UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 333-44634
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
(Exact name of Registrant as specified in its Charter)
Delaware 75-2287683
(State or other jurisdiction of IRS Employer
incorporation or organization) Identification No.)
2435 North Central Expressway
Richardson, Texas 75080
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(Address of principal executive offices) (zip code)
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Registrant's telephone number, including area code: (972) 699-4062
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.
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).
PART I
Item 1. Business
GENERAL
Kaneb Pipe Line Operating Partnership, L.P., a Delaware limited
partnership (the "Partnership"), is engaged in the refined petroleum products
and anhydrous ammonia pipeline business and the terminaling of petroleum
products and specialty liquids. Kaneb Pipe Line Partners, L.P. ("KPP") (NYSE:
KPP), a master limited partnership, holds a 99% interest as a limited partner in
the Partnership. Kaneb Pipe Line Company LLC, a Delaware limited liability
company ("KPL"), a wholly-owned subsidiary of Kaneb Services LLC, a Delaware
limited liability company ("KSL") (NYSE: KSL), holds the 1% interest as general
partner of the Partnership and a 1% interest as general partner of KPP. The
terminaling business of the Partnership is conducted through Support Terminals
Operating Partnership, L.P. ("STOP"), and its affiliated partnerships and
corporate entities, which operate under the trade names "ST Services" and
"StanTrans," among others; and Statia Terminals Holdings Company LLC and its
subsidiary entities ("Statia").
PIPELINE BUSINESS
Introduction
The Partnership's pipeline business consists primarily of the transportation of refined petroleum products as a common carrier in Kansas, Nebraska, Iowa, South Dakota, North Dakota, Colorado, Wyoming and Minnesota. On December 24, 2002, the Partnership acquired the Northern Great Plains Product System from Tesoro Refining and Marketing Company for approximately $100 million. This product pipeline system is now referred to as the Partnership's North Pipeline. On November 1, 2002, the Partnership acquired a 2,000 mile anhydrous ammonia pipeline from Koch Pipeline Company, LP and Koch Fertilizer Storage and Terminal Company for approximately $139 million. The Partnership's three refined petroleum products pipelines and the anhydrous ammonia pipeline are described below.
East Pipeline
Construction of the East Pipeline commenced in 1953 with a line from southern Kansas to Geneva, Nebraska. During subsequent years, the East Pipeline was extended northward to its present terminus at Jamestown, North Dakota, west to North Platte, Nebraska and east into the State of Iowa. The East Pipeline, which moves refined products from south to north, now consists of 2,090 miles of pipeline ranging in size from 6 inches to 16 inches.
The East Pipeline system also consists of 17 product terminals in Kansas, Nebraska, Iowa, South Dakota and North Dakota with total storage capacity of approximately 3.5 million barrels and an additional 23 product tanks with total storage capacity of approximately 1,118,393 barrels at its tank farm installations at McPherson and El Dorado, Kansas. The system also has six origin pump stations in Kansas and 38 booster pump stations throughout the system. Additionally, the system maintains various office and warehouse facilities, and an extensive quality control laboratory.
The East Pipeline transports refined petroleum products, including propane, received from refineries in southeast Kansas and other connecting pipelines to its terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries connected to the East Pipeline or through other pipelines directly connected to the pipeline system. Five connecting pipelines can deliver propane for shipment through the East Pipeline from gas processing plants in Texas, New Mexico, Oklahoma and Kansas.
Much of the refined petroleum products delivered through the East Pipeline are ultimately used as fuel for railroads or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop drying facilities. Demand for refined petroleum products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East Pipeline. Government agricultural policies and crop prices also affect the agricultural sector. Although periods of drought suppress agricultural demand for some refined petroleum products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times.
The mix of refined petroleum products delivered varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall. In addition, weather conditions in the areas served by the East Pipeline affect both the demand for and the mix of the refined petroleum products delivered through the East Pipeline, although historically any impact on total volumes shipped has been short-term. Tariffs charged to shippers for transportation of products do not vary according to the type of product delivered.
West Pipeline
The Partnership acquired the West Pipeline in February 1995, increasing the Partnership's pipeline business in South Dakota and expanding it into Wyoming and Colorado. The West Pipeline system includes approximately 550 miles of pipeline in Wyoming, Colorado and South Dakota, four truck-loading terminals and numerous pump stations situated along the system. The system's four product terminals have a total storage capacity of over 1.7 million barrels.
The West Pipeline originates near Casper, Wyoming, where it serves as a connecting point with Sinclair's Little America Refinery and the Seminoe Pipeline which transports product from Billings, Montana area refineries. At Douglas, Wyoming, a 6 inch pipeline branches off to serve the Partnership's Rapid City, South Dakota terminal approximately 190 miles away. The 6 inch pipeline also receives product from Wyoming Refining's pipeline at a connection located near the Wyoming/South Dakota border. From Douglas, the Partnership's pipeline continues southward through a delivery point at the Burlington Northern junction to terminals at Cheyenne, Wyoming, the Denver metropolitan area and Fountain, Colorado.
The West Pipeline system parallels the Partnership's East Pipeline to the west. The East Pipeline's North Platte line terminates in western Nebraska, approximately 200 miles east of the West Pipeline's Cheyenne, Wyoming Terminal. The West Pipeline serves Denver and other eastern Colorado markets and supplies jet fuel to Ellsworth Air Force Base at Rapid City, South Dakota, as compared to the East Pipeline's largely agricultural service area. The West Pipeline has a relatively small number of shippers who, with few exceptions, are also shippers on the Partnership's East Pipeline system.
North Pipeline
The North Pipeline, acquired in December 2002, runs from west to east approximately 440 miles from its origin at the Tesoro Refining and Marketing Company's Mandan, North Dakota refinery to the Minneapolis, Minnesota area. It has four product terminals, one in North Dakota and three in Minnesota, with a total tankage capacity of 1.3 million barrels. The North Pipeline crosses the Partnership's East Pipeline near Jamestown, North Dakota where the two pipelines are connected. The North Pipeline is presently supplied exclusively by the Mandan refinery, however, it is capable of delivering or receiving products to or from the East Pipeline.
Ammonia Pipeline
In November 2002, the Partnership acquired the anhydrous ammonia pipeline (the "Ammonia Pipeline") from two Koch companies. Anhydrous ammonia is primarily used as agricultural fertilizer through direct application. Other uses are as a component of various types of dry fertilizer as well as use as a cleaning agent in power plant scrubbers. The 2,000 mile pipeline originates in the Louisiana delta area where it has access to three marine terminals on the Mississippi River. It moves north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri, one branch splits going east into Illinois and Indiana, and the other branch continues north into Iowa and then turning west into Nebraska. The Partnership acquired a storage and loading terminal near Hermann, Missouri which was leased back to Koch Nitrogen. The operations headquarters for the Ammonia Pipeline is located in Hermann, Missouri. The Ammonia Pipeline is connected to twenty-two other third party owned terminals and also has several industrial facility delivery locations. Product is primarily supplied to the pipeline from plants in Louisiana and foreign-source product delivered through the marine terminals.
Other Systems
The Partnership also owns three single-use pipelines, located near Umatilla, Oregon; Rawlins, Wyoming and Pasco, Washington, each of which supplies diesel fuel to a railroad fueling facility. The Oregon and Washington lines are fully automated, however the Wyoming line utilizes a coordinated startup procedure between the refinery and the railroad. For the year ended December 31, 2003, these three systems combined transported a total of 3.7 million barrels of diesel fuel, representing an aggregate of $1.5 million in revenues.
Pipelines Products and Activities
The revenues for the East Pipeline, West Pipeline, North Pipeline, Ammonia Pipeline and Other Pipelines (collectively, the "Pipelines") are based upon volumes and distances of product shipped. The following table reflects the total volume, barrel miles of refined petroleum products shipped and total operating revenues earned by the Pipelines for each of the periods indicated, but does not include any information on the Ammonia Pipeline. In addition information on the North Pipeline system prior to 2003 is not included. During the year of 2003, the Ammonia Pipeline shipped 1,155,160 tons of ammonia generating $21.3 million of revenue.
Year Ended December 31,
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2003 2002 2001 2000 1999
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Volume (1).................. 102,928 89,780 92,116 89,192 85,356
Barrel miles (2)............ 21,327 18,275 18,567 17,843 18,440
Revenues (3)................ $98,329 $78,240 $74,976 $70,685 $67,607
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(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)
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2003 2002 2001 2000 1999
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Gasoline.................... 53,205 45,106 46,268 44,215 41,472
Diesel and fuel oil......... 46,072 40,450 42,354 41,087 40,435
Propane..................... 3,651 4,224 3,494 3,890 3,449
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Total....................... 102,928 89,780 92,116 89,192 85,356
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Diesel and fuel oil are used in farm machinery and equipment, over-the-road transportation, railroad fueling and residential fuel oil. Gasoline is primarily used in over-the-road transportation and propane is used for crop drying, residential heating and to power irrigation equipment. The mix of refined petroleum products delivered varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall. In addition, weather conditions in the areas served by the East Pipeline affect both the demand for and the mix of the refined petroleum products delivered through the East Pipeline, although historically any overall impact on the total volumes shipped has been short-term. Tariffs charged to shippers for transportation of products do not vary according to the type of product delivered. Demand on the North Pipeline is mainly of the same agricultural nature as the East Pipeline except for the Minneapolis terminal area which is more metropolitan.
Maintenance and Monitoring
The Pipelines have been constructed and are maintained in a manner consistent with applicable federal, state and local laws and regulations, standards prescribed by the American Petroleum Institute and accepted industry practice. Further, protective measures are taken and routine preventive maintenance is performed on the Pipelines in order to prolong their useful lives. Such measures include cathodic protection to prevent external corrosion, inhibitors to prevent internal corrosion and periodic inspection of the Pipelines. Additionally, the Pipelines are patrolled at regular intervals to identify equipment or activities by third parties that, if left unchecked, could result in encroachment upon the Pipeline's rights-of-way and possible damage to the Pipelines.
The Partnership uses state-of-the-art Supervisory Control and Data Acquisition remote supervisory control software programs to continuously monitor and control the Pipelines from the Wichita, Kansas headquarters and from the Roseville, Minnesota terminal for the North Pipeline. The system monitors quantities of products injected in and delivered through the Pipelines and automatically signals the Wichita or Roseville personnel upon deviations from normal operations that requires attention.
Pipeline Operations
For pipeline operations, integrity management and public safety, the East Pipeline, the West Pipeline, the North Pipeline and the Ammonia Pipeline are subject to federal regulation by one or more of the following governmental agencies or laws: the Federal Energy Regulatory Commission ("FERC"), the Surface Transportation Board, the Department of Transportation, the Environmental Protection Agency, and the Homeland Security Act. Additionally, the operations and integrity of the Pipelines are subject to the respective state jurisdictions along the route of the systems. See "Regulation."
Except for the three single-use pipelines and certain ethanol facilities, all of the Partnership's pipeline operations constitute common carrier operations and are subject to federal tariff regulation. In May 1998, the Partnership was authorized by the FERC to adopt market-based rates in approximately one-half of its markets on the East and West systems. Common carrier activities are those for which transportation through the Partnership's Pipelines is available at published tariffs filed, in the case of interstate petroleum product shipments, with the FERC or, in the case of intrastate petroleum product shipments in Kansas, Colorado, Wyoming and North Dakota, with the relevant state authority, to any shipper of refined petroleum products who requests such services and satisfies the conditions and specifications for transportation. The Ammonia Pipeline is subject to federal regulation by the Surface Transportation Board, rather than the FERC.
In general, a shipper on one of the Partnership's refined petroleum products pipelines delivers products to the pipeline from refineries or third party pipelines that connect to the Pipelines. The Pipelines' refined petroleum products operations also include 25 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum transport trucks. Five of the 25 terminals also receive propane into storage tanks and then load it into transport trucks. The Ammonia Pipeline receives product from anhydrous ammonia plants or from the marine terminals for imported product. Tariffs for transportation are charged to shippers based upon transportation from the origination point on the pipeline to the point of delivery. Such tariffs also include charges for terminaling and storage of product at the Pipeline's terminals. Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of refined petroleum products.
Each shipper transporting product on a pipeline is required to supply the Partnership with a notice of shipment indicating sources of products and destinations. All shipments are tested or receive refinery certifications to ensure compliance with the Partnership's specifications. Petroleum shippers are generally invoiced by the Partnership immediately upon the product entering one of the Petroleum Pipelines.
The following table shows the number of tanks owned by the Partnership at each refined petroleum product terminal location at December 31, 2003, the storage capacity in barrels and truck capacity of each terminal location.
Location of Number Tankage Truck
Terminals of Tanks Capacity Capacity(a)
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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
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Totals 349 6,545,000
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(a) Number of trucks that may be simultaneously loaded.
(b) This terminal is situated on land leased through August 7, 2007 at an
annual rental of $2,400. The Partnership has the right to renew the
lease upon its expiration for an additional term of 20 years at the
same annual rental rate.
(c) This terminal is situated on land leased through the year 2060 for a
total rental of $2,000.
(d) Also loads rail tank cars.
(e) Two terminals
The East Pipeline also has intermediate storage facilities consisting of 13 storage tanks at El Dorado, Kansas and 10 storage tanks at McPherson, Kansas, with aggregate capacities of approximately 584,393 and 534,000 barrels, respectively. During 2003, approximately 56.7%, 91.7% and 85.5% of the deliveries of the East, the West and the North Pipelines, respectively, were made through their terminals, and the remainder of the respective deliveries of such lines were made to other pipelines and customer owned storage tanks.
Storage of product at terminals pending delivery is considered by the Partnership to be an integral part of the petroleum product delivery service of the pipelines. Shippers generally store refined petroleum products for less than one week. Ancillary services, including injection of shipper-furnished and generic additives, are available at each terminal.
The Partnership owns 1,500 tons of ammonia storage at the terminal near Hermann, Missouri. One half of the capacity is leased to Koch Nitrogen to support their leased terminal obligations.
Demand for and Sources of Refined Petroleum Products
The Partnership's pipeline business depends in large part on the level of demand for refined petroleum products in the markets served by the pipelines and the ability and willingness of refiners and marketers having access to the pipelines to supply such demand by deliveries through the pipelines.
Much of the refined petroleum products delivered through the East Pipeline and the western three terminals on the North Pipeline is ultimately used as fuel for railroads or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop drying facilities. Demand for refined petroleum products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipeline. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined petroleum products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times.
While there is some agricultural demand for the refined petroleum products delivered through the West Pipeline, as well as military jet fuel volumes, most of the demand is centered in the Denver and Colorado Springs area. Because demand on the West Pipeline and the Minneapolis area terminal of the North Pipeline is significantly weighted toward urban and suburban areas, the product mix on the West Pipeline and that terminal includes a substantially higher percentage of gasoline than the product mix on the East Pipeline.
The Partnership's refined petroleum products pipelines are also dependent upon adequate levels of production of refined petroleum products by refineries connected to the Pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. The refineries connected directly to the East Pipeline obtain crude oil from producing fields located primarily in Kansas, Oklahoma and Texas, and, to a much lesser extent, from other domestic or foreign sources. In addition, refineries in Kansas, Oklahoma and Texas are also connected to the East Pipeline through other pipelines. These refineries obtain their supplies of crude oil from a variety of sources. The refineries connected directly to the West Pipeline are located in Casper and Cheyenne, Wyoming and Denver, Colorado. Refineries in Billings and Laurel, Montana are connected to the West Pipeline through other pipelines. These refineries obtain their supplies of crude oil primarily from Rocky Mountain sources. The North Pipeline, is heavily dependent on the Tesoro Mandan refinery which primarily operates on North Dakota crude oil although it has the ability to access other crude oils. If operations at any one refinery were discontinued, the Partnership believes (assuming unchanged demand for refined petroleum products in markets served by the refined petroleum products pipelines) that the effects thereof would be short-term in nature, and the Partnership's business would not be materially adversely affected over the long term because such discontinued production could be replaced by other refineries or by other sources.
The majority of the refined petroleum product transported through the East Pipeline in 2003 was produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, and operated by the National Cooperative Refining Association ("NCRA"), Frontier Refining and Conoco/Phillips, Inc. respectively. The NCRA and Frontier Refining refineries are connected directly to the East Pipeline. The McPherson, Kansas refinery operated by NCRA accounted for approximately 30.1% of the total amount of product shipped over the East Pipeline in 2003. The East Pipeline also has direct access by third party pipelines to four other refineries in Kansas, Oklahoma and Texas and to Gulf Coast supplies of products through connecting pipelines that receive products from pipelines originating on the Gulf Coast. Five connecting pipelines can deliver propane from gas processing plants in Texas, New Mexico, Oklahoma and Kansas to the East Pipeline for shipment.
The majority of the refined petroleum products transported through the West Pipeline is produced at the Frontier Refinery located at Cheyenne, Wyoming, the Valero Energy Corporation and Suncor Refineries located at Denver, Colorado, and Sinclair's Little America Refinery located at Casper, Wyoming, all of which are connected directly to the West Pipeline. The West Pipeline also has access to three Billings, Montana, area refineries through a connecting pipeline.
Demand for and Sources of Anhydrous Ammonia
The Partnership's Ammonia Pipeline business depends on the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production ("Direct Application" or "DA"), the weather (DA is not effective if the ground is too wet or too dry) and the price of natural gas (the primary component of anhydrous ammonia).
The Ammonia Pipeline is the largest of three anhydrous ammonia pipelines in the United States and the only one that has the capability of receiving foreign production directly into the system and transporting anhydrous ammonia into the nation's corn belt. This ability to receive either domestic or foreign anhydrous ammonia is a competitive advantage over the next largest ammonia system which originates in Oklahoma and extends into Iowa.
Corn producers have several fertilizer alternatives such as liquid, dry or Direct Application. Liquid and dry fertilizers are both upgrades of anhydrous ammonia and therefore are generally more costly but are less sensitive to weather conditions during application. DA is the cheapest method of fertilizer application but cannot be applied if the ground is too wet or extremely dry.
Principal Customers
The Partnership had a total of approximately 55 shippers in 2003. The principal shippers include four integrated oil companies, four refining companies, three large farm cooperatives and one railroad. Transportation revenues attributable to the top 10 shippers were $86.6 million, $61.5 million and $51.5 million, which accounted for 72%, 74% and 69% of total Partnership revenues shipped for each of the years 2003, 2002 and 2001, respectively.
Competition and Business Considerations
The East and North Pipelines' major competitor is an independent, regulated common carrier pipeline system owned by Magellan Midstream Partners, L.P. ("Magellan"), formerly the Williams Companies, Inc., that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. The Magellan system is a substantially more extensive system than the East and North Pipelines. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users, although refined product pricing at either the origin or terminal point on a pipeline may outweigh transportation costs. Twenty-one of the East Pipeline's and all four of the North Pipeline's delivery terminals are located within 2 to 145 miles of, and in direct competition with Magellan's terminals.
The West Pipeline competes with the truck-loading racks of the Cheyenne and Denver refineries and the Denver terminals of the Chase Terminal Company and Conoco/Phillips. Valero L.P. terminals in Denver and Colorado Springs, connected to a Valero L.P. pipeline from their Texas Panhandle Refinery, are major competitors to the West Pipeline's Denver and Fountain Terminals, respectively.
Because pipelines are generally the lowest cost method for intermediate and long-haul movement of refined petroleum products, the Partnership's more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other companies in the areas where the Partnership delivers products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. The Partnership believes high capital costs, tariff regulation, environmental considerations and problems in acquiring rights-of-way make it unlikely that other competing pipeline systems comparable in size and scope to its pipelines will be built in the near future, provided its pipelines have available capacity to satisfy demand and its tariffs remain at reasonable levels.
The costs associated with transporting products from a loading terminal to end users limit the geographic size of the market that can be served economically by any terminal. Transportation to end users from the loading terminals of the Partnership is conducted principally by trucking operations of unrelated third parties. Trucks may competitively deliver products in some of the areas served by the Partnership's pipelines. However, trucking costs render that mode of transportation not competitive for longer hauls or larger volumes. The Partnership does not believe that trucks are, or will be, effective competition to its long-haul volumes over the long term.
Competitors of the Ammonia Pipeline include another anhydrous ammonia pipeline which originates in Oklahoma and terminates in Iowa. The competitor pipeline has the same DA demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Barges and railroads represent other forms of direct competition to the pipeline under certain market conditions.
LIQUIDS TERMINALING BUSINESS
Introduction
The Partnership's terminaling business is conducted through the Support Terminal Services operation ("ST Services" or "ST") and Statia Terminals International N.V. ("Statia"). ST Services is one of the largest independent petroleum products and specialty liquids terminaling companies in the United States. Statia, acquired on February 28, 2002 for a purchase price of $178 million (net of cash acquired), plus the assumption of $107 million of debt, owns and operates the Partnership's two largest terminals and provides related value-added services, including crude oil and petroleum product blending and processing, berthing of vessels at their marine facilities, and emergency and spill response services. In addition to its terminaling services, Statia sells bunkers, which is the fuel marine vessels consume, and bulk petroleum products to various commercial interests.
For the year ended December 31, 2003, the Partnership's terminaling business accounted for approximately 41% of the Partnership's revenues. As of December 31, 2003, ST operated 37 facilities in 20 states, with a total storage capacity of approximately 33.9 million barrels. ST also owns and operates six terminals located in the United Kingdom, having a total capacity of approximately 5.5 million barrels. In September 2002, ST acquired eight terminals in Australia and New Zealand with a total capacity of approximately 1.2 million barrels for approximately $47 million in cash. ST Services and its predecessors have a long history in the terminaling business and handle a wide variety of liquids from petroleum products to specialty chemicals to edible liquids. At the end of 2003, Statia's tank capacity was 18.8 million barrels, including an 11.3 million barrel storage and transshipment facility located on the Netherlands Antilles island of St. Eustatius, and a 7.5 million barrel storage and transshipment facility located at Point Tupper, Nova Scotia, Canada.
The Partnership's terminal facilities provide storage and handling services on a fee basis for petroleum products, specialty chemicals and other liquids. The Partnership's six largest terminal facilities are located on the Island of St. Eustatius, Netherlands Antilles; in Point Tupper, Nova Scotia, Canada; in Piney Point, Maryland; in Linden, New Jersey (50% owned joint venture); in Crockett, California; and in Martinez, California.
Description of Largest Terminal Facilities
St. Eustatius, Netherlands Antilles
Statia owns and operates an 11.3 million barrel petroleum terminaling facility located on the Netherlands Antilles island of St. Eustatius, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and can accommodate the world's largest tankers for loading and discharging crude oil. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station, and an offshore single point mooring buoy with loading and unloading capabilities serve the terminal's customers' vessels. The St. Eustatius facility has a total of 51 tanks. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability as well as in-tank mixers. In addition to the storage and blending services at St. Eustatius, the facility has the flexibility to utilize certain storage capacity for both feedstock and refined products to support its atmospheric distillation unit, which is capable of processing up to 15,000 BPD of feedstock, ranging from condensates to heavy crude oil. Statia owns and operates all of the berthing facilities at its St. Eustatius terminal and charges vessels a fee for their use. Vessel owners or charterers may incur separate fees for associated services such as pilotage, tug assistance, line handling, launch service, emergency response services, and other ship services.
Point Tupper, Nova Scotia, Canada
Statia owns and operates a 7.5 million barrel terminaling facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia, Canada, which is located approximately 700 miles from New York City, 850 miles from Philadelphia and 2,500 miles from Mongstad, Norway. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast and Canada as well as the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate substantially all of the world's largest, fully-laden very large crude carriers and ultra large crude carriers for loading and discharging crude oil, petroleum products, and petrochemicals. The Point Tupper facility has a total of 37 tanks. Its butane sphere is one of the largest of its kind in North America. The facility's tanks were renovated in 1994 to comply with construction standards that meet or exceed American Petroleum Institute, NFPA, and other material industry standards. Crude oil and petroleum product movements at the terminal are fully automated. Separate Statia fees apply for the use of the jetty facility as well as associated services, including pilotage, tug assistance, line handling, launch service, spill response services, and other ship services. Statia also charters tugs, mooring launches, and other vessels to assist with the movement of vessels through the Strait of Canso and the safe berthing of vessels at Point Tupper and to provide other services to vessels.
Piney Point, Maryland
The largest domestic terminal currently owned by ST is located on approximately 400 acres on the Potomac River. The facility was acquired as part of the purchase of the liquids terminaling assets of Steuart Petroleum Company and certain of its affiliates (collectively "Steuart") in December 1995. The Piney Point terminal has approximately 5.4 million barrels of storage capacity in 28 tanks and is the closest deep-water facility to Washington, D.C. This terminal competes with other large petroleum terminals in the East Coast water-borne market extending from New York Harbor to Norfolk, Virginia. The terminal currently stores petroleum products consisting primarily of fuel oils and asphalt. The terminal has a dock with a 36-foot draft for tankers and four berths for barges. It also has truck-loading facilities, product-blending capabilities and is connected to a pipeline which supplies residual fuel oil to two power generating stations.
Linden, New Jersey
In October 1998, ST entered into a joint venture relationship with Northville Industries Corp. ("Northville") to acquire a 50% ownership interest in and the management of the terminal facility at Linden, New Jersey that was previously owned by Northville. The 44-acre facility provides ST with deep-water terminaling capabilities at New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The facility has a total capacity of approximately 3.9 million barrels in 22 tanks, can receive products via ship, barge and pipeline and delivers product by ship, barge, pipeline and truck. The terminal owns two docks and leases a third with draft limits of 35, 24 and 24 feet, respectively.
Crockett, California
The Crockett Terminal was acquired in January 2001 as a part of the Shore acquisition. The terminal has approximately 3 million barrels of tankage and is located in the San Francisco Bay area. The facility provides deep-water access for handling petroleum products and gasoline additives such as ethanol. The terminal offers pipeline connections to various refineries and pipelines. It receives and delivers product by vessel, barge, pipeline and truck-loading facilities. The terminal also has railroad tank car unloading capability.
Martinez, California
The Martinez Terminal, also acquired in January 2001 as a part of the Shore acquisition, is located in the refinery area of San Francisco Bay. It has approximately 3.1 million barrels of tankage and handles refined petroleum products as well as crude oil. The terminal is connected to a pipeline and to area refineries by pipelines and can also receive and deliver products by vessel or barge. It also has a truck rack for product delivery.
The Partnership's facilities have been designed with engineered structural measures to minimize the possibility of the occurrence and the level of damage in the event of a spill or fire. All loading areas, tanks, pipes and pumping areas are "contained" to collect any spillage and insure that only properly treated water is discharged from the site.
Other Terminal Sites
In addition to the four major domestic facilities described above, ST Services has 31 other terminal facilities located throughout the United States, six facilities in the United Kingdom, four facilities in Australia and four in New Zealand. These other facilities primarily store petroleum products for a variety of customers, with the exception of the facilities in Texas City, Texas, which handles specialty chemicals; Columbus, Georgia, which handles aviation gasoline and specialty chemicals; Winona, Minnesota, which handles nitrogen fertilizer solutions; Savannah, Georgia, which handles chemicals and caustic solutions, as well as petroleum products; Vancouver, Washington, which handles chemicals and fertilizer; Eastham, United Kingdom which handles chemicals and animal fats; and Runcorn, United Kingdom, which handles molten sulphur, and the Australian and New Zealand terminals which handle chemicals and animal fats and oil. Overall, these facilities provide ST Services with locations which are diverse geographically, in products handled and in customers served.
The following table outlines the Partnership's terminal locations, capacities, tanks and primary products handled:
Tankage No. of Primary Products
Facility Capacity Tanks Handled
----------------------------- -------------- -------- ---------------------------------
Major U. S. Terminals:
Piney Point, MD 5,403,000 28 Petroleum
Linden, NJ(a) 3,884,000 22 Petroleum
Crockett, CA 3,048,000 24 Petroleum, Ethanol
Martinez, CA 3,106,000 19 Petroleum
Jacksonville, FL 2,069,000 30 Petroleum
Texas City, TX 2,161,000 136 Chemicals, Petrochemicals,
Petroleum
Other U. S. Terminals:
Montgomery, AL(b) 162,000 7 Petroleum, Jet Fuel
Moundville, AL 310,000 6 Jet Fuel
Tucson, AZ(a) 174,000 7 Petroleum
Los Angeles, CA 597,000 20 Petroleum
Richmond, CA 617,000 25 Petroleum, Ethanol
Stockton, CA 706,000 32 Petroleum, Ethanol, Fertilizer
Bremen, GA 182,000 9 Petroleum, Jet Fuel
Brunswick, GA 302,000 3 Fertilizer, Pulp Liquor
Columbus, GA 175,000 24 Petroleum, Chemicals
Macon, GA(b) 307,000 10 Petroleum, Jet Fuel
Savannah, GA 903,000 28 Petroleum, Chemicals
Blue Island, IL 752,000 19 Petroleum, Ethanol
Chillicothe, IL(a) 270,000 6 Petroleum
Peru, IL 221,000 8 Petroleum, Fertilizer
Indianapolis, IN 410,000 18 Petroleum
Westwego, LA 849,000 53 Molasses, Fertilizer, Caustic,
Chemicals
Andrews AFB Pipeline, MD(b) 72,000 3 Jet Fuel
Baltimore, MD 832,000 50 Chemicals, Asphalt, Jet Fuel
Salisbury, MD 177,000 14 Petroleum
Winona, MN 267,000 8 Fertilizer
Reno, NV 107,000 7 Petroleum
Paulsboro, NJ 1,580,000 18 Petroleum
Alamogordo, NM(b) 120,000 5 Jet Fuel
Drumright, OK 315,000 4 Petroleum
Portland, OR 1,119,000 31 Petroleum
Philadelphia, PA 894,000 11 Petroleum
Dumfries, VA 554,000 16 Petroleum, Asphalt
Virginia Beach, VA(b) 40,000 2 Jet Fuel
Tacoma, WA 377,000 15 Petroleum
Vancouver, WA 543,000 55 Chemicals, Fertilizer, Petroleum
Milwaukee, WI 308,000 7 Petroleum
Foreign Terminals:
St. Eustatius, Netherlands
Antilles. 11,350,000 60 Petroleum, crude oil
Point Tupper, Canada 7,514,000 40 Petroleum, crude oil
Sydney, Australia 330,000 65 Chemicals, fats and oils
Melbourne, Australia 468,000 118 Specialty chemicals
Geelong, Australia 145,000 14 Specialty chemicals, petroleum
Adelaide, Australia 90,000 24 Chemicals, tallow, petroleum
Auckland, New Zealand (a) 74,000 44 Fats, oils and chemicals
New Plymouth, New Zealand 35,000 10 Fats, oils and chemicals
Mt. Maunganui, New Zealand 83,000 24 Fats, oils and chemicals
Wellington, New Zealand 50,000 13 Fats, oils and chemicals
Grays, England 1,945,000 53 Petroleum
Eastham, England 2,185,000 162 Chemicals, Petroleum, Animal Fats
Runcorn, England 146,000 4 Molten sulphur
Glasgow, Scotland 344,000 16 Petroleum
Leith, Scotland 459,000 34 Petroleum, Chemicals
Belfast, Northern Ireland 407,000 41 Petroleum
--------------- --------------
59,538,000 1,502
=============== ==============
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(a) The terminal is 50% owned by ST.
(b) Facility also includes pipelines to U.S. government military base locations.
Customers
Statia provides terminaling services for crude oil and refined petroleum products to many of the world's largest producers of crude oil, integrated oil companies, oil traders, and refiners. Statia's crude oil transshipment customers include an oil producer that leases and utilizes 5.0 million barrels of storage at St. Eustatius, and a major international oil company which leases and utilizes 3.6 million barrels of storage at Point Tupper, both of which have long-term contracts with Statia. In addition, two different international oil companies each lease and utilize 1.0 million barrels of clean products storage at St. Eustatius and Point Tupper, respectively. Also in Canada, a consortium consisting of major oil companies sends natural gas liquids via pipeline to certain processing facilities on land leased from Statia. After processing, certain products are stored at the Point Tupper facility under a long-term contract. In addition, Statia's blending capabilities have attracted customers who have leased capacity primarily for blending purposes and who have contributed to Statia's bunker fuel and bulk product sales.
The storage and transport of jet fuel for the U.S. Department of Defense is an important part of ST's business. Eleven of ST's terminal sites are involved in the terminaling or transport (via pipeline) of jet fuel for the Department of Defense and four of the eleven locations have been utilized solely by the U.S. Government. Of the eleven locations, six include pipelines which deliver jet fuel directly to nearby military bases.
Competition and Business Considerations
In addition to the terminals owned by independent terminal operators, such as the Partnership, many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminaling services to third parties. In many instances, major energy and chemical companies that own storage and terminaling facilities are also significant customers of independent terminal operators, such as the Partnership. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines. Terminals located near deep-water port facilities are referred to as "deep-water terminals" and terminals without such facilities are referred to as "inland terminals"; although some inland facilities located on or near navigable rivers are served by barges.
Terminal versatility is a function of the operator's ability to offer handling for diverse products with complex handling requirements. The service function typically provided by the terminal includes, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must be in compliance with applicable environmental regulations. A terminal operator's ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.
A few companies offering liquid terminaling facilities have significantly more capacity than the Partnership. However, much of the Partnership's tankage can be described as "niche" facilities that are equipped to properly handle "specialty" liquids or provide facilities or services where management believes the Partnership enjoys an advantage over competitors. As a result, many of the Partnership's terminals compete against other large petroleum products terminals, rather than specialty liquids facilities. Such specialty or "niche" tankage is less abundant in the U.S. and "specialty" liquids typically command higher terminal fees than lower-price bulk terminaling for petroleum products.
The main competition to crude oil storage at Statia's facilities is from "lightering" which is the process by which liquid cargo is transferred to smaller vessels, usually while at sea. The price differential between lightering and terminaling is primarily driven by the charter rates for vessels of various sizes. Lightering generally takes significantly longer than discharging at a terminal. Depending on charter rates, the longer charter period associated with lightering is generally offset by various costs associated with terminaling, including storage costs, dock charges, and spill response fees. However, terminaling is generally safer and reduces the risk of environmental damage associated with lightering, provides more flexibility in the scheduling of deliveries, and allows customers of Statia to deliver their products to multiple locations. Lightering in U.S. territorial waters creates a risk of liability for owners and shippers of oil under the U.S. Oil Pollution Act of 1990 and other state and federal legislation. In Canada, similar liability exists under the Canadian Shipping Act. Terminaling also provides customers with the ability to access value-added terminal services.
In the bunkering business, Statia competes with ports offering bunker fuels to which, or from which, each vessel travels or are along the route of travel of the vessel. Statia also competes with bunker delivery locations around the world. In the Western Hemisphere, alternative bunker locations include ports on the U.S. East coast and Gulf coast and in Panama, Puerto Rico, the Bahamas, Aruba, Curacao, and Halifax. In addition, Statia competes with Rotterdam and various North Sea locations.
CAPITAL EXPENDITURES
Capital expenditures by the Pipelines, including routine maintenance and expansion expenditures, but excluding acquisitions, were $9.6 million, $9.5 million and $4.3 million for 2003, 2002 and 2001, respectively. During these periods, adequate capacity existed on these pipelines to accommodate volume growth, and the expenditures required for environmental and safety improvements were not material in amount. Capital expenditures, including routine maintenance and expansion expenditures, but excluding acquisitions, for the Partnership's terminaling operations were $34.6 million, $21.0 million and $12.9 million for 2003, 2002 and 2001, respectively.
Capital expenditures of the Partnership during 2004, including routine maintenance and expansion expenditures, but excluding acquisitions, are expected to be approximately $28 million to $32 million. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." Additional expansion-related capital expenditures will depend on future opportunities to expand the Partnership's operations. Such future expenditures, however, will depend on many factors beyond the Partnership's control, including, without limitation, demand for refined petroleum products and terminaling services in the Partnership's market areas, local, state and federal governmental regulations, fuel conservation efforts and the availability of financing on acceptable terms. No assurance can be given that required capital expenditures will not exceed anticipated amounts during the year or thereafter or that the Partnership will have the ability to finance such expenditures through borrowings or choose to do so.
REGULATION
Interstate Regulation
The interstate common carrier petroleum product pipeline operations of the Partnership are subject to rate regulation by FERC under the Interstate Commerce Act. The Interstate Commerce Act provides, among other things, that to be lawful the rates of common carrier petroleum pipelines must be "just and reasonable" and not unduly discriminatory. New and changed rates must be filed with the FERC, which may investigate their lawfulness on protest or its own motion. The FERC may suspend the effectiveness of such rates for up to seven months. If the suspension expires before completion of the investigation, the rates go into effect, but the pipeline can be required to refund to shippers, with interest, any difference between the level the FERC determines to be lawful and the filed rates under investigation. Rates that have become final and effective may be challenged by a complaint to FERC filed by a shipper or on the FERC's own initiative. Reparations may be recovered by the party filing the complaint for the two-year period prior to the complaint, if FERC finds the rate to be unlawful.
The FERC allows for a rate of return for petroleum products pipelines determined by adding (i) the product of a rate of return equal to the nominal cost of debt multiplied by the portion of the rate base that is deemed to be financed with debt and (ii) the product of a rate of return equal to the real (i.e., inflation-free) cost of equity multiplied by the portion of the rate base that is deemed to be financed with equity. The appropriate rate of return for a petroleum pipeline is determined on a case-by-case basis, taking into account cost of capital, competitive factors and business and financial risks associated with pipeline operations.
Under Title XVIII of the Energy Policy Act of 1992 (the "EP Act"), rates that were in effect on October 24, 1991 that were not subject to a protest, investigation or complaint are deemed to be just and reasonable. Such rates, commonly referred to as grandfathered rates, are subject to challenge only for limited reasons. Any relief granted pursuant to such challenges may be prospective only. Because the Partnership's rates that were in effect on October 24, 1991, were not subject to investigation and protest at that time, those rates could be deemed to be just and reasonable pursuant to the EP Act. The Partnership's current rates became final and effective in July 2000, and the Partnership believes that its currently effective tariffs are just and reasonable and would withstand challenge under the FERC's cost-based rate standards. Because of the complexity of rate making, however, the lawfulness of any rate is never assured.
On October 22, 1993, the FERC issued Order No. 561 which adopted a simplified rate making methodology for future oil pipeline rate changes in the form of indexation. Indexation, which is also known as price cap regulation, establishes ceiling prices on oil pipeline rates based on application of a broad-based measure of inflation in the general economy to existing rates. Rate increases up to the ceiling level are to be discretionary for the pipeline, and, for such rate increases, there will be no need to file cost-of-service or supporting data. Moreover, so long as the ceiling is not exceeded, a pipeline may make a limitless number of rate change filings. This indexing mechanism calculates a ceiling rate. Rate decreases are required if the indexing mechanism operates to reduce the ceiling rate below a pipeline's existing rates. The pipeline may increase its rates to this calculated ceiling rate without filing a formal cost based justification and with limited risk of shipper protests.
The indexation method is to serve as the principal basis for the establishment of oil pipeline rate changes in the future. However, the FERC determined that a pipeline may utilize any one of the following alternative methodologies to indexing: (i) a cost-of-service methodology may be utilized by a pipeline to justify a change in a rate if a pipeline can demonstrate that its increased costs are prudently incurred and that there is a substantial divergence between such increased costs and the rate that would be produced by application of the index; and (ii) a pipeline may base its rates upon a "light-handed" market-based form of regulation if it is able to demonstrate a lack of significant market power in the relevant markets.
On September 15, 1997, the Partnership filed an Application for Market Power Determination with the FERC seeking market based rates for approximately half of its markets. In May 1998, the FERC granted the Partnership's application and approximately half of the markets served by the East and West Pipelines subsequently became subject to market force regulation.
In the FERC's Lakehead decision issued June 15, 1995, the FERC partially disallowed Lakehead's inclusion of income taxes in its cost of service. Specifically, the FERC held that Lakehead was entitled to receive an income tax allowance with respect to income attributable to its corporate partners, but was not entitled to receive such an allowance for income attributable to partnership interests held by individuals. Lakehead's motion for rehearing was denied by the FERC and Lakehead appealed the decision to the U.S. Court of Appeals. Subsequently, the case was settled by Lakehead and the appeal was withdrawn. In another FERC proceeding involving a different oil pipeline limited partnership, various shippers challenged such pipeline's inclusion of an income tax allowance in its cost of service. The FERC decided this case on the same basis as its holding in the Lakehead case. If the FERC were to partially or completely disallow the income tax allowance in the cost of service of the East and West pipelines on the basis set forth in the Lakehead order, KPL believes that the Partnership's ability to pay distributions to the holders of the Units would not be impaired; however, in view of the uncertainties involved in this issue, there can be no assurance in this regard.
The Ammonia Pipeline rates are regulated by the Surface Transportation Board (the "STB"). The STB was established in 1996 when the Interstate Commerce Commission was terminated by the ICC Termination Act of 1995. The STB is headed by Board Members appointed by the President and confirmed by the Senate and is authorized to have three members. The STB jurisdiction generally includes railroad rate and service issues, rail restructuring transactions and labor matters related thereto; certain trucking company, moving van, and non-contiguous ocean shipping company rate matters; and certain pipeline matters not regulated by the FERC. In the performance of its functions, the STB is charged with promoting, where appropriate, substantive and procedural regulatory reform in the economic regulation of surface transportation, and with providing an efficient and effective forum for the resolution of disputes. The STB seeks to facilitate commerce by providing an effective forum for efficient dispute resolution and facilitation of appropriate market-based business transactions.
The Partnership issued a STB tariff that became effective April 1, 2003. The tariff filing combined the STB interstate tariff and the Louisiana intrastate tariff into one document and standardized the tariff regulation between the two regulatory bodies. The tariff filing modified the capacity allocation procedures and established a minimum tariff rate of $5.00 per ton. The tariff filing implemented a 7% tariff increase across all tariff rates. Another modification was the removal of the "Industrial User" classification which effectively increases the tariff rates actually paid for transportation to certain shippers by more than 7%. Dyno Nobel, an industrial user in Missouri, has filed a protest against the tariff filing. Dyno's protest centered on basically two issues. First, it questioned the Partnership's ability to file a tariff without first obtaining approval from the STB. Second, it questioned the amount of effective increase on its particular situation on a cost justification basis. CF Industries also filed a protest questioning the Partnership's ability to file a tariff without first obtaining approval from the STB. The Partnership believes it has regulatory precedent in making the tariff filing and can cost justify the tariff rate change. Initial data requests have been submitted and answered, and summary judgment has been requested on the issue of the Partnership's ability to file a tariff change. The cost justification portion of the Dyno protest will go forward after the resolution of the tariff filing issue.
Intrastate Regulation
The intrastate operations of the East Pipeline in Kansas are subject to regulation by the Kansas Corporation Commission, the intrastate operations of the West Pipeline in Colorado and Wyoming are subject to regulation by the Colorado Public Utility Commission and the Wyoming Public Service Commission, respectively, and the intrastate operations of the North Pipeline are subject to regulation by the North Dakota Public Utility Commission. Like the FERC, the state regulatory authorities require that shippers be notified of proposed intrastate tariff increases and have an opportunity to protest such increases. The Partnership also files with such state authorities copies of interstate tariff changes filed with the FERC. In addition to challenges to new or proposed rates, challenges to intrastate rates that have already become effective are permitted by complaint of an interested person or by independent action of the appropriate regulatory authority.
The intrastate operations of the Ammonia Pipeline in Louisiana are subject to regulation by the Louisiana Public Service Commission. Shippers under the Louisiana intrastate tariff have similar rights as those mentioned in the paragraph above.
ENVIRONMENTAL MATTERS
General
The operations of the Partnership are subject to federal, state and local laws and regulations relating to the protection of the environment in the United States and to the environmental laws and regulations of the host countries in regard to the terminals acquired overseas. Although the Partnership believes that its operations are in general compliance with applicable environmental regulations, risks of substantial costs and liabilities are inherent in pipeline and terminal operations, and there can be no assurance that significant costs and liabilities will not be incurred by the Partnership. Moreover, it is possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations of the Partnership, past and present, could result in substantial costs and liabilities to the Partnership.
See "Item 3 - Legal Proceedings" for information concerning two lawsuits against certain subsidiaries of the Partnership involving claims for environmental damages.
Water
The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 and other statutes as they pertain to prevention and response to oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone. In the event of an oil spill into such waters, substantial liabilities could be imposed upon the Partnership. Regulations concerning the environment are continually being developed and revised in ways that may impose additional regulatory burdens on the Partnership.
Contamination resulting from spills or releases of refined petroleum products is not unusual within the petroleum pipeline and liquids terminaling industries. The East Pipeline and ST Services have experienced limited groundwater contamination at various terminal and pipeline sites resulting from various causes including activities of previous owners. Remediation projects are underway or under construction using various remediation techniques. The costs to remediate contamination at several ST terminal locations are being borne by the former owners under indemnification agreements. Although no assurances can be made, the Partnership believes that the aggregate cost of these remediation efforts will not be material.
The EPA has promulgated regulations that may require the Partnership to apply for permits to discharge storm water runoff. Storm water discharge permits also may be required in certain states in which the Partnership operates. Where such requirements are applicable, the Partnership has applied for such permits and, after the permits are received, will be required to sample storm water effluent before releasing it. The Partnership believes that effluent limitations could be met, if necessary, with minor modifications to existing facilities and operations. Although no assurance in this regard can be given, the Partnership believes that the changes will not have a material effect on the Partnership's financial condition or results of operations.
Aboveground Storage Tank Acts
A number of the states in which the Partnership operates in the United States have passed statutes regulating aboveground tanks containing liquid substances. Generally, these statutes require that such tanks include secondary containment systems or that the operators take certain alternative precautions to ensure that no contamination results from any leaks or spills from the tanks. Although there is not total federal regulation of all above ground tanks, the DOT has adopted an industry standard that addresses tank inspection, repair, alteration and reconstruction. This action requires pipeline companies to comply with the standard for tank inspection and repair for all tanks regulated by the DOT. The Partnership is in substantial compliance with all above ground storage tank laws in the states with such laws. Although no assurance can be given, the Partnership believes that the future implementation of above ground storage tank laws by either additional states or by the federal government will not have a material adverse effect on the Partnership's financial condition or results of operations.
Air Emissions
The operations of the Partnership are subject to the Federal Clean Air Act and comparable state and local statutes. The Partnership believes that the operations of its pipelines and terminals are in substantial compliance with such statutes in all states in which they operate.
Amendments to the Federal Clean Air Act enacted in 1990 require or will require most industrial operations in the United States to incur future capital expenditures in order to meet the air emission control standards that have been and are to be developed and implemented by the EPA and state environmental agencies. Pursuant to these Clean Air Act Amendments, those Partnership facilities that emit volatile organic compounds ("VOC") or nitrogen oxides are subject to increasingly stringent regulations, including requirements that certain sources install maximum or reasonably available control technology. In addition, the 1999 Federal Clean Air Act Amendments include a new operating permit for major sources ("Title V Permits"), which applies to some of the Partnership's facilities. Additionally, new dockside loading facilities owned or operated by the Partnership in the United States will be subject to the New Source Performance Standards that were proposed in May 1994. These regulations require control of VOC emissions from the loading and unloading of tank vessels.
Although the Partnership is in substantial compliance with applicable air pollution laws, in anticipation of the implementation of stricter air control regulations, the Partnership is taking actions to substantially reduce its air emissions. The Partnership plans to install bottom loading and vapor recovery equipment on the loading racks at selected terminal sites along the East Pipeline that do not already have such emissions control equipment. These modifications will substantially reduce the total air emissions from each of these facilities. Having begun in 1993, this project is being phased in over a period of years.
Solid Waste
The Partnership generates non-hazardous solid waste that is subject to the requirements of the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes in the United States. The EPA is considering the adoption of stricter disposal standards for non-hazardous wastes. RCRA also governs the disposal of hazardous wastes. At present, the Partnership is not required to comply with a substantial portion of the RCRA requirements because the Partnership's operations generate minimal quantities of hazardous wastes. However, it is anticipated that additional wastes, which could include wastes currently generated during pipeline operations, will in the future be designated as "hazardous wastes". Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses by the Partnership.
At the terminal sites at which groundwater contamination is present, there is also limited soil contamination as a result of the aforementioned spills. The Partnership is under no present requirements to remove these contaminated soils, but the Partnership may be required to do so in the future. Soil contamination also may be present at other Partnership facilities at which spills or releases have occurred. Under certain circumstances, the Partnership may be required to clean up such contaminated soils. Although these costs should not have a material adverse effect on the Partnership, no assurance can be given in this regard.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund") imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of its ordinary operations, the Partnership may generate waste that may fall within CERCLA's definition of a "hazardous substance". The Partnership may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.
Environmental Impact Statement
The United States National Environmental Policy Act of 1969 (the "NEPA") applies to certain extensions or additions to a pipeline system. Under NEPA, if any project that would significantly affect the quality of the environment requires a permit or approval from any United States federal agency, a detailed environmental impact statement must be prepared. The effect of the NEPA may be to delay or prevent construction of new facilities or to alter their location, design or method of construction.
Indemnification
KPL has agreed to indemnify the Partnership against liabilities for damage to the environment resulting from operations of the East Pipeline prior to October 3, 1989. Such indemnification does not extend to any liabilities that arise after such date to the extent such liabilities result from change in environmental laws or regulations. Under such indemnity, KPL is presently liable for the remediation of contamination at certain East Pipeline sites. In addition, the Partnership was wholly or partially indemnified under certain acquisition contracts for some environmental costs. Most of such contracts contain time and amount limitations on the indemnities. To the extent that environmental liabilities exceed the amount of such indemnity, the Partnership has affirmatively assumed the excess environmental liabilities.
SAFETY REGULATION
The Partnership's pipelines are subject to regulation by the United States Department of Transportation (the "DOT") under the Hazardous Liquid Pipeline Safety Act of 1979 ("HLPSA") relating to the design, installation, testing, construction, operation, replacement and management of their pipeline facilities. The HLPSA covers anhydrous ammonia, petroleum and petroleum products pipelines and requires any entity that owns or operates pipeline facilities to comply with such safety regulations and to permit access to and copying of records and to make certain reports and provide information as required by the Secretary to Transportation. The Federal Pipeline Safety Act of 1992 amended the HLPSA to include requirements of the future use of internal inspection devices. The Partnership does not believe that it will be required to make any substantial capital expenditures to comply with the requirements of HLPSA as so amended.
On November 3, 2000, the DOT issued new regulations intended by the DOT to assess the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could adversely affect highly populated areas, areas unusually sensitive to environmental impact and commercially navigable waterways. Under the regulations, an operator is required, among other things, to conduct baseline integrity assessment tests (such as internal inspections) within seven years, conduct future integrity tests at typically five-year intervals and develop and follow a written risk-based integrity management program covering the designated high consequence areas. The Partnership does not believe that the increased costs of compliance with these regulations will materially affect the Partnership's results of operations.
The Partnership is subject to the requirements of the United States Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be collected regarding hazardous materials used or produced in operations and that this information be provided to employees, state and local authorities and citizens. The Partnership believes that it is in general compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to benzene.
The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act, and comparable state statutes require the Partnership to organize information about the hazardous materials used in its operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request. In general, the Partnership expects to increase its expenditures during the next decade to comply with more stringent industry and regulatory safety standards such as those described above. Such expenditures cannot be accurately estimated at this time, although they are not expected to have a material adverse impact on the Partnership.
EMPLOYEES
The Partnership has no employees. The business of the Partnership is conducted by the general partner, KPL, and its affiliate, Kaneb LLC, which employs all persons necessary for the operation of the Partnership's business. At December 31, 2003, approximately 1,060 persons were employed. Approximately 152 of the persons at seven terminal locations in the United States and Canada were subject to representation by labor unions and collective bargaining or similar contracts at that date. KPL and Kaneb LLC consider relations with their employees to be good.
AVAILABLE INFORMATION
The Partnership files annual, quarterly, and other reports and other information with the Securities and Exchange Commission ("SEC") under the Securities Exchange Act of 1934 (the "Exchange Act"). You may read and copy any materials that the Partnership files with the SEC at the SEC's Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy information statements, and other information regarding issuers that file electronically with the SEC.
The Partnership also makes available free of charge on or through the Partnership's Internet site (http://www.kaneb.com) the Partnership's Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other information statements and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after the reports and other information is electronically filed with, or furnished to, the SEC.
Item 2. Properties
The properties owned or utilized by the Partnership and its subsidiaries are generally described in Item 1 of this Report. Additional information concerning the obligations of the Partnership and its subsidiaries for lease and rental commitments is presented under the caption "Commitments and Contingencies" in Note 6 to the Partnership's consolidated financial statements. Such descriptions and information are hereby incorporated by reference into this Item 2.
The properties used in the operations of the Partnership's pipelines are owned by the Partnership, through its subsidiary entities, except for KPL's operational headquarters, located in Wichita, Kansas, which is held under a lease that expires in 2009. Statia's facilities are owned through subsidiaries and the majority of ST's facilities are owned, while the remainder, including some of its terminal facilities located in port areas and its operational headquarters, located in Dallas, Texas, are held pursuant to lease agreements having various expiration dates, rental rates and other terms.
Item 3. Legal Proceedings
Grace Litigation. Certain subsidiaries of the Partnership were sued in a Texas state court in 1997 by Grace Energy Corporation ("Grace"), the entity from which the Partnership acquired ST Services in 1993. The lawsuit involves environmental response and remediation costs allegedly resulting from jet fuel leaks in the early 1970's from a pipeline. The pipeline, which connected a former Grace terminal with Otis Air Force Base in Massachusetts (the "Otis pipeline" or the "pipeline"), ceased operations in 1973 and was abandoned before 1978, when the connecting terminal was sold to an unrelated entity. Grace alleged that subsidiaries of the Partnership acquired the abandoned pipeline, as part of the acquisition of ST Services in 1993 and assumed responsibility for environmental damages allegedly caused by the jet fuel leaks. Grace sought a ruling from the Texas court that these subsidiaries are responsible for all liabilities, including all present and future remediation expenses, associated with these leaks and that Grace has no obligation to indemnify these subsidiaries for these expenses. In the lawsuit, Grace also sought indemnification for expenses of approximately $3.5 million that it incurred since 1996 for response and remediation required by the State of Massachusetts and for additional expenses that it expects to incur in the future. The consistent position of the Partnership's subsidiaries has been that they did not acquire the abandoned pipeline as part of the 1993 ST Services transaction, and therefore did not assume any responsibility for the environmental damage nor any liability to Grace for the pipeline.
At the end of the trial, the jury returned a verdict including findings that (1) Grace had breached a provision of the 1993 acquisition agreement by failing to disclose matters related to the pipeline, and (2) the pipeline was abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired ST Services. On August 30, 2000, the Judge entered final judgment in the case that Grace take nothing from the subsidiaries on its claims seeking recovery of remediation costs. Although the Partnership's subsidiaries have not incurred any expenses in connection with the remediation, the court also ruled, in effect, that the subsidiaries would not be entitled to indemnification from Grace if any such expenses were incurred in the future. Moreover, the Judge let stand a prior summary judgment ruling that the pipeline was an asset acquired by the Partnership's subsidiaries as part of the 1993 ST Services transaction and that any liabilities associated with the pipeline would have become liabilities of the subsidiaries. Based on that ruling, the Massachusetts Department of Environmental Protection and Samson Hydrocarbons Company (successor to Grace Petroleum Company) wrote letters to ST Services alleging its responsibility for the remediation, and ST Services responded denying any liability in connection with this matter. The Judge also awarded attorney fees to Grace of more than $1.5 million. Both the Partnership's subsidiaries and Grace have appealed the trial court's final judgment to the Texas Court of Appeals in Dallas. In particular, the subsidiaries have filed an appeal of the judgment finding that the Otis pipeline and any liabilities associated with the pipeline were transferred to them as well as the award of attorney fees to Grace.
On April 2, 2001, Grace filed a petition in bankruptcy, which created an automatic stay against actions against Grace. This automatic stay covers the appeal of the Dallas litigation, and the Texas Court of Appeals has issued an order staying all proceedings of the appeal because of the bankruptcy. Once that stay is lifted, the Partnership's subsidiaries that are party to the lawsuit intend to resume vigorous prosecution of the appeal.
The Otis Air Force Base is a part of the Massachusetts Military Reservation ("MMR Site"), which has been declared a Superfund Site pursuant to CERCLA. The MMR Site contains a number of groundwater contamination plumes, two of which are allegedly associated with the Otis pipeline, and various other waste management areas of concern, such as landfills. The United States Department of Defense, pursuant to a Federal Facilities Agreement, has been responding to the Government remediation demand for most of the contamination problems at the MMR Site. Grace and others have also received and responded to formal inquiries from the United States Government in connection with the environmental damages allegedly resulting from the jet fuel leaks. The Partnership's subsidiaries voluntarily responded to an invitation from the Government to provide information indicating that they do not own the pipeline. In connection with a court-ordered mediation between Grace and the Partnership's subsidiaries, the Government advised the parties in April 1999 that it has identified two spill areas that it believes to be related to the pipeline that is the subject of the Grace suit. The Government at that time advised the parties that it believed it had incurred costs of approximately $34 million, and expected in the future to incur costs of approximately $55 million, for remediation of one of the spill areas. This amount was not intended to be a final accounting of costs or to include all categories of costs. The Government also advised the parties that it could not at that time allocate its costs attributable to the second spill area.
By letter dated July 26, 2001, the United States Department of Justice ("DOJ") advised ST Services that the Government intends to seek reimbursement from ST Services under the Massachusetts Oil and Hazardous Material Release Prevention and Response Act and the Declaratory Judgment Act for the Government's response costs at the two spill areas discussed above. The DOJ relied in part on the Texas state court judgment, which in the DOJ's view, held that ST Services was the current owner of the pipeline and the successor-in-interest of the prior owner and operator. The Government advised ST Services that it believes it has incurred costs exceeding $40 million, and expects to incur future costs exceeding an additional $22 million, for remediation of the two spill areas. The Partnership believes that its subsidiaries have substantial defenses. ST Services responded to the DOJ on September 6, 2001, contesting the Government's positions and declining to reimburse any response costs. The DOJ has not filed a lawsuit against ST Services seeking cost recovery for its environmental investigation and response costs. Representatives of ST Services have met with representatives of the Government on several occasions since September 6, 2001 to discuss the Government's claims and to exchange information related to such claims. Additional exchanges of information are expected to occur in the future and additional meetings may be held to discuss possible resolution of the Government's claims without litigation. The Partnership does not believe this matter will have a materially adverse effect on its financial condition, although there can be no assurances as to the ultimate outcome.
PEPCO Litigation. On April 7, 2000, a fuel oil pipeline in Maryland owned by Potomac Electric Power Company ("PEPCO") ruptured. Work performed with regard to the pipeline was conducted by a partnership of which ST Services is general partner. PEPCO has reported that it has incurred total cleanup costs of $70 million to $75 million. PEPCO probably will continue to incur some cleanup related costs for the foreseeable future, primarily in connection with EPA requirements for monitoring the condition of some of the impacted areas. Since May 2000, ST Services has provisionally contributed a minority share of the cleanup expense, which has been funded by ST Services' insurance carriers. ST Services and PEPCO have not, however, reached a final agreement regarding ST Services' proportionate responsibility for this cleanup effort, if any, and cannot predict the amount, if any, that ultimately may be determined to be ST Services' share of the remediation expense, but ST believes that such amount will be covered by insurance and therefore will not materially adversely affect the Partnership's financial condition.
As a result of the rupture, purported class actions were filed against PEPCO and ST Services in federal and state court in Maryland by property and business owners alleging damages in unspecified amounts under various theories, including under the Oil Pollution Act ("OPA") and Maryland common law. The federal court consolidated all of the federal cases in a case styled as In re Swanson Creek Oil Spill Litigation. A settlement of the consolidated class action, and a companion state-court class action, was reached and approved by the federal judge. The settlement involved creation and funding by PEPCO and ST Services of a $2,250,000 class settlement fund, from which all participating claimants would be paid according to a court-approved formula, as well as a court-approved payment to plaintiffs' attorneys. The settlement has been consummated and the fund, to which PEPCO and ST Services contributed equal amounts, has been distributed. Participating claimants' claims have been settled and dismissed with prejudice. A number of class members elected not to participate in the settlement, i.e., to "opt out," thereby preserving their claims against PEPCO and ST Services. All non-participant claims have been settled for immaterial amounts with ST Services' portion of such settlements provided by its insurance carrier.
PEPCO and ST Services agreed with the federal government and the State of Maryland to pay costs of assessing natural resource damages arising from the Swanson Creek oil spill under OPA and of selecting restoration projects. This process was completed in mid-2002. ST Services' insurer has paid ST Services' agreed 50 percent share of these assessment costs. In late November 2002, PEPCO and ST Services entered into a Consent Decree resolving the federal and state trustees' claims for natural resource damages. The decree required payments by ST Services and PEPCO of a total of approximately $3 million to fund the restoration projects and for remaining damage assessment costs. The federal court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO and ST have each paid their 50% share and thus fully performed their payment obligations under the Consent Decree. ST Services' insurance carrier funded ST Services' payment.
The U.S. Department of Transportation ("DOT") has issued a Notice of Proposed Violation to PEPCO and ST Services alleging violations over several years of pipeline safety regulations and proposing a civil penalty of $647,000 jointly against the two companies. ST Services and PEPCO have contested the DOT allegations and the proposed penalty. A hearing was held before the Office of Pipeline Safety at the DOT in late 2001. ST Services does not anticipate any further hearings on the subject and is still awaiting the DOT's ruling.
By letter dated January 4, 2002, the Attorney General's Office for the State of Maryland advised ST Services that it intended to seek penalties from ST Services in connection with the April 7, 2000 spill. The State of Maryland subsequently asserted that it would seek penalties against ST Services and PEPCO totaling up to $12 million. A settlement of this claim was reached in mid-2002 under which ST Services' insurer will pay a total of slightly more than $1 million in installments over a five year period. PEPCO has also reached a settlement of these claims with the State of Maryland. Accordingly, the Partnership believes that this matter will not have a material adverse effect on its financial condition.
On December 13, 2002, ST Services sued PEPCO in the Superior Court, District of Columbia, seeking, among other things, a declaratory judgment as to ST Services' legal obligations, if any, to reimburse PEPCO for costs of the oil spill. On December 16, 2002, PEPCO sued ST Services in the United States District Court for the District of Maryland, seeking recovery of all its costs for remediation of and response to the oil spill. Pursuant to an agreement between ST Services and PEPCO, ST Services' suit was dismissed, subject to refiling. ST Services has moved to dismiss PEPCO's suit. ST Services is vigorously defending against PEPCO's claims and is pursuing its own counterclaims for return of monies ST Services has advanced to PEPCO for settlements and cleanup costs. The Partnership believes that any costs or damages resulting from these lawsuits will be covered by insurance and therefore will not materially adversely affect the Partnership's financial condition. The amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy which has a $600,000 retention, but the Partnership does not believe that such retention, if incurred, would materially adversely affect the Partnership's financial condition.
The Partnership has other contingent liabilities resulting from litigation, claims and commitments incident to the ordinary course of business. Management of the Partnership believes, based on the advice of counsel, that the ultimate resolution of such contingencies will not have a materially adverse effect on the financial position, results of operations or liquidity of the Partnership.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for the Registrant's Partnership Interests and Related Partners Matters
KPP owns a 99% interest as sole limited partner interest and KPL owns a 1% general partner interest in the Partnership. There is no established public trading market for the Partnership ownership interests.
The Partnership makes regular cash distributions, in accordance with its partnership agreement, within 45 days after the end of each quarter to limited partner and general partner interests.
The Partnership is a limited partnership that is not subject to federal income tax. Instead, the partners are required to report their allocable share of the Partnership income, gain, loss, deduction and credit, regardless of whether the Partnership makes distributions.
Item 6. Summary Historical Financial and Operating Data
The following table sets forth, for the periods and at the dates indicated, selected historical financial data for Kaneb Pipe Line Operating Partnership, L.P. and its subsidiaries (the "Partnership"). The data in the table (in thousands) is derived from the historical financial statements of the Partnership and should be read in conjunction with the Partnership's audited financial statements. See also "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Year Ended December 31,
---------------------------------------------------------------------
2003 2002 (a) 2001 (a) 2000 1999
---------- ----------- --------- --------- ----------
Income Statement Data:
Revenues:
Services.......................... $ 354,591 $ 288,669 $ 207,796 $ 156,232 $ 158,028
Products.......................... 215,823 97,961 - - -
----------- ----------- --------- ---------- ----------
570,414 386,630 207,796 156,232 158,028
----------- ----------- --------- ---------- ----------
Costs and expenses:
Cost of products sold............. 195,100 90,898 - - -
Operating costs................... 168,537 131,326 90,632 69,653 69,148
Depreciation and amortization..... 53,155 39,425 23,184 16,253 15,043
Gain on sale of assets............ - (609) - (1,126) -
General and administrative........ 25,121 19,869 11,889 11,881 9,424
----------- ----------- --------- ---------- ----------
441,913 280,909 125,705 96,661 93,615
----------- ----------- --------- ---------- ----------
Operating income...................... 128,501 105,721 82,091 59,571 64,413
Interest and other income............. 261 3,570 4,277 316 408
Interest expense...................... (38,757) (28,110) (14,783) (12,283) (13,390)
Loss on debt extinguishment........... - (3,282) (6,540) - -
Income tax expense.................... (5,223) (4,083) (256) (943) (1,496)
----------- ----------- --------- ---------- ----------
Income before cumulative effect of
change in accounting principle.... 84,782 73,816 64,789 46,661 49,935
Cumulative effect of change in
accounting principle - adoption
of new accounting standard for
asset retirement obligations...... (1,593) - - - -
----------- ----------- ---------- ---------- ----------
Net income ........................... $ 83,189 $ 73,816 $ 64,789 $ 46,661 $ 49,935
=========== =========== ========= ========== ==========
Cash distributions declared........... $ 102,948 $ 79,816 $ 62,156 $ 53,485 $ 51,850
=========== =========== ========= ========== ==========
Balance Sheet Data (at year end):
Property and equipment, net........... $ 1,112,970 $ 1,092,192 $ 481,274 $ 321,355 $ 316,883
Total assets.......................... 1,264,682 1,215,410 548,371 375,063 365,953
Long-term debt........................ 617,696 694,330 262,624 166,900 155,987
Partners' capital..................... 493,589 393,314 220,527 161,735 169,321
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(a) See Note 3 to Consolidated Financial Statements regarding acquisitions.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
This discussion should be read in conjunction with the consolidated financial statements of Kaneb Pipe Line Operating Partnership, L.P. (the "Partnership") and notes thereto and the summary historical financial and operating data included elsewhere in this report.
GENERAL
The Partnership, a limited partnership, is engaged in the refined petroleum products and anhydrous ammonia pipeline business and the terminaling of petroleum products and specialty liquids. Kaneb Pipe Line Partners, L.P. ("KPP"), a master limited partnership, holds a 99% interest as limited partner in the Partnership. Kaneb Pipe Line Company LLC ("KPL"), now a wholly owned subsidiary of Kaneb Services LLC ("KSL"), manages and controls the operations of KPP through its general partner interest and an 18% (at December 31, 2003) limited partner interest. KPL owns a 1% interest as general partner of the Partnership and a 1% interest as general partner of KPP.
The Partnership's petroleum pipeline business consists primarily of the transportation, as a common carrier, of refined petroleum products in Kansas, Nebraska, Iowa, South Dakota, North Dakota, Colorado, Wyoming and Minnesota. Common carrier activities are those under which transportation through the pipelines is available at published tariffs filed, in the case of interstate shipments with the Federal Energy Regulatory Commission (the "FERC"), or in the case of intrastate shipments, with the relevant state authority, to any shipper of refined petroleum products who requests such services and satisfies the conditions and specifications for transportation. The petroleum pipelines primarily transport gasoline, diesel oil, fuel oil and propane. Substantially all of the petroleum pipeline operations constitute common carrier operations that are subject to federal or state tariff regulations. The Partnership also owns an approximately 2,000-mile anhydrous ammonia pipeline system acquired from Koch Pipeline Company, L.P. in November of 2002 (see "Liquidity and Capital Resources"). The fertilizer pipeline originates in southern Louisiana, proceeds north through Arkansas and Missouri, and then branches east into Illinois and Indiana and north and west into Iowa and Nebraska. The Partnership's petroleum pipeline business depends on the level of demand for refined petroleum products in the markets served by the pipelines and the ability and willingness of refineries and marketers having access to the pipelines to supply such demand by deliveries through the pipelines. The Partnership's pipeline revenues are based on volumes shipped and the distance over which such volumes are transported.
The Partnership's terminaling business is conducted through Support Terminal Services ("ST Services") and Statia Terminals International N.V. ("Statia"). ST Services is one of the largest independent petroleum products and specialty liquids terminaling companies in the United States. In the United States, ST Services operates 37 facilities in 20 states. ST Services also owns and operates six terminals located in the United Kingdom and eight terminals in Australia and New Zealand. ST Services and its predecessors have a long history in the terminaling business and handle a wide variety of liquids from petroleum products to specialty chemicals to edible liquids. Statia, acquired on February 28, 2002 (see "Liquidity and Capital Resources"), owns a terminal on the Island of St. Eustatius, Netherlands Antilles and a terminal at Point Tupper, Nova Scotia, Canada. Independent terminal owners generally compete on the basis of the location and versatility of the terminals, service and price. Terminal versatility is a function of the operator's ability to offer handling for diverse products with complex handling requirements. The service function typically provided by the terminal includes the safe storage of product at specified temperatures and other conditions, as well as receipt and delivery from the terminal. The ability to obtain attractive pricing is dependent largely on the quality, versatility and reputation of the facility. Terminaling revenues are earned based on fees for the storage and handling of products.
The Partnership's product sales business delivers bunker fuels to ships in the Caribbean and Nova Scotia, Canada, and sells bulk petroleum products to various commercial customers at those locations. In the bunkering business, the Partnership competes with ports offering bunker fuels along the route of the vessel. Vessel owners or charterers are charged berthing and other fees for associated services such as pilotage, tug assistance, line handling, launch service and emergency response services.
OVERVIEW
In 2003, The Partnership integrated the major acquisitions completed in 2002 and focused on the performance of those operations, as well as its core business, to generate increased cash flow. The Partnership's success in this effort enabled it to increase cash distributions twice in 2003. On an annualized basis, KPP raised its distribution $0.08 in May 2003 and then another $0.12 in November 2003. The Partnership had a very strong year as revenues increased 48%, operating income increased 22% and net income increased 13%.
In 2003, the Partnership completed the financing for the $600 million of acquisitions it made in 2002, which were financed half with equity and half with debt. In March 2003, KPP sold approximately three million units - the largest and most successful equity offering in its history. The Partnership completed the placement of its permanent financing in May 2003, and over 85% of that debt is at favorable fixed rates, thereby limiting its exposure to rising interest rates. The Partnership also completed a new revolving credit facility of $400 million, with the ability to increase it to $450 million.
The Partnership has a very strong balance sheet and the financial capacity for further expansion. The Partnership has integrated and assimilated the substantial acquisitions it made in 2002 and has seen the contribution of those operations to its results in 2003. The Partnership now actively seeks opportunities for strategic and substantial growth.
CONSOLIDATED RESULTS OF OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 570,414 $ 386,630 $ 207,796
=========== =========== ===========
Operating income..................................... $ 128,501 $ 105,721 $ 82,091
=========== =========== ===========
Income before cumulative effect of change in
accounting principle............................. $ 84,782 $ 73,816 $ 64,789
Cumulative effect of change in accounting principle.. (1,593) - -
---------- ----------- -----------
Net income........................................... $ 83,189 $ 73,816 $ 64,789
=========== =========== ===========
Capital expenditures, excluding acquisitions......... $ 44,741 $ 31,101 $ 17,246
=========== =========== ===========
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For the year ended December 31, 2003, revenues increased by $183.8 million, or 48%, compared to 2002, due to a $36.9 million increase in revenues in the pipeline business, a $29.0 million increase in revenues in the terminaling business and a $117.9 million increase in product sales revenues. See "Liquidity and Capital Resources" regarding 2002 acquisitions. Operating income for the year ended December 31, 2003 increased by $22.8 million, or 22%, when compared to 2002, due to a $13.2 million increase in pipeline operating income, a $1.5 million increase in terminaling operating income and a $8.1 million increase in product sales operating income. Income before cumulative effect of change in accounting principle increased by $11.0 million, or 15%, when compared to 2002. Overall, 2003 net income, including a charge of $1.6 million for the cumulative effect of change in accounting principle - adoption of new accounting standard for asset retirement obligations, increased by $9.4 million, or 13%, when compared to 2002.
For the year ended December 31, 2002, revenues increased by $178.8 million, or 86%, compared to 2001, due to a $73.2 million increase in revenues in the terminaling business and a $7.7 million increase in revenues in the pipeline business. 2002 revenues also include $97.9 million in product sales revenues from a business acquired with Statia in February of 2002. See "Liquidity and Capital Resources". Operating income for the year ended December 31, 2002 increased by $23.6 million, or 29%, when compared to 2001, due to a $19.7 million increase in terminaling business operating income, a $1.9 million increase in pipeline operating income and 2002 product sales operating income of $2.1 million. Overall, net income for the year ended December 31, 2002 increased by $9.0 million, or 14%, when compared to 2001.
PIPELINE OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 119,633 $ 82,698 $ 74,976
Operating costs...................................... 46,379 33,744 28,844
Depreciation and amortization........................ 14,117 6,408 5,478
General and administrative........................... 7,277 3,923 3,881
----------- ----------- -----------
Operating income..................................... $ 51,860 $ 38,623 $ 36,773
=========== =========== ===========
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The Partnership's pipeline revenues are based on volumes shipped and the distances over which such volumes are transported. Because tariff rates are regulated by the FERC or STB, the pipelines compete on the basis of quality of service, including delivering products at convenient locations on a timely basis to meet the needs of its customers. For the year ended December 31, 2003, revenues increased by $36.9 million, or 45%, compared to 2002, due entirely to the November and December 2002 pipeline acquisitions (see "Liquidity and Capital Resources"). For the year ended December 31, 2002, revenues increased by $7.7 million, or 10%, compared to 2001, due to higher per barrel rates realized on volumes shipped on existing pipelines and as a result of the 2002 pipeline acquisitions. Approximately $4.5 million of the 2002 revenue increase was a result of the pipeline acquisitions. Barrel miles on petroleum pipelines totaled 21.3 billion (including 4.7 billion for the petroleum pipeline acquired in December of 2002), 18.3 billion and 18.6 billion for the years ended December 31, 2003, 2002 and 2001, respectively.
Operating costs, which include fuel and power costs, materials and supplies, maintenance and repair costs, salaries, wages and employee benefits, and property and other taxes, increased by $12.6 million in 2003 and $4.9 million in 2002. The increase in 2003 was due to the 2002 pipeline acquisitions and increases in planned maintenance. The increase in 2002 was due to the pipeline acquisitions and increases in expenditures for routine repairs and maintenance. For the years ended December 31, 2003 and 2002, depreciation and amortization increased by $7.7 million and $0.9 million, respectively, when compared to the respective prior year, due to the pipeline acquisitions. General and administrative costs which includes managerial, accounting and administrative personnel costs, office rental expense, legal and professional costs and other non-operating costs increased by $3.4 million in 2003, when compared to 2002, due primarily to the pipeline acquisitions and increases in personnel-related costs.
TERMINALING OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 234,958 $ 205,971 $ 132,820
Operating costs...................................... 114,030 94,480 61,788
Depreciation and amortization........................ 38,089 32,368 17,706
Gain on sale of assets............................... - (609) -
General and administrative........................... 16,307 14,692 8,008
----------- ----------- -----------
Operating income..................................... $ 66,532 $ 65,040 $ 45,318
=========== =========== ===========
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For the year ended December 31, 2003, the Partnership's terminaling revenues increased by $29.0 million, or 14%, when compared to 2002, due to the 2002 terminal acquisitions (see "Liquidity and Capital Resources") and overall increases in the average price realized per barrel of tankage utilized. For the year ended December 31, 2002, revenues increased by $73.2 million, or 55%, compared to 2001, due to the terminal acquisitions and overall increases in utilizations at existing locations. Approximately $25 million of the 2003 revenue increase and $63 million of the 2002 revenue increase was a result of the terminal acquisitions. Average annual tankage utilized for the years ended December 31, 2003, 2002 and 2001 aggregated 46.7 million barrels, 46.5 million barrels and 30.1 million barrels, respectively. Average revenues per barrel of tankage utilized for the years ended December 31, 2003, 2002 and 2001 was $5.02, $4.43 and $4.41, respectively. The increase in 2003 average revenues per barrel of tankage utilized was the result of changes in product mix resulting from the 2002 terminals acquisitions and foreign currency exchange differences. The increase in 2002 average revenues per barrel of tankage utilized was due to more favorable domestic market conditions, when compared to 2001.
In 2003, operating costs increased by $19.6 million, when compared to 2002, due to the 2002 terminal acquisitions, repair costs associated with hurricane Isabel and increases in planned maintenance. In 2002, operating costs increased by $32.7 million, when compared to 2001, due to the 2002 terminal acquisitions and increases in volumes stored at existing locations. For the years ended December 31, 2003 and 2002, depreciation and amortization increased by $5.7 million and $14.7 million, respectively, due to the terminal acquisitions. In 2002, KPP sold land and other terminaling business assets for net proceeds of approximately $1.1 million, recognizing a gain on disposition of assets of $0.6 million. General and administrative expense increased by $1.6 million in 2003 and by $6.7 million in 2002, due to the terminal acquisitions and increases in personnel-related costs.
PRODUCT SALES OPERATIONS
Year Ended December 31,
---------------------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
Revenues............................................. $ 215,823 $ 97,961 $ -
Cost of products sold................................ 195,100 90,898 -
----------- ----------- -----------
Gross margin......................................... $ 20,723 $ 7,063 $ -
=========== =========== ===========
Operating income..................................... $ 10,109 $ 2,058 $ -
=========== =========== ===========
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The product sales business, which was acquired with Statia (see "Liquidity and Capital Resources"), delivers bunker fuels to ships in the Caribbean and Nova Scotia, Canada and sells bulk petroleum products to various commercial interests. For the year ended December 31, 2003, product sales revenues, gross margin and operating income increased by $117.9 million, $13.7 million and $8.1 million, respectively, when compared to 2002, due to increases in both sales price and volumes. Approximately $95.8 of the 2003 revenue increase was due to volume increases and $22.1 million was due to price increases, when compared to 2002. The results of operations for the year ended December 31, 2002 include the operations of the product sales business since the date of acquisition, February 28, 2002.
Product inventories are maintained at minimum levels to meet customers' needs; however, market prices for petroleum products can fluctuate significantly in short periods of time.
INTEREST AND OTHER INCOME
In September of 2002, the Partnership entered into a treasury lock contract, maturing on November 4, 2002, for the purpose of locking in the US Treasury interest rate component on $150 million of anticipated thirty-year public debt offerings. The treasury lock contract originally qualified as a cash flow hedging instrument under Statement of Financial Accounting Standards ("SFAS") No. 133. In October of 2002, the Partnership, due to various market factors, elected to defer issuance of the public debt securities, effectively eliminating the cash flow hedging designation for the treasury lock contract. On October 29, 2002, the contract was settled resulting in a net realized gain of $3.0 million, which was recognized as a component of interest and other income.
In March of 2001, the Partnership entered into two contracts for the purpose of locking in interest rates on $100 million of anticipated ten-year public debt offerings. As the interest rate locks were not designated as hedging instruments pursuant to the requirements of SFAS No. 133, increases or decreases in the fair value of the contracts are included as a component of interest and other income. On May 22, 2001, the contracts were settled resulting in a gain of $3.8 million, which is included in interest and other income in 2001.
INTEREST EXPENSE
For the year ended December 31, 2003, interest expense increased by $10.6 million, when compared to 2002, due to increases in fixed rate debt resulting from the 2002 pipeline and terminal acquisitions (see "Liquidity and Capital Resources"), partially offset by overall declines in interest rates on variable rate debt.
For the year ended December 31, 2002, interest expense increased by $13.3 million, when compared to 2001, due to overall increases in debt levels resulting from the 2002 acquisitions (see "Liquidity and Capital Resources"), partially offset by declines in interest rates on variable rate debt.
INCOME TAXES
Partnership operations are not subject to federal or state income taxes. However, certain operations are conducted through separate taxable wholly-owned U.S. and foreign corporate subsidiaries. The income tax expense for these subsidiaries was $5.2 million, $4.1 million and $0.3 million for the years ended December 31, 2003, 2002 and 2001, respectively. The 2003 and 2002 increases in income taxes, compared to the respective prior year, was primarily due to foreign taxes on terminaling operations acquired in 2002 (see "Liquidity and Capital Resources").
On June 1, 1989, the governments of the Netherlands Antilles and St. Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January 1, 1989, which expired on December 31, 2000. This agreement requires a subsidiary of the Partnership, which was acquired with Statia on February 28, 2002, to pay a 2% rate on taxable income, as defined therein, or a minimum payment of 500,000 Netherlands Antilles guilders ($0.3 million) per year. The agreement further provides that any amounts paid in order to meet the minimum annual payment will be available to offset future tax liabilities under the agreement to the extent that the minimum annual payment is greater than 2% of taxable income. The subsidiary is currently engaged in discussions with representatives appointed by the Island Territory of St. Eustatius regarding the renewal or modification of the agreement, but the ultimate outcome cannot be predicted at this time. The subsidiary has accrued amounts assuming a new agreement becomes effective, and continues to make payments, as required, under the previous agreement.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities was $142.0 million, $91.8 million and $95.7 million for the years 2003, 2002 and 2001, respectively. The increase in 2003, compared to 2002, was due to increases in pipeline, terminaling and product sales revenues and operating income, primarily a result of the 2002 acquisitions, and changes in working capital components from the timing of cash receipts and disbursements. The 2002 decrease in cash provided by operating activities, when compared to 2001, was due to the payment of personnel-related costs assumed with the Statia acquisition, initial working capital requirements of the pipeline businesses acquired in 2002 and changes in working capital components resulting from the timing of cash receipts and disbursements, partially offset by overall increases in revenues and operating income.
Capital expenditures, including routine maintenance and expansion expenditures, but excluding acquisitions, were $44.7 million, $31.1 million and $17.2 million for 2003, 2002 and 2001, respectively. The increase in 2003 and 2002 capital expenditures, when compared to the respective prior year, is the result of planned maintenance and expansion capital expenditures related to the pipeline and terminaling operations acquired in 2002 and higher maintenance capital expenditures in the existing pipeline and terminaling businesses. During all periods, adequate pipeline capacity existed to accommodate volume growth, and the expenditures required for environmental and safety improvements were not, and are not expected in the future to be, significant. Environmental damages are included under the Partnership's insurance coverages (subject to deductibles and limits). The Partnership anticipates that capital expenditures (including routine maintenance and expansion expenditures, but excluding acquisitions) will total approximately $28 million to $32 million in 2004. Such future expenditures, however, will depend on many factors beyond the Partnership's control, including, without limitation, demand for refined petroleum products and terminaling services in the Partnership's market areas, local, state and federal government regulations, fuel conservation efforts and the availability of financing on acceptable terms. No assurance can be given that required capital expenditures will not exceed anticipated amounts during the year or thereafter or that the Partnership will have the ability to finance such expenditures through borrowings, or choose to do so.
The Partnership makes regular cash distributions in accordance with its Partnership agreement within 45 days after the end of each quarter to limited partner and general partner interests. Aggregate distributions of $98.2 million, $74.4 million and $62.2 million, were paid to limited partner interests and general partner interests in 2003, 2002 and 2001, respectively.
The Partnership expects to fund future cash distributions and routine maintenance capital expenditures with existing cash and anticipated cash flows from operations. Expansionary capital expenditures are expected to be funded through additional Partnership bank borrowings and/or future public debt offerings or KPP public equity offerings.
In January of 2001, the Partnership used proceeds from its revolving credit agreement to repay in full its $128 million of mortgage notes. Under the provisions of the mortgage notes, the Partnership incurred a $6.5 million prepayment penalty which was recognized as loss on debt extinguishment in 2001.
In January of 2001, the Partnership acquired Shore Terminals LLC ("Shore") for $107 million in cash and 1,975,090 KPP limited partnership units (valued at $56.5 million on the date of agreement and its announcement). Financing for the cash portion of the purchase price was initially supplied by the Partnership's revolving credit facility.
In January of 2002, KPP issued 1,250,000 limited partnership units in a public offering at $41.65 per unit, generating approximately $49.7 million in net proceeds. The proceeds were used to reduce borrowings under the Partnership's revolving credit agreement.
In February of 2002, the Partnership issued $250 million of 7.75% senior unsecured notes due February 15, 2012. The net proceeds from the public offering, $248.2 million, were used to repay the Partnership's revolving credit agreement and to partially fund the acquisition of all of the liquids terminaling subsidiaries of Statia Terminals Group NV ("Statia"). Under the note indenture, interest is payable semi-annually in arrears on February 15 and August 15 of each year. The notes are redeemable, as a whole or in part, at the option of the Partnership, at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes, or the sum of the present value of the remaining scheduled payments of principal and interest, discounted to the redemption date at the applicable U.S. Treasury rate, as defined in the indenture, plus 30 basis points. The note indenture contains certain financial and operational covenants, including certain limitations on investments, sales of assets and transactions with affiliates and, absent an event of default, such covenants do not restrict distributions to partners. At December 31, 2003, the Partnership was in compliance with all covenants.
On February 28, 2002, the Partnership acquired Statia for approximately $178 million in cash (net of acquired cash). The acquired Statia subsidiaries had approximately $107 million in outstanding debt, including $101 million of 11.75% notes due in November 2003. The cash portion of the purchase price was initially funded by the Partnership's revolving credit agreement and proceeds from the Partnership's February 2002 public debt offering. In April of 2002, the Partnership redeemed all of Statia's 11.75% notes at 102.938% of the principal amount, plus accrued interest. The redemption was funded by the Partnership's revolving credit facility. Under the provisions of the 11.75% notes, the Partnership incurred a $3.0 million prepayment penalty, of which $2.0 million was recognized as loss on debt extinguishment in 2002.
In May of 2002, KPP issued 1,565,000 limited partnership units in a public offering at a price of $39.60 per unit, generating approximately $59.1 million in net proceeds. A portion of the offering proceeds were used to fund the Partnership's September 2002 acquisition of the Australia and New Zealand terminals.
On September 18, 2002, the Partnership acquired eight bulk liquid storage terminals in Australia and New Zealand from Burns Philp & Co. Ltd. for approximately $47 million in cash.
On November 1, 2002, the Partnership acquired an approximately 2,000-mile anhydrous ammonia pipeline system from Koch Pipeline Company, L.P. for approximately $139 million in cash. This fertilizer pipeline system originates in southern Louisiana, proceeds north through Arkansas and Missouri, and then branches east into Illinois and Indiana and north and west into Iowa and Nebraska. The acquisition was initially financed with bank debt.
In November of 2002, KPP issued 2,095,000 limited partnership units in a public offering at $33.36 per unit, generating approximately $66.7 million in net proceeds. The offering proceeds were used to reduce bank borrowings for the fertilizer pipeline acquisition.
On December 24, 2002, the Partnership acquired a 400-mile petroleum products pipeline and four terminals in North Dakota and Minnesota from Tesoro Refining and Marketing Company for approximately $100 million in cash, subject to normal post-closing adjustments. The acquisition was initially funded with bank debt.
In March of 2003, KPP issued 3,122,500 limited partnership units in a public offering at $36.54 per unit, generating approximately $109.1 million in net proceeds. The proceeds were used to reduce bank borrowings.
In April of 2003, the Partnership entered into a new credit agreement with a group of banks that provides for a $400 million unsecured revolving credit facility through April of 2006. The credit facility, which provides for an increase in the commitment up to an aggregate of $450 million by mutual agreement between the Partnership and the banks, bears interest at variable rates and has a variable commitment fee on unused amounts. The credit facility contains certain financial and operating covenants, including limitations on investments, sales of assets and transactions with affiliates and, absent an event of default, does not restrict distributions to partners. At December 31, 2003, the Partnership was in compliance with all covenants. Initial borrowings on the credit agreement ($324.2 million) were used to repay all amounts outstanding under the Partnership's $275 million credit agreement and $175 million bridge loan agreement. At December 31, 2003, $54.2 million was outstanding under the new credit agreement.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior unsecured notes due June 1, 2013. The net proceeds from the public offering, $247.6 million, were used to reduce amounts due under the 2003 revolving credit agreement. Under the note indenture, interest is payable semi-annually in arrears on June 1 and December 1 of each year. The notes are redeemable, as a whole or in part, at the option of the Partnership, at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes, or the sum of the present value of the remaining scheduled payments of principal and interest, discounted to the redemption date at the applicable U.S. Treasury rate, as defined in the indenture, plus 30 basis points. The note indenture contains certain financial and operational covenants, including certain limitations on investments, sales of assets and transactions with affiliates and, absent an event of default, such covenants do not restrict distributions to partners. At December 31, 2003, the Partnership was in compliance with all covenants. In connection with the offering, on May 8, 2003, the Partnership entered into a treasury lock contract for the purpose of locking in the US Treasury interest rate component on $100 million of the debt. The treasury lock contract, which qualified as a cash flow hedging instrument under SFAS No. 133, was settled on May 19, 2003 with a cash payment by the Partnership of $1.8 million. The settlement cost of the contract has been recorded as a component of accumulated other comprehensive income and is being amortized, as interest expense, over the life of the debt.
The following is a schedule by period of the Partnership's debt repayment obligations and material contractual commitments as of December 31, 2003:
Less than After
Total 1 year 1 -3 years 4 -5 years 5 years
----------- ----------- ---------- ----------- ----------
(in thousands)
Debt:
Revolving credit facility......... $ 54,169 $ - $ 54,169 $ - $ -
7.75% senior unsecured notes...... 250,000 - - - 250,000
5.875% senior unsecured notes..... 250,000 - - - 250,000
Other bank debt................... 63,527 - 63,527 - -
----------- ----------- --------- ---------- ----------
Debt subtotal.................. 617,696 - 117,696 - 500,000
----------- ----------- --------- ---------- ----------
Contractual commitments:
Operating leases.................. 10,723 4,325 3,706 2,350 342
----------- ----------- --------- ---------- ----------
Contractual commitments
subtotal.................... 10,723 4,325 3,706 2,350 342
----------- ----------- --------- ---------- ----------
Total.......................... $ 628,419 $ 4,325 $ 121,402 $ 2,350 $ 500,342
=========== =========== ========= ========== ==========
|
See also "Item 1 - Environmental Matters" and "Item 3 - Legal Proceedings".
OFF-BALANCE SHEET TRANSACTIONS
The Partnership was not a party to any off-balance sheet transactions at December 31, 2003, or for any of the years ended December 31, 2003, 2002 and 2001.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the Partnership's financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant accounting policies are included in the Notes to the Consolidated Financial Statements.
Critical accounting policies are those that are most important to the portrayal to the Partnership's financial position and results of operations. These policies require management's most difficult, subjective or complex judgments, often employing the use of estimates about the effect of matters that are inherently uncertain. The Partnership's most critical accounting policies pertain to impairment of property and equipment and environmental costs.
The carrying value of property and equipment is periodically evaluated using management's estimates of undiscounted future cash flows, or, in some cases, third-party appraisals, as the basis of determining if impairment exists under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which was adopted effective January 1, 2002. To the extent that impairment is indicated to exist, an impairment loss is recognized under SFAS No. 144 based on fair value. The application of SFAS No. 144 did not have a material impact on the results of operations of the Partnership for the years ended December 31, 2003 or 2002. However, future evaluations of carrying value are dependent on many factors, several of which are out of the Partnership's control, including demand for refined petroleum products and terminaling services in the Partnership's market areas, and local, state and federal governmental regulations. To the extent that such factors or conditions change, it is possible that future impairments might occur, which could have a material effect on the results of operations of the Partnership.
Environmental expenditures that relate to current operations are expensed or capitalized, as appropriate. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or remedial efforts are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the completion of a feasibility study or the Partnership's commitment to a formal plan of action. The application of the Partnership's environmental accounting policies did not have a material impact on the results of operations of the Partnership for the years ended December 31, 2003, 2002 or 2001. Although the Partnership believes that its operations are in general compliance with applicable environmental regulations, risks of substantial costs and liabilities are inherent in pipeline and terminaling operations. Moreover, it is possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies thereunder, and legal claims for damages to property or persons resulting from the operations of the Partnership could result in substantial costs and liabilities, any of which could have a material effect on the results of operations of the Partnership.
RECENT ACCOUNTING PRONOUNCEMENT
In December 2003, the FASB issued Interpretation No. 46 (Revised December 2003), "Consolidation of Variable Interest Entities (FIN 46R), primarily to clarify the required accounting for interests in variable interest entities (VIEs). This standard replaces FASB Interpretation No. 46, Consolidation of Variable Interest Entities, that was issued in January 2003 to address certain situations in which a company should include in its financial statements the assets, liabilities and activities of another entity. For the Partnership, application of FIN 46R is required for interests in certain VIEs that are commonly referred to as special-purpose entities, or SPEs, as of December 31, 2003 and for interests in all other types of VIEs as of March 31, 2004. The application of FIN 46R has not and is not expected to have a material impact on the consolidated financial statements of the Partnership.
Item 7(a). Quantitative and Qualitative Disclosures About Market Risk
The principal market risks (i.e., the risk of loss arising from the adverse changes in market rates and prices) to which the Partnership is exposed are interest rates on the Partnership's debt and investment portfolios, fluctuations of petroleum product prices on inventories held for resale, and fluctuations in foreign currency.
The Partnership's investment portfolio consists of cash equivalents; accordingly, the carrying amounts approximate fair value. The Partnership's investments are not material to its financial position or performance. Assuming variable rate debt of $117.7 million at December 31, 2003, a one percent increase in interest rates would increase annual net interest expense by approximately $1.2 million. Information regarding the Partnership's interest rate hedging transactions are included in "Item 7 -Interest and Other Income" and "Item 7 - Liquidity and Capital Resources".
The product sales business periodically purchases refined petroleum products for resale as bunker fuel and sales to commercial interests. Petroleum inventories are generally held for short periods of time, not exceeding 90 days. As the Partnership does not engage in derivative transactions to hedge the value of the inventory, it is subject to market risk from changes in global oil markets.
A significant portion of the terminaling business is exposed to fluctuations in foreign currency exchange rates. (See "Item 7 - Terminaling Operations".)
Item 8. Financial Statements and Supplementary Data
The financial statements and supplementary data of the Partnership begin on page F-1 of this report. Such information is hereby incorporated by reference into this Item 8.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
Item 9(a). Controls and Procedures
Kaneb Pipe Line Company LLC's principal executive officer and principal financial officer, after evaluating as of December 31, 2003, the effectiveness of the Partnership's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934), have concluded that, as of such date, the Partnership's disclosure controls and procedures are adequate and effective to ensure that material information relating to the Partnership and its consolidated subsidiaries would be made known to them by others within those entities.
During the fourth quarter of 2003, there have been no changes in the Partnership's internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, those internal controls subsequent to the date of the evaluation. As a result, no corrective actions were required or undertaken.
PART III
Item 10. Directors and Executive Officers of the Registrant
The Partnership does not have directors or officers. All directors of the general partner are elected annually by KPL. All officers serve at the discretion of the directors. The information contained in Item 10 of KPP's Form 10-K, for the year ended December 31, 2003, is incorporated by reference in this report.
CODE OF ETHICS
The Partnership has adopted a Code of Ethics applicable to all employees, including the principal executive officer, principal financial officer and directors of the General Partner. A copy of the Code of Ethics will be provided without charge by written request to Investor Relations, 2435 North Central Expressway, Richardson, Texas 75080.
Item 11. Executive Compensation
The officers of the general partner manage and operate the Partnership's business. The Partnership does not directly employ any of the persons responsible for managing or operating the Partnership's operations, but instead reimburses the general partner for the services of such persons. The information contained in Item 11 of KPP's Form 10-K for the year ended December 31, 2003, is incorporated by reference in this report.
Item 12. Security Ownership of Certain Beneficial Owners and Management
KPP owns a 99% interest as the sole limited partner interest and KPL owns a 1% general partner interest in the Partnership. Information identifying security ownership by the Directors and Officers of KPL is contained in Item 12 of KPP's Form 10-K, for the year ended December 31, 2003, and is incorporated by reference in this report.
Item 13. Certain Relationships and Related Transactions
KPL is entitled to certain reimbursements under the Partnership Agreement. For additional information regarding the nature and amount of such reimbursements, see Note 7 to the Partnership's consolidated financial statements.
Item 14. Principal Accounting Fees and Services
The information contained in Item 14 of KPP's Form 10-K for the year ended December 31, 2003 is incorporated by reference in this report.
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) Financial Statements Beginning
Page
---------
Set forth below is a list of financial statements appearing in this
report.
Kaneb Pipe Line Operating Partnership, L.P. and Subsidiaries Financial Statements:
Independent Auditors' Report.............................................................. F - 1
Consolidated Statements of Income - Three Years Ended December 31, 2003................... F - 2
Consolidated Balance Sheets - December 31, 2003 and 2002.................................. F - 3
Consolidated Statements of Cash Flows - Three Years Ended December 31, 2003............... F - 4
Consolidated Statements of Partners' Capital - Three Years ended December 31, 2003........ F - 5
Notes to Consolidated Financial Statements................................................ F - 6
(a)(2) Financial Statement Schedules
Set forth below is the financial statement schedule appearing in this
report.
Schedule II - Kaneb Pipe Line Operating Partnership, L.P. Valuation and Qualifying Accounts -
Years Ended December 31, 2003, 2002 and 2001.............................................. F - 21
|
Schedules, other than the one listed above, have been omitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements or related notes thereto.
(a)(3) List of Exhibits
3.1 Amended and Restated Agreement of Limited Partnership, dated September 27, 1989, filed as Exhibit 3.1 to the Registrant's Form 10-K for the year ended December 31, 2001, which exhibit is hereby incorporated by reference.
3.2 Amendment to Amended and Restated Agreement of Limited Partnership dated October 27, 2003, filed herewith.
10.1 ST Agreement and Plan of Merger dated December 21, 1992 by and between Grace Energy Corporation, Support Terminal Services, Inc., Standard Transpipe Corp., and Kaneb Pipe Line Operating Partnership, NSTS, Inc. and NSTI, Inc. as amended by Amendment of STS Merger Agreement dated March 2, 1993, filed as Exhibit 10.1 of the exhibits to KPP's Current Report on Form 8-K ("Form 8-K"), dated March 16, 993, which exhibit is hereby incorporated by reference.
10.2 Agreement for Sale and Purchase of Assets between Wyco Pipe Line Company and the Partnership, dated February 19, 1995, filed as Exhibit 10.1 of the exhibits to KPP's March 1995 Form 8-K, which exhibit is hereby incorporated by reference.
10.3 Asset Purchase Agreements between and among Steuart Petroleum Company, SPC Terminals, Inc., Piney Point Industries, Inc., Steuart Investment Company, Support Terminals Operating Partnership, L.P. and the Partnership, as amended, dated August 27, 1995, filed as Exhibits 10.1, 10.2, 10.3, and 10.4 of the exhibits to KPP's Current Report on Form 8-K dated January 3, 1996, which exhibits are hereby incorporated by reference.
10.4 Formation and Purchase Agreement, between and among Support Terminal Operating Partnership, L.P., Northville Industries Corp. and AFFCO, Corp., dated October 30, 1998, filed as exhibit 10.9 to KPP's Form 10-K for the year ended December 31, 1998, which exhibit is hereby incorporated by reference.
10.5 Agreement, between and among, GATX Terminals Limited, ST Services, Ltd., ST Eastham, Ltd., GATX Terminals Corporation, Support Terminals Operating Partnership, L.P. and Kaneb Pipe Line Partners, L.P., dated January 26, 1999, filed as Exhibit 10.10 to KPP's Form 10-K for the year ended December 31, 1998, which exhibit is hereby incorporated by reference.
10.6 Credit Agreement, between and among, Kaneb Pipe Line Operating Partnership, L.P., ST Services, Ltd. and SunTrust Bank, Atlanta, dated January 27, 1999, filed as Exhibit 10.11 to KPP's Form 10-K for the year ended December 31, 1998, which exhibit is hereby incorporated by reference.
10.7 Revolving Credit Agreement, dated as of April 24, 2003 among Kaneb Pipe Line Operating Partnership, L.P., Kaneb Pipe Line Partners, L.P., The Lenders From Time To Time Party Hereto, and SunTrust Bank, as Administrative Agent, filed as Exhibit 10.11 to the Registrant's Form 10-Q for the period ended March 31, 2003, which exhibit is hereby incorporated by reference.
10.8 Securities Purchase Agreement Among Shore Terminals LLC, Kaneb Pipe Line Partners, L.P. and the Sellers Named Therein, dated as of September 22, 2000, Amendment No. 1 To Securities Purchase Agreement, dated as of November 28, 2000 and Registration Rights Agreement, dated as of January 3, 2001, filed as Exhibits 10.1, 10.2 and 10.3 of the exhibits to KPP's Current Report on Form 8-K dated January 3, 2001, which exhibits are hereby incorporated by reference.
10.9 Stock Purchase Agreement, dated as of November 12, 2001, by and between Kaneb Pipe Line Operating Partnership, L.P., and Statia Terminals Group NV, a public company with limited liability organized under the laws of the Netherlands Antilles, filed as Exhibit 10.1 to the exhibits to KPP's Current Report on Form 8-K, dated January 11, 2002, and incorporated herein by reference.
10.10 Voting and Option Agreement dated as of November 12, 2001, by
and between Kaneb Pipe Line Operating Partnership, L.P., and
Statia Terminals Holdings N.V., a Netherlands Antilles company
and a shareholder of Statia Terminals Group NV, a Netherlands
Antilles company filed as Exhibit 10.1 to the exhibits to
Registrant's Current Report on Form 8-K, dated January 11,
2002, and incorporated herein by reference.
10.11* Amended and Restated Kaneb LLC 2002 Long Term Incentive Plan,
dated June 30, 2003, filed as Exhibit 10.1 to the exhibits to
Registrant's Form 10-Q for the period ended June 30, 2003, and
incorporated herein by reference.
21 List of Subsidiaries, filed herewith.
23 Consent of KPMG LLP, filed herewith.
31.1 Certification of Chief Executive Officer, Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002, dated as of March 12,
2004.
31.2 Certification of Chief Financial Officer, Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002, dated as of March 12,
2004.
32.1 Certification of Chief Executive Officer, Pursuant to Section
906(a) of the Sarbanes-Oxley Act of 2002, dated as of March
12, 2004.
32.2 Certification of Chief Financial Officer, Pursuant to Section
906(a) of the Sarbanes-Oxley Act of 2002, dated as of March
12, 2004.
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* Denotes management contract.
(b) Reports on Form 8-K
Current Report on Form 8-K filed with the SEC on October 30, 2003.
INDEPENDENT AUDITORS' REPORT
To the Partners of
Kaneb Pipe Line Operating Partnership, L.P.
We have audited the consolidated financial statements of Kaneb Pipe Line Operating Partnership, L.P. and its subsidiaries (the "Partnership") as listed in the index appearing under Item 15(a)(1). In connection with our audits of the consolidated financial statements, we have also audited the financial statement schedule as listed in the index appearing under Item 15(a)(2). These consolidated financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership and its subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects the information set forth therein.
As described in Note 2, the Partnership adopted Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" in 2003.
KPMG LLP
Dallas, Texas
February 20, 2004
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
-----------------------------------------------------------
2003 2002 2001
----------------- ----------------- -----------------
Revenues:
Services........................................... $ 354,591,000 $ 288,669,000 $ 207,796,000
Products........................................... 215,823,000 97,961,000 -
------------- ------------- --------------
Total revenues.................................. 570,414,000 386,630,000 207,796,000
------------- ------------- --------------
Costs and expenses:
Cost of products sold.............................. 195,100,000 90,898,000 -
Operating costs.................................... 168,537,000 131,326,000 90,632,000
Depreciation and amortization...................... 53,155,000 39,425,000 23,184,000
Gain on sale of assets............................. - (609,000) -
General and administrative......................... 25,121,000 19,869,000 11,889,000
------------- ------------- --------------
Total costs and expenses........................ 441,913,000 280,909,000 125,705,000
------------- ------------- --------------
Operating income...................................... 128,501,000 105,721,000 82,091,000
Interest and other income............................. 261,000 3,570,000 4,277,000
Interest expense...................................... (38,757,000) (28,110,000) (14,783,000)
Loss on debt extinguishment........................... - (3,282,000) (6,540,000)
------------- ------------- --------------
Income before income taxes and cumulative effect of
change in accounting principle..................... 90,005,000 77,899,000 65,045,000
Income tax expense.................................... (5,223,000) (4,083,000) (256,000)
------------- -------------- --------------
Income before cumulative effect of change in
accounting principle............................... 84,782,000 73,816,000 64,789,000
Cumulative effect of change in accounting principle -
adoption of new accounting standard for asset
retirement obligations............................. (1,593,000) - -
------------- ------------- --------------
Net income ........................................... $ 83,189,000 $ 73,816,000 $ 64,789,000
============= ============= ==============
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See notes to consolidated financial statements.
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------------------------
2003 2002
---------------- ----------------
ASSETS
Current assets:
Cash and cash equivalents............................................... $ 38,626,000 $ 22,028,000
Accounts receivable (net of allowance for doubtful accounts
of $1,693,000 in 2003 and $1,765,000 in 2002)........................ 51,864,000 48,926,000
Inventories............................................................. 9,324,000 4,922,000
Prepaid expenses and other.............................................. 9,205,000 8,498,000
---------------- ----------------
Total current assets................................................. 109,019,000 84,374,000
---------------- ----------------
Property and equipment..................................................... 1,360,319,000 1,288,762,000
Less accumulated depreciation.............................................. 247,349,000 196,570,000
---------------- ----------------
Net property and equipment........................................... 1,112,970,000 1,092,192,000
---------------- ----------------
Investment in affiliates................................................... 25,456,000 25,604,000
Excess of cost over fair value of net assets of acquired business and
other assets............................................................ 17,237,000 13,240,000
---------------- ----------------
$ 1,264,682,000 $ 1,215,410,000
================ ================
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable........................................................ $ 27,941,000 $ 22,064,000
Accrued expenses........................................................ 31,642,000 29,339,000
Accrued distributions payable........................................... 26,344,000 21,639,000
Accrued interest payable................................................ 9,297,000 7,896,000
Accrued taxes, other than income taxes.................................. 4,031,000 3,598,000
Deferred terminaling fees............................................... 7,061,000 6,246,000
Payable to general partner.............................................. 3,630,000 5,403,000
---------------- ----------------
Total current liabilities............................................ 109,946,000 96,185,000
---------------- ----------------
Long-term debt............................................................. 617,696,000 694,330,000
Other liabilities and deferred taxes....................................... 43,451,000 31,581,000
Commitments and contingencies
Partners' capital:
Limited partners........................................................ 480,323,000 390,904,000
General partner......................................................... 894,000 1,016,000
Accumulated other comprehensive income.................................. 12,372,000 1,394,000
---------------- ----------------
Total partners' capital.............................................. 493,589,000 393,314,000
---------------- ----------------
$ 1,264,682,000 $ 1,215,410,000
================ ================
|
See notes to consolidated financial statements.
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------------------------------
2003 2002 2001
------------- ------------- --------------
Operating activities:
Net income ........................................ $ 83,189,000 $ 73,816,000 $ 64,789,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization................... 53,155,000 39,425,000 23,184,000
Equity in earnings of affiliates, net of
distributions................................. 148,000 (3,164,000) (5,000)
Gain on sale of assets.......................... - (609,000) -
Deferred income taxes........................... 1,683,000 3,105,000 256,000
Cumulative effect of change in accounting
principle..................................... 1,593,000 - -
Other liabilities............................... 1,190,000 (1,341,000) (5,422,000)
Changes in working capital components:
Accounts receivable........................... (2,938,000) (12,379,000) (824,000)
Inventories, prepaid expenses and other....... (5,109,000) (6,601,000) 1,601,000
Accounts payable and accrued expenses......... 10,829,000 (1,192,000) 9,298,000
Payable to general partner.................... (1,773,000) 702,000 2,812,000
-------------- ------------- --------------
Net cash provided by operating activities.. 141,967,000 91,762,000 95,689,000
-------------- ------------- --------------
Investing activities:
Acquisitions, net of cash acquired................. (1,644,000) (468,477,000) (111,562,000)
Capital expenditures............................... (44,741,000) (31,101,000) (17,246,000)
Proceeds from sale of assets....................... - 1,107,000 2,807,000
Other, net......................................... (1,109,000) 306,000 (111,000)
-------------- ------------- --------------
Net cash used in investing activities...... (47,494,000) (498,165,000) (126,112,000)
-------------- -------------- --------------
Financing activities:
Issuance of debt................................... 291,377,000 746,087,000 260,500,000
Payments of debt................................... (382,831,000) (426,647,000) (164,776,000)
Distributions...................................... (98,243,000) (74,439,000) (62,156,000)
Net proceeds from issuance of units by KPP......... 109,056,000 175,527,000 -
-------------- ------------- --------------
Net cash provided by (used in) financing
activities............................. (80,641,000) 420,528,000 33,568,000
-------------- ------------- --------------
Effect of exchange rate changes on cash............... 2,766,000 - -
-------------- ------------- --------------
Increase in cash and cash equivalents................. 16,598,000 14,125,000 3,145,000
Cash and cash equivalents at beginning of period...... 22,028,000 7,903,000 4,758,000
-------------- ------------- --------------
Cash and cash equivalents at end of period............ $ 38,626,000 $ 22,028,000 $ 7,903,000
============== ============= ==============
Supplemental cash flow information:
Cash paid for interest............................. $ 34,818,000 $ 25,942,000 $ 14,028,000
============== ============= ==============
Non-cash investing and financing activities -
Issuance of units by KPP in connection with
acquisition of terminals........................ $ - $ - $ 56,488,000
============== ============= ==============
|
See notes to consolidated financial statements.
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
Accumulated
Other
Limited General Comprehensive Comprehensive
Partner Partner Income (Loss) Total Income
-------------- ----------- -------------- ------------- ----------------
Partners' capital at January 31, 2001.... $ 162,288,000 $ 984,000 $ (1,537,000) $ 161,735,000
2001 income allocation................. 64,141,000 648,000 - 64,789,000 $ 64,789,000
Distributions declared................. (61,554,000) (602,000) - (62,156,000) -
Issuance of units by KPP, net of
offering costs....................... 56,488,000 - - 56,488,000 -
Foreign currency translation
adjustment........................... - - (329,000) (329,000) (329,000)
-------------- ----------- ----------- -------------- ---------------
Comprehensive income for the year...... $ 64,460,000
===============
Partners' capital at December 31, 2001... 221,363,000 1,030,000 (1,866,000) 220,527,000
2002 income allocation................. 73,078,000 738,000 - 73,816,000 $ 73,816,000
Distributions declared................. (79,064,000) (752,000) - (79,816,000) -
Issuance of units by KPP, net of
offering costs....................... 175,527,000 - - 175,527,000 -
Foreign currency translation
adjustment........................... - - 3,260,000 3,260,000 3,260,000
-------------- ----------- ----------- -------------- ---------------
Comprehensive income for the year...... $ 77,076,000
===============
Partners' capital at December 31, 2002... 390,904,000 1,016,000 1,394,000 393,314,000
2003 income allocation................. 82,357,000 832,000 - 83,189,000 $ 83,189,000
Distributions declared................. (101,994,000) (954,000) - (102,948,000) -
Issuance of units by KPP, net of
offering costs....................... 109,056,000 - - 109,056,000 -
Foreign currency translation
adjustment........................... - - 12,662,000 12,662,000 12,662,000
Interest rate hedging transaction...... - - (1,684,000) (1,684,000) (1,684,000)
-------------- ------------ ----------- -------------- ---------------
Comprehensive income for the year...... $ 94,167,000
===============
Partners' capital at December 31, 2003... $ 480,323,000 $ 894,000 $12,372,000 $ 493,589,000
============== =========== =========== ==============
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See notes to consolidated financial statements.
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. PARTNERSHIP ORGANIZATION
Kaneb Pipe Line Operating Partnership, L.P. (the "Partnership"), a limited partnership, owns and operates a refined petroleum products and fertilizer pipeline business and a petroleum products and specialty liquids storage and terminaling business. Kaneb Pipe Line Partners, L.P. ("KPP"), a master limited partnership, holds a 99% interest as limited partner in the Partnership. Kaneb Pipe Line Company LLC ("KPL"), a wholly owned subsidiary of Kaneb Services LLC ("KSL"), manages and controls the operations of KPP through its general partner interest and 18% (at December 31, 2003) limited partnership interest. KPL owns a 1% interest as general partner of the Partnership and a 1% interest as general partner of KPP.
In March of 2003, KPP issued 3,122,500 limited partnership units in a public offering at $36.54 per unit, generating approximately $109.1 million in net proceeds. The proceeds were used to reduce bank borrowings (See Note 5).
In November of 2002, KPP issued 2,095,000 limited partnership units in a public offering at $33.36 per unit, generating approximately $66.7 million in net proceeds. The offering proceeds were used to reduce bank borrowings for the November 2002 fertilizer pipeline acquisition (see Notes 3 and 5).
In May of 2002, KPP issued 1,565,000 limited partnership units in a public offering at a price of $39.60 per unit, generating approximately $59.1 million in net proceeds. A portion of the offering proceeds were used to fund the Partnership's September 2002 acquisition of the Australia and New Zealand terminals (see Note 3).
In January of 2002, KPP issued 1,250,000 limited partnership units in a public offering at $41.65 per unit, generating approximately $49.7 million in net proceeds. The proceeds were used to reduce borrowings under the Partnership's revolving credit agreement (see Note 5).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following significant accounting policies are followed by the Partnership in the preparation of the consolidated financial statements.
Cash and Cash Equivalents
The Partnership's policy is to invest cash in highly liquid investments
with original maturities of three months or less. Accordingly, uninvested cash
balances are kept at minimum levels. Such investments are valued at cost, which
approximates market, and are classified as cash equivalents.
Inventories
Inventories consist primarily of petroleum products purchased for resale in the product sales operations and are valued at the lower of cost or market. Cost is determined by using the weighted-average cost method.
Property and Equipment
Property and equipment are carried at historical cost. Additions of new equipment and major renewals and replacements of existing equipment are capitalized. Repairs and minor replacements that do not materially increase values or extend useful lives are expensed. Depreciation of property and equipment is provided on a straight-line basis at rates based upon expected useful lives of various classes of assets, as disclosed in Note 4. The rates used for pipeline and storage facilities are the same as those which have been promulgated by the Federal Energy Regulatory Commission. Upon disposal of assets depreciated on an individual basis, the gains and losses are included in current operating income. Upon disposal of assets depreciated on a group basis, unless unusual in nature or amount, residual cost, less salvage, is charged against accumulated depreciation.
Effective January 1, 2002, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The adoption of SFAS No. 144 did not have a material impact on the consolidated financial statements of the Partnership. Under SFAS No. 144, the carrying value of property and equipment is periodically evaluated using undiscounted future cash flows as the basis for determining if impairment exists. To the extent impairment is indicated to exist, an impairment loss will be recognized based on fair value.
Revenue and Income Recognition
The pipeline business provides pipeline transportation of refined petroleum products, liquified petroleum gases, and anhydrous ammonia fertilizer. Pipeline revenues are recognized as services are provided. The Partnership's terminaling services business provides terminaling and other ancillary services. Storage fees are generally billed one month in advance and are reported as deferred income. Terminaling revenues are recognized in the month services are provided. Revenues for the product sales business are recognized when product is sold and title and risk pass to the customer.
Foreign Currency Translation
The Partnership translates the balance sheet of its foreign subsidiaries using year-end exchange rates and translates income statement amounts using the average exchange rates in effect during the year. The gains and losses resulting from the change in exchange rates from year to year have been reported separately as a component of accumulated other comprehensive income (loss) in Partners' Capital. Gains and losses resulting from foreign currency transactions are included in the consolidated statements of income. The local currency is considered to be the functional currency, except in the Netherland Antilles and Canada, where the U.S. dollar is the functional currency.
Excess of Cost Over Fair Value of Net Assets of Acquired Business
Effective January 1, 2002, the Partnership adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which eliminates the amortization of goodwill (excess of cost over fair value of net assets of acquired business) and other intangible assets with indefinite lives. Under SFAS No. 142, intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their useful lives. At December 31, 2003, the Partnership had no intangible assets subject to amortization under SFAS No. 142. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the assets might be impaired. SFAS No. 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If an impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. Based on valuations and analysis performed by the Partnership at initial adoption date and at December 31, 2003, the Partnership determined that the implied fair value of its goodwill exceeded carrying value and, therefore, no impairment charge was necessary. Goodwill amortization included in the results of operations of the Partnership for the year ended December 31, 2001 was not material.
Environmental Matters
Environmental expenditures that relate to current operations are expensed or capitalized, as appropriate. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or remedial efforts are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the completion of a feasibility study or the Partnership's commitment to a formal plan of action.
Asset Retirement Obligations
Effective January 1, 2003, the Partnership adopted SFAS No. 143 "Accounting for Asset Retirement Obligations", which establishes requirements for the removal-type costs associated with asset retirements. At the initial adoption date of SFAS No. 143, the Partnership recorded an asset retirement obligation of approximately $5.5 million and recognized a cumulative effect of change in accounting principle of $1.6 million for its legal obligations to dismantle, dispose of, and restore certain leased pipeline and terminaling facilities, including petroleum and chemical storage tanks, terminaling facilities and barges. The Partnership did not record a retirement obligation for certain of its pipeline and terminaling assets because sufficient information is presently not available to estimate a range of potential settlement dates for the obligation. In these cases, the obligation will be initially recognized in the period in which sufficient information exists to estimate the obligation. At December 31, 2003, the Partnership had no assets which were legally restricted for purposes of settling asset retirement obligations. The effect of SFAS No. 143, assuming adoption on January 1, 2001, was not material to the results of operations of the Partnership for the years ended December 31, 2003, 2002 and 2001. In 2003, accretion expense of $0.4 million was included in operating costs.
Comprehensive Income
The Partnership follows the provisions of SFAS No. 130, "Reporting Comprehensive Income", for the reporting and display of comprehensive income and its components in a full set of general purpose financial statements. SFAS No. 130 requires additional disclosure and does not affect the Partnership's financial position or results of operations.
Income Taxes
Income (loss) before income tax expense and extraordinary items, is made up of the following components:
Year Ended December 31,
---------------------------------------------------------
2003 2002 2001
------------- ------------- --------------
Partnership operations........................ $ 71,104,000 $ 71,614,000 $ 62,650,000
Corporate operations:
Domestic................................. (3,055,000) 2,046,000 (1,594,000)
Foreign.................................. 21,956,000 4,239,000 3,989,000
------------- ------------- --------------
$ 90,005,000 $ 77,899,000 $ 65,045,000
============= ============= ==============
|
Partnership operations are not subject to federal or state income taxes. However, certain operations of terminaling operations are conducted through wholly-owned corporate subsidiaries which are taxable entities. The provision for income taxes for the periods ended December 31, 2003, 2002 and 2001 primarily consists of U.S. and foreign income taxes of $5.2 million, $4.1 million and $0.3 million, respectively. The net deferred tax liability of $20.6 million and $17.8 million at December 31, 2003 and 2002, respectively, consists of deferred tax liabilities of $48.8 million and $41.7 million, respectively, and deferred tax assets of $28.2 million and $23.9 million, respectively. The deferred tax liabilities consist primarily of tax depreciation in excess of book depreciation and the deferred tax assets consist primarily of net operating loss carryforwards. The U.S. corporate operations have net operating loss carryforwards for tax purposes totaling approximately $43.1 million which are subject to various limitations on use and expire in years 2008 through 2023.
On June 1, 1989, the governments of the Netherlands Antilles and St. Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January 1, 1989, which expired on December 31, 2000. This agreement requires a subsidiary of the Partnership, which was acquired with Statia on February 28, 2002 (see Note 3), to pay a 2% rate on taxable income, as defined therein, or a minimum payment of 500,000 Netherlands Antilles guilders ($0.3 million) per year. The agreement further provides that any amounts paid in order to meet the minimum annual payment will be available to offset future tax liabilities under the agreement to the extent that the minimum annual payment is greater than 2% of taxable income. The subsidiary is currently engaged in discussions with representatives appointed by the Island Territory of St. Eustatius regarding the renewal or modification of the agreement, but the ultimate outcome cannot be predicted at this time. The subsidiary has accrued amounts assuming a new agreement becomes effective, and continues to make payments, as required, under the previous agreement.
Since the income or loss of the operations which are conducted through limited partnerships will be included in the tax returns of the individual partners of the Partnership, no provision for income taxes has been recorded in the accompanying financial statements on these earnings. The tax returns of the Partnership are subject to examination by federal and state taxing authorities. If any such examination results in adjustments to distributive shares of taxable income or loss, the tax liability of the partners would be adjusted accordingly.
The tax attributes of the Partnership's net assets flow directly to each individual partner. Individual partners will have different investment bases depending upon the timing and prices of acquisition of Partnership units. Further, each partner's tax accounting, which is partially dependent upon their individual tax position, may differ from the accounting followed in the financial statements. Accordingly, there could be significant differences between each individual partner's tax basis and their proportionate share of the net assets reported in the financial statements. SFAS No. 109, "Accounting for Income Taxes," requires disclosure of the aggregate difference in the basis of its net assets for financial and tax reporting purposes. Management of the Partnership does not believe that, in the Partnership's circumstances, the aggregate difference would be meaningful information.
Cash Distributions
The Partnership makes regular cash distributions in accordance with its Partnership agreement within 45 days after the end of each quarter to limited partner and general partner interests. Aggregate distributions of $98.2 million, $74.4 million and $62.2 million, were paid to limited partner interests and general partner interests in 2003, 2002 and 2001, respectively.
Derivative Instruments
Effective January 1, 2001, the Partnership adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", which establishes the accounting and reporting standards for such activities. Under SFAS No. 133, companies must recognize all derivative instruments on their balance sheet at fair value. Changes in the value of derivative instruments, which are considered hedges, are offset against the change in fair value of the hedged item through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings, depending on the nature of the hedge. SFAS No. 133 requires that unrealized gains and losses on derivatives not qualifying for hedge accounting be recognized currently in earnings. On January 1, 2001, the Partnership was not a party to any derivative contracts and, accordingly, initial adoption of SFAS No. 133 at that date did not have any effect on the Partnership's result of operations or financial position.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior unsecured notes due June 1, 2013 (see Note 5.) In connection with the offering, on May 8, 2003, the Partnership entered into a treasury lock contract for the purpose of locking in the US Treasury interest rate component on $100 million of the debt. The treasury lock contract, which qualified as a cash flow hedging instrument under SFAS No. 133, was settled on May 19, 2003 with a cash payment by the Partnership of $1.8 million. The settlement cost of the contract has been recorded as a component of accumulated other comprehensive income and is being amortized, as interest expense, over the life of the debt. For the year ended December 31, 2003, $0.1 million of amortization is included in interest expense.
In September of 2002, the Partnership entered into a treasury lock contract, maturing on November 4, 2002, for the purpose of locking in the US Treasury interest rate component on $150 million of anticipated thirty-year public debt offerings. The treasury lock contract originally qualified as a cash flow hedging instrument under SFAS No. 133. In October of 2002, the Partnership, due to various market factors, elected to defer issuance of the public debt securities, effectively eliminating the cash flow hedging designation for the treasury lock contract. On October 29, 2002, the contract was settled resulting in a net realized gain of $3.0 million, which was recognized as a component of interest and other income.
In March of 2001, the Partnership entered into two contracts for the purpose of locking in interest rates on $100 million of anticipated ten-year public debt offerings. As the interest rate locks were not designated as hedging instruments pursuant to the requirements of SFAS No. 133, increases or decreases in the fair value of the contracts were included as a component of interest and other income. On May 22, 2001, the contracts were settled resulting in a gain of $3.8 million, which is included in interest and other income in 2001.
Estimates
The preparation of the Partnership's financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Recent Accounting Pronouncements
Effective January 1, 2003, the Partnership adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities", which requires that all restructurings initiated after December 31, 2002 be recorded when they are incurred and can be measured at fair value. The initial adoption of SFAS No. 146 had no effect on the consolidated financial statements of the Partnership.
The Partnership has adopted the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements of Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57, and 107, and a rescission of FASB Interpretation No. 34." This interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the interpretation are applicable to guarantees issued or modified after December 31, 2002. The initial application of this interpretation had no effect on the consolidated financial statements of the Partnership.
In December 2003, the FASB issued Interpretation No. 46 (Revised December 2003), "Consolidation of Variable Interest Entities (FIN 46R), primarily to clarify the required accounting for interests in variable interest entities (VIEs). This standard replaces FASB Interpretation No. 46, Consolidation of Variable Interest Entities, that was issued in January 2003 to address certain situations in which a company should include in its financial statements the assets, liabilities and activities of another entity. For the Partnership, application of FIN 46R is required for interests in certain VIEs that are commonly referred to as special-purpose entities, or SPEs, as of December 31, 2003 and for interests in all other types of VIEs as of March 31, 2004. The application of FIN 46R has not and is not expected to have a material impact on the consolidated financial statements of the Partnership.
The Partnership has adopted the provisions of SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities", which amends and clarifies financial accounting and reporting for derivative instruments and hedging activities. The adoption of SFAS No. 149, which was effective for derivative contracts and hedging relationships entered into or modified after June 30, 2003, had no impact on the Partnership's consolidated financial statements.
On July 1, 2003, the Partnership adopted SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity", which requires certain financial instruments, which were previously accounted for as equity, to be classified as liabilities. The adoption of SFAS No. 150 had no effect on the consolidated financial statements of the Partnership.
3. ACQUISITIONS
On December 24, 2002, the Partnership acquired a 400-mile petroleum products pipeline and four terminals in North Dakota and Minnesota from Tesoro Refining and Marketing Company for approximately $100 million in cash, subject to normal post-closing adjustments. The acquisition was initially funded with bank debt (see Note 5). Based on the evaluations performed, no amounts were assigned to goodwill or to other intangible assets in the purchase price allocation.
On November 1, 2002, the Partnership acquired an approximately 2,000-mile anhydrous ammonia pipeline system from Koch Pipeline Company, L.P. for approximately $139 million in cash. This fertilizer pipeline system originates in southern Louisiana, proceeds north through Arkansas and Missouri, and then branches east into Illinois and Indiana and north and west into Iowa and Nebraska. The acquisition was initially funded with bank debt (see Note 5). The results of operations and cash flows of the acquired business are included in the consolidated financial statements of the Partnership since the date of acquisition. Based on the evaluations performed, no amounts were assigned to goodwill or to other intangible assets in the purchase price allocation.
On September 18, 2002, the Partnership acquired eight bulk liquid storage terminals in Australia and New Zealand from Burns Philp & Co. Ltd. for approximately $47 million in cash. The results of operations and cash flows of the acquired business are included in the consolidated financial statements of the Partnership since the date of acquisition. Based on the evaluations performed, no amounts were assigned to goodwill or to other intangible assets in the purchase price allocation.
On February 28, 2002, the Partnership acquired all of the liquids terminaling subsidiaries of Statia Terminals Group NV ("Statia") for approximately $178 million in cash (net of acquired cash). The acquired Statia subsidiaries had approximately $107 million in outstanding debt, including $101 million of 11.75% notes due in November 2003. The cash portion of the purchase price was initially funded by the Partnership's revolving credit agreement and proceeds from the Partnership's February 2002 public debt offering (see Note 5). In April of 2002, the Partnership redeemed all of Statia's 11.75% notes at 102.938% of the principal amount, plus accrued interest. The redemption was funded by the Partnership's revolving credit facility (see Note 5). Under the provisions of the 11.75% notes, the Partnership incurred a $3.0 million prepayment penalty, of which $2.0 million was recognized as loss on debt extinguishment in 2002.
The results of operations and cash flows of Statia are included in the consolidated financial statements of the Partnership since the date of acquisition. Based on the valuations performed, no amounts were assigned to goodwill or to other tangible assets. A summary of the allocation of the Statia purchase price, net of cash acquired, is as follows:
Current assets......................................... $ 10,898,000
Property and equipment................................. 320,008,000
Other assets........................................... 53,000
Current liabilities.................................... (39,052,000)
Long-term debt......................................... (107,746,000)
Other liabilities...................................... (5,957,000)
-------------
Purchase price..................................... $ 178,204,000
=============
|
Assuming the Statia acquisition occurred on January 1, 2001, unaudited pro forma revenues and net income would have been $411.3 million and $72.8 million, respectively, for the year ended December 31, 2002, and $410.0 million and $63.9 million, respectively, for the year ended December 31, 2001.
On January 3, 2001, the Partnership acquired Shore Terminals LLC ("Shore") for $107 million in cash and 1,975,090 KPP limited partnership units (valued at $56.5 million on the date of agreement and its announcement). Financing for the cash portion of the purchase price was initially supplied by the Partnership's revolving credit facility (see Note 5). The acquisition was accounted for using the purchase method of accounting.
4. PROPERTY AND EQUIPMENT
The cost of property and equipment is summarized as follows:
Estimated
Useful December 31,
Life --------------------------------------
(Years) 2003 2002
-------------- ------------------ -----------------
Land...................................... - $ 75,912,000 $ 72,152,000
Buildings................................. 25 - 35 36,229,000 27,559,000
Pipeline and terminaling equipment........ 15 - 40 1,115,458,000 1,067,794,000
Marine equipment.......................... 15 - 30 87,204,000 84,641,000
Furniture and fixtures.................... 5 - 15 11,388,000 7,892,000
Transportation equipment.................. 3 - 6 7,360,000 5,414,000
Construction work-in-progress............. - 26,768,000 23,310,000
------------------ -----------------
Total property and equipment.............. 1,360,319,000 1,288,762,000
Less accumulated depreciation............. 247,349,000 196,570,000
------------------ -----------------
Net property and equipment................ $ 1,112,970,000 $ 1,092,192,000
================== =================
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5. LONG-TERM DEBT
Long-term debt is summarized as follows:
December 31,
-------------------------------------
2003 2002
--------------- --------------
$400 million revolving credit facility, due in April of 2006........ $ 54,169,000 $ -
$250 million 5.875% senior unsecured notes, due in June of 2013..... 250,000,000 -
$250 million 7.75% senior unsecured notes, due in February of 2012.. 250,000,000 250,000,000
$275 million revolving credit facility, repaid in April of 2003..... - 243,000,000
Bank bridge facility, repaid in April of 2003....................... - 175,000,000
Term loans, due in April of 2006.................................... 29,243,000 26,330,000
Australian bank facility, due in April of 2006...................... 34,284,000 -
--------------- --------------
Total long-term debt................................................ $ 617,696,000 $ 694,330,000
=============== ==============
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In April of 2003, the Partnership entered into a new credit agreement with a group of banks that provides for a $400 million unsecured revolving credit facility through April of 2006. The credit facility, which provides for an increase in the commitment up to an aggregate of $450 million by mutual agreement between the Partnership and the banks, bears interest at variable rates and has a variable commitment fee on unused amounts. The credit facility contains certain financial and operating covenants, including limitations on investments, sales of assets and transactions with affiliates and, absent an event of default, does not restrict distributions to partners. At December 31, 2003, the Partnership was in compliance with all covenants. Initial borrowings on the credit agreement ($324.2 million) were used to repay all amounts outstanding under the Partnership's $275 million credit agreement and $175 million bridge loan agreement. At December 31, 2003, $54.2 million was outstanding under the new credit agreement.
On May 19, 2003, the Partnership issued $250 million of 5.875% senior unsecured notes due June 1, 2013. The net proceeds from the public offering, $247.6 million, were used to reduce amounts due under the revolving credit agreement. Under the note indenture, interest is payable semi-annually in arrears on June 1 and December 1 of each year. The notes are redeemable, as a whole or in part, at the option of the Partnership, at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes, or the sum of the present value of the remaining scheduled payments of principal and interest, discounted to the redemption date at the applicable U.S. Treasury rate, as defined in the indenture, plus 30 basis points. The note indenture contains certain financial and operational covenants, including certain limitations on investments, sales of assets and transactions with affiliates and, absent an event of default, such covenants do not restrict distributions to partners. At December 31, 2003, the Partnership was in compliance with all covenants.
In February of 2002, the Partnership issued $250 million of 7.75% senior unsecured notes due February 15, 2012. The net proceeds from the public offering, $248.2 million, were used to repay the Partnership's revolving credit agreement and to partially fund the Statia acquisition (see Note 3). Under the note indenture, interest is payable semi-annually in arrears on February 15 and August 15 of each year. The notes are redeemable, as a whole or in part, at the option of the Partnership, at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes, or the sum of the present value of the remaining scheduled payments of principal and interest, discounted to the redemption date at the applicable U.S. Treasury rate, as defined in the indenture, plus 30 basis points. The note indenture contains certain financial and operational covenants, including certain limitations on investments, sales of assets and transactions with affiliates and, absent an event of default, such covenants do not restrict distributions to partners. At December 31, 2003, the Partnership was in compliance with all covenants.
In January of 2001, the Partnership used proceeds from its revolving credit agreement to repay in full its $128 million of mortgage notes. Under the provisions of the mortgage notes, the Partnership incurred a $6.5 million prepayment penalty, which was recognized as loss on debt extinguishment in 2001.
6. COMMITMENTS AND CONTINGENCIES
The following is a schedule by years of future minimum lease payments under operating leases as of December 31, 2003:
Year ending December 31:
2004...................................... $ 4,325,000
2005...................................... 2,028,000
2006...................................... 1,678,000
2007...................................... 1,416,000
2008...................................... 934,000
Thereafter................................ 342,000
--------------
Total minimum lease payments.................... $ 10,723,000
==============
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Total rent expense under operating leases amounted to $14.5 million, $9.4 million and $4.2 million for the years ended December 31, 2003, 2002 and 2001, respectively.
The operations of the Partnership are subject to federal, state and local laws and regulations in the United States and the various foreign locations relating to protection of the environment. Although the Partnership believes its operations are in general compliance with applicable environmental regulations, risks of additional costs and liabilities are inherent in pipeline and terminal operations, and there can be no assurance that significant costs and liabilities will not be incurred by the Partnership. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations of the Partnership, could result in substantial costs and liabilities to the Partnership. The Partnership has recorded an undiscounted reserve for environmental claims in the amount of $28.6 million at December 31, 2003, including $25.5 million related to acquisitions of pipelines and terminals. During 2003, 2002 and 2001, respectively, the Partnership incurred $2.1 million, $2.4 million and $5.2 million of costs related to such acquisition reserves and reduced the liability accordingly.
KPL has indemnified the Partnership against liabilities for damage to the environment resulting from operations of the pipeline prior to October 3, 1989 (the date of formation of the Partnership). The indemnification does not extend to any liabilities that arise after such date to the extent that the liabilities result from changes in environmental laws and regulations.
Certain subsidiaries of the Partnership were sued in a Texas state court in 1997 by Grace Energy Corporation ("Grace"), the entity from which the Partnership acquired ST Services in 1993. The lawsuit involves environmental response and remediation costs allegedly resulting from jet fuel leaks in the early 1970's from a pipeline. The pipeline, which connected a former Grace terminal with Otis Air Force Base in Massachusetts (the "Otis pipeline" or the "pipeline"), ceased operations in 1973 and was abandoned before 1978, when the connecting terminal was sold to an unrelated entity. Grace alleged that subsidiaries of the Partnership acquired the abandoned pipeline, as part of the acquisition of ST Services in 1993 and assumed responsibility for environmental damages allegedly caused by the jet fuel leaks. Grace sought a ruling from the Texas court that these subsidiaries are responsible for all liabilities, including all present and future remediation expenses, associated with these leaks and that Grace has no obligation to indemnify these subsidiaries for these expenses. In the lawsuit, Grace also sought indemnification for expenses of approximately $3.5 million that it incurred since 1996 for response and remediation required by the State of Massachusetts and for additional expenses that it expects to incur in the future. The consistent position of the Partnership's subsidiaries has been that they did not acquire the abandoned pipeline as part of the 1993 ST Services transaction, and therefore did not assume any responsibility for the environmental damage nor any liability to Grace for the pipeline.
At the end of the trial, the jury returned a verdict including findings that (1) Grace had breached a provision of the 1993 acquisition agreement by failing to disclose matters related to the pipeline, and (2) the pipeline was abandoned before 1978 -- 15 years before the Partnership's subsidiaries acquired ST Services. On August 30, 2000, the Judge entered final judgment in the case that Grace take nothing from the subsidiaries on its claims seeking recovery of remediation costs. Although the Partnership's subsidiaries have not incurred any expenses in connection with the remediation, the court also ruled, in effect, that the subsidiaries would not be entitled to indemnification from Grace if any such expenses were incurred in the future. Moreover, the Judge let stand a prior summary judgment ruling that the pipeline was an asset acquired by the Partnership's subsidiaries as part of the 1993 ST Services transaction and that any liabilities associated with the pipeline would have become liabilities of the subsidiaries. Based on that ruling, the Massachusetts Department of Environmental Protection and Samson Hydrocarbons Company (successor to Grace Petroleum Company) wrote letters to ST Services alleging its responsibility for the remediation, and ST Services responded denying any liability in connection with this matter. The Judge also awarded attorney fees to Grace of more than $1.5 million. Both the Partnership's subsidiaries and Grace have appealed the trial court's final judgment to the Texas Court of Appeals in Dallas. In particular, the subsidiaries have filed an appeal of the judgment finding that the Otis pipeline and any liabilities associated with the pipeline were transferred to them as well as the award of attorney fees to Grace.
On April 2, 2001, Grace filed a petition in bankruptcy, which created an automatic stay against actions against Grace. This automatic stay covers the appeal of the Dallas litigation, and the Texas Court of Appeals has issued an order staying all proceedings of the appeal because of the bankruptcy. Once that stay is lifted, the Partnership's subsidiaries that are party to the lawsuit intend to resume vigorous prosecution of the appeal.
The Otis Air Force Base is a part of the Massachusetts Military Reservation ("MMR Site"), which has been declared a Superfund Site pursuant to CERCLA. The MMR Site contains a number of groundwater contamination plumes, two of which are allegedly associated with the Otis pipeline, and various other waste management areas of concern, such as landfills. The United States Department of Defense, pursuant to a Federal Facilities Agreement, has been responding to the Government remediation demand for most of the contamination problems at the MMR Site. Grace and others have also received and responded to formal inquiries from the United States Government in connection with the environmental damages allegedly resulting from the jet fuel leaks. The Partnership's subsidiaries voluntarily responded to an invitation from the Government to provide information indicating that they do not own the pipeline. In connection with a court-ordered mediation between Grace and the Partnership's subsidiaries, the Government advised the parties in April 1999 that it has identified two spill areas that it believes to be related to the pipeline that is the subject of the Grace suit. The Government at that time advised the parties that it believed it had incurred costs of approximately $34 million, and expected in the future to incur costs of approximately $55 million, for remediation of one of the spill areas. This amount was not intended to be a final accounting of costs or to include all categories of costs. The Government also advised the parties that it could not at that time allocate its costs attributable to the second spill area.
By letter dated July 26, 2001, the United States Department of Justice ("DOJ") advised ST Services that the Government intends to seek reimbursement from ST Services under the Massachusetts Oil and Hazardous Material Release Prevention and Response Act and the Declaratory Judgment Act for the Government's response costs at the two spill areas discussed above. The DOJ relied in part on the Texas state court judgment, which in the DOJ's view, held that ST Services was the current owner of the pipeline and the successor-in-interest of the prior owner and operator. The Government advised ST Services that it believes it has incurred costs exceeding $40 million, and expects to incur future costs exceeding an additional $22 million, for remediation of the two spill areas. The Partnership believes that its subsidiaries have substantial defenses. ST Services responded to the DOJ on September 6, 2001, contesting the Government's positions and declining to reimburse any response costs. The DOJ has not filed a lawsuit against ST Services seeking cost recovery for its environmental investigation and response costs. Representatives of ST Services have met with representatives of the Government on several occasions since September 6, 2001 to discuss the Government's claims and to exchange information related to such claims. Additional exchanges of information are expected to occur in the future and additional meetings may be held to discuss possible resolution of the Government's claims without litigation. The Partnership does not believe this matter will have a materially adverse effect on its financial condition, although there can be no assurances as to the ultimate outcome.
On April 7, 2000, a fuel oil pipeline in Maryland owned by Potomac Electric Power Company ("PEPCO") ruptured. Work performed with regard to the pipeline was conducted by a partnership of which ST Services is general partner. PEPCO has reported that it has incurred total cleanup costs of $70 million to $75 million. PEPCO probably will continue to incur some cleanup related costs for the foreseeable future, primarily in connection with EPA requirements for monitoring the condition of some of the impacted areas. Since May 2000, ST Services has provisionally contributed a minority share of the cleanup expense, which has been funded by ST Services' insurance carriers. ST Services and PEPCO have not, however, reached a final agreement regarding ST Services' proportionate responsibility for this cleanup effort, if any, and cannot predict the amount, if any, that ultimately may be determined to be ST Services' share of the remediation expense, but ST believes that such amount will be covered by insurance and therefore will not materially adversely affect the Partnership's financial condition.
As a result of the rupture, purported class actions were filed against PEPCO and ST Services in federal and state court in Maryland by property and business owners alleging damages in unspecified amounts under various theories, including under the Oil Pollution Act ("OPA") and Maryland common law. The federal court consolidated all of the federal cases in a case styled as In re Swanson Creek Oil Spill Litigation. A settlement of the consolidated class action, and a companion state-court class action, was reached and approved by the federal judge. The settlement involved creation and funding by PEPCO and ST Services of a $2,250,000 class settlement fund, from which all participating claimants would be paid according to a court-approved formula, as well as a court-approved payment to plaintiffs' attorneys. The settlement has been consummated and the fund, to which PEPCO and ST Services contributed equal amounts, has been distributed. Participating claimants' claims have been settled and dismissed with prejudice. A number of class members elected not to participate in the settlement, i.e., to "opt out," thereby preserving their claims against PEPCO and ST Services. All non-participant claims have been settled for immaterial amounts with ST Services' portion of such settlements provided by its insurance carrier.
PEPCO and ST Services agreed with the federal government and the State of Maryland to pay costs of assessing natural resource damages arising from the Swanson Creek oil spill under OPA and of selecting restoration projects. This process was completed in mid-2002. ST Services' insurer has paid ST Services' agreed 50 percent share of these assessment costs. In late November 2002, PEPCO and ST Services entered into a Consent Decree resolving the federal and state trustees' claims for natural resource damages. The decree required payments by ST Services and PEPCO of a total of approximately $3 million to fund the restoration projects and for remaining damage assessment costs. The federal court entered the Consent Decree as a final judgment on December 31, 2002. PEPCO and ST have each paid their 50% share and thus fully performed their payment obligations under the Consent Decree. ST Services' insurance carrier funded ST Services' payment.
The U.S. Department of Transportation ("DOT") has issued a Notice of Proposed Violation to PEPCO and ST Services alleging violations over several years of pipeline safety regulations and proposing a civil penalty of $647,000 jointly against the two companies. ST Services and PEPCO have contested the DOT allegations and the proposed penalty. A hearing was held before the Office of Pipeline Safety at the DOT in late 2001. ST Services does not anticipate any further hearings on the subject and is still awaiting the DOT's ruling.
By letter dated January 4, 2002, the Attorney General's Office for the State of Maryland advised ST Services that it intended to seek penalties from ST Services in connection with the April 7, 2000 spill. The State of Maryland subsequently asserted that it would seek penalties against ST Services and PEPCO totaling up to $12 million. A settlement of this claim was reached in mid-2002 under which ST Services' insurer will pay a total of slightly more than $1 million in installments over a five year period. PEPCO has also reached a settlement of these claims with the State of Maryland. Accordingly, the Partnership believes that this matter will not have a material adverse effect on its financial condition.
On December 13, 2002, ST Services sued PEPCO in the Superior Court, District of Columbia, seeking, among other things, a declaratory judgment as to ST Services' legal obligations, if any, to reimburse PEPCO for costs of the oil spill. On December 16, 2002, PEPCO sued ST Services in the United States District Court for the District of Maryland, seeking recovery of all its costs for remediation of and response to the oil spill. Pursuant to an agreement between ST Services and PEPCO, ST Services' suit was dismissed, subject to refiling. ST Services has moved to dismiss PEPCO's suit. ST Services is vigorously defending against PEPCO's claims and is pursuing its own counterclaims for return of monies ST Services has advanced to PEPCO for settlements and cleanup costs. The Partnership believes that any costs or damages resulting from these lawsuits will be covered by insurance and therefore will not materially adversely affect the Partnership's financial condition. The amounts claimed by PEPCO, if recovered, would trigger an excess insurance policy which has a $600,000 retention, but the Partnership does not believe that such retention, if incurred, would materially adversely affect the Partnership's financial condition.
The Partnership has other contingent liabilities resulting from litigation, claims and commitments incident to the ordinary course of business. Management of the Partnership believes, based on the advice of counsel, that the ultimate resolution of such contingencies will not have a materially adverse effect on the financial position, results of operations or liquidity of the Partnership.
7. RELATED PARTY TRANSACTIONS
The Partnership has no employees and is managed and controlled by KPL. KPL and KSL are entitled to reimbursement of all direct and indirect costs related to the business activities of the Partnership. These costs, which totaled $36.3 million, $27.3 million and $18.1 million for the years ended December 31, 2003, 2002 and 2001, respectively, include compensation and benefits paid to officers and employees of KPL and KSL, insurance premiums, general and administrative costs, tax information and reporting costs, legal and audit fees. Included in this amount is $26.6 million, $17.7 million and $14.3 million of compensation and benefits, paid to officers and employees of KPL and KSL for the years ended December 31, 2003, 2002 and 2001, respectively. In addition, the Partnership paid $0.6 million in 2003, $0.6 million in 2002 and $0.5 million in 2001 for an allocable portion of KPL's overhead expenses. At December 31, 2003 and 2002, the Partnership owed KPL and KSL $3.6 million and $5.4 million, respectively, for these expenses which are due under normal invoice terms.
8. BUSINESS SEGMENT DATA
The Partnership conducts business through three principal segments; the "Pipeline Operations," which consists primarily of the transportation of refined petroleum products and fertilizer in the Midwestern states as a common carrier, the "Terminaling Operations," which provides storage for petroleum products, specialty chemicals and other liquids, and the "Product Sales Operations", which delivers bunker fuel to ships in the Caribbean and Nova Scotia, Canada and sells bulk petroleum products to various commercial interests.
The Partnership measures segment profit as operating income. Total assets are those assets controlled by each reportable segment. Business segment data is as follows:
Year Ended December 31,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Business segment revenues:
Pipeline operations.................................. $ 119,633,000 $ 82,698,000 $ 74,976,000
Terminaling operations............................... 234,958,000 205,971,000 132,820,000
Product sales operations............................. 215,823,000 97,961,000 -
---------------- --------------- --------------
$ 570,414,000 $ 386,630,000 $ 207,796,000
================ =============== ==============
Business segment profit:
Pipeline operations.................................. $ 51,860,000 $ 38,623,000 $ 36,773,000
Terminaling operations............................... 66,532,000 65,040,000 45,318,000
Product sales operations............................. 10,109,000 2,058,000 -
---------------- --------------- --------------
Operating income.................................. 128,501,000 105,721,000 82,091,000
Interest and other income ........................... 261,000 3,570,000 4,277,000
Interest expense..................................... (38,757,000) (28,110,000) (14,783,000)
Loss on debt extinguishment.......................... - (3,282,000) (6,540,000)
---------------- --------------- --------------
Income before income taxes and cumulative effect
of change in accounting principle............... $ 90,005,000 $ 77,899,000 $ 65,045,000
================ =============== ==============
Business segment assets:
Depreciation and amortization:
Pipeline operations............................... $ 14,117,000 $ 6,408,000 $ 5,478,000
Terminaling operations............................ 38,089,000 32,368,000 17,706,000
Product sales operations.......................... 949,000 649,000 -
---------------- --------------- --------------
$ 53,155,000 $ 39,425,000 $ 23,184,000
================ =============== ==============
Capital expenditures (excluding acquisitions):
Pipeline operations............................... $ 9,584,000 $ 9,469,000 $ 4,309,000
Terminaling operations............................ 34,572,000 20,953,000 12,937,000
Product sales operations.......................... 585,000 679,000 -
---------------- --------------- --------------
$ 44,741,000 $ 31,101,000 $ 17,246,000
================ =============== ==============
|
December 31,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Total assets:
Pipeline operations................................ $ 352,901,000 $ 352,657,000 $ 105,156,000
Terminaling operations............................. 874,185,000 844,321,000 443,215,000
Product sales operations........................... 37,596,000 18,432,000 -
---------------- --------------- --------------
$ 1,264,682,000 $ 1,215,410,000 $ 548,371,000
================ =============== ==============
|
The following geographical area data includes revenues and operating income based on location of the operating segment and net property and equipment based on physical location.
Year Ended December 31,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Geographical area revenues:
United States........................................ $ 240,518,000 $ 202,124,000 $ 186,734,000
United Kingdom....................................... 26,392,000 23,937,000 21,062,000
Netherlands Antilles................................. 241,693,000 132,387,000 -
Canada............................................... 41,689,000 23,207,000 -
Australia and New Zealand............................ 20,122,000 4,975,000 -
---------------- --------------- --------------
$ 570,414,000 $ 386,630,000 $ 207,796,000
================ =============== ==============
Geographical area operating income:
United States........................................ $ 87,962,000 $ 82,906,000 $ 76,575,000
United Kingdom....................................... 8,583,000 7,318,000 5,516,000
Netherlands Antilles................................. 19,223,000 9,616,000 -
Canada............................................... 6,777,000 4,398,000 -
Australia and New Zealand............................ 5,956,000 1,483,000 -
---------------- --------------- --------------
$ 128,501,000 $ 105,721,000 $ 82,091,000
================ =============== ==============
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December 31,
------------------------------------------------------
2003 2002 2001
---------------- --------------- --------------
Geographical area net property and equipment:
United States........................................ $ 693,295,000 $ 690,178,000 $ 440,104,000
United Kingdom....................................... 51,392,000 46,543,000 41,170,000
Netherlands Antilles................................. 217,143,000 224,810,000 -
Canada............................................... 74,995,000 78,789,000 -
Australia and New Zealand............................ 76,145,000 51,872,000 -
---------------- --------------- --------------
$ 1,112,970,000 $ 1,092,192,000 $ 481,274,000
================ =============== ==============
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9. FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK
The estimated fair value of all debt as of December 31, 2003 and 2002 was approximately $630 million and $709 million, as compared to the carrying value of $618 million and $694 million, respectively. These fair values were estimated using discounted cash flow analysis, based on the Partnership's current incremental borrowing rates for similar types of borrowing arrangements. These estimates are not necessarily indicative of the amounts that would be realized in a current market exchange. See Note 2 regarding derivative instruments.
The Partnership markets and sells its services to a broad base of customers and performs ongoing credit evaluations of its customers. The Partnership does not believe it has a significant concentration of credit risk at December 31, 2003. No customer constituted 10 percent or more of consolidated revenues in 2003, 2002 or 2001.
10. QUARTERLY FINANCIAL DATA (unaudited)
Quarterly operating results for 2003 and 2002 are summarized as follows:
Quarter Ended
--------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
---------------- ---------------- --------------- --------------
2003:
Revenues....................... $ 140,757,000 $ 146,948,000 $ 140,404,000 $ 142,305,000
================ ================ =============== ==============
Operating income............... $ 33,598,000 $ 33,041,000 $ 32,016,000 $ 29,846,000
================ ================ =============== ==============
Net income..................... $ 22,049,000(a) $ 22,829,000 $ 20,323,000 $ 17,988,000
================ ================ =============== ==============
2002:
Revenues....................... $ 67,642,000 $ 100,702,000 $ 103,304,000 $ 114,982,000
================ ================ =============== ==============
Operating income............... $ 23,225,000 $ 27,756,000 $ 27,870,000 $ 26,870,000
================ ================ =============== ==============
Net income..................... $ 17,416,000 $ 17,133,000(b) $ 19,491,000 $ 19,776,000(c)
================ ================ =============== ==============
|
(a) Includes cumulative effect of change in accounting principle - adoption of new accounting standard for asset retirement obligations of approximately $1.6 million in expense.
(b) Includes loss on debt extinguishment of approximately $1.9 million.
(c) Includes loss on debt extinguishment of approximately $1.2 million and gain on interest rate lock transaction at approximately $3.0 million.
Schedule II
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
VALUATION AND QUALIFYING ACCOUNTS
(in thousands)
Additions
------------------------------
Balance at Charged to Charged to Balance at
Beginning of Costs and Other End of
Period Expenses Accounts Deductions Period
------------- ------------- ------------ -------------- ------------
ALLOWANCE DEDUCTED FROM
ASSETS TO WHICH THEY APPLY
Year Ended December 31, 2003:
For doubtful receivables
classified as current assets... $ 1,765 $ 401 $ - $ (473)(b) $ 1,693
============= =========== ============= ======== ==========
Year Ended December 31, 2002:
For doubtful receivables
classified as current assets... $ 278 $ 925 $ 841(a) $ (279)(b) $ 1,765
============= =========== ============= ======== ==========
Year Ended December 31, 2001:
For doubtful receivables
classified as current assets... $ 250 $ 124 $ - $ (96)(b) $ 278
============= =========== ============= ======== ==========
|
Notes:
(a) Allowance for doubtful receivables from 2002 acquisitions.
(b) Receivable write-offs and reclassifications, net of recoveries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, Kaneb Pipe Line Operating Partnership, L.P. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KANEB PIPE LINE OPERATING
PARTNERSHIP, L.P.
By: Kaneb Pipe Line Company LLC
General Partner
By: //s// EDWARD D. DOHERTY
---------------------------------
Chairman of the Board and
Chief Executive Officer
Date: March 12, 2004
|
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of Kaneb Pipe Line Operating Partnership, L.P. and in the capacities with Kaneb Pipe Line Company LLC and on the date indicated.
Signature Title Date
---------------------------------------- --------------------------- --------------
Principal Executive Officer
//s// EDWARD D. DOHERTY Chairman of the Board March 12, 2004
---------------------------------------- and Chief Executive Officer
Principal Accounting Officer
//s// HOWARD C. WADSWORTH Vice President March 12, 2004
---------------------------------------- Treasurer & Secretary
Directors
//s// SANGWOO AHN Director March 12, 2004
----------------------------------------
//s// JOHN R. BARNES Director March 12, 2004
----------------------------------------
//s// MURRAY R. BILES Director March 12, 2004
----------------------------------------
//s// FRANK M. BURKE, JR. Director March 12, 2004
----------------------------------------
//s// CHARLES R. COX Director March 12, 2004
----------------------------------------
//s// HANS KESSLER Director March 12, 2004
----------------------------------------
//s// JAMES R. WHATLEY Director March 12, 2004
----------------------------------------
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Exhibit 31.1
I, Edward D. Doherty, Chief Executive Officer of Kaneb Pipe Line Company LLC, as General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:
1. I have reviewed this annual report on Form 10-K of Kaneb Pipe Line Operating Partnership, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) [intentionally omitted pursuant to SEC Release No. 34-47986];
c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report, based on such evaluation; and
d) disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
//s// EDWARD D. DOHERTY
--------------------------------------------
Edward D. Doherty
Chief Executive Officer
|
Exhibit 31.2
I, Howard C. Wadsworth, Chief Financial Officer of Kaneb Pipe Line Company LLC, as General Partner for Kaneb Pipe Line Operating Partnership, L.P. certify that:
1. I have reviewed this annual report on Form 10-K of Kaneb Pipe Line Operating Partnership, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) [intentionally omitted pursuant to SEC Release No. 34-47986];
c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report, based on such evaluation; and
d) disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
//s// HOWARD C. WADSWORTH
-----------------------------------
Howard C. Wadsworth
Chief Financial Officer
|
Exhibit 32.1
The undersigned, being the Chief Executive Officer of Kaneb Pipe Line Company LLC, as General Partner of Kaneb Pipe Line Operating Partnership, L.P. (the "Partnership"), hereby certifies that, to his knowledge, the Partnership's Annual Report on Form 10-K for the year ended December 31, 2003, filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
This written statement is being furnished to the Securities and Exchange Commission as an exhibit to such Form 10-K. A signed original of this written statement required by Section 906 has been provided to Kaneb Pipe Line Operating Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.
Date: March 12, 2004
//s// EDWARD D. DOHERTY
--------------------------------------------
Edward D. Doherty
Chief Executive Officer
|
Exhibit 32.2
The undersigned, being the Chief Financial Officer of Kaneb Pipe Line Company LLC, as General Partner of Kaneb Pipe Line Operating Partnership, L.P. (the "Partnership"), hereby certifies that, to his knowledge, the Partnership's Annual Report on Form 10-K for the year ended December 31, 2003, filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
This written statement is being furnished to the Securities and Exchange Commission as an exhibit to such Form 10-K. A signed original of this written statement required by Section 906 has been provided to Kaneb Pipe Line Operating Partnership, L.P. and will be retained by Kaneb Pipe Line Operating Partnership, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.
Date: March 12, 2004
//s// HOWARD C. WADSWORTH
-----------------------------------
Howard C. Wadsworth
Chief Financial Officer
|
Exhibit 3.2
AMENDMENT TO PARTNERSHIP AGREEMENT
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
This Amendment (this "Amendment") to Partnership Agreement is entered into by and among Kaneb Pipeline Company LLC , a Delaware limited liability company (the "General Partner"), as general partner of Kaneb Pipe Line Operating Partnership, L.P., a Delaware limited partnership (the "Partnership"), and Kaneb Pipe Line Partners, L.P. (the "Limited Partner") as the limited partner of the Partnership, as hereinafter provided.
WHEREAS, the General Partner and the Limited Partner entered into that certain Amended and Restated Agreement of Limited Partnership of the Partnership dated September 27, 1989 (the "Partnership Agreement"), and
WHEREAS, the General Partner and the Limited Partner desire to amend
Section 2.5 of the Partnership Agreement as set forth herein; and
Now, Therefore, the General Partner does hereby amend Section 2.5 of the Partnership Agreement to provide, in its entirety, as follows:
"2.5 Term. The Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act on September 13, 1989, and shall continue in existence in perpetuity, unless earlier terminated in accordance with any provisions of this Agreement."
This Amendment shall be effective as of June 30, 2003, regardless of when it is executed.
IN WITNESS WHEREOF, the parties hereto have hereunto set their hands this 27th day of October, 2003.
GENERAL PARTNER:
KANEB PIPE LINE COMPANY LLC
By: //s// HOWARD C. WADSWORTH
Name: Howard C. Wadsworth
Title: Vice President, Treasurer
and Secretary
|
LIMITED PARTNER:
Kaneb Pipe Line Partners, L.P.
By: Kaneb Pipe Line Company LLC,
as its sole general partner
By: //s// EDWARD D. DOHERTY
Name: Edward D. Doherty
Title: Chairman of the Board
and Chief Executive Officer
|
Exhibit 21
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
SUBSIDIARY LIST
KANEB PIPE LINE OPERATING PARTNERSHIP, L.P.
Kaneb Pipe Line Holding Company LLC
Statia Technology, Inc.
Statia Marine, Inc.
Statia Terminals International N.V.
Statia Terminals Corporation N.V.
Statia Terminals Canada, Incorporated Point Tupper Marine Services Co.
Statia Terminals Canada Partnership
Statia Terminals Canada Holdings Co.
Statia Terminals Antilles N.V.
Saba Trustcompany N.V.
Bicen Development Corporation N.V.
Statia Terminals N.V.
Statia Laboratory Services N.V.
Statia Tugs N.V.
Statia Terminals Delaware, Inc.
Statia Terminals, Inc. Statia Terminals New Jersey, Inc. Seven Seas Steamship Company, Inc. Seven Seas Steamship Company (Saint Eustatius) N.V.
Support Terminal Operating Partnership, L.P.
ST Services Ltd
ST Eastham Ltd.
ST Linden Terminal, LLC
ST/Center Chillicothe Terminal LLC
Support Terminal Services, Inc.
StanTrans, Inc.
StanTrans Holding, Inc.
StanTrans Partners, L.P.
Shore Terminals LLC
ST Australia Pty. Ltd.
Terminals Pty Ltd.
ST New Zealand Pty Ltd.
Bulk Storage Terminals Limited
BST (Auckland) Limited
Exhibit 23
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 February 20, 2004, with respect to the consolidated balance sheets of Kaneb Pipe Line Operating Partnership, L.P. and subsidiaries as of December 31, 2003 and 2002, 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, 2003, and related financial statement schedule, which report appears in the December 31, 2003 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.
KPMG LLP
Dallas, Texas
March 12, 2004