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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
COMMISSION FILE NUMBER 1-13603
TE PRODUCTS PIPELINE COMPANY, LIMITED PARTNERSHIP
(Exact name of Registrant as specified in its charter)
DELAWARE 76-0329620
(State of Incorporation or Organization) (I.R.S. Employer Identification Number)
2929 ALLEN PARKWAY
P.O. BOX 2521
HOUSTON, TEXAS 77252-2521
(Address of principal executive offices, including zip code)
(713) 759-3636
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
6.45% Senior Notes, due January 15, 2008 New York Stock Exchange
7.51% Senior Notes, due January 15, 2028 New York Stock Exchange
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 twelve months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K 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. [ ]
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TABLE OF CONTENTS
PART I
ITEMS 1. Business and Properties..................................................................................1
AND 2.
ITEM 3. Legal Proceedings.......................................................................................10
ITEM 4. Submission of Matters to a Vote of Security Holders.....................................................10
PART II
ITEM 5. Market for Registrant's Common Equity and Related Partnership Interest Matters..........................10
ITEM 6. Selected Financial Data ................................................................................11
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................12
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risks.............................................19
ITEM 8. Financial Statements and Supplementary Data.............................................................19
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................19
PART III
ITEM 10. Directors and Executive Officers of the Registrant......................................................19
ITEM 11. Executive Compensation..................................................................................21
ITEM 12. Security Ownership of Certain Beneficial Owners and Management..........................................26
ITEM 13. Certain Relationships and Related Transactions..........................................................27
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.........................................28
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ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
TE Products Pipeline Company, Limited Partnership, (the "Partnership"),
a Delaware limited partnership, was formed in March 1990. TEPPCO Partners, L.P.
(the "Parent Partnership") owns a 98.9899% interest as the sole limited partner
interest and Texas Eastern Products Pipeline Company (the "Company" or "General
Partner") owns a 1.0101% general partner interest in the Partnership. The
General Partner performs all management and operating functions required for the
Partnership.
On June 18, 1997, PanEnergy Corp ("PanEnergy") and Duke Power Company
completed a previously announced merger. At closing, the combined companies
became Duke Energy Corporation ("Duke Energy"). The Company, previously a
wholly-owned subsidiary of PanEnergy, became an indirect wholly-owned subsidiary
of Duke Energy on the date of the merger.
Effective March 31, 1998, TEPPCO Colorado, LLC ("TEPPCO Colorado"), a
wholly owned subsidiary of the Partnership, purchased two fractionation
facilities located in Weld County, Colorado, from Duke Energy Field Services,
Inc. ("DEFS"), a wholly-owned subsidiary of Duke Energy. The transaction was
accounted for under the purchase method of accounting.
The Partnership is one of the largest pipeline common carriers of
refined petroleum products and LPGs in the United States. The Partnership owns
and operates an approximate 4,300-mile pipeline system (together with the
receiving, storage and terminaling facilities mentioned below, the "Pipeline
System" or "Pipeline" or "System") extending from southeast Texas through the
central and midwestern United States to the northeastern United States. The
Pipeline System includes delivery terminals for outloading product to other
pipelines, tank trucks, rail cars or barges, as well as substantial storage
capacity at Mont Belvieu, Texas, the largest LPGs storage complex in the United
States, and at other locations. The Partnership also owns two marine receiving
terminals, one near Beaumont, Texas, and the other at Providence, Rhode Island.
The Providence terminal is not physically connected to the Pipeline. As an
interstate common carrier, the Pipeline System offers interstate transportation
services, pursuant to tariffs filed with the Federal Energy Regulatory
Commission ("FERC"), to any shipper of refined petroleum products and LPGs who
requests such services, provided that the products tendered for transportation
satisfy the conditions and specifications contained in the applicable tariff. In
addition to the revenues received by the Pipeline System from its interstate
tariffs, it also receives revenues from the shuttling of LPGs between refinery
and petrochemical facilities on the upper Texas Gulf Coast and ancillary
transportation, storage and marketing services at key points along the System.
Substantially all the petroleum products transported and stored in the Pipeline
System are owned by the Partnership's customers. Petroleum products are received
at terminals located principally on the southern end of the Pipeline System,
stored, scheduled into the Pipeline in accordance with customer nominations and
shipped to delivery terminals for ultimate delivery to the final distributor
(e.g., gas stations and retail propane distribution centers) or to other
pipelines. Pipelines are generally the lowest cost method for intermediate and
long-haul overland transportation of petroleum products. The Pipeline System is
the only pipeline that transports LPGs to the Northeast.
The Partnership's business depends in large part on (i) the level of
demand for refined petroleum products and LPGs in the geographic locations
served by it and (ii) the ability and willingness of customers having access to
the Pipeline System to supply such demand by deliveries through the System. The
Partnership cannot predict the impact of future fuel conservation measures,
alternate fuel requirements, governmental regulation, technological advances in
fuel economy and energy-generation devices, all of which could reduce the demand
for refined petroleum products and LPGs in the areas served by the Partnership.
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OPERATIONS
The Partnership conducts business and owns properties located in 13
states. Operations consist of interstate transportation, storage and terminaling
of petroleum products; short-haul shuttle transportation of LPGs at the Mont
Belvieu, Texas complex; sale of product inventory; fractionation of natural gas
liquids (effective March 31, 1998); and other ancillary services. Products are
transported in liquid form from the upper Texas Gulf Coast through two parallel
underground pipelines that extend to Seymour, Indiana. From Seymour, segments of
the Pipeline System extend to the Chicago, Illinois; Lima, Ohio; Selkirk, New
York; and Philadelphia, Pennsylvania, areas. The Pipeline System east of
Todhunter, Ohio, is dedicated solely to LPGs transportation and storage
services.
The Pipeline System includes 30 storage facilities with an aggregate
storage capacity of 13 million barrels of refined petroleum products and 38
million barrels of LPGs, including storage capacity leased to outside parties.
The Pipeline System makes deliveries to customers at 55 locations including 19
Partnership owned truck racks, rail car facilities and marine facilities.
Deliveries to other pipelines occur at various facilities owned by the
Partnership or by third parties.
PIPELINE SYSTEM
The Pipeline System is comprised of a 20-inch diameter line extending
in a generally northeasterly direction from Baytown, Texas (located
approximately 30 miles east of Houston), to a point in southwest Ohio near
Lebanon and Todhunter. A second line, which also originates at Baytown, is 16
inches in diameter until it reaches Beaumont, Texas, at which point it reduces
to a 14-inch diameter line. This second line extends along the same path as the
20-inch diameter line to the Pipeline System's terminal in El Dorado, Arkansas,
before continuing as a 16-inch diameter line to Seymour, Indiana. The Pipeline
System also has smaller diameter lines that extend laterally from El Dorado to
Helena and Arkansas City, Arkansas, from Tyler, Texas, to El Dorado and from
McRae, Arkansas, to West Memphis, Arkansas. The lines from El Dorado to Helena
and Arkansas City have 10-inch diameters. The line from Tyler to El Dorado
varies in diameter from 8 inches to 10 inches. The line from McRae to West
Memphis has a 12-inch diameter. The Pipeline System also includes a 14-inch
diameter line from Seymour, Indiana, to Chicago, Illinois, and a 10-inch
diameter line running from Lebanon to Lima, Ohio. This 10-inch diameter pipeline
connects to the Buckeye Pipe Line Company system that serves, among others,
markets in Michigan and eastern Ohio. Also, the Pipeline System has a 6-inch
diameter pipeline connection to the Greater Cincinnati/Northern Kentucky
International Airport and a 8-inch diameter pipeline connection to the George
Bush Intercontinental Airport, Houston. In addition, there are numerous smaller
diameter lines associated with the gathering and distribution system.
The Pipeline System continues eastward from Todhunter, Ohio, to
Greensburg, Pennsylvania, at which point it branches into two segments, one
ending in Selkirk, New York (near Albany), and the other ending at Marcus Hook,
Pennsylvania (near Philadelphia). The Pipeline east of Todhunter and ending in
Selkirk is an 8-inch diameter line, whereas the line starting at Greensburg and
ending at Marcus Hook varies in diameter from 6 inches to 8 inches. East of
Todhunter, Ohio, the Partnership transports only LPGs through the Pipeline.
The Pipeline System has been constructed and is in general compliance
with applicable federal, state and local laws and regulations, and accepted
industry standards and practices. The Partnership performs regular maintenance
on all the facilities of the Pipeline System and has an ongoing process of
inspecting segments of the Pipeline System and making repairs and replacements
when necessary or appropriate. In addition, the Partnership conducts periodic
air patrols of the Pipeline System to monitor pipeline integrity and third-party
right of way encroachments.
MAJOR MARKETS
The Pipeline System's major operations are the transportation, storage
and terminaling of refined petroleum products and LPGs along its mainline
system, and the storage and short-haul transportation of LPGs associated with
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its Mont Belvieu operations. Product deliveries, in millions of barrels (MMBbls)
on a regional basis, over the last three years were as follows:
PRODUCT DELIVERIES (MMBbls)
YEARS ENDED DECEMBER 31,
----------------------------
1998 1997 1996
------ ------ ------
Refined Products Transportation:
Central (1) ........................... 71.5 69.4 66.9
Midwest (2) ........................... 34.8 29.9 28.7
Ohio and Kentucky ..................... 24.2 20.7 19.7
------ ------ ------
Subtotal .......................... 130.5 120.0 115.3
------ ------ ------
LPGs Mainline Transportation:
Central, Midwest and Kentucky (1)(2) .. 18.5 23.8 24.6
Ohio and Northeast (3) ................ 13.5 18.2 17.0
------ ------ ------
Subtotal .......................... 32.0 42.0 41.6
------ ------ ------
Mont Belvieu Operations:
LPGs .................................. 25.1 27.8 22.5
------ ------ ------
Total Product Deliveries .......... 187.6 189.8 179.4
====== ====== ======
- ----------------
(1) Arkansas, Louisiana, Missouri and Texas.
(2) Illinois and Indiana.
(3) New York and Pennsylvania.
The mix of products delivered varies seasonally, with gasoline demand
generally stronger in the spring and summer months and LPGs demand generally
stronger in the fall and winter months. Weather and economic conditions in the
geographic areas served by the Pipeline System also affect the demand for and
the mix of the products delivered.
Refined products and LPGs deliveries over the last three years were as
follows:
PRODUCT DELIVERIES (MMBbls)
YEARS ENDED DECEMBER 31,
----------------------------
1998 1997 1996
------ ------ ------
Refined Products Transportation:
Gasoline ........................... 74.0 66.8 65.4
Jet Fuels .......................... 23.8 22.4 20.7
Middle Distillates(1) .............. 26.1 24.0 23.2
MTBE/Toluene ....................... 6.6 6.8 6.0
------ ------ ------
Subtotal ....................... 130.5 120.0 115.3
------ ------ ------
LPGs Mainline Transportation:
Propane ............................ 25.5 34.7 35.2
Butanes ............................ 6.5 7.3 6.4
------ ------ ------
Subtotal ....................... 32.0 42.0 41.6
------ ------ ------
Mont Belvieu Operations:
LPGs ............................... 25.1 27.8 22.5
------ ------ ------
Total Product Deliveries ....... 187.6 189.8 179.4
====== ====== ======
- ----------------
(1) Primarily diesel fuel, heating oil and other middle distillates.
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Refined Petroleum Products Transportation
The Pipeline System transports refined petroleum products from the
upper Texas Gulf Coast, eastern Texas and southern Arkansas to the Central and
Midwest regions of the United States with deliveries in Texas, Louisiana,
Arkansas, Missouri, Illinois, Kentucky, Indiana and Ohio. At these points,
refined petroleum products are delivered to Partnership-owned terminals,
connecting pipelines and customer-owned terminals. The volume of refined
petroleum products transported by the Pipeline System is directly affected by
the demand for such products in the geographic regions the System serves. Such
market demand varies based upon the different end uses to which the refined
products deliveries are applied. Demand for gasoline, which accounts for a
substantial portion of the volume of refined products transported through the
Pipeline System, depends upon price, prevailing economic conditions and
demographic changes in the markets served. Demand for refined products used in
agricultural operations is affected by weather conditions, government policy and
crop prices. Demand for jet fuel depends upon prevailing economic conditions and
military usage.
Effective January 1, 1996, the Clean Air Act Amendments of 1990
mandated the use of reformulated gasolines in nine metropolitan areas of the
United States, including the Houston and Chicago areas served by the System. A
portion of the reformulated and oxygenated gasolines includes methyl tertiary
butyl ether ("MTBE") as a major blending component. The Partnership has invested
in modifications to the System needed to allow the Partnership to achieve
increased revenues from the transportation and storage of MTBE as well as other
blending components used in the production of reformulated gasolines.
LPGs Mainline Transportation
The Pipeline System transports LPGs from the upper Texas Gulf Coast to
the Central, Midwest and Northeast regions of the United States. The Pipeline
System east of Todhunter, Ohio, is devoted solely to the transportation of LPGs.
Since LPGs demand is generally stronger in the winter months, the Pipeline
System often operates near capacity during such time. Propane deliveries are
generally sensitive to the weather and meaningful year-to-year variations have
occurred and will likely continue to occur.
The Partnership's ability to serve markets in the Northeast is enhanced
by its propane import terminal at Providence, Rhode Island. This facility
includes a 400,000-barrel refrigerated storage tank along with ship unloading
and truck loading facilities. Although the terminal is operated by the
Partnership, the utilization of the terminal is committed by contract to a major
propane marketer through May 2001.
Mont Belvieu LPGs Storage and Pipeline Shuttle
A key aspect of the Pipeline System's LPGs business is its storage and
pipeline asset base in the Mont Belvieu, Texas, complex serving the
fractionation, refining and petrochemical industries. The complex is the largest
of its kind in the United States and provides substantial capacity and
flexibility in the transportation, terminaling and storage of natural gas
liquids, LPGs and olefins.
The Partnership has approximately 33 million barrels of LPGs storage
capacity, including storage capacity leased to outside parties, at the Mont
Belvieu complex. The Partnership's Mont Belvieu short-haul transportation
shuttle system, consisting of a complex system of pipelines and interconnects,
ties Mont Belvieu to virtually every refinery and petrochemical facility on the
upper Texas Gulf Coast.
Product Sales and Other
The Partnership also derives revenue from the sale of product
inventory, terminaling activities and other ancillary services associated with
the transportation and storage of refined petroleum products and LPGs.
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Effective March 31, 1998, operations also included fractionation of
NGLs. NGL fractionation involves the separation of NGLs from processed natural
gas into individual components (primarily ethane, propane, butanes and natural
gasoline). The Partnership's two fractionator facilities are located in Weld
County, Colorado. The Greeley Fractionator has a capacity of 378,000 gallons per
day. The Spindle Fractionator has a capacity of 126,000 gallons per day.
Effective with the purchase of the fractionation facilities, TEPPCO Colorado
entered into a twenty-year Fractionation Agreement, under which TEPPCO Colorado
receives a variable fee for all fractionated volumes delivered to DEFS. TEPPCO
Colorado and DEFS also entered into a Operation and Maintenance Agreement,
whereby DEFS operates and maintains the fractionation facilities. For these
services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated
volumes delivered to DEFS. Revenues recognized from the fractionation facilities
totaled $5.5 million from April 1, 1998 through December 31, 1998. All such
revenue was received from DEFS pursuant to the Fractionation Agreement.
CUSTOMERS
The Pipeline System's customers for the transportation of refined
petroleum products include major integrated oil companies, independent oil
companies and wholesalers. End markets for these deliveries are primarily (i)
retail service stations, (ii) truck stops, (iii) agricultural enterprises, (iv)
refineries (for MTBE and other blend stocks), and (v) military and commercial
jet fuel users.
Propane shippers include wholesalers and retailers who, in turn, sell
to commercial, industrial, agricultural and residential heating customers, as
well as utilities who use propane as a fuel source. Refineries constitute the
Partnership's major customers for butane and isobutane, which are used as a
blend stock for gasolines and as a feed stock for alkylation units,
respectively.
At December 31, 1998, the Partnership had approximately 140 customers.
Transportation revenues (and percentage of total revenues) attributable to the
top 10 shippers were $90 million (42%), $85 million (38%), and $81 million (38%)
for the years ended December 31, 1998, 1997 and 1996, respectively. During 1998,
billings to Marathon Ashland, LLC, a major integrated oil company, accounted for
approximately 10% of the Partnership's revenues. During 1997 and 1996, no single
customer accounted for greater than 10% of the Partnership's total revenues.
Loss of a business relationship with a significant customer could have an
adverse affect on the consolidated financial position, results of operations and
liquidity of the Partnership.
COMPETITION
The Pipeline System conducts operations without the benefit of
exclusive franchises from government entities. Interstate common carrier
transportation services are provided through the System pursuant to tariffs
filed with the FERC.
Because pipelines are generally the lowest cost method for intermediate
and long-haul overland movement of refined petroleum products and LPGs, the
Pipeline System's most significant competitors (other than indigenous production
in its markets) are pipelines in the areas where the Pipeline System delivers
products. Competition among common carrier pipelines is based primarily on
transportation charges, quality of customer service and proximity to end users.
The General Partner believes the Partnership is competitive with other pipelines
serving the same markets; however, comparison of different pipelines is
difficult due to varying product mix and operations.
Trucks, barges and railroads competitively deliver products in some of
the areas served by the Pipeline System. Trucking costs, however, render that
mode of transportation less competitive for longer hauls or larger volumes.
Barge fees for the transportation of refined products are generally lower than
the Partnership's tariffs. The Partnership faces competition from rail movements
of LPGs in several geographic areas. The most significant area is the Northeast,
where rail movements of propane from Sarnia, Canada, compete with propane moved
on the Pipeline System.
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TITLE TO PROPERTIES
The Partnership believes it has satisfactory title to all of its
assets. Such properties are subject to liabilities in certain cases, such as
customary interests generally contracted in connection with acquisition of the
properties, liens for taxes not yet due, easements, restrictions, and other
minor encumbrances. The Partnership believes none of these liabilities
materially affects the value of such properties or the Partnership's interest
therein or will materially interfere with their use in the operation of the
Partnership's business.
CAPITAL EXPENDITURES
Capital expenditures by the Partnership were $22.7 million for the year
ended December 31, 1998. This amount includes capitalized interest of $0.8
million. Approximately $1.6 million was used for revenue-generating projects and
$20.3 million was used for System integrity projects and for sustaining existing
operations of the Partnership.
In February 1999, the Partnership announced plans to construct three
new pipelines between the Partnership's terminal in Mont Belvieu, Texas and Port
Arthur, Texas. The project includes three 12-inch diameter common-carrier
pipelines and associated facilities. Each pipeline will be approximately 70
miles in length. Upon completion, the new pipelines will transport ethylene,
propylene and natural gasoline. The anticipated completion date is the fourth
quarter of 2000. The cost of this project is expected to total approximately $72
million. Approximately $43 million is expected to be incurred in 1999, with the
remainder in 2000. The Partnership expects the majority of this project will be
financed through external borrowings.
The Partnership estimates that the remaining capital expenditures for
1999 will be approximately $20 million. Substantially all such expenditures are
expected to be used for life-cycle replacements and to upgrade current
facilities. The Partnership revises capital spending periodically in response to
changes in cash flows and operations.
REGULATION
The Partnership's interstate common carrier pipeline operations are
subject to rate regulation by the FERC under the Interstate Commerce Act
("ICA"), the Energy Policy Act of 1992 ("Act") and rules and orders promulgated
pursuant thereto. FERC regulation requires that interstate oil pipeline rates be
posted publicly and that these rates be "just and reasonable" and
nondiscriminatory.
Rates of interstate oil pipeline companies, like the Partnership, are
currently regulated by FERC primarily through an index methodology, whereby a
pipeline is allowed to change its rates based on the change from year-to-year in
the Producer Price Index for finished goods less 1% ("PPI Index"). In the
alternative, interstate oil pipeline companies may elect to support rate filings
by using a cost-of-service methodology, competitive market showings ("Market
Based Rates") or agreements between shippers and the oil pipeline company that
the rate is acceptable. With one immaterial exception, the Partnership has used
the index methodology since the adoption thereof in 1996. The Partnership is
considering requesting the FERC to allow the Partnership to utilize Market Based
Rates for interstate shipments of refined petroleum products, while maintaining
the index methodology for rates governing interstate shipments of LPGs. The
Partnership does not believe that the adoption of Market Based Rates will have a
material impact on the Partnership, since the Partnership's current rates are
highly influenced by competitive factors, but Market Based Rates will provide
the Partnership with rate flexibility.
In a June 1996 decision, the FERC disallowed the inclusion of imputed
income taxes in the cost-of-service tariff filing of Lakehead Pipeline Company,
Limited Partnership ("Lakehead"), an unrelated oil pipeline limited partnership.
The FERC's decision held that Lakehead was entitled to include an income tax
allowance in its cost-of-service for income attributable to corporate partners
but not on income attributable to individual partners. In 1997, Lakehead reached
an agreement with its shippers on all contested rates and withdrew its appeal of
the June
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1996 decision. In January 1999, in another FERC proceeding, SFPP, L.P., the FERC
followed its decision in Lakehead and held that SFPP may claim an income tax
allowance with respect to income attributable to SFPP, Inc.'s general
partnership interest and income attributable to corporations holding publicly
traded limited partnership interests, but not for income attributable to
non-corporate limited partners, both individuals and other entities. The
decision also disallowed the income tax allowance attributable to SFPP, Inc.'s
limited partnership interest under facts peculiar to the way SFPP held its
limited partnership interests. Neither the FERC's decision in Lakehead nor the
Administrative Law Judge's initial decision in SFPP, L.P. affects the
Partnership's current rates and rate structure because the Partnership uses the
index methodology to support its rates. However, the Lakehead and SFPP decisions
might become relevant to the Partnership should it (i) elect in the future to
use the cost-of-service methodology or (ii) be required to use such methodology
to defend its indexed rates against a shipper protest alleging that an indexed
rate increase substantially exceeds actual cost increases. Should such
circumstances arise, there can be no assurance with respect to the effect of
such precedents on the Partnership's rates in view of the uncertainties involved
in this issue.
ENVIRONMENTAL MATTERS
The operations of the Partnership are subject to federal, state and
local laws and regulations relating to protection of the environment. Although
the Partnership believes its operations are in material compliance with
applicable environmental regulations, risks of significant costs and liabilities
are inherent in pipeline operations, and there can be no assurance that
significant costs and liabilities will not be incurred. Moreover, it is possible
that other developments, such as increasingly strict environmental laws and
regulations and enforcement policies thereunder, and claims for damages to
property or persons resulting from its operations, could result in substantial
costs and liabilities to the Partnership.
Water
The Federal Water Pollution Control Act of 1972, as renamed and amended
as the Clean Water Act ("CWA"), imposes strict controls against the discharge of
oil and its derivatives into navigable waters. The CWA provides penalties for
any discharges of petroleum products in reportable quantities and imposes
substantial potential liability for the costs of removing an oil or hazardous
substance spill. State laws for the control of water pollution also provide
varying civil and criminal penalties and liabilities in the case of a release of
petroleum or its derivatives in surface waters or into the groundwater. Spill
prevention control and countermeasure requirements of federal laws require
appropriate containment berms and similar structures to help prevent the
contamination of navigable waters in the event of a petroleum tank spill,
rupture or leak.
Contamination resulting from spills or release of refined petroleum
products is an inherent risk within the petroleum pipeline industry. To the
extent that groundwater contamination requiring remediation exists along the
Pipeline System as a result of past operations, the Partnership believes any
such contamination could be controlled or remedied without having a material
adverse effect on the financial condition of the Partnership, but such costs are
site specific, and there can be no assurance that the effect will not be
material in the aggregate.
The primary federal law for oil spill liability is the Oil Pollution
Act of 1990 ("OPA"), which addresses three principal areas of oil pollution --
prevention, containment and cleanup, and liability. It applies to vessels,
offshore platforms, and onshore facilities, including terminals, pipelines and
transfer facilities. In order to handle, store or transport oil, shore
facilities are required to file oil spill response plans with the appropriate
agency being either the United States Coast Guard, the United States Department
of Transportation Office of Pipeline Safety ("OPS") or the Environmental
Protection Agency ("EPA"). Numerous states have enacted laws similar to OPA.
Under OPA and similar state laws, responsible parties for a regulated facility
from which oil is discharged may be liable for removal costs and natural
resources damages. The General Partner believes that the Partnership is in
material compliance with regulations pursuant to OPA and similar state laws.
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The EPA has adopted regulations that require the Partnership to have
permits in order to discharge certain storm water run-off. Storm water discharge
permits may also be required by certain states in which the Partnership
operates. Such permits may require the Partnership to monitor and sample the
effluent. The General Partner believes that the Partnership is in material
compliance with effluent limitations at existing facilities.
Air Emissions
The operations of the Partnership are subject to the federal Clean Air
Act and comparable state and local statutes. The Clean Air Act Amendments of
1990 (the "Clean Air Act") will require most industrial operations in the United
States to incur future capital expenditures in order to meet the air emission
control standards that are to be developed and implemented by the EPA and state
environmental agencies during the next decade. Pursuant to the Clean Air Act,
any Partnership facilities that emit volatile organic compounds or nitrogen
oxides and are located in ozone non-attainment areas will face increasingly
stringent regulations, including requirements that certain sources install the
reasonably available control technology. The EPA is also required to promulgate
new regulations governing the emissions of hazardous air pollutants. Some of the
Partnership's facilities are included within the categories of hazardous air
pollutant sources which will be affected by these regulations. The Partnership
does not anticipate that changes currently required by the Clean Air Act
hazardous air pollutant regulations will have a material adverse effect on the
Partnership.
The Clean Air Act also introduced the new concept of federal operating
permits for major sources of air emissions. Under this program, one federal
operating permit (a "Title V" permit) is issued. The permit acts as an umbrella
that includes all other federal, state and local preconstruction and/or
operating permit provisions, emission standards, grandfathered rates, and record
keeping, reporting, and monitoring requirements in a single document. The
federal operating permit is the tool that the public and regulatory agencies use
to review and enforce a site's compliance with all aspects of clean air
regulation at the federal, state and local level. The Partnership has completed
applications for all twelve facilities for which such regulations apply, and has
received the final permit for three facilities.
Solid Waste
The Partnership generates hazardous and non-hazardous solid wastes that
are subject to requirements of the federal Resource Conservation and Recovery
Act ("RCRA") and comparable state statutes. Amendments to RCRA require the EPA
to promulgate regulations banning the land disposal of all hazardous wastes
unless the wastes meet certain treatment standards or the land-disposal method
meets certain waste containment criteria. In 1990, the EPA issued the Toxicity
Characteristic Leaching Procedure, which substantially expanded the number of
materials defined as hazardous waste. Certain wastewater and other wastes
generated from the Partnership's business activities previously classified as
nonhazardous are now classified as hazardous due to the presence of dissolved
aromatic compounds. The Partnership utilizes waste minimization and recycling
processes and has installed pre-treatment facilities to reduce the volume of its
hazardous waste. The Partnership currently has three active on-site waste water
treatment facilities. Operating expenses of these facilities have not had a
material adverse effect on the financial position or results of operations of
the Partnership.
Superfund
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as "Superfund," imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons who
contributed to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of a facility and companies that
disposed or arranged for the disposal of the hazardous substances found at a
facility. CERCLA also authorizes the EPA and, in some instances, third parties
to take actions 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 Pipeline System generates
wastes that may fall within CERCLA's definition of a "hazardous substance."
Should a disposal facility previously used by the Partnership
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require clean up in the future, 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.
The Company was notified by the EPA in the fall of 1998 that it might
have potential liability for waste material allegedly disposed by the Company at
the Casmalia Disposal Site in Santa Barbara County, California. The EPA has
offered the Company a de minimus settlement offer of $0.3 million to settle
liability associated with the Company's alleged involvement. The Company
believes based on the information furnished by the EPA that it has been
erroneously named as an entity that disposed of waste material at the Casmalia
Disposal Site. The Company intends to continue to vigorously pursue dismissal
from this matter.
Other Environmental Proceedings
The Partnership and the Indiana Department of Environmental Management
("IDEM") have entered into an Agreed Order that will ultimately result in a
remediation program for any on-site and off-site groundwater contamination
attributable to the Partnership's operations at the Seymour, Indiana, terminal.
A Feasibility Study, which includes the Partnership's proposed remediation
program, has been approved by IDEM. IDEM will issue a Record of Decision
formally approving the remediation program. After the Record of Decision has
been issued, the Partnership will enter into an Agreed Order for the continued
operation and maintenance of the program. The Partnership estimates that the
costs of the remediation program being proposed by the Partnership for the
Seymour terminal will not exceed the amount accrued therefore (approximately
$0.8 million at December 31, 1998). In the opinion of the Company, the
completion of the remediation program being proposed by the Partnership, if such
program is approved by IDEM, will not have a material adverse impact on the
Partnership's financial condition, results of operations or liquidity.
The Partnership received a compliance order from the Louisiana
Department of Environmental Quality ("DEQ") during 1994 relative to potential
environmental contamination at the Partnership's Arcadia, Louisiana facility,
which may be attributable to the operations of the Partnership and adjacent
petroleum terminals of other companies. The Partnership and all adjacent
terminals have been assigned to the Groundwater Division of DEQ, in which a
consolidated plan will be developed. The Partnership has finalized a negotiated
Compliance Order with DEQ that will allow the Partnership to continue with a
remediation plan similar to the one previously agreed to by DEQ and implemented
by the Company. In the opinion of the General Partner, the completion of the
remediation program being proposed by the Partnership will not have a future
material adverse impact on the Partnership.
SAFETY REGULATION
The Partnership is subject to regulation by the United States
Department of Transportation ("DOT") under the Hazardous Liquid Pipeline Safety
Act of 1979 ("HLPSA") and comparable state statutes relating to the design,
installation, testing, construction, operation, replacement and management of
its pipeline facilities. HLPSA covers petroleum and petroleum products and
requires any entity that owns or operates pipeline facilities to comply with
such regulations, to permit access to and copying of records and to make certain
reports and provide information as required by the Secretary of Transportation.
The Partnership believes it is in material compliance with HLPSA requirements.
The Partnership is also subject to the requirements of the federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
Partnership believes it is in material compliance with OSHA and state
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposures.
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 and disclose 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
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higher industry and regulatory safety standards such as those described above.
Such expenditures cannot be accurately estimated at this time, although the
General Partner does not believe that they will have a future material adverse
impact on the Partnership.
The Partnership is subject to OSHA Process Safety Management ("PSM")
regulations which are designed to prevent or minimize the consequences of
catastrophic releases of toxic, reactive, flammable, or explosive chemicals.
These regulations apply to any process which involves a chemical at or above the
specified thresholds; or any process which involves a flammable liquid or gas,
as defined in the regulations, stored on site in one location, in a quantity of
10,000 pounds or more. The Partnership utilizes certain covered processes and
maintains storage of LPGs in pressurized tanks, caverns and wells in excess of
10,000 pounds at various locations. Flammable liquids stored in atmospheric
tanks below their normal boiling point without benefit of chilling or
refrigeration are exempt. The Partnership believes it is in material compliance
with the PSM regulations.
EMPLOYEES
The Partnership does not have any employees, officers or directors. The
General Partner is responsible for the management of the Partnership. As of
December 31, 1998, the General Partner had 515 employees.
ITEM 3. LEGAL PROCEEDINGS
The Partnership has been, in the ordinary course of business, a
defendant in various lawsuits and a party to various legal proceedings, some of
which are covered in whole or in part by insurance. The General Partner believes
that the outcome of such lawsuits and other proceedings will not individually or
in the aggregate have a material adverse effect on the Partnership's financial
condition, operations or cash flows.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
NONE
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED PARTNERSHIP INTEREST
MATTERS
TEPPCO Partners, L.P. owns a 98.9899% interest as the sole limited
partner interest and Texas Eastern Products Pipeline Company owns a 1.0101%
general partner interest in the Partnership. There is no established public
trading market for the Partnership ownership interests.
The Partnership makes quarterly cash distributions of its Available
Cash, as defined by the Partnership Agreements. Available Cash consists
generally of all cash receipts less cash disbursements and cash reserves
necessary for working capital, anticipated capital expenditures and
contingencies the General Partner deems appropriate and necessary.
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's income, gain, loss, deduction and credit, regardless of
whether the Partnership makes distributions.
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ITEM 6. SELECTED FINANCIAL DATA
The following tables set forth, for the periods and at the dates
indicated, selected consolidated financial and operating data for the
Partnership. The financial data was derived from the consolidated financial
statements of the Partnership and should be read in conjunction with the
Partnership's audited consolidated financial statements included in the Index to
Financial Statements on page F-1 of this report. See also Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS AND OPERATING DATA)
INCOME STATEMENT DATA:
Operating revenues:
Transportation -- refined products ......... $ 119,854 $ 107,304 $ 98,641 $ 96,190 $ 89,442
Transportation -- LPGs ..................... 60,902 79,371 80,219 70,576 73,458
Mont Belvieu operations .................... 10,880 12,815 11,811 13,570 12,290
Other ...................................... 20,147 22,603 25,354 23,380 22,112
---------- ---------- ---------- ---------- ----------
Total operating revenues .................. 211,783 222,093 216,025 203,716 197,302
Operating expenses ............................ 107,102 106,771 105,182 103,938 94,337
Depreciation and amortization ................. 26,040 23,772 23,409 23,286 23,063
---------- ---------- ---------- ---------- ----------
Operating income .............................. 78,641 91,550 87,434 76,492 79,902
Interest expense -- net ....................... (28,982) (32,229) (33,534) (34,987) (36,076)
Other income -- net ........................... 2,873 2,604 5,346 5,689 3,189
---------- ---------- ---------- ---------- ----------
Income before extraordinary item .............. 52,532 61,925 59,246 47,194 47,015
Extraordinary loss on debt extinguishment(1) .. (73,509) -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income (loss) ............................. $ (20,977) $ 61,925 $ 59,246 $ 47,194 $ 47,015
========== ========== ========== ========== ==========
BALANCE SHEET DATA (AT PERIOD END):
Property, plant and equipment -- net .......... $ 567,566 $ 567,681 $ 561,068 $ 533,470 $ 540,577
Total assets .................................. 696,486 673,909 671,241 669,915 665,331
Long-term debt (net of current maturities) .... 427,722 309,512 326,512 339,512 349,512
Partners' capital ............................. 228,138 306,060 293,274 279,202 272,350
CASH FLOW DATA:
Net cash from operations ...................... $ 83,915 $ 83,604 $ 86,121 $ 78,456 $ 70,082
Capital expenditures .......................... (22,710) (32,931) (51,264) (25,967) (20,826)
Cash investments -- net ....................... 2,357 18,860 4,148 6,527 (41,776)
Distributions ................................. (56,774) (49,042) (45,174) (40,342) (34,720)
- -------------------
(1) Extraordinary item reflects the loss related to the early extinguishment of
the First Mortgage Notes on January 27, 1998.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The following information is provided to facilitate increased
understanding of the 1998, 1997 and 1996 consolidated financial statements and
accompanying notes of the Partnership included in the Index to Financial
Statements on page F-1 of this report. Material period-to-period variances in
the consolidated statements of income are discussed under "Results of
Operations." The "Financial Condition and Liquidity" section analyzes cash flows
and financial position. Discussion included in "Other Matters" addresses key
trends, future plans and contingencies. Throughout these discussions, management
addresses items that are reasonably likely to materially affect future liquidity
or earnings.
The Partnership is involved in the transportation, storage and
terminaling of petroleum products and the fractionation of NGLs. Revenues are
derived from the transportation of refined products and LPGs, the storage and
short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex,
sale of product inventory and other ancillary services. Labor and electric power
costs comprise the two largest operating expense items of the Partnership.
Operations are somewhat seasonal with higher revenues generally realized during
the first and fourth quarters of each year. Refined products volumes are
generally higher during the second and third quarters because of greater demand
for gasolines during the spring and summer driving seasons. LPGs volumes are
generally higher from November through March due to higher demand in the
Northeast for propane, a major fuel for residential heating.
RESULTS OF OPERATIONS
For the year ended December 31, 1998, the Partnership reported a net
loss of $21.0 million. The net loss included an extraordinary loss for early
extinguishment of debt of $73.5 million. Excluding the extraordinary loss, net
income for the year would have been $52.5 million, compared with net income of
$61.9 million for 1997. The $9.4 million decrease in income before loss on debt
extinguishment resulted primarily from a $12.9 million decrease in operating
income, partially offset by a $3.2 million decrease in interest expense, net of
capitalized interest.
Net income for the year ended December 31, 1997 increased 5% to $61.9
million, compared with net income of $59.2 million for the year ended December
31, 1996. The increase in net income resulted from a $6.1 million increase in
operating revenues and a $1.3 million decrease in interest expense, net of
capitalized interest. These increases were partially offset by a $2.0 million
increase in costs and expenses, and a $2.7 million decrease in other income -
net. See discussion below of factors affecting net income for the comparative
periods.
Volume and average tariff information for 1998, 1997 and 1996 is presented
below:
PERCENTAGE
INCREASE
YEARS ENDED DECEMBER 31, (DECREASE)
---------------------------------- -----------------------
1998 1997 1996 1998 1997
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT TARIFF INFORMATION)
Volumes Delivered
Refined products ....................... 130,467 119,971 115,262 9% 4%
LPGs ................................... 32,048 41,991 41,640 (24%) 1%
Mont Belvieu operations ................ 25,072 27,869 22,522 (10%) 24%
-------- -------- -------- -------- --------
Total ............................... 187,587 189,831 179,424 (1%) 6%
======== ======== ======== ======== ========
Average Tariff per Barrel
Refined products ....................... $ 0.92 $ 0.89 $ 0.86 3% 3%
LPGs ................................... 1.90 1.89 1.93 1% (2%)
Mont Belvieu operations ................ 0.16 0.15 0.17 7% (12%)
Average system tariff per barrel .... $ 0.98 $ 1.00 $ 1.02 (2%) (2%)
======== ======== ======== ======== ========
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1998 Compared to 1997
Operating revenues for the year ended 1998 decreased 5% to $211.8
million from $222.1 million for the year ended 1997. This $10.3 million decrease
resulted from an $18.5 million decrease in LPGs transportation revenues, a $2.5
million decrease in other operating revenues and a $1.9 million decrease in
revenues generated from Mont Belvieu operations, partially offset by a $12.6
million increase in refined products transportation revenues.
Refined products transportation revenues increased $12.6 million for
the year ended December 31, 1998, compared with the prior year, as a result of
the 9% increase in volumes delivered and a 3% increase in the refined products
average tariff per barrel. The 9% increase in volumes delivered in 1998 was
attributable to (i) favorable Midwest price differentials for motor fuel,
distillate, jet fuel and natural gasoline; and (ii) the full-period impact of
capacity expansions of the mainline System between El Dorado, Arkansas, and
Seymour, Indiana, the Ark-La-Tex System between Shreveport, Louisiana, and El
Dorado, and the connection to the Colonial pipeline at Beaumont, Texas. The 3%
increase in the refined products average tariff per barrel reflects new tariff
structures for volumes transported on the expanded portion of the Ark-La-Tex
system and barrels originating from the pipeline connection with Colonial's
pipeline.
LPGs transportation revenues decreased $18.5 million for the year ended
December 31, 1998, compared with the prior year, due to a 24% decrease in
volumes delivered, partially offset by a 1% increase in the LPGs average tariff
per barrel. Propane revenues decreased $16.7 million, or 25%, from the prior
year primarily due to decreased propane deliveries in the Midwest and Northeast
market areas attributable to warmer winter and spring weather during 1998 and
unfavorable differentials versus competing Canadian product. Butane revenues
decreased $1.7 million, or 13%, from the prior year due primarily to unfavorable
blending economics in the Midwest and termination of a throughput agreement
during the second quarter of 1998. Decreased petrochemical demand along the
upper Texas Gulf Coast resulted in a 32% decrease in short-haul propane
deliveries. The 1% increase in the LPGs average tariff per barrel resulted from
an increase in 1998 of the ratio of long-haul to short-haul propane deliveries.
Revenues generated from Mont Belvieu operations decreased $1.9 million
for the year ended December 31, 1998, compared with the prior year, primarily
due to lower storage revenue, lower product receipt charges and decreased
propane dehydration fees. Additionally, Mont Belvieu shuttle deliveries
decreased 10% during the year ended 1998, compared with the prior year, due to
lower petrochemical and refinery demand for LPGs along the upper Texas Gulf
Coast. The decrease in the Mont Belvieu shuttle deliveries was largely offset by
a 7% increase in the average tariff per barrel attributable to a lower
percentage in 1998 of contract deliveries, which generally carry lower tariffs.
Other operating revenues decreased $2.5 million during the year ended
December 31, 1998, compared with 1997, primarily due to decreased product
inventory volumes sold, unfavorable product location exchange differentials
incurred to position system inventory, lower amounts of butane received in the
Midwest for summer storage and decreased terminaling revenues. These decreases
were partially offset by $5.5 million of operating revenues from the
fractionator facilities acquired on March 31, 1998.
Costs and expenses increased $2.6 million during the year ended
December 31, 1998, compared with the prior year, due to a $3.7 million increase
in operating, general and administrative expenses and a $2.3 million increase in
depreciation and amortization charges, partially offset by a $3.0 million
decrease in operating fuel and power expense and a $0.4 million decrease in
taxes - other than income. The increase in operating, general and administrative
expenses was primarily attributable to $3.4 million of expense to write down the
book-value of product inventory to market-value, credits of $3.0 million
recorded during 1997 for insurance recovery of past litigation costs related to
the Seymour terminal, a $0.9 million increase in expenses related to Year 2000
activities, $0.6 million of expense related to the fractionator facilities
acquired on March 31, 1998, and increased product measurement losses. These
increases in operating, general and administrative expenses were partially
offset by
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expenses recorded for environmental remediation at the Partnership's Seymour,
Indiana, terminal in the third quarter of 1997, and lower supplies and services
related to pipeline operations and maintenance. Depreciation and amortization
expense increased as a result of amortization of the value assigned to the
Fractionation Agreement beginning on March 31, 1998, and capital additions
placed in service. Operating fuel and power expense decreased from the prior
year due primarily to increased mainline pumping efficiencies, lower long-haul
LPGs volumes and lower summer peak power rates in Arkansas.
Interest expense decreased $3.9 million during the year ended December
31, 1998, compared with 1997, as a result of the repayment on January 27, 1998
of the remaining $326.5 million principal balance of the First Mortgage Notes,
partially offset by interest expense on the $390.0 million principal amount of
the Senior Notes issued on January 27, 1998, and interest expense on the $38.0
million term-loan used to finance the purchase of the fractionation assets on
March 31, 1998. The weighted average interest rate of the $326.5 million
principal amount of the First Mortgage Notes was 10.09%, compared with the
weighted average interest rate of the $390.0 million principal amount of the
Senior Notes of 7.02%. The interest rate on the $38.0 million term loan is
6.53%. Interest capitalized decreased $0.7 million from the prior year as a
result of lower construction balances related to capital projects.
Other income - net increased during the year ended December 31, 1998,
compared with the prior year, as a result of a $0.4 million gain on the sale of
non-carrier assets in June 1998 and a $0.5 million loss on the sale of
non-carrier assets in August 1997. These factors were partially offset by lower
interest income earned on cash investments in 1998.
1997 Compared to 1996
Operating revenues for the year ended 1997 increased 3% to $222.1
million from $216.0 million for the year ended 1996. This $6.1 million increase
resulted from a $8.7 million increase in refined products transportation
revenues and a $1.0 million increase in revenues generated from Mont Belvieu
operations, partially offset by a $0.8 million decrease in LPGs transportation
revenues and a $2.7 million decrease in other operating revenues.
Refined products transportation revenues increased $8.7 million for the
year ended December 31, 1997, compared with the prior year, as a result of the
4% increase in volumes delivered and a 3% increase in the refined products
average tariff per barrel. The 4% increase in volumes delivered in 1997 was
attributable to the capacity expansion of the mainline System between El Dorado,
Arkansas, and Seymour, Indiana, which was completed during the first quarter of
1997; capacity expansion of the Ark-La-Tex System between Shreveport, Louisiana,
and El Dorado, which was placed in service on March 31, 1997; and the connection
to the Colonial pipeline, which was placed in service on May 1, 1997. Also, jet
fuel deliveries increased to 22.4 million barrels due to a full year of
deliveries to the United States Air Force Base near Little Rock, Arkansas, which
was completed in June 1996, as well as higher demand from commercial airlines in
the Midwest. Distillate and natural gasoline deliveries increased during 1997 as
a result of higher demand in the Midwest market area. MTBE deliveries at the
marine terminal near Beaumont, Texas increased in 1997 as a result of higher
production along the upper Texas Gulf Coast. The 3% increase in the refined
products average tariff per barrel in 1997 was primarily attributable to new
tariff structures for volumes transported on the Ark-La-Tex System and volumes
originating from the Colonial pipeline connection.
LPGs transportation revenues decreased $0.8 million for the year ended
December 31, 1997, compared with the prior year, due to a 2% decrease in the
LPGs average tariff per barrel, partially offset by a 1% increase in volumes
delivered. Long-haul propane deliveries were lower than in the prior year
because of warmer winter weather in the Northeast during the first and fourth
quarters of 1997. These decreases were partially offset by stronger demand for
butane as a refinery feedstock due to the resumption during the second quarter
of 1997 of operations at a Northeast refinery that was shut down during early
1996. Increased petrochemical demand along the upper Texas Gulf Coast resulted
in a 17% increase in short-haul propane deliveries. The 2% decrease in the LPGs
average tariff per barrel resulted from an increase in 1997 of the ratio of
short-haul to long-haul propane deliveries.
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Revenues generated from Mont Belvieu operations increased $1.0 million
for the year ended December 31, 1997, compared with the prior year, due
primarily to higher terminaling fees on butane received into the system,
increased propane dehydration fees and higher petrochemical demand for LPGs
along the upper Texas Gulf Coast. The decrease in the Mont Belvieu operations
average tariff per barrel was due to a higher percentage in 1997 of contract
deliveries, which generally carry lower tariffs.
Other operating revenues decreased $2.7 million during the year ended
December 31, 1997, compared with 1996, as a result of lower volumes of product
sold in 1997, lower propane imports at the Partnership's marine terminal at
Providence, Rhode Island, reduced refined products storage volumes and
write-downs of product inventory values as a result of higher volumes of product
blends in 1997. These decreases were partially offset by increased terminaling
revenues.
Costs and expenses increased $2.0 million during the year ended
December 31, 1997, compared with the prior year, due to a $2.4 million
throughput-related increase in operating fuel and power expense, a $1.0 million
increase in taxes - other than income taxes and a $0.4 million increase in
depreciation and amortization charges, partially offset by a $1.8 million
decrease in operating, general and administrative expenses. The increase in
taxes - other than income taxes, was due primarily to higher property tax
assessments in 1997 and increased sales taxes in 1997. The decrease in
operating, general and administrative expenses was primarily attributable to
credits of $3.0 million recorded during 1997 for insurance reimbursement of past
litigation costs related to the Seymour terminal, decreased outside service
costs for System maintenance and lower product measurement losses in 1997. The
decrease in operating, general and administrative expenses was partially offset
by increased labor and benefits expense and rental expense of the Colonial
capacity lease.
Interest expense decreased $1.2 million during the year ended December
31, 1997, compared with 1996, due to the $13.0 million principal payment on the
First Mortgage Notes in March 1997. Interest capitalized increased $0.1 million
over the prior year as a result of higher construction balances related to
capital projects, which commenced during 1996, and were completed during 1997.
Other income - net decreased during the year ended December 31, 1997,
compared with the prior year, due primarily to lower interest income earned on
cash balances as a result of lower cash balances during 1997, and a $0.5 million
loss recorded on the sale of the Partnership's Arkansas City, Arkansas,
terminal.
FINANCIAL CONDITION AND LIQUIDITY
Net cash from operations for the year ended December 31, 1998, totaled
$83.9 million, comprised primarily of $78.6 million of income before
extraordinary loss on early extinguishment of debt and charges for depreciation
and amortization, and $5.3 million of cash provided from working capital
changes. This compares with cash flows from operations of $83.6 million for the
year ended 1997, which was comprised of $85.7 million of income before charges
for depreciation and amortization, partially offset by $2.1 million used for
working capital changes. The increase in cash provided by working capital
changes in 1998, as compared to the prior year, was primarily attributable to
collection of receivable balances. Net cash from operations for the year ended
December 31, 1996 totaled $86.1 million, which was comprised of $82.7 million of
income before charges for depreciation and amortization and $3.4 million of cash
provided by other working capital changes. Net cash from operations includes
interest payments of $27.0 million, $33.6 million and $34.7 million for each of
the years ended 1998, 1997 and 1996, respectively.
The Partnership routinely invests excess cash in liquid investments as
part of its cash management program. Investments of cash in discounted
commercial paper and Eurodollar time deposits with original maturities at date
of purchase of 90 days or less are included in cash and cash equivalents.
Short-term investments of cash consist of investment-grade corporate notes with
maturities during 1999. Long-term investments are comprised of investment-grade
corporate notes with varying maturities between 2000 and 2003. Interest income
earned on all investments is included in cash from operations. Cash flows from
investing activities included proceeds from investments of $3.1 million, $25.0
million and $18.6 million for each of the years ended 1998, 1997 and 1996,
respectively. Cash flows from investing activities also included additional
investments of $0.7 million, $6.2 million and $14.4 million for each of the
years ended 1998, 1997 and 1996,
15
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respectively. Cash balances related to the investment of cash and proceeds from
the investment of cash were $46.5 million, $56.1 million and $65.0 million for
the years ended December 31, 1998, 1997 and 1996, respectively.
Capital expenditures totaled $22.7 million for the year ended December
31, 1998, compared with capital expenditures of $32.9 million for the year ended
December 31, 1997. The decrease in 1998 reflects lower spending for
revenue-generating projects due to higher construction costs incurred in 1997
for completion of expansion projects started in 1996. Such projects included the
replacement of approximately 54 miles of an 8-inch diameter line with a 10-inch
diameter line between Shreveport, Louisiana, and El Dorado, Arkansas, which was
placed in service on March 31, 1997; pipeline modifications to increase mainline
capacity by 50,000 barrels per day between El Dorado and Seymour, Indiana, which
was completed during the first quarter of 1997; and expenditures to complete the
pipeline connection to Colonial Pipeline Company's ("Colonial") pipeline at
Beaumont, Texas, which was placed in service on May 1, 1997. Capital
expenditures for 1996 totaled $51.3 million. The large amount of capital
expenditures in 1996 related to the projects identified above. Capital
expenditures for System integrity projects and for sustaining existing
operations totaled $20.3 million, $18.9 million and $12.1 million for each of
the years ended 1998, 1997 and 1996, respectively.
The Partnership makes quarterly cash distributions of all of its
Available Cash, generally defined as consolidated cash receipts less
consolidated cash disbursements and cash reserves established by the general
partner in its sole discretion or as required by the terms of the Notes.
Generally, distributions are made 98.9899% to the Parent Partnership and 1.0101%
to the general partner. For the years ended December 31, 1998, 1997 and 1996,
cash distributions totaled $56.8 million, $49.0 million and $45.2 million,
respectively. The distribution increases reflect the Partnership's success in
improving cash flow levels. On February 5, 1999, the Partnership paid a cash
distribution of $14.7 million for the quarter ended December 31, 1998.
On January 27, 1998, the Partnership completed the issuance of $180
million principal amount of 6.45% Senior Notes due 2008, and $210 million
principal amount of 7.51% Senior Notes due 2028 (collectively the "Senior
Notes"). The 6.45% Senior Notes due 2008 are not subject to redemption prior to
January 15, 2008. The 7.51% Senior Notes due 2028 may be redeemed at any time
after January 15, 2008, at the option of the Partnership, in whole or in part,
at a premium. Net proceeds from the issuance of the Senior Notes totaled
approximately $386 million and was used to repay in full the $61.0 million
principal amount of the 9.60% Series A First Mortgage Notes, due 2000, and the
$265.5 million principal amount of the 10.20% Series B First Mortgage Notes, due
2010. The premium for the early redemption of the First Mortgage Notes totaled
$70.1 million. The repayment of the First Mortgage Notes and the issuance of the
Senior Notes reduced the level of cash required for debt service until 2008. The
Partnership recorded an extraordinary charge of $73.5 million during the first
quarter of 1998, which represents the redemption premium of $70.1 million and
unamortized debt issue costs related to the First Mortgage Notes of $3.4
million.
The Senior Notes do not have sinking fund requirements. Interest on the
Senior Notes is payable semiannually in arrears on January 15 and July 15 of
each year. The Senior Notes are unsecured obligations of the Partnership and
will rank on a parity with all other unsecured and unsubordinated indebtedness
of the Partnership. The indenture governing the Senior Notes contains covenants,
including, but not limited to, covenants limiting (i) the creation of liens
securing indebtedness and (ii) sale and leaseback transactions. However, the
indenture does not limit the Partnership's ability to incur additional
indebtedness.
In connection with the purchase of the fractionation assets from DEFS
as of March 31, 1998, TEPPCO Colorado received a $38 million bank loan from
SunTrust Bank. Proceeds from the loan were received on April 21, 1998. The loan
bears interest at a rate of 6.53%, which is payable quarterly. The principal
balance of the loan is payable in full on April 21, 2001.
The Partnership is guarantor on the loan.
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OTHER MATTERS
Regulatory and Environmental
The operations of the Partnership are subject to federal, state and
local laws and regulations relating to protection of the environment. Although
the Partnership believes the operations of the Pipeline System are in material
compliance with applicable environmental regulations, risks of significant costs
and liabilities are inherent in pipeline operations, and there can be no
assurance that significant costs and liabilities will not be incurred. Moreover,
it is possible that other developments, such as increasingly strict
environmental laws and regulations and enforcement policies thereunder, and
claims for damages to property or persons resulting from the operations of the
Pipeline System, could result in substantial costs and liabilities to the
Partnership. The Partnership does not anticipate that changes in environmental
laws and regulations will have a material adverse effect on its financial
position, operations or cash flows in the near term.
The Partnership and the Indiana Department of Environmental Management
("IDEM") have entered into an Agreed Order that will ultimately result in a
remediation program for any on-site and off-site groundwater contamination
attributable to the Partnership's operations at the Seymour, Indiana, terminal.
A Feasibility Study, which includes the Partnership's proposed remediation
program, has been approved by IDEM. IDEM will issue a Record of Decision
formally approving the remediation program. After the Record of Decision has
been issued, the Partnership will enter into an Agreed Order for the continued
operation and maintenance of the program. The Partnership estimates that the
costs of the remediation program being proposed by the Partnership for the
Seymour terminal will not exceed the amount accrued therefore (approximately
$0.8 million at December 31, 1998). In the opinion of the Company, the
completion of the remediation program being proposed by the Partnership, if such
program is approved by IDEM, will not have a material adverse impact on the
Partnership's financial condition, results of operations or liquidity.
Year 2000 Issues
In 1997, the Company initiated a program to prepare the Partnership's
process controls and business computer systems for the "Year 2000" issue.
Process controls are the automated equipment including hardware and software
systems which run operational activities. Business computer systems are the
computer hardware and software used by the Partnership. The Partnership is
utilizing both internal and external resources to identify, test, remediate or
replace all non-compliant computerized systems and applications. The Company
continues to evaluate appropriate courses of corrective action, including
replacement of certain systems whose associated costs would be recorded as
assets and amortized. The Partnership incurred approximately $1.3 million of
expense during 1997 and 1998 related to the Year 2000 issue. The Company
estimates the remaining amounts required to address the Year 2000 issue will be
approximately $4.0 million. A portion of such costs would have been incurred as
part of normal system and application upgrades. In certain cases, the timing of
expenditures has been accelerated due to the Year 2000 issue. Although the
Company believes this estimate to be reasonable, due to the complexities of the
Year 2000 issue, there can be no assurance that the actual costs to address the
Year 2000 issue will not be significantly greater.
The Partnership has adopted a three-phase Year 2000 program consisting
of: Phase I Preliminary Assessment; Phase II - Detailed Assessment and
Remediation Planning; and Phase III - Remediation Activities and Testing. The
Partnership has completed Phase I; Phase II is nearing completion; and Phase III
is ongoing. Remediation Activities and Testing for systems deemed most critical
are scheduled to be completed by mid-1999, with testing of all process controls
and business computer systems completed during the third quarter of 1999.
With respect to its third-party relationships, the Partnership has
contacted its suppliers and service providers to assess their state of Year 2000
readiness. Information continues to be updated regularly, thus the Partnership
anticipates receiving additional information in the near future that will assist
in determining the extent to which the Partnership may be vulnerable to those
third parties' failure to remediate their Year 2000 issues. However, there can
be no assurance that the systems of other companies, on which the Partnership's
systems rely,
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will be timely converted, or converted in a manner that is compatible with the
Partnership's systems, or that any such failures by other companies would not
have a material adverse effect on the Partnership.
Despite the Partnership's efforts to address and remediate its Year
2000 issue, there can be no assurance that all process controls and business
computer systems will continue without interruption through January 1, 2000 and
beyond. The complexity of identifying and testing all embedded microprocessors
that are installed in hardware throughout the pipeline system used for process
or flow control, transportation, security, communication and other systems may
result in unforeseen operational failures. Although the amount of potential
liability and lost revenue cannot be estimated, failures that result in
substantial disruptions of business activities could have a material adverse
effect on the Partnership. In order to mitigate potential disruptions, the
Partnership will complete contingency plans for its critical systems, processes
and external relationships by mid-fourth quarter of 1999.
Other
During June 1997, the Partnership filed rate increases on selective
refined products tariffs and LPGs tariffs, averaging 1.7%. These rate increases
became effective July 1, 1997 without suspension or refund obligation. On July
1, 1998, general rate decreases of 0.62% for both refined products tariffs and
LPGs tariffs became effective. The rate decreases were calculated pursuant to
the index methodology promulgated by the FERC.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement establishes standards for
and disclosures of derivative instruments and hedging activities. This statement
is effective for fiscal years beginning after June 15, 1999. The Partnership
does not expect the adoption of this statement to have a material impact on its
financial condition or results of operations.
In February 1999, the Partnership announced plans to construct three
new pipelines between the Partnership's terminal in Mont Belvieu, Texas and Port
Arthur, Texas. The project includes three 12-inch diameter common-carrier
pipelines and associated facilities. Each pipeline will be approximately 70
miles in length. Upon completion, the new pipelines will transport ethylene,
propylene and natural gasoline. The anticipated completion date is the fourth
quarter of 2000. The cost of this project is expected to total approximately $72
million. Approximately $43 million is expected to be incurred in 1999, with the
remainder in 2000. The Partnership expects the majority of this project will be
financed through external borrowings.
The matters discussed herein include "forward-looking statements"
within the meaning of various provisions of the Securities Act of 1933 and the
Securities Exchange Act of 1934. All statements, other than statements of
historical facts, included in this document that address activities, events or
developments that the Partnership expects or anticipates will or may occur in
the future, including such things as estimated future capital expenditures
(including the amount and nature thereof), business strategy and measures to
implement strategy, competitive strengths, goals, expansion and growth of the
Partnership's business and operations, plans, references to future success,
references to intentions as to future matters and other such matters are
forward-looking statements. These statements are based on certain assumptions
and analyses made by the Partnership in light of its experience and its
perception of historical trends, current conditions and expected future
developments as well as other factors it believes are appropriate under the
circumstances. However, whether actual results and developments will conform
with the Partnership's expectations and predictions is subject to a number of
risks and uncertainties, including general economic, market or business
conditions, the opportunities (or lack thereof) that may be presented to and
pursued by the Partnership, competitive actions by other pipeline companies,
changes in laws or regulations, and other factors, many of which are beyond the
control of the Partnership. Consequently, all of the forward-looking statements
made in this document are qualified by these cautionary statements and there can
be no assurance that actual results or developments anticipated by the
Partnership will be realized or, even if realized, that they will have the
expected consequences to or effect on the Partnership or its business or
operations.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
At December 31, 1998, the Partnership's had outstanding $180 million
principal amount of 6.45% Senior Notes due 2008, and $210 million principal
amount of 7.51% Senior Notes due 2028 (collectively the "Senior Notes").
Additionally, the Partnership's had a $38 million bank loan outstanding from
SunTrust Bank. The SunTrust loan bears interest at a fixed rate of 6.53% and is
payable in full in April 2001. At December 31, 1998, the estimated fair value of
the Senior Notes and the SunTrust loan was approximately $406.6 million and
$39.3 million, respectively.
The Partnership periodically enters into futures contracts to hedge its
exposure to price risk on product inventory transactions. Recognized gains and
losses related to futures contracts which qualify as hedges are recognized in
income when the related inventory transactions are completed. Gains and losses
related to futures contracts, to the extent settled in cash, are reported as a
component of product inventory in the consolidated balance sheet until
recognized as income. At December 31, 1998, there were no outstanding futures
contracts.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements of the Partnership, together with
the independent auditors' report thereon of KPMG LLP, begin on page F-1 of this
report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Partnership does not have directors or officers. Set forth below is
certain information concerning the directors and executive officers of the
General Partner. All directors of the General Partner are elected annually by
Duke Energy. All officers serve at the discretion of the directors.
William L. Thacker, age 53, was elected a director of the General
Partner in 1992 and Chairman of the Board in October 1997. Mr. Thacker was
elected President and Chief Operating Officer in September 1992 and Chief
Executive Officer in January 1994. Prior to joining the Company, Mr. Thacker was
President of Unocal Pipeline Company from 1986 until 1992.
Fred J. Fowler, age 53, is Vice Chairman of the Board of the General
Partner and is Chairman of the Compensation Committee. He was elected a director
in November 1998. Mr. Fowler is group president, energy transmission of Duke
Energy. Mr. Fowler joined PanEnergy in 1985 and served in a variety of positions
in marketing, transportation and exchange. He was appointed group vice president
of PanEnergy in 1996.
Richard J. Osborne, age 48, was elected a director of the General
Partner in October 1998. Mr. Osborne is executive vice president and chief
financial officer of Duke Energy. He previously served as vice president and
chief financial officer of Duke Energy from 1991 to 1997. Mr. Osborne joined
Duke Energy in 1975.
Jim W. Mogg, age 50, was elected a director of the General Partner in
October 1997. Mr. Mogg is president and chief executive officer of Duke Energy
Field Services, Inc. Mr. Mogg was previously president of Centana Energy
Corporation and senior vice president for Panhandle Eastern Pipe Line Company.
Mr. Mogg joined Panhandle Eastern Pipe Line Company in 1973.
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Ruth G. Shaw, age 51, was elected a director of the General Partner in
December 1997. Ms. Shaw is executive vice president and chief administrative
officer of Duke Energy. Ms. Shaw joined Duke Power Company in 1992 as vice
president of corporate communications. In April 1994, she was elected senior
vice president, corporate resources and chief administrative officer. Ms. Shaw
is a director of First Union Corp. and Avado Brands, Inc.
Carl D. Clay, age 66, is a director of the General Partner and a member
of the Compensation and Audit Committees. He was elected in January 1995. Mr.
Clay retired from Marathon Oil Company in 1994 after 33 years during which he
served as director of transportation and logistics and president of Marathon
Pipe Line Company.
Derrill Cody, age 60, is a director of the General Partner having been
elected in 1989. He is the Chairman of the Audit Committee and serves on the
Compensation Committee of the General Partner. Mr. Cody is presently of counsel
to McKinney, Stringer & Webster, P.C., which represents Duke Energy in certain
matters. He is also an advisor to Duke Energy pursuant to a personal contract.
Mr. Cody served as Chief Executive Officer of Texas Eastern Gas Pipeline Company
from 1987 to 1989. Mr. Cody is also a director of Barrett Resources Corporation.
John P. DesBarres, age 59, is a director of the General Partner, having
been elected in May 1995. He is a member of the Compensation and Audit
Committees. Mr. DesBarres was formerly chairman, president and chief executive
officer of Transco Energy Company from 1992 to 1995. He joined Transco in 1991
as president and chief executive officer. Prior to joining Transco, Mr.
DesBarres served as chairman, president and chief executive officer for Santa Fe
Pacific Pipelines, Inc. from 1988 to 1991.
Milton Carroll, age 49, was elected a director of the General Partner
in November 1997 and is a member of the Compensation and Audit Committees. Mr.
Carroll founded and has been president and chief executive officer of Instrument
Products, Inc., a manufacturer of oil field tools and other precision products,
since 1977. Mr. Carroll is a director of Reliant Energy, Seagull Energy Corp.,
and Blue Cross Blue Shield of Texas.
Charles H. Leonard, age 50, is Senior Vice President, Chief Financial
Officer and Treasurer of the General Partner. Mr. Leonard joined the Company in
1988 as Vice President and Controller. In November 1989, he was elected Vice
President and Chief Financial Officer. He was elected Senior Vice President in
March 1990, and Treasurer in October 1996.
James C. Ruth, age 51, is Vice President, General Counsel and Secretary
of the General Partner, having been elected in 1991. He was elected as Secretary
in 1998. Mr. Ruth was Vice President and Assistant General Counsel of the
General Partner from 1989 to 1991.
Thomas R. Harper, age 58, is Vice President, Product Transportation and
Refined Products Marketing of the General Partner. Mr. Harper joined the Company
in 1987 as Director of Product Transportation, and was elected to his present
position in 1988.
David L. Langley, age 51, is Vice President, Business Development and
LPG Services of the General Partner. Mr. Langley has been with the Company in
various managerial positions since 1975 and was elected Vice President, LPG
Business Center, in 1988. He was elected to his current position in 1990.
O. Horton Cunningham, age 50, is Vice President, Technical Services, of
the General Partner, having been elected in October 1996. Mr. Cunningham served
as Vice President, Operations, from 1990 until October 1996. Mr. Cunningham
joined the Company in 1987 as Manager of Environmental Affairs and was promoted
to Director of Safety and Environmental Affairs in 1988 and Director of
Engineering and Compliance in 1989.
Ernest P. Hagan, age 54, is Vice President, Operations, of the General
Partner, having been elected in October 1996. Mr. Hagan was previously Director
of Engineering and Right-of-Way from 1994 until October 1996, and from 1986
until 1994 he was Region Manager of the Southwest Region. Mr. Hagan joined the
Company in 1971.
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Sharon S. Stratton, age 60, is Vice President, Human Resources of the
General Partner, having been elected in January 1999. Ms. Stratton served as
Director, Human Resources of the General Partner from 1992 to 1998. She
previously served in a variety of human resource positions with PanEnergy. Ms.
Stratton joined PanEnergy in 1976.
J. Michael Cockrell, age 52, is Vice President of the General Partner,
having been elected in January 1999. Mr. Cockrell also serves as President of
TEPPCO Crude Oil, LLC ("TCO"). He joined PanEnergy in 1987 and served in a
variety of positions in supply and development, including president of Duke
Energy Transport and Trading Company.
William S. Dickey, age 41, is Vice President of the General Partner,
having been elected in January 1999. Mr. Dickey also serves as Senior Vice
President and Chief Financial Officer of TCO. He previously served as vice
president and chief financial officer of Duke Energy Field Services from 1994 to
1998. Mr. Dickey joined PanEnergy in 1987.
Based on information furnished to the Company and written
representation that no other reports were required, to the Company's knowledge,
all applicable Section 16(a) filing requirements were complied with during the
year ended December 31, 1998, except that one such report covering one
transaction in Limited Partner Units of the Parent Partnership was filed late by
Ruth G. Shaw.
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.
Directors of the General Partner who are neither officers nor employees
of either the Company or Duke Energy receive a stipend of $15,000 per annum,
$750 for attendance at each meeting of the Board of Directors, $750 for
attendance at each meeting of a committee of the Board of Directors and
reimbursement of expenses incurred in connection with attendance at a meeting of
the Board of Directors or a committee of the Board of Directors. Each outside
director who serves as chairman of a committee of the Board of Directors
receives an additional stipend of $2,000 per annum.
Messrs. Thacker, Fowler, Mogg and Osborne and Ms. Shaw were not
compensated for their services as directors, and it is not anticipated that any
compensation for service as a director will be paid in the future to directors
who are full-time employees of Duke Energy, the General Partner or any of their
affiliates.
The following table reflects cash compensation paid or accrued by the
General Partner for the years ended December 31, 1998, 1997 and 1996, with
respect to its Chief Executive Officer and the executive officers (collectively,
the "Named Executive Officers").
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SUMMARY COMPENSATION TABLE
LONG TERM COMPENSATION
---------------------------
AWARDS PAYOUTS
ANNUAL COMPENSATION OTHER ------------- -------------
---------------------------- ANNUAL SECURITIES LTICP AND ALL OTHER
NAME AND BONUS COMPENSATION UNDERLYING 1994 LTIP COMPENSATION
PRINCIPAL POSITION YEAR SALARY($) ($)(1) ($)(2) OPTIONS(#)(3) PAYOUTS($)(4) ($)(5)
------------------ ---- --------- ------- ------- ------------- ------------- -------
William L. Thacker ............... 1998 250,000 86,400 77,114 39,000 148,858 24,666
Chairman, President and 1997 237,708 98,200 78,551 8,800 358,168 21,529
Chief Executive Officer 1996 224,667 107,500 79,988 -- 113,447 19,723
Charles H. Leonard ............... 1998 149,333 39,200 14,820 12,000 95,331 13,406
Senior Vice President, Chief 1997 145,750 52,000 29,985 -- 25,444 12,960
Financial Officer and 1996 142,958 54,800 35,691 -- 16,094 12,780
Treasurer
James C. Ruth .................... 1998 138,333 36,200 38,557 12,000 41,095 15,079
Vice President and 1997 134,333 46,000 39,276 -- 27,901 14,968
General Counsel 1996 130,417 48,600 39,994 -- 20,052 13,506
O. Horton Cunningham ............. 1998 134,333 35,000 36,147 12,000 42,551 14,513
Vice President 1997 130,333 43,000 36,821 -- 27,029 11,799
1996 126,000 45,300 37,495 -- 23,597 11,052
David L. Langley ................. 1998 134,333 34,800 23,134 12,000 50,516 12,968
Vice President 1997 129,292 42,800 23,565 -- 52,028 12,992
1996 123,750 47,800 23,997 -- 20,080 12,000
Thomas R. Harper ................. 1998 134,333 35,200 23,134 12,000 40,054 16,117
Vice President 1997 129,083 43,000 23,565 -- 33,533 15,243
1996 123,125 46,500 23,997 -- 14,370 13,339
Ernest P. Hagan (6) .............. 1998 126,292 27,100 -- 12,000 -- 12,090
Vice President 1997 120,417 39,200 -- 2,300 -- 10,769
1996 29,375 6,525 -- -- -- 2,257
- -------------
(1) Amounts represent bonuses accrued during the year under the Management
Incentive Compensation Plan ("MICP"). Payments under the MICP were made in
the subsequent year.
(2) Amounts shown for 1998, 1997 and 1996 are for quarterly distribution
equivalents under the terms of the Company's Long Term Incentive
Compensation Plan ("LTICP").
(3) Amounts represent awards pursuant to the Texas Eastern Products Pipeline
Company 1994 Long Term Incentive Plan ("1994 LTIP"). See "Compensation
Pursuant to General Partner Plans" for further discussion of the 1994 LTIP.
(4) Amounts represent the value of redemptions under the 1996 amendment to the
LTICP and credits earned to Performance Unit accounts and options exercised
under the terms of 1994 LTIP. Also, for Mr. Thacker in 1997 and 1996,
amounts include crediting of phantom units awarded in a prior year under the
terms of the LTICP.
(5) Includes amounts contributed by the Company for the Named Executive Officers
under the Employees' Savings Plan of PanEnergy ("ESP") and under the
PanEnergy Key Executive Deferred Compensation Plan, an unfunded, defined
contribution plan that allows eligible employees to elect deferral of base
salary and bonus, and receive matching Company contributions, whenever and
to the extent that their participation in the
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ESP is limited by provisions of the Internal Revenue Code, and the imputed
value of premiums paid by the Company for insurance on the Named Executive
Officers' lives.
(6) Mr. Hagan was named Vice President, Operations, effective October 1, 1996.
Amounts for 1996 represent compensation for the period October 1, 1996,
through December 31, 1996.
EXECUTIVE EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS
On September 1, 1992, William L. Thacker, Jr. and the Company entered
into an employment agreement, which set a minimum base salary of $190,000 per
year. The Company may terminate the employment agreement for cause, death or
disability. In addition, the Company or Mr. Thacker may terminate the agreement
upon written notice. Additionally, the Company granted 16,000 phantom units with
distribution equivalents to Mr. Thacker pursuant to the LTICP discussed below.
Mr. Thacker participates in other Company sponsored benefit plans on the same
basis as other senior executives of the Company.
On December 1, 1998, the Company entered into employment agreements
with O. Horton Cunningham, Ernest P. Hagan, Thomas R. Harper, David L. Langley,
Charles H. Leonard and James C. Ruth. The agreements may be terminated for
death, disability or by the Company with or without cause. In the event one of
the named executives' employment is terminated due to death or disability or by
the Company for cause, such executive is entitled only to base salary earned
through the date of termination. In the event of termination for any other
reason, such executive is entitled to base salary earned through the date of
termination plus a lump sum severance payment equal to two times such
executive's base annual salary and two times the current target bonus approved
under the MICP by the Compensation Committee. In the event that an executive is
involuntarily terminated following a change in control, such executive is
entitled to a lump sum severance payment equal to two times his base annual
salary plus two times his current target bonus.
COMPENSATION PURSUANT TO GENERAL PARTNER PLANS
Management Incentive Compensation Plan
The General Partner has established the MICP, which provides for the
payment of additional cash compensation to participants if certain Partnership
performance and personal objectives are met each year. The Compensation
Committee (the "Committee") determines at the beginning of each year which
employees are eligible to become participants in the MICP. Each participant is
assigned a target award by the Committee. Such target award determines the
additional compensation to be paid if all Partnership performance and personal
objectives are met and all Minimum Quarterly Distributions have been made for
the year. The amount of the awards may range from 10% to 56% of a participant's
base salary. Awards are paid as soon as practicable following approval by the
Committee after the close of a year.
Long Term Incentive Compensation Plan
The LTICP provides key employees with an incentive award based upon the
grant of phantom units. The LTICP is administered by the Committee, which has
sole and absolute discretion to determine the amount of an award. The credit of
phantom units under the terms of the LTICP is contingent upon all cash
distributions being made to the Unitholders of the Parent Partnership and the
General Partner. The Committee may also establish performance targets for
crediting of phantom units. The award consists of phantom units with a total
market value, as of the date of the award, that may not exceed 100% of the base
salary of a participant. The phantom units are credited to each participant at
the rate of 10% per year beginning on the first anniversary date of the award. A
final credit of 60% of the phantom units awarded will occur on the fifth
anniversary date of the award. The phantom units may be redeemed by a
participant at any time following credit to a participant in accordance with
terms and conditions prescribed by the Committee. The redemption price of the
phantom units is based on the market value of a Limited Partner Unit of the
Parent Partnership as of the date of redemption. In the event of a change of
control, all phantom units
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awarded to a participant will be redeemed. Each participant also receives a
quarterly distribution equivalent in cash based upon a percentage of the
distributions to the General Partner for such quarter. In 1995, the LTICP was
amended to require annual redemptions, effective January 1, 1996, of 20% of the
phantom units previously credited to each participant. See Item 13, "Certain
Relationships and Related Transactions."
1994 Long Term Incentive Plan
The 1994 LTIP provides key employees with an incentive award whereby a
participant is granted an option to purchase Limited Partner Units of the Parent
Partnership together with a stipulated number of Performance Units. Each
Performance Unit creates a credit to a participant's Performance Unit account
when earnings of the Parent Partnership exceed a threshold, which was $1.00,
$1.25 and $1.875 per Limited Partner Unit for the awards made in 1994, 1995, and
1997, respectively. No Performance Unit awards were granted during 1996 and
1998. When earnings for a calendar year (exclusive of certain special items)
exceed the threshold, the excess amount is credited to the participant's
Performance Unit account. The balance in the account may be used to exercise
Unit options granted in connection with the Performance Units or may be
withdrawn two years after the underlying options expire, usually 10 years from
the date of grant. Under the agreement for such Unit options, the options become
exercisable in equal installments over periods of one, two, and three years from
the date of the grant. Options may also be exercised by normal means once
vesting requirements are met.
The following table shows all grants of unit options of the Parent
Partnership to the Named Executive Officers in 1998. No Stock appreciation
rights (SARs) were granted to any Named Executive Officer in 1998 nor were the
exercise prices on unit options previously awarded amended or adjusted.
OPTION/SAR GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS
-----------------------------------------------------------------------------------
GRANT DATE
NUMBER OF PERCENT OF VALUE
SECURITIES TOTAL OPTIONS/ ---------------
UNDERLYING SARS GRANTED EXERCISE OR GRANT DATE
OPTIONS/SARS TO EMPLOYEES BASE PRICE EXPIRATION PRESENT
GRANTED(1)(#) IN FISCAL YEAR ($/UNIT) DATE VALUE(2)$
--------------- -------------- ------------- ------------ ---------------
Mr. Thacker .............. 39,000 35 25.6875 1/18/08 $94,770
Mr. Leonard .............. 12,000 11 25.6875 1/18/08 $29,160
Mr. Ruth ................. 12,000 11 25.6875 1/18/08 $29,160
Mr. Cunningham ........... 12,000 11 25.6875 1/18/08 $29,160
Mr. Langley .............. 12,000 11 25.6875 1/18/08 $29,160
Mr. Harper ............... 12,000 11 25.6875 1/18/08 $29,160
Mr. Hagan ................ 12,000 11 25.6875 1/18/08 $29,160
- --------------------
(1) On January 16, 1998, Mr. Thacker was granted options to purchase 39,000
Limited Partner Units under the terms of the 1994 LTIP at an exercise
price of $25.6875 per Limited Partner Unit, which was the fair market
value of a Limited Partner Unit on the date of grant. Also on January
16, 1998, Messrs. Leonard, Ruth, Cunningham, Langley, Harper and Hagan
were granted options to purchase 12,000 Limited Partner Units under the
terms of the 1994 LTIP at an exercise price of $25.6875, which was the
fair market value of a Limited Partner Unit on the date of grant. No
Performance Units were granted in 1998.
(2) Based on the Black-Scholes option valuation model. The key input
variables used in valuing the options were: risk-free interest rate
based on 6-year Treasury strips - 5.5%; dividend yield - 7.8%; Unit
price volatility - 18%. Expected dividend yield and price volatility
was based on historical Limited Partner Unit data. No adjustments for
non-transferability or risk of forfeiture were made. The actual value,
if any, a grantee amy realize will depend on the excess of the Limited
Partner Unit price over the exercise price on the date the option is
exercised, so that there is no assurance the value realized will be at
or near the value estimated by the Black-Scholes model.
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The following table provides information concerning the unit options of
the Parent Partnership exercised by each of the Named Executive Officers during
1998 and the value of unexercised unit options to the Named Executive Officers
as of December 31, 1998. The value assigned to each unexercised, "in the money"
option is based on the positive spread between the exercise price of such option
and the fair market value of a Limited Partner Unit on December 31, 1998. The
fair market value is the average of the high and low prices of a Limited Partner
Unit on that date as reported in The Wall Street Journal. In assessing the
value, it should be kept in mind that no matter what theoretical value is placed
on an option on a particular date, its ultimate value will be dependent on the
market value of the Parent Partnership's Limited Partner Unit price at a future
date. The future value will depend in part on the efforts of the Named Executive
Officers to foster the future success of the Partnership.
AGGREGATED OPTIONS/SAR EXERCISES IN LAST FISCAL YEAR AND
FISCAL YEAR-END OPTION/SAR VALUES
VALUE OF
UNEXERCISED
NUMBER OF SECURITIES IN-THE MONEY
UNDERLYING UNEXERCISED OPTIONS/SARS
SHARES OPTIONS/SARS AT FY-END AT FY-END ($)
ACQUIRED ON VALUE (#) EXERCISABLE/ EXERCISABLE/
NAME EXERCISE (#) REALIZED($) UNEXERCISABLE (1) UNEXERCISABLE
- ------------------------------ ------------- ----------- ----------------------- ------------------
Mr. Thacker .................... 5,298 $68,065 22,164/44,896 $201,790/$16,216
Mr. Leonard .................... 2,800 $38,866 10,694/12,000 $113,290/$0
Mr. Ruth ....................... 708 $9,472 11,592/12,000 $122,803/$0
Mr. Cunningham ................. 708 $9,472 10,518/12,000 $111,425/$0
Mr. Langley .................... 2,000 $26,757 6,000/12,000 $63,563/$0
Mr. Harper ..................... 1,218 $16,295 10,632/12,000 $112,633/$0
Mr. Hagan ...................... -- -- 759/13,541 $2,087/$4,238
(1) Future exercisability of currently unexercisable options depends on the
grantee remaining employed by the Company throughout the vesting period
of the options, subject to provisions applicable at retirement, death,
or total disability.
1997 Employee Incentive Compensation Plan
The General Partner has adopted the 1997 Employee Incentive
Compensation Plan ("1997 EICP"), which provides an award of shadow units to all
employees who are not eligible to participate in the MICP. The 1997 EICP is
administered by the Committee, which maintains an incentive award account for
each participant. Each participant is eligible for an annual award of up to 600
shadow units, depending on the level of earnings achieved by the Partnership
each year, which generally entitles such participant to receive a credit equal
to the quarterly distribution that such participant would have received had the
participant been the owner of Limited Partner Units of the Parent Partnership.
The Committee may add a premium from 10% to 30% to the credit if certain safety
and operational goals are attained. Payment of the credits is contingent upon
the participant remaining in the employment of the General Partner during the
year in which the shadow units are outstanding. Awards to participants are paid
in cash following the close of each year in an amount equal to the credits in
the participant's incentive award account with respect to such year.
PENSION PLAN
The Company's employees, along with employees of other Duke Energy
affiliates, are included in either of two noncontributory, qualified, defined
benefit retirement plans: the Retirement Cash Balance Plan and the Retirement
Income Plan. The Retirement Income Plan ceased admitting new participants after
December 31, 1998. In addition, the Named Executive Officers participate in the
Executive Cash Balance Plan, which is a noncontributory, non qualified, defined
benefit retirement plan. A portion of the benefits earned in the Executive Cash
Balance Plan is attributable to compensation in excess of the Internal Revenue
Service annual compensation
25
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limit ($160,000 for 1998) and deferred compensation, as well as reductions
caused by maximum benefit limitations that apply to qualified plans from the
benefits that would otherwise be provided under the Retirement Cash Balance Plan
and the Retirement Income Plan. Benefits under the Retirement Cash Balance Plan,
the Retirement Income Plan and the Executive Cash Balance Plan are based on
eligible pay, generally consisting of base pay and lump-sum merit increases. The
Retirement Cash Balance Plan and the Retirement Income Plan exclude deferred
compensation, other than deferrals pursuant to Sections 401(k) and 125 of the
Internal Revenue Code.
Under a new benefit accrual formula that applies in determining
benefits under the Retirement Cash Balance Plan, and the Retirement Income Plan
on and after January 1, 1999, an eligible employee's plan account receives a pay
credit at the end of each month in which the employee remains eligible and
receives eligible pay for services. The monthly pay credit is equal to a
percentage of the employee's monthly eligible pay. The percentage depends on age
added to completed years of services at the beginning of the year, as shown
below:
MONTHLY PAY CREDIT
AGE AND SERVICE PERCENTAGE
--------------- ---------------------
34 or less .......................... 4%
35 to 49 ............................ 5%
50 to 64 ............................ 6%
65 or more .......................... 7%
In addition, the employee receives a monthly allocation of 4% for any
portion of eligible pay above the Social Security taxable wage base ($72,600 for
1999). However, for certain other employees of the Company, the percentage is a
flat 3% of eligible pay. Employee accounts also receive monthly interest credits
on their balances. The rate of the interest credit is adjusted quarterly and
equals the yield on 30-year U.S. Treasury Bonds during the third week of the
last month of the previous quarter, subject to a minimum rate of 4% per year and
a maximum rate of 9% per year.
Prior to application of the new benefit accrual formula, benefits for
eligible employees, including benefits under the Retirement Income Plan for
1998, were determined under other formulas. To transition from a prior formula
to the new formula, an eligible employee's accrued benefit earned under the
prior formula is preserved as a minimum, and the employee's account under the
new benefit accrual formula receives an opening balance derived from a variety
of factors.
Assuming that the Named Executive Officers continue in their present
positions at their present salaries until retirement at age 65, their estimated
annual pensions in a single life annuity form under the applicable plan(s)
attributable to such salaries would be as follows: William L. Thacker, $238,677;
Charles H. Leonard, $99,974; James C. Ruth, $179,397; O. Horton Cunningham,
$95,908; David L. Langley, $168,898; Thomas R. Harper, $61,117; and Ernest P.
Hagan, $125,878. Such estimates were calculated assuming interest credits at a
rate of 7% per annum and using a future Social Security taxable wage base equal
to $72,600.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
TEPPCO Partners, L.P. (the "Parent Partnership") owns a 98.9899%
interest as the sole limited partner interest and Texas Eastern Products
Pipeline Company owns a 1.0101% general partner interest in the Partnership. The
information below identifies security ownership of the Parent Partnership.
(a) Security Ownership of Certain Beneficial Owners
As of March 1, 1999, Duke Energy, through its ow