Other Income"
and "Item 7 - Liquidity and Capital Resources".
The product sales business periodically purchases refined petroleum
products for resale as bunker fuel and sales to commercial interests. Petroleum
inventories are generally held for short periods of time, not exceeding 90 days.
As the Partnership does not engage in derivative transactions to hedge the value
of the inventory, it is subject to market risk from changes in global oil
markets.
Item 8. Financial Statements and Supplementary Data
The financial statements and supplementary data of the Partnership begin on
page F-1 of this report. Such information is hereby incorporated by reference
into this Item 8.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
Item 9(a). Controls and Procedures
Kaneb Pipe Line Company LLC's principal executive officer and principal
financial officer, after evaluating as of December 31, 2004, the effectiveness
of the Partnership's disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934), have concluded
that, as of such date, the Partnership's disclosure controls and procedures are
adequate and effective to ensure that material information relating to the
Partnership and its consolidated subsidiaries would be made known to them by
others within those entities.
During the fourth quarter of 2004, there have been no changes in the
Partnership's internal controls over financial reporting that have materially
affected, or are reasonably likely to materially affect, those internal controls
subsequent to the date of the evaluation. As a result, no corrective actions
were required or undertaken.
PART III
Item 10. Directors and Executive Officers of the Registrant
The Partnership does not have directors or officers. All directors of the
general partner are elected annually by KPL. All officers serve at the
discretion of the directors. The information contained in Item 10 of KPP's Form
10-K, for the year ended December 31, 2004, is incorporated by reference in this
report.
CODE OF ETHICS
The Partnership has adopted a Code of Ethics applicable to all employees,
including the principal executive officer, principal financial officer and
directors of the General Partner. The Partnership has also adopted Corporate
Governance Guidelines, which address director qualification standards; director
access to management, and as necessary and appropriate, independent advisors;
director compensation; director orientation and continuing education; management
succession and annual performance evaluation of the board. Copies of the Code of
Ethics and the Corporate Governance Guidelines are available on Kaneb's website
at www.kaneb.com and will be provided without charge by written request to
Investor Relations, 2435 North Central Expressway, Richardson, Texas 75080.
Item 11. Executive Compensation
The officers of the general partner manage and operate the Partnership's
business. The Partnership does not directly employ any of the persons
responsible for managing or operating the Partnership's operations, but instead
reimburses the general partner for the services of such persons. The information
contained in Item 11 of KPP's Form 10-K for the year ended December 31, 2004, is
incorporated by reference in this report.
Item 12. Security Ownership of Certain Beneficial Owners and Management
KPP owns a 99% interest as the sole limited partner and KPL owns a 1%
general partner interest in the Partnership. Information identifying security
ownership by the Directors and Officers of KPL is contained in Item 12 of KPP's
Form 10-K for the year ended December 31, 2004, and is incorporated by reference
in this report.
Item 13. Certain Relationships and Related Transactions
KPL is entitled to certain reimbursements under the Partnership Agreement.
For additional information regarding the nature and amount of such
reimbursements, see Note 7 to the Partnership's consolidated financial
statements.
Item 14. Principal Accounting Fees and Services
The information contained in Item 14 of KPP's Form 10-K for the year ended
December 31, 2004 is incorporated by reference in this report.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(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:
Report of Independent Registered Public Accounting Firm.................................. F - 1
Consolidated Statements of Income - Three Years Ended December 31, 2004................... F - 2
Consolidated Balance Sheets - December 31, 2004 and 2003.................................. F - 3
Consolidated Statements of Cash Flows - Three Years Ended December 31, 2004............... F - 4
Consolidated Statements of Partners' Capital - Three Years ended December 31, 2004........ F - 5
Notes to Consolidated Financial Statements................................................ F - 6
(a) (2)Financial Statement Schedules
Set forth below is the financial statement schedule appearing in this
report.
Schedule II - Kaneb Pipe Line Operating Partnership, L.P. Valuation and Qualifying Accounts
- Years Ended December 31, 2004, 2003 and 2002........................................... F -22
Schedules, other than the one listed above, have been omitted because
of the absence of the conditions under which they are required or
because the required information is included in the consolidated
financial statements or related notes thereto.
(a) (3)List of Exhibits
2.1 Agreement and Plan of Merger dated as of October 31, 2004, filed
as Exhibit 2.1 to Registrant's Form 8-K, filed October 31, 2004,
which exhibit is hereby incorporated by reference.
3.1 Amended and Restated Agreement of Limited Partnership, dated
September 27, 1989, filed as Exhibit 3.1 to the Registrant's Form
10-K for the year ended December 31, 2001, which exhibit is
hereby incorporated by reference.
3.2 Amendment to Amended and Restated Agreement of Limited
Partnership dated October 27, 2003, filed as Exhibit 3.2 to the
Registrant's Form 10-K for the year ended December 31, 2003,
which exhibit is hereby incorporated by reference.
10.1 Formation and Purchase Agreement, between and among Support
Terminal Operating Partnership, L.P., Northville Industries Corp.
and AFFCO, Corp., dated October 30, 1998, filed as exhibit 10.9
to KPP's Form 10-K for the year ended December 31, 1998, which
exhibit is hereby incorporated by reference.
10.2 Credit Agreement, between and among, Kaneb Pipe Line Operating
Partnership, L.P., ST Services, Ltd. and SunTrust Bank, Atlanta,
dated January 27, 1999, filed as Exhibit 10.11 to KPP's Form 10-K
for the year ended December 31, 1998, which exhibit is hereby
incorporated by reference.
10.3 Revolving Credit Agreement, dated as of April 24, 2003 among
Kaneb Pipe Line Operating Partnership, L.P., Kaneb Pipe Line
Partners, L.P., The Lenders From Time To Time Party Hereto, and
SunTrust Bank, as Administrative Agent, filed as Exhibit 10.11 to
the Registrant's Form 10-Q for the period ended March 31, 2003,
which exhibit is hereby incorporated by reference.
10.4*Amended and Restated Kaneb LLC 2002 Long Term Incentive Plan,
dated June 30, 2003, filed as Exhibit 10.1 to the exhibits to
Registrant's Form 10-Q for the period ended June 30, 2003, and
incorporated herein by reference. 10.5* Supplement to the Kaneb
LLC 2002 Long Term Incentive Plan, dated effective as of October
31, 2004, between Kaneb LLC and the participant named therein,
filed as Exhibit 10.1 to the exhibits to Registrant's Current
Report on Form 8-K file November 3, 2004, and incorporated herein
by reference.
21 List of Subsidiaries, filed herewith.
22 Form S-4, as amended and filed January 25, 2005, by Valero L.P.,
and incorporated herein by reference.
23 Consent of KPMG LLP, filed herewith.
31.1 Certification of Chief Executive Officer, Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002, dated as of March 16, 2005.
31.2 Certification of Chief Financial Officer, Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002, dated as of March 16, 2005.
32.1 Certification of Chief Executive Officer, Pursuant to Section
906(a) of the Sarbanes-Oxley Act of 2002, dated as of March 16,
2005.
32.2 Certification of Chief Financial Officer, Pursuant to Section
906(a) of the Sarbanes-Oxley Act of 2002, dated as of March 16,
2005.
* Denotes management contract.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Kaneb Pipe Line Operating Partnership, L.P.
We have audited the consolidated financial statements of Kaneb Pipe Line
Operating Partnership, L.P. and its subsidiaries (the "Partnership") as listed
in the index appearing under Item 15(a)(1). In connection with our audits of the
consolidated financial statements, we have also audited the financial statement
schedule as listed in the index appearing under Item 15(a)(2). These
consolidated financial statements and financial statement schedule are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on the consolidated financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with standards of the Public Company
Accounting Standards Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Partnership as
of December 31, 2004 and 2003, and the results of its operations and its cash
flows for each of the years in the three-year period ended December 31, 2004, in
conformity with U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when considered in relation
to the basic consolidated financial statements taken as a whole, presents
fairly, in all material respects the information set forth therein.
As described in Note 2, the Partnership adopted Statement of Financial
Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" in
2003.
KPMG LLP
Dallas, Texas
March 11, 2005
F - 1
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
-----------------------------------------------------------
2004 2003 2002
----------------- ----------------- -----------------
Revenues:
Services........................................... $ 379,155,000 $ 354,591,000 $ 288,669,000
Products........................................... 269,054,000 215,823,000 97,961,000
------------- ------------- --------------
Total revenues.................................. 648,209,000 570,414,000 386,630,000
------------- ------------- --------------
Costs and expenses:
Cost of products sold.............................. 246,858,000 195,100,000 90,898,000
Operating costs.................................... 176,976,000 168,537,000 131,326,000
Depreciation and amortization...................... 56,648,000 53,155,000 39,425,000
Gain on sale of assets............................. - - (609,000)
General and administrative......................... 30,937,000 25,121,000 19,869,000
------------- ------------- --------------
Total costs and expenses........................ 511,419,000 441,913,000 280,909,000
------------- ------------- --------------
Operating income...................................... 136,790,000 128,501,000 105,721,000
Interest and other income............................. 267,000 261,000 3,570,000
Interest expense...................................... (42,750,000) (38,757,000) (28,110,000)
Loss on debt extinguishment........................... - - (3,282,000)
------------- ------------- --------------
Income before income taxes and cumulative effect of
change in accounting principle..................... 94,307,000 90,005,000 77,899,000
Income tax expense.................................... (3,282,000) (5,223,000) (4,083,000)
------------- ------------- ---------------
Income before cumulative effect of change in
accounting principle............................... 91,025,000 84,782,000 73,816,000
Cumulative effect of change in accounting principle -
adoption of new accounting standard for asset
retirement obligations............................. - (1,593,000) -
------------- ------------- --------------
Net income ........................................... $ 91,025,000 $ 83,189,000 $ 73,816,000
============= ============= ==============
See notes to consolidated financial statements.
F - 2
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------------------------
2004 2003
---------------- ----------------
ASSETS
Current assets:
Cash and cash equivalents............................................... $ 34,336,000 $ 38,626,000
Accounts receivable (net of allowance for doubtful accounts
of $1,283,000 in 2004 and $1,693,000 in 2003)........................ 71,035,000 51,864,000
Inventories............................................................. 15,519,000 9,324,000
Prepaid expenses and other.............................................. 12,371,000 9,205,000
---------------- ----------------
Total current assets................................................. 133,261,000 109,019,000
---------------- ----------------
Property and equipment..................................................... 1,450,972,000 1,360,319,000
Less accumulated depreciation.............................................. 302,381,000 247,349,000
---------------- ----------------
Net property and equipment........................................... 1,148,591,000 1,112,970,000
---------------- ----------------
Investment in affiliates................................................... 25,939,000 25,456,000
Excess of cost over fair value of net assets of acquired business and
other assets............................................................ 17,525,000 17,237,000
---------------- ----------------
$ 1,325,316,000 $ 1,264,682,000
================ ================
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable........................................................ $ 44,071,000 $ 27,941,000
Accrued expenses........................................................ 28,894,000 31,642,000
Accrued distributions payable........................................... 26,960,000 26,344,000
Accrued interest payable................................................ 9,365,000 9,297,000
Accrued taxes, other than income taxes.................................. 4,828,000 4,031,000
Deferred terminaling fees............................................... 8,851,000 7,061,000
Payable to general partner.............................................. 4,528,000 3,630,000
---------------- ----------------
Total current liabilities............................................ 127,497,000 109,946,000
---------------- ----------------
Long-term debt............................................................. 671,952,000 617,696,000
Other liabilities and deferred taxes....................................... 44,386,000 43,451,000
Commitments and contingencies
Partners' capital:
Limited partner......................................................... 464,263,000 480,323,000
General partner......................................................... 820,000 894,000
Accumulated other comprehensive income.................................. 16,398,000 12,372,000
---------------- ----------------
Total partners' capital.............................................. 481,481,000 493,589,000
---------------- ----------------
$ 1,325,316,000 $ 1,264,682,000
================ ================
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,
---------------------------------------------------------
2004 2003 2002
------------- ------------- --------------
Operating activities:
Net income ........................................ $ 91,025,000 $ 83,189,000 $ 73,816,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization................... 56,648,000 53,155,000 39,425,000
Equity in earnings of affiliates, net of
distributions................................. (483,000) 148,000 (3,164,000)
Gain on sale of assets.......................... - - (609,000)
Deferred income taxes........................... (671,000) 1,683,000 3,105,000
Cumulative effect of change in accounting
principle..................................... - 1,593,000 -
Other liabilities............................... (1,666,000) 1,190,000 (1,341,000)
Changes in working capital components:
Accounts receivable........................... (19,171,000) (2,938,000) (12,379,000)
Inventories, prepaid expenses and other....... (9,361,000) (5,109,000) (6,601,000)
Accounts payable and accrued expenses......... 15,112,000 10,829,000 (1,192,000)
Payable to general partner.................... 898,000 (1,773,000) 702,000
-------------- ------------- --------------
Net cash provided by operating activities.. 132,331,000 141,967,000 91,762,000
-------------- ------------- --------------
Investing activities:
Acquisitions, net of cash acquired................. (41,853,000) (1,644,000) (468,477,000)
Capital expenditures............................... (42,214,000) (44,741,000) (31,101,000)
Proceeds from sale of assets....................... - - 1,107,000
Other, net......................................... 1,327,000 (1,109,000) 306,000
-------------- ------------- --------------
Net cash used in investing activities...... (82,740,000) (47,494,000) (498,165,000)
-------------- ------------- ---------------
Financing activities:
Issuance of debt................................... 51,080,000 291,377,000 746,087,000
Payments of debt................................... - (382,831,000) (426,647,000)
Distributions...................................... (106,598,000) (98,243,000) (74,439,000)
Net proceeds from issuance of units by KPP......... - 109,056,000 175,527,000
-------------- ------------- --------------
Net cash provided by (used in) financing
activities............................. (55,518,000) (80,641,000) 420,528,000
-------------- ------------- --------------
Effect of exchange rate changes on cash............... 1,637,000 2,766,000 -
-------------- ------------- --------------
Increase (decrease) in cash and cash equivalents...... (4,290,000) 16,598,000 14,125,000
Cash and cash equivalents at beginning of period...... 38,626,000 22,028,000 7,903,000
-------------- ------------- --------------
Cash and cash equivalents at end of period............ $ 34,336,000 $ 38,626,000 $ 22,028,000
============== ============= ==============
Supplemental cash flow information - cash paid for
interest........................................... $ 41,321,000 $ 34,818,000 $ 25,942,000
============== ============= ==============
See notes to consolidated financial statements.
F - 4
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
Accumulated
Other
Limited General Comprehensive Comprehensive
Partner Partner Income (Loss) Total Income
-------------- ----------- ------------- --------------- ----------------
Partners' capital at January 1, 2002..... $ 221,363,000 $ 1,030,000 $(1,866,000) $ 220,527,000
2002 income allocation................. 73,078,000 738,000 - 73,816,000 $ 73,816,000
Distributions declared................. (79,064,000) (752,000) - (79,816,000) -
Issuance of units by KPP, net of
offering costs....................... 175,527,000 - - 175,527,000 -
Foreign currency translation adjustment - - 3,260,000 3,260,000 3,260,000
-------------- ----------- ----------- -------------- ---------------
Comprehensive income for the year...... $ 77,076,000
===============
Partners' capital at December 31, 2002... 390,904,000 1,016,000 1,394,000 393,314,000
2003 income allocation................. 82,357,000 832,000 - 83,189,000 $ 83,189,000
Distributions declared................. (101,994,000) (954,000) - (102,948,000) -
Issuance of units by KPP, net of
offering costs....................... 109,056,000 - - 109,056,000 -
Foreign currency translation adjustment - - 12,662,000 12,662,000 12,662,000
Interest rate hedging transaction...... - - (1,684,000) (1,684,000) (1,684,000)
-------------- ------------ ----------- -------------- ---------------
Comprehensive income for the year...... $ 94,167,000
===============
Partners' capital at December 31, 2003... 480,323,000 894,000 12,372,000 493,589,000
2004 income allocation................. 90,115,000 910,000 - 91,025,000 $ 91,025,000
Distributions declared................. (106,230,000) (984,000) - (107,214,000) -
Foreign currency translation adjustment - - 3,846,000 3,846,000 3,846,000
Interest rate hedging transaction...... - - 180,000 180,000 180,000
Amortization of restricted KPP units... 55,000 - - 55,000 -
-------------- ------------ ----------- -------------- ---------------
Comprehensive income for the year...... $ 95,051,000
===============
Partners' capital at December 31, 2004... $ 464,263,000 $ 820,000 $16,398,000 $ 481,481,000
============== =========== =========== ==============
See notes to consolidated financial statements.
F - 5
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. PARTNERSHIP ORGANIZATION
General
Kaneb Pipe Line Operating Partnership, L.P. (the "Partnership"), a limited
partnership, owns and operates a refined petroleum products and fertilizer
pipeline business and a petroleum products and specialty liquids storage and
terminaling business. Kaneb Pipe Line Partners, L.P. ("KPP"), a master limited
partnership, holds a 99% interest as limited partner in the Partnership. Kaneb
Pipe Line Company LLC ("KPL"), a wholly owned subsidiary of Kaneb Services LLC
("KSL"), manages and controls the operations of KPP through its general partner
interest and 18% (at December 31, 2004) limited partnership interest. KPL owns a
1% interest as general partner of the Partnership and a 1% interest as general
partner of KPP.
Valero L.P. Merger Agreement
On October 31, 2004, Valero L.P. and KPP entered into a definitive
agreement to merge (the "KPP Merger") Valero L.P. and KPP. Under the terms of
the agreement, each holder of units of limited partnership interests in KPP will
receive a number of Valero L.P. common units based on an exchange ratio that
fluctuates within a fixed range to provide $61.50 in value of Valero L.P. units
for each unit of KPP. The actual exchange ratio will be determined at the time
of the closing of the proposed merger and is subject to a fixed value collar of
plus or minus five percent of Valero L.P.'s per unit price of $57.25 as of
October 7, 2004. Should Valero L.P.'s per unit price fall below $54.39 per unit,
the exchange ratio will remain fixed at 1.1307 Valero L.P. units for each unit
of KPP. Likewise, should Valero L.P.'s per unit price exceed $60.11 per unit of
KPP, the exchange ratio will remain fixed at 1.0231 Valero L.P. units for each
unit of KPP.
In a separate definitive agreement, on October 31, 2004, Valero L.P. agreed
to acquire by merger (the "KSL Merger") all of the outstanding common shares of
KSL for cash. Under the terms of that agreement, Valero L.P. is offering to
purchase all of the outstanding shares of KSL at $43.31 per share.
The completion of the KPP Merger is subject to the customary regulatory
approvals including those under the Hart-Scott-Rodino Antitrust Improvements
Act. The completion of the KPP Merger is also subject to completion of the KSL
Merger. All required unitholder and shareholder approvals have been obtained.
Upon completion of the mergers, the general partner of the combined partnership
will be owned by affiliates of Valero Energy Corporation and KPP and KSL will
become wholly owned subsidiaries of Valero L.P.
Issuance of KPP Limited Partnership Units
In March of 2003, KPP issued 3,122,500 limited partnership units in a
public offering at $36.54 per unit, generating approximately $109.1 million in
net proceeds. The proceeds were used to reduce bank borrowings (See Note 5).
In November of 2002, KPP issued 2,095,000 limited partnership units in a
public offering at $33.36 per unit, generating approximately $66.7 million in
net proceeds. The offering proceeds were used to reduce bank borrowings for the
November 2002 fertilizer pipeline acquisition (see Notes 3 and 5).
In May of 2002, KPP issued 1,565,000 limited partnership units in a public
offering at a price of $39.60 per unit, generating approximately $59.1 million
in net proceeds. A portion of the offering proceeds were used to fund its
September 2002 acquisition of the Australia and New Zealand terminals (see Note
3).
In January of 2002, KPP issued 1,250,000 limited partnership units in a
public offering at $41.65 per unit, generating approximately $49.7 million in
net proceeds. The proceeds were used to reduce borrowings under the
Partnership's revolving credit agreement (see Note 5).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following significant accounting policies are followed by the
Partnership in the preparation of the consolidated financial statements.
Cash and Cash Equivalents
The Partnership's policy is to invest cash in highly liquid investments
with original maturities of three months or less. Accordingly, uninvested cash
balances are kept at minimum levels. Such investments are valued at cost, which
approximates market, and are classified as cash equivalents.
Inventories
Inventories consist primarily of petroleum products purchased for resale in
the product sales operations and are valued at the lower of cost or market. Cost
is determined by using the weighted-average cost method.
Property and Equipment
Property and equipment are carried at historical cost. Additions of new
equipment and major renewals and replacements of existing equipment are
capitalized. Repairs and minor replacements that do not materially increase
values or extend useful lives are expensed. Depreciation of property and
equipment is provided on a straight-line basis at rates based upon expected
useful lives of various classes of assets, as disclosed in Note 4. The rates
used for pipeline and storage facilities are the same as those which have been
promulgated by the Federal Energy Regulatory Commission. Upon disposal of assets
depreciated on an individual basis, the gains and losses are included in current
operating income. Upon disposal of assets depreciated on a group basis, unless
unusual in nature or amount, residual cost, less salvage, is charged against
accumulated depreciation.
Effective January 1, 2002, the Partnership adopted Statement of Financial
Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", which addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. The adoption of
SFAS No. 144 did not have a material impact on the consolidated financial
statements of the Partnership. Under SFAS No. 144, the carrying value of
property and equipment is periodically evaluated using undiscounted future cash
flows as the basis for determining if impairment exists. To the extent
impairment is indicated to exist, an impairment loss will be recognized based on
fair value.
Revenue and Income Recognition
The pipeline business provides pipeline transportation of refined petroleum
products, liquified petroleum gases, and anhydrous ammonia fertilizer. Pipeline
revenues are recognized as services are provided. The Partnership's terminaling
services business provides terminaling and other ancillary services. Storage
fees are generally billed one month in advance and are reported as deferred
income. Terminaling revenues are recognized in the month services are provided.
Revenues for the product sales business are recognized when product is sold and
title and risk pass to the customer.
Foreign Currency Translation
The Partnership translates the balance sheet of its foreign subsidiaries
using year-end exchange rates and translates income statement amounts using the
average exchange rates in effect during the year. The gains and losses resulting
from the change in exchange rates from year to year have been reported
separately as a component of accumulated other comprehensive income (loss) in
Partners' Capital. Gains and losses resulting from foreign currency transactions
are included in the consolidated statements of income. The local currency is
considered to be the functional currency, except in the Netherland Antilles and
Canada, where the U.S. dollar is the functional currency.
Excess of Cost Over Fair Value of Net Assets of Acquired Business
Effective January 1, 2002, the Partnership adopted SFAS No. 142, "Goodwill
and Other Intangible Assets," which eliminates the amortization of goodwill
(excess of cost over fair value of net assets of acquired business) and other
intangible assets with indefinite lives. Under SFAS No. 142, intangible assets
with lives restricted by contractual, legal, or other means will continue to be
amortized over their useful lives. At December 31, 2004, the Partnership had no
intangible assets subject to amortization under SFAS No. 142. Goodwill and other
intangible assets not subject to amortization are tested for impairment annually
or more frequently if events or changes in circumstances indicate that the
assets might be impaired. SFAS No. 142 requires a two-step process for testing
impairment. First, the fair value of each reporting unit is compared to its
carrying value to determine whether an indication of impairment exists. If an
impairment is indicated, then the fair value of the reporting unit's goodwill is
determined by allocating the unit's fair value to its assets and liabilities
(including any unrecognized intangible assets) as if the reporting unit had been
acquired in a business combination. The amount of impairment for goodwill is
measured as the excess of its carrying value over its fair value. Based on
valuations and analysis performed by the Partnership at initial adoption date
and at each annual evaluation date, including December 31, 2004, the Partnership
determined that the implied fair value of its goodwill exceeded carrying value
and, therefore, no impairment charge was necessary.
Environmental Matters
Environmental expenditures that relate to current operations are expensed
or capitalized, as appropriate. Expenditures that relate to an existing
condition caused by past operations, and which do not contribute to current or
future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or remedial efforts are probable, and the costs
can be reasonably estimated. Generally, the timing of these accruals coincides
with the completion of a feasibility study or the Partnership's commitment to a
formal plan of action.
Asset Retirement Obligations
Effective January 1, 2003, the Partnership adopted SFAS No. 143 "Accounting
for Asset Retirement Obligations", which establishes requirements for the
removal-type costs associated with asset retirements. At the initial adoption
date of SFAS No. 143, the Partnership recorded an asset retirement obligation of
approximately $5.5 million and recognized a cumulative effect of change in
accounting principle of $1.6 million for its legal obligations to dismantle,
dispose of, and restore certain leased pipeline and terminaling facilities,
including petroleum and chemical storage tanks, terminaling facilities and
barges. The Partnership did not record a retirement obligation for certain of
its pipeline and terminaling assets because sufficient information is presently
not available to estimate a range of potential settlement dates for the
obligation. In these cases, the obligation will be initially recognized in the
period in which sufficient information exists to estimate the obligation. At
December 31, 2004, the Partnership had no assets which were legally restricted
for purposes of settling asset retirement obligations. The effect of SFAS No.
143, assuming adoption on January 1, 2002, was not material to the results of
operations of the Partnership for the years ended December 31, 2004, 2003 and
2002. For the years ended December 31, 2004 and 2003, accretion expense of $0.2
million and $0.4 million, respectively, was included in operating costs.
Comprehensive Income
The Partnership follows the provisions of SFAS No. 130, "Reporting
Comprehensive Income", for the reporting and display of comprehensive income and
its components in a full set of general purpose financial statements. SFAS No.
130 requires additional disclosure and does not affect the Partnership's
financial position or results of operations.
Income Taxes
Income (loss) before income tax expense and extraordinary items, is made up
of the following components:
Year Ended December 31,
---------------------------------------------------------
2004 2003 2002
------------- ------------- --------------
Partnership operations........................ $ 75,917,000 $ 71,104,000 $ 71,614,000
Corporate operations:
Domestic................................. (4,888,000) (3,055,000) 2,046,000
Foreign.................................. 23,278,000 21,956,000 4,239,000
------------- ------------- --------------
$ 94,307,000 $ 90,005,000 $ 77,899,000
============= ============= ==============
Partnership operations are not subject to federal or state income taxes.
However, certain operations of terminaling operations are conducted through
wholly-owned corporate subsidiaries which are taxable entities. The provision
for income taxes for the periods ended December 31, 2004, 2003 and 2002
primarily consists of U.S. and foreign income taxes of $3.3 million, $5.2
million and $4.1 million, respectively. The net deferred tax liability of $21.5
million, $20.6 million and $17.8 million at December 31, 2004, 2003 and 2002,
respectively, consists of deferred tax liabilities of $35.1 million, $48.8
million and $41.7 million, respectively, and deferred tax assets of $13.6
million, $28.2 million and $23.9 million, respectively. The deferred tax
liabilities consist primarily of tax depreciation in excess of book
depreciation. The deferred tax assets consist primarily of net operating loss
carryforwards. The U.S. corporate operations have net operating loss
carryforwards for tax purposes totaling approximately $42.8 million, which are
subject to various limitations on use and expire in years 2008 through 2023.
On June 1, 1989, the governments of the Netherlands Antilles and St.
Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January
1, 1989, which expired on December 31, 2000. This agreement required a
subsidiary of the Partnership, which was acquired with Statia on February 28,
2002 (see Note 3), to pay a 2% rate on taxable income, as defined therein, or a
minimum payment of 500,000 Netherlands Antilles guilders ($0.3 million) per
year. The agreement further provided that any amounts paid in order to meet the
minimum annual payment were available to offset future tax liabilities under the
agreement to the extent that the minimum annual payment is greater than 2% of
taxable income. The subsidiary is currently engaged in discussions with
representatives appointed by the Island Territory of St. Eustatius regarding the
renewal or modification of the agreement, but the ultimate outcome cannot be
predicted at this time. The subsidiary has accrued amounts assuming a new
agreement becomes effective, and continues to make payments, as required, under
the previous agreement.
Since the income or loss of the operations which are conducted through
limited partnerships will be included in the tax returns of the individual
partners of the Partnership, no provision for income taxes has been recorded in
the accompanying financial statements on these earnings. The tax returns of the
Partnership are subject to examination by federal and state taxing authorities.
If any such examination results in adjustments to distributive shares of taxable
income or loss, the tax liability of the partners would be adjusted accordingly.
The tax attributes of the Partnership's net assets flow directly to each
individual partner. Individual partners will have different investment bases
depending upon the timing and prices of acquisition of Partnership interests.
Further, each partner's tax accounting, which is partially dependent upon their
individual tax position, may differ from the accounting followed in the
financial statements. Accordingly, there could be significant differences
between each individual partner's tax basis and their proportionate share of the
net assets reported in the financial statements. SFAS No. 109, "Accounting for
Income Taxes," requires disclosure of the aggregate difference in the basis of
its net assets for financial and tax reporting purposes. Management of the
Partnership does not believe that, in the Partnership's circumstances, the
aggregate difference would be meaningful information.
Cash Distributions
The Partnership makes regular cash distributions in accordance with its
Partnership agreement within 45 days after the end of each quarter to limited
partner and general partner interests. Aggregate distributions of $106.6
million, $98.2 million and $74.4 million, were paid to limited partner interests
and general partner interests in 2004, 2003 and 2002, respectively.
Derivative Instruments
The Partnership follows the provisions of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities", which establishes the accounting
and reporting standards for such activities. Under SFAS No. 133, companies must
recognize all derivative instruments on their balance sheet at fair value.
Changes in the value of derivative instruments, which are considered hedges, are
offset against the change in fair value of the hedged item through earnings, or
recognized in other comprehensive income until the hedged item is recognized in
earnings, depending on the nature of the hedge. SFAS No. 133 requires that
unrealized gains and losses on derivatives not qualifying for hedge accounting
be recognized currently in earnings.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior
unsecured notes due June 1, 2013 (see Note 5.) In connection with the offering,
on May 8, 2003, the Partnership entered into a treasury lock contract for the
purpose of locking in the US Treasury interest rate component on $100 million of
the debt. The treasury lock contract, which qualified as a cash flow hedging
instrument under SFAS No. 133, was settled on May 19, 2003 with a cash payment
by the Partnership of $1.8 million. The settlement cost of the contract has been
recorded as a component of accumulated other comprehensive income and is being
amortized, as interest expense, over the life of the debt. For the years ended
December 31, 2004 and 2003, $0.2 million and $0.1 million, respectively, of
amortization is included in interest expense.
In September of 2002, the Partnership entered into a treasury lock
contract, maturing on November 4, 2002, for the purpose of locking in the US
Treasury interest rate component on $150 million of anticipated thirty-year
public debt offerings. The treasury lock contract originally qualified as a cash
flow hedging instrument under SFAS No. 133. In October of 2002, the Partnership,
due to various market factors, elected to defer issuance of the public debt
securities, effectively eliminating the cash flow hedging designation for the
treasury lock contract. On October 29, 2002, the contract was settled resulting
in a net realized gain of $3.0 million, which was recognized as a component of
interest and other income.
Estimates
The preparation of the Partnership's financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
Recent Accounting Pronouncements
Effective January 1, 2003, the Partnership adopted SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities", which
requires that all restructurings initiated after December 31, 2002 be recorded
when they are incurred and can be measured at fair value. The adoption of SFAS
No. 146 had no effect on the consolidated financial statements of the
Partnership.
The Partnership has adopted the provisions of FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements of Guarantees, Including
Indirect Guarantees of Indebtedness to Others, an interpretation of FASB
Statements No. 5, 57, and 107, and a rescission of FASB Interpretation No. 34."
This interpretation elaborates on the disclosures to be made by a guarantor in
its interim and annual financial statements about its obligations under
guarantees issued. The interpretation also clarifies that a guarantor is
required to recognize, at inception of a guarantee, a liability for the fair
value of the obligation undertaken. The initial recognition and measurement
provisions of the interpretation are applicable to guarantees issued or modified
after December 31, 2002. The application of this interpretation had no effect on
the consolidated financial statements of the Partnership.
In December 2003, the FASB issued Interpretation No. 46 (Revised December
2003), "Consolidation of Variable Interest Entities (FIN 46R), primarily to
clarify the required accounting for interests in variable interest entities
(VIEs). This standard replaces FASB Interpretation No. 46, Consolidation of
Variable Interest Entities, that was issued in January 2003 to address certain
situations in which a company should include in its financial statements the
assets, liabilities and activities of another entity. For the Partnership,
application of FIN 46R is required for interests in certain VIEs that are
commonly referred to as special-purpose entities, or SPEs, as of December 31,
2003 and for interests in all other types of VIEs as of March 31, 2004. The
application of FIN 46R did not have a material impact on the consolidated
financial statements of the Partnership.
The Partnership has adopted the provisions of SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities", which amends
and clarifies financial accounting and reporting for derivative instruments and
hedging activities. The adoption of SFAS No. 149, which was effective for
derivative contracts and hedging relationships entered into or modified after
June 30, 2003, had no impact on the Partnership's consolidated financial
statements.
On July 1, 2003, the Partnership adopted SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity", which requires certain financial instruments, which were previously
accounted for as equity, to be classified as liabilities. The adoption of SFAS
No. 150 had no effect on the consolidated financial statements of the
Partnership.
3. ACQUISITIONS
On December 24, 2002, the Partnership acquired a 400-mile petroleum
products pipeline and four terminals in North Dakota and Minnesota from Tesoro
Refining and Marketing Company for approximately $100 million in cash, subject
to normal post-closing adjustments. The acquisition was initially funded with
bank debt (see Note 5). Based on the evaluations performed, no amounts were
assigned to goodwill or to other intangible assets in the purchase price
allocation.
On November 1, 2002, the Partnership acquired an approximately 2,000-mile
anhydrous ammonia pipeline system from Koch Pipeline Company, L.P. for
approximately $139 million in cash. This fertilizer pipeline system originates
in southern Louisiana, proceeds north through Arkansas and Missouri, and then
branches east into Illinois and Indiana and north and west into Iowa and
Nebraska. The acquisition was initially funded with bank debt (see Note 5). The
results of operations and cash flows of the acquired business are included in
the consolidated financial statements of the Partnership since the date of
acquisition. Based on the evaluations performed, no amounts were assigned to
goodwill or to other intangible assets in the purchase price allocation.
On September 18, 2002, the Partnership acquired eight bulk liquid storage
terminals in Australia and New Zealand from Burns Philp & Co. Ltd. for
approximately $47 million in cash. The results of operations and cash flows of
the acquired business are included in the consolidated financial statements of
the Partnership since the date of acquisition. Based on the evaluations
performed, no amounts were assigned to goodwill or to other intangible assets in
the purchase price allocation.
On February 28, 2002, the Partnership acquired all of the liquids
terminaling subsidiaries of Statia Terminals Group NV ("Statia") for
approximately $178 million in cash (net of acquired cash). The acquired Statia
subsidiaries had approximately $107 million in outstanding debt, including $101
million of 11.75% notes due in November 2003. The cash portion of the purchase
price was initially funded by the Partnership's revolving credit agreement and
proceeds from the Partnership's February 2002 public debt offering (see Note 5).
In April of 2002, the Partnership redeemed all of Statia's 11.75% notes at
102.938% of the principal amount, plus accrued interest. The redemption was
funded by the Partnership's revolving credit facility (see Note 5). Under the
provisions of the 11.75% notes, the Partnership incurred a $3.0 million
prepayment penalty, of which $2.0 million was recognized as loss on debt
extinguishment in 2002.
The results of operations and cash flows of Statia are included in the
consolidated financial statements of the Partnership since the date of
acquisition. Based on the valuations performed, no amounts were assigned to
goodwill or to other tangible assets. A summary of the allocation of the Statia
purchase price, net of cash acquired, is as follows:
Current assets .............................. $ 10,898,000
Property and equipment ...................... 320,008,000
Other assets ................................ 53,000
Current liabilities ......................... (39,052,000)
Long-term debt .............................. (107,746,000)
Other liabilities ........................... (5,957,000)
-------------
Purchase price .......................... $ 178,204,000
=============
4. PROPERTY AND EQUIPMENT
The cost of property and equipment is summarized as follows:
Estimated
Useful December 31,
Life --------------------------------------
(Years) 2004 2003
-------------- ------------------ -----------------
Land...................................... - $ 84,878,000 $ 75,912,000
Buildings................................. 25 - 35 39,077,000 36,229,000
Pipeline and terminaling equipment........ 15 - 40 1,187,323,000 1,115,458,000
Marine equipment.......................... 15 - 30 87,937,000 87,204,000
Furniture and fixtures.................... 5 - 15 15,201,000 11,388,000
Transportation equipment.................. 3 - 6 7,790,000 7,360,000
Construction work-in-progress............. - 28,766,000 26,768,000
------------------ -----------------
Total property and equipment.............. 1,450,972,000 1,360,319,000
Less accumulated depreciation............. 302,381,000 247,349,000
------------------ -----------------
Net property and equipment................ $ 1,148,591,000 $ 1,112,970,000
================== =================
5. LONG-TERM DEBT
Long-term debt is summarized as follows:
December 31,
--------------------------------------
2004 2003
------------------ -----------------
$400 million revolving credit facility, due in April of 2006....... $ 95,669,000 $ 54,169,000
$250 million 5.875% senior unsecured notes, due in June of 2013.... 250,000,000 250,000,000
$250 million 7.75% senior unsecured notes, due in February of 2012. 250,000,000 250,000,000
Term loans, due in April of 2006................................... 40,770,000 29,243,000
Australian bank facility, due in April of 2006..................... 35,513,000 34,284,000
------------------ -----------------
Total long-term debt............................................... $ 671,952,000 $ 617,696,000
================== =================
In April of 2003, the Partnership entered into a credit agreement with a
group of banks that provides for a $400 million unsecured revolving credit
facility through April of 2006. The credit facility, which provides for an
increase in the commitment up to an aggregate of $450 million by mutual
agreement between the Partnership and the banks, bears interest at variable
rates and has a variable commitment fee on unused amounts. The credit facility
contains certain financial and operating covenants, including limitations on
investments, sales of assets and transactions with affiliates and, absent an
event of default, does not restrict distributions to partners. At December 31,
2004, the Partnership was in compliance with all covenants. Initial borrowings
on the credit agreement ($324.2 million) were used to repay all amounts
outstanding under the Partnership's $275 million credit agreement and $175
million bridge loan agreement. At December 31, 2004, $95.7 million was
outstanding under the credit agreement.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior
unsecured notes due June 1, 2013. The net proceeds from the public offering,
$247.6 million, were used to reduce amounts due under the revolving credit
agreement. Under the note indenture, interest is payable semi-annually in
arrears on June 1 and December 1 of each year. The notes are redeemable, as a
whole or in part, at the option of the Partnership, at any time, at a redemption
price equal to the greater of 100% of the principal amount of the notes, or the
sum of the present value of the remaining scheduled payments of principal and
interest, discounted to the redemption date at the applicable U.S. Treasury
rate, as defined in the indenture, plus 30 basis points. The note indenture
contains certain financial and operational covenants, including certain
limitations on investments, sales of assets and transactions with affiliates
and, absent an event of default, such covenants do not restrict distributions to
partners. At December 31, 2004, the Partnership was in compliance with all
covenants.
In February of 2002, the Partnership issued $250 million of 7.75% senior
unsecured notes due February 15, 2012. The net proceeds from the public
offering, $248.2 million, were used to repay the Partnership's revolving credit
agreement and to partially fund the Statia acquisition (see Note 3). Under the
note indenture, interest is payable semi-annually in arrears on February 15 and
August 15 of each year. The notes are redeemable, as a whole or in part, at the
option of the Partnership, at any time, at a redemption price equal to the
greater of 100% of the principal amount of the notes, or the sum of the present
value of the remaining scheduled payments of principal and interest, discounted
to the redemption date at the applicable U.S. Treasury rate, as defined in the
indenture, plus 30 basis points. The note indenture contains certain financial
and operational covenants, including certain limitations on investments, sales
of assets and transactions with affiliates and, absent an event of default, such
covenants do not restrict distributions to partners. At December 31, 2004, the
Partnership was in compliance with all covenants.
6. COMMITMENTS AND CONTINGENCIES
Total rent expense under operating leases amounted to $9.4 million, $14.5
million and $13.4 million for the years ended December 31, 2002, 2003 and 2004,
respectively.
The following is a schedule by years of future minimum lease payments under
operating leases as of December 31, 2004:
Year ending December 31:
2005.................................................. $ 9,756,000
2006.................................................. 8,536,000
2007.................................................. 6,181,000
2008.................................................. 5,279,000
2009.................................................. 4,013,000
Thereafter............................................ 18,140,000
--------------
Total minimum lease payments................................ $ 51,905,000
==============
The operations of the Partnership are subject to federal, state and local
laws and regulations in the United States and the various foreign locations
relating to protection of the environment. Although the Partnership believes its
operations are in general compliance with applicable environmental regulations,
risks of additional costs and liabilities are inherent in pipeline and terminal
operations, and there can be no assurance that significant costs and liabilities
will not be incurred by the Partnership. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property or persons
resulting from the operations of the Partnership, could result in substantial
costs and liabilities to the Partnership. The Partnership has recorded an
undiscounted reserve for environmental claims in the amount of $23.0 million at
December 31, 2004, including $16.9 million related to acquisitions of pipelines
and terminals. During 2004, 2003 and 2002, respectively, the Partnership
incurred $6.7 million, $2.1 million and $2.4 million of costs related to such
acquisition reserves and reduced the liability accordingly.
KPL has indemnified the Partnership against liabilities for damage to the
environment resulting from operations of the pipeline prior to October 3, 1989
(the date of formation of the Partnership). The indemnification does not extend
to any liabilities that arise after such date to the extent that the liabilities
result from changes in environmental laws and regulations.
Certain subsidiaries of the Partnership were sued in a Texas state court in
1997 by Grace Energy Corporation ("Grace"), the entity from which the
Partnership acquired ST Services in 1993. The lawsuit involves environmental
response and remediation costs allegedly resulting from jet fuel leaks in the
early 1970's from a pipeline. The pipeline, which connected a former Grace
terminal with Otis Air Force Base in Massachusetts (the "Otis pipeline" or the
"pipeline"), ceased operations in 1973 and was abandoned before 1978, when the
connecting terminal was sold to an unrelated entity. Grace alleged that
subsidiaries of the Partnership acquired the abandoned pipeline as part of the
acquisition of ST Services in 1993 and assumed responsibility for environmental
damages allegedly caused by the jet fuel leaks. Grace sought a ruling from the
Texas court that these subsidiaries are responsible for all liabilities,
including all present and future remediation expenses, associated with these
leaks and that Grace has no obligation to indemnify these subsidiaries for these
expenses. In the lawsuit, Grace also sought indemnification for expenses of
approximately $3.5 million that it had incurred since 1996 for response and
remediation required by the State of Massachusetts and for additional expenses
that it expects to incur in the future. The consistent position of the
Partnership's subsidiaries has been that they did not acquire the abandoned
pipeline as part of the 1993 ST Services transaction, and therefore did not
assume any responsibility for the environmental damage nor any liability to
Grace for the pipeline.
At the end of the trial, the jury returned a verdict including findings
that (1) Grace had breached a provision of the 1993 acquisition agreement by
failing to disclose matters related to the pipeline, and (2) the pipeline was
abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired
ST Services. On August 30, 2000, the Judge entered final judgment in the case
that Grace take nothing from the subsidiaries on its claims seeking recovery of
remediation costs. Although the Partnership's subsidiaries have not incurred any
expenses in connection with the remediation, the court also ruled, in effect,
that the subsidiaries would not be entitled to indemnification from Grace if any
such expenses were incurred in the future. Moreover, the Judge let stand a prior
summary judgment ruling that the pipeline was an asset acquired by the
Partnership's subsidiaries as part of the 1993 ST Services transaction and that
any liabilities associated with the pipeline would have become liabilities of
the subsidiaries. Based on that ruling, the Massachusetts Department of
Environmental Protection and Samson Hydrocarbons Company (successor to Grace
Petroleum Company) wrote letters to ST Services alleging its responsibility for
the remediation, and ST Services responded denying any liability in connection
with this matter. The Judge also awarded attorney fees to Grace of more than
$1.5 million. Both the Partnership's subsidiaries and Grace have appealed the
trial court's final judgment to the Texas Court of Appeals in Dallas. In
particular, the subsidiaries have filed an appeal of the judgment finding that
the Otis pipeline and any liabilities associated with the pipeline were
transferred to them as well as the award of attorney fees to Grace.
On April 2, 2001, Grace filed a petition in bankruptcy, which created an
automatic stay of actions against Grace. This automatic stay covers the appeal
of the Dallas litigation, and the Texas Court of Appeals has issued an order
staying all proceedings of the appeal because of the bankruptcy. Once that stay
is lifted, the Partnership's subsidiaries that are party to the lawsuit intend
to resume vigorous prosecution of the appeal.
The Otis Air Force Base is a part of the Massachusetts Military Reservation
("MMR Site"), which has been declared a Superfund Site pursuant to CERCLA. The
MMR Site contains a number of groundwater contamination plumes, two of which are
allegedly associated with the Otis pipeline, and various other waste management
areas of concern, such as landfills. The United States Department of Defense,
pursuant to a Federal Facilities Agreement, has been responding to the
Government remediation demand for most of the contamination problems at the MMR
Site. Grace and others have also received and responded to formal inquiries from
the United States Government in connection with the environmental damages
allegedly resulting from the jet fuel leaks. The Partnership's subsidiaries
voluntarily responded to an invitation from the Government to provide
information indicating that they do not own the pipeline. In connection with a
court-ordered mediation between Grace and the Partnership's subsidiaries, the
Government advised the parties in April 1999 that it has identified two spill
areas that it believes to be related to the pipeline that is the subject of the
Grace suit. The Government at that time advised the parties that it believed it
had incurred costs of approximately $34 million, and expected in the future to
incur costs of approximately $55 million, for remediation of one of the spill
areas. This amount was not intended to be a final accounting of costs or to
include all categories of costs. The Government also advised the parties that it
could not at that time allocate its costs attributable to the second spill area.
By letter dated July 26, 2001, the United States Department of Justice
("DOJ") advised ST Services that the Government intends to seek reimbursement
from ST Services under the Massachusetts Oil and Hazardous Material Release
Prevention and Response Act and the Declaratory Judgment Act for the
Government's response costs at the two spill areas discussed above. The DOJ
relied in part on the Texas state court judgment, which in the DOJ's view, held
that ST Services was the current owner of the pipeline and the
successor-in-interest of the prior owner and operator. The Government advised ST
Services that it believes it has incurred costs exceeding $40 million, and
expects to incur future costs exceeding an additional $22 million, for
remediation of the two spill areas. The Partnership believes that its
subsidiaries have substantial defenses. ST Services responded to the DOJ on
September 6, 2001, contesting the Government's positions and declining to
reimburse any response costs. The DOJ has not filed a lawsuit against ST
Services seeking cost recovery for its environmental investigation and response
costs. Representatives of ST Services have met with representatives of the
Government on several occasions since September 6, 2001 to discuss the
Government's claims and to exchange information related to such claims.
Additional exchanges of information are expected to occur in the future and
additional meetings may be held to discuss possible resolution of the
Government's claims without litigation. The Partnership does not believe this
matter will have a materially adverse effect on its financial condition,
although there can be no assurances as to the ultimate outcome.
On April 7, 2000, a fuel oil pipeline in Maryland owned by Potomac Electric
Power Company ("PEPCO") ruptured. Work performed with regard to the pipeline was
conducted by a partnership of which ST Services is general partner. PEPCO has
reported that it has incurred total cleanup costs of $70 million to $75 million.
PEPCO probably will continue to incur some cleanup related costs for the
foreseeable future, primarily in connection with EPA requirements for monitoring
the condition of some of the impacted areas. Since May 2000, ST Services has
provisionally contributed a minority share of the cleanup expense, which has
been funded by ST Services' insurance carriers. ST Services and PEPCO have not,
however, reached a final agreement regarding ST Services' proportionate
responsibility for this cleanup effort, if any, and cannot predict the amount,
if any, that ultimately may be determined to be ST Services' share of the
remediation expense, but ST Services believes that such amount will be covered
by insurance and therefore will not materially adversely affect the
Partnership's financial condition.
As a result of the rupture, purported class actions were filed against
PEPCO and ST Services in federal and state court in Maryland by property and
business owners alleging damages in unspecified amounts under various theories,
including under the Oil Pollution Act ("OPA") and Maryland common law. The
federal court consolidated all of the federal cases in a case styled as In re
Swanson Creek Oil Spill Litigation. A settlement of the consolidated class
action, and a companion state-court class action, was reached and approved by
the federal judge. The settlement involved creation and funding by PEPCO and ST
Services of a $2,250,000 class settlement fund, from which all participating
claimants would be paid according to a court-approved formula, as well as a
court-approved payment to plaintiffs' attorneys. The settlement has been
consummated and the fund, to which PEPCO and ST Services contributed equal
amounts, has been distributed. Participating claimants' claims have been settled
and dismissed with prejudice. A number of class members elected not to
participate in the settlement, i.e., to "opt out," thereby preserving their
claims against PEPCO and ST Services. All non-participant claims have been
settled for immaterial amounts with ST Services' portion of such settlements
provided by its insurance carrier.
PEPCO and ST Services agreed with the federal government and the State of
Maryland to pay costs of assessing natural resource damages arising from the
Swanson Creek oil spill under OPA and of selecting restoration projects. This
process was completed in mid-2002. ST Services' insurer has paid ST Services'
agreed 50 percent share of these assessment costs. In late November 2002, PEPCO
and ST Services entered into a Consent Decree resolving the federal and state
trustees' claims for natural resource damages. The decree required payments by
ST Services and PEPCO of a total of approximately $3 million to fund the
restoration projects and for remaining damage assessment costs. The federal
court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO
and ST Services have each paid their 50% share and thus fully performed their
payment obligations under the Consent Decree. ST Services' insurance carrier
funded ST Services' payment.
The U.S. Department of Transportation ("DOT") has issued a Notice of
Proposed Violation to PEPCO and ST Services alleging violations over several
years of pipeline safety regulations and proposing a civil penalty of $647,000
jointly against the two companies. ST Services and PEPCO have contested the DOT
allegations and the proposed penalty. A hearing was held before the Office of
Pipeline Safety at the DOT in late 2001. In June of 2004, the DOT issued a final
order reducing the penalty to $256,250 jointly against ST Services and PEPCO and
$74,000 against ST Services. On September 14, 2004, ST Services petitioned for
reconsideration of the order.
By letter dated January 4, 2002, the Attorney General's Office for the
State of Maryland advised ST Services that it intended to seek penalties from ST
Services in connection with the April 7, 2000 spill. The State of Maryland
subsequently asserted that it would seek penalties against ST Services and PEPCO
totaling up to $12 million. A settlement of this claim was reached in mid-2002
under which ST Services' insurer will pay a total of slightly more than $1
million in installments over a five year period. PEPCO has also reached a
settlement of these claims with the State of Maryland. Accordingly, the
Partnership believes that this matter will not have a material adverse effect on
its financial condition.
On December 13, 2002, ST Services sued PEPCO in the Superior Court,
District of Columbia, seeking, among other things, a declaratory judgment as to
ST Services' legal obligations, if any, to reimburse PEPCO for costs of the oil
spill. On December 16, 2002, PEPCO sued ST Services in the United States
District Court for the District of Maryland, seeking recovery of all its costs
for remediation of and response to the oil spill. Pursuant to an agreement
between ST Services and PEPCO, ST Services' suit was dismissed, subject to
refiling. ST Services has moved to dismiss PEPCO's suit. ST Services is
vigorously defending against PEPCO's claims and is pursuing its own
counterclaims for return of monies ST Services has advanced to PEPCO for
settlements and cleanup costs. The Partnership believes that any costs or
damages resulting from these lawsuits will be covered by insurance and therefore
will not materially adversely affect the Partnership's financial condition. The
amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy
which has a $600,000 retention, but the Partnership does not believe that such
retention, if incurred, would materially adversely affect the Partnership's
financial condition.
In 2003, Exxon Mobil filed a lawsuit in the New Jersey state court against
GATX Corporation, Kinder Morgan Liquid Terminals ("Kinder Morgan"), the
successor in interest to GATX Terminals Corporation ("GATX"), and ST Services,
seeking reimbursement for remediation costs associated with the Paulsboro, New
Jersey terminal. The terminal was owned and operated by Exxon Mobil from the
early 1950's until 1990 when purchased by GATX. ST Services purchased the
terminal in 2000 from GATX. GATX was subsequently acquired by Kinder Morgan. As
a condition to the sale to GATX in 1990, Exxon Mobil undertook certain
remediation obligations with respect to the site. In the lawsuit, Exxon Mobil is
claiming that it has complied with its remediation and contractual obligations
and is entitled to reimbursement from GATX Corporation, the parent company of
GATX, Kinder Morgan, and ST Services for costs in the amount of $400,000 that it
claims are related to releases at the site subsequent to its sale of the
terminal to GATX. It is also alleging that any remaining remediation
requirements are the responsibility of GATX Corporation, Kinder Morgan, or ST
Services. Kinder Morgan has alleged that it was relieved of any remediation
obligations pursuant to the sale agreement between its predecessor, GATX, and ST
Services. ST Services believes that, except for remediation involving immaterial
amounts, GATX Corporation or Exxon Mobil are responsible for the remaining
remediation of the site. Costs of completing the required remediation depend on
a number of factors and cannot be determined at the current time.
A subsidiary of the Partnership purchased the approximately 2,000-mile
ammonia pipeline system from Koch Pipeline Company, L.P. and Koch Fertilizer
Storage and Terminal Company in 2002. The rates of the ammonia pipeline are
subject to regulation by the Surface Transportation Board (the "STB"). The STB
had issued an order in May 2000, prescribing maximum allowable rates the
Partnership's predecessor could charge for transportation to certain destination
points on the pipeline system. In 2003, the Partnership instituted a 7% general
increase to pipeline rates. On August 1, 2003, CF Industries, Inc. ("CFI") filed
a complaint with the STB challenging these rate increases. On August 11, 2004,
STB ordered the Partnership to pay reparations to CFI and to return CFI's rates
to the levels permitted under the rate prescription. The Partnership has
complied with the order. The STB, however, indicated in the order that it would
lift the rate prescription in the event the Partnership could show "materially
changed circumstances." The Partnership has submitted evidence of "materially
changed circumstances," which specifically includes its capital investment in
the pipeline. CFI has argued that the Partnership's acquisition costs should not
be considered by the STB as a measure of the Partnership's investment base. The
STB is expected to decide the issue within the second quarter of 2005.
Also, on June 16, 2003, Dyno Nobel Inc. ("Dyno") filed a complaint with the
STB challenging the 2003 rate increase on the basis that (i) the rate increase
constitutes a violation of a contract rate, (ii) rates are discriminatory and
(iii) the rates exceed permitted levels. Dyno also intervened in the CFI
proceeding described above. Unlike CFI, Dyno's rates are not subject to a rate
prescription. As of December 31, 2004, Dyno would be entitled to approximately
$2 million in rate refunds, should it be successful. The Partnership believes,
however, that Dyno's claims are without merit.
The Partnership has other contingent liabilities resulting from litigation,
claims and commitments incident to the ordinary course of business. Management
of the Partnership believes, after consulting with counsel, that the ultimate
resolution of such contingencies will not have a materially adverse effect on
the financial position, results of operations or liquidity of the Partnership.
7. RELATED PARTY TRANSACTIONS
The Partnership has no employees and is managed and controlled by KPL. KPL
and KSL are entitled to reimbursement of all direct and indirect costs related
to the business activities of the Partnership. These costs, which totaled $36.0
million, $36.3 million and $27.3 million for the years ended December 31, 2004,
2003 and 2002, respectively, include compensation and benefits paid to officers
and employees of KPL and KSL, insurance premiums, general and administrative
costs, tax information and reporting costs, legal and audit fees. Included in
this amount is $24.2 million, $26.6 million and $17.7 million of compensation
and benefits, paid to officers and employees of KPL and KSL for the years ended
December 31, 2004, 2003 and 2002, respectively. In addition, the Partnership
paid $0.8 million in 2004, $0.6 million in 2003 and $0.6 million in 2002 for an
allocable portion of KPL's overhead expenses. At December 31, 2004 and 2003, the
Partnership owed KPL and KSL $4.5 million and $3.6 million, respectively, for
these expenses which are due under normal invoice terms.
8. BUSINESS SEGMENT DATA
The Partnership conducts business through three principal segments; the
"Pipeline Operations," which consists primarily of the transportation of refined
petroleum products and fertilizer in the Midwestern states as a common carrier,
the "Terminaling Operations," which provides storage for petroleum products,
specialty chemicals and other liquids, and the "Product Sales Operations", which
delivers bunker fuel to ships in the Caribbean and Nova Scotia, Canada and sells
bulk petroleum products to various commercial interests.
The Partnership measures segment profit as operating income. Total assets
are those assets controlled by each reportable segment. Business segment data is
as follows:
Year Ended December 31,
------------------------------------------------------
2004 2003 2002
---------------- --------------- --------------
Business segment revenues:
Pipeline operations.................................. $ 119,803,000 $ 119,633,000 $ 82,698,000
Terminaling operations............................... 259,352,000 234,958,000 205,971,000
Product sales operations............................. 269,054,000 215,823,000 97,961,000
---------------- --------------- --------------
$ 648,209,000 $ 570,414,000 $ 386,630,000
================ =============== ==============
Business segment profit:
Pipeline operations.................................. $ 48,853,000 $ 51,860,000 $ 38,623,000
Terminaling operations............................... 74,663,000 66,532,000 65,040,000
Product sales operations............................. 13,274,000 10,109,000 2,058,000
---------------- --------------- --------------
Operating income.................................. 136,790,000 128,501,000 105,721,000
Interest and other income ........................... 267,000 261,000 3,570,000
Interest expense..................................... (42,750,000) (38,757,000) (28,110,000)
Loss on debt extinguishment.......................... - - (3,282,000)
---------------- --------------- --------------
Income before income taxes and cumulative effect
of change in accounting principle............... $ 94,307,000 $ 90,005,000 $ 77,899,000
================ =============== ==============
Business segment assets:
Depreciation and amortization:
Pipeline operations............................... $ 14,538,000 $ 14,117,000 $ 6,408,000
Terminaling operations............................ 41,232,000 38,089,000 32,368,000
Product sales operations.......................... 878,000 949,000 649,000
---------------- --------------- --------------
$ 56,648,000 $ 53,155,000 $ 39,425,000
================ =============== ==============
Capital expenditures (excluding acquisitions):
Pipeline operations............................... $ 10,334,000 $ 9,584,000 $ 9,469,000
Terminaling operations............................ 29,511,000 34,572,000 20,953,000
Product sales operations.......................... 2,369,000 585,000 679,000
---------------- --------------- --------------
$ 42,214,000 $ 44,741,000 $ 31,101,000
================ =============== ==============
Total assets:
Pipeline operations................................ $ 351,195,000 $ 352,901,000 $ 352,657,000
Terminaling operations............................. 917,966,000 874,185,000 844,321,000
Product sales operations.......................... 56,155,000 37,596,000 18,432,000
---------------- --------------- --------------
$ 1,325,316,000 $ 1,264,682,000 $1,215,410,000
================ =============== ==============
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,
------------------------------------------------------
2004 2003 2002
---------------- --------------- --------------
Geographical area revenues:
United States........................................ $ 251,775,000 $ 240,518,000 $ 202,124,000
United Kingdom....................................... 29,540,000 26,392,000 23,937,000
Netherlands Antilles................................. 298,273,000 241,693,000 132,387,000
Canada............................................... 43,671,000 41,689,000 23,207,000
Australia and New Zealand............................ 24,950,000 20,122,000 4,975,000
---------------- --------------- --------------
$ 648,209,000 $ 570,414,000 $ 386,630,000
================ =============== ==============
Geographical area operating income:
United States........................................ $ 93,965,000 $ 87,962,000 $ 82,906,000
United Kingdom....................................... 7,704,000 8,583,000 7,318,000
Netherlands Antilles................................. 22,629,000 19,223,000 9,616,000
Canada............................................... 5,248,000 6,777,000 4,398,000
Australia and New Zealand............................ 7,244,000 5,956,000 1,483,000
---------------- --------------- --------------
$ 136,790,000 $ 128,501,000 $ 105,721,000
================ =============== ==============
December 31,
------------------------------------------------------
2004 2003 2002
---------------- --------------- --------------
Geographical area net property and equipment:
United States........................................ $ 718,236,000 $ 693,295,000 $ 690,178,000
United Kingdom....................................... 63,968,000 51,392,000 46,543,000
Netherlands Antilles................................. 211,382,000 217,143,000 224,810,000
Canada............................................... 71,374,000 74,995,000 78,789,000
Australia and New Zealand............................ 83,631,000 76,145,000 51,872,000
---------------- --------------- --------------
$ 1,148,591,000 $ 1,112,970,000 $1,092,192,000
================ =============== ==============
9. FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK
The estimated fair value of all debt as of December 31, 2004 and 2003 was
approximately $728 million and $630 million, as compared to the carrying value
of $672 million and $618 million, respectively. These fair values were estimated
using discounted cash flow analysis, based on the Partnership's current
incremental borrowing rates for similar types of borrowing arrangements. These
estimates are not necessarily indicative of the amounts that would be realized
in a current market exchange. See Note 2 regarding derivative instruments.
The Partnership markets and sells its services to a broad base of customers
and performs ongoing credit evaluations of its customers. The Partnership does
not believe it has a significant concentration of credit risk at December 31,
2004. No customer constituted 10 percent or more of consolidated revenues in
2004, 2003 or 2002.
10. QUARTERLY FINANCIAL DATA (unaudited)
Quarterly operating results for 2004 and 2003 are summarized as follows:
Quarter Ended
--------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
---------------- ---------------- --------------- --------------
2004:
Revenues....................... $ 146,413,000 $ 153,958,000 $ 167,668,000 $ 180,170,000
================ ================ =============== ==============
Operating income............... $ 32,562,000 $ 35,650,000 $ 34,146,000 $ 34,432,000
================ ================ =============== ==============
Net income..................... $ 20,979,000 $ 24,531,000 $ 22,291,000 $ 23,224,000
================ ================ =============== ==============
2003:
Revenues....................... $ 140,757,000 $ 146,948,000 $ 140,404,000 $ 142,305,000
================ ================ =============== ==============
Operating income............... $ 33,598,000 $ 33,041,000 $ 32,016,000 $ 29,846,000
================ ================ =============== ==============
Net income..................... $ 22,049,000(a) $ 22,829,000 $ 20,323,000 $ 17,988,000
================ ================ =============== ==============
(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.
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, 2004:
For doubtful receivables
classified as current assets... $ 1,693 $ 832 $ - $ (1,242)(b) $ 1,283
=========== =========== =========== ========= ==========
Year Ended December 31, 2003:
For doubtful receivables
classified as current assets... $ 1,765 $ 401 $ - $ (473)(b) $ 1,693
=========== =========== =========== ========= ==========
Year Ended December 31, 2002:
For doubtful receivables
classified as current assets... $ 278 $ 925 $ 841(a) $ (279)(b) $ 1,765
=========== =========== =========== ========= ==========
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 16, 2005
Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed below by the following persons on behalf of Kaneb
Pipe Line Operating Partnership, L.P. and in the capacities with Kaneb Pipe Line
Company LLC and on the date indicated.
Signature Title Date
- ---------------------------------------- ---------------------- ---------------
Principal Executive Officer
//s// EDWARD D. DOHERTY Chairman of the Board March 16, 2005
- ---------------------------------------- and Chief Executive Officer
Principal Accounting Officer
//s// HOWARD C. WADSWORTH Vice President March 16, 2005
- ---------------------------------------- Treasurer & Secretary
Directors
//s// SANGWOO AHN Director March 16, 2005
- ----------------------------------------
//s// JOHN R. BARNES Director March 16, 2005
- ----------------------------------------
//s// MURRAY R. BILES Director March 16, 2005
- ----------------------------------------
//s// FRANK M. BURKE Director March 16, 2005
- ----------------------------------------
//s// CHARLES R. COX Director March 16, 2005
- ----------------------------------------
//s// HANS KESSLER Director March 16, 2005
- ----------------------------------------
//s// JAMES R. WHATLEY Director March 16, 2005
- ----------------------------------------
Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Edward D. Doherty, Chief Executive Officer of Kaneb Pipe Line Company LLC, as
General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:
1. I have reviewed this annual report on Form 10-K of Kaneb Pipe Line
Operating Partnership, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this annual report is being prepared;
b) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles;
c) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this annual report our conclusions
about the effectiveness of the disclosure controls and procedures, as
of the end of the period covered by this annual report, based on such
evaluation; and
d) disclosed in this annual report any change in the registrant's
internal control over financial reporting that occurred during the
registrant's most recent fiscal quarter that has materially affected,
or is reasonably likely to materially affect, the registrant's
internal control over financial reporting; and
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board
of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: March 16, 2005
//s// EDWARD D. DOHERTY
-----------------------------------
Edward D. Doherty
Chief Executive Officer
Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Howard C. Wadsworth, Chief Financial Officer of Kaneb Pipe Line Company LLC,
as General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:
1. I have reviewed this annual report on Form 10-K of Kaneb Pipe Line
Operating Partnership, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this annual report is being prepared;
b) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles;
c) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this annual report our conclusions
about the effectiveness of the disclosure controls and procedures, as
of the end of the period covered by this annual report, based on such
evaluation; and
d) disclosed in this annual report any change in the registrant's
internal control over financial reporting that occurred during the
registrant's most recent fiscal quarter that has materially affected,
or is reasonably likely to materially affect, the registrant's
internal control over financial reporting; and
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board
of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: March 16, 2005
//s// HOWARD C. WADSWORTH
-----------------------------------
Howard C. Wadsworth
Chief Financial Officer
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 906(A) OF THE SARBANES-OXLEY ACT OF 2002
The undersigned, being the Chief Executive Officer of Kaneb Pipe Line Company
LLC, as General Partner of Kaneb Pipe Line Operating Partnership, L.P. (the
"Partnership"), hereby certifies that, to his knowledge, the Partnership's
Annual Report on Form 10-K for the year ended December 31, 2004, filed with the
United States Securities and Exchange Commission pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully
complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and that information contained in such Annual Report fairly
presents, in all material respects, the financial condition and results of
operations of the Partnership.
This written statement is being furnished to the Securities and Exchange
Commission as an exhibit to such Form 10-K. A signed original of this written
statement required by Section 906 has been provided to Kaneb Pipe Line Operating
Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership,
L.P. and furnished to the Securities and Exchange Commission or its staff upon
request.
Date: March 16, 2005
//s// EDWARD D. DOHERTY
----------------------------------------
Edward D. Doherty
Chief Executive Officer
Exhibit 32.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 906(A) OF THE SARBANES-OXLEY ACT OF 2002
The undersigned, being the Chief Financial Officer of Kaneb Pipe Line Company
LLC, as General Partner of Kaneb Pipe Line Operating Partnership, L.P. (the
"Partnership"), hereby certifies that, to his knowledge, the Partnership's
Annual Report on Form 10-K for the year ended December 31, 2004, filed with the
United States Securities and Exchange Commission pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully
complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and that information contained in such Annual Report fairly
presents, in all material respects, the financial condition and results of
operations of the Partnership.
This written statement is being furnished to the Securities and Exchange
Commission as an exhibit to such Form 10-K. A signed original of this written
statement required by Section 906 has been provided to Kaneb Pipe Line Operating
Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership,
L.P. and furnished to the Securities and Exchange Commission or its staff upon
request.
Date: March 16, 2005
//s// HOWARD C. WADSWORTH
---------------------------------------
Howard C. Wadsworth
Vice President, Treasurer and Secretary
(Chief Financial Officer)
Exhibit 23
Consent of Independent Registered Public Accounting Firm
The Partners of
Kaneb Pipe Line Operating Partnership, L.P.:
We consent to the incorporation by reference in the registration statement
numbers 333-71638 and 333-108642 on Form S-3 of Kaneb Pipe Line Operating
Partnership, L.P. of our report dated March 11, 2005, with respect to the
consolidated balance sheets of Kaneb Pipe Line Operating Partnership, L.P. and
subsidiaries as of December 31, 2004 and 2003, and the related consolidated
statements of income, partners' capital and cash flows for each of the years in
the three-year period ended December 31, 2004, and related financial statement
schedule, which report appears in the December 31, 2004 annual report on Form
10-K of Kaneb Pipe Line Operating Partnership, L.P. Our report refers to a
change in accounting for asset retirement obligations in 2003.
KPMG LLP
Dallas, Texas
March 16, 2005