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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 1-10403
TEPPCO PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
DELAWARE 76-0291058
(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
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LIMITED PARTNER UNITS REPRESENTING LIMITED NEW YORK STOCK EXCHANGE
PARTNER INTERESTS
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. [ ]
At March 1, 1999 the aggregate market value of the registrant's Limited
Partner Units held by non-affiliates was $653,480,681, which was computed using
the average of the high and low sales prices of the Limited Partner Units on
March 1, 1999.
Limited Partner Units outstanding as of March 1, 1999: 29,000,000.
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TABLE OF CONTENTS
PART I
ITEMS 1. Business and Properties..................................... 1
AND 2.
ITEM 3. Legal Proceedings........................................... 12
ITEM 4. Submission of Matters to a Vote of Security Holders......... 12
PART II
ITEM 5. Market for Registrant's Units and Related Unitholder
Matters..................................................... 12
ITEM 6. Selected Financial Data..................................... 14
ITEM 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 15
ITEM 7A. Quantitative and Qualitative Disclosures About Market
Risks....................................................... 23
ITEM 8. Financial Statements and Supplementary Data................. 23
ITEM 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 23
PART III
ITEM 10. Directors and Executive Officers of the Registrant.......... 23
ITEM 11. Executive Compensation...................................... 25
ITEM 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 30
ITEM 13. Certain Relationships and Related Transactions.............. 31
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 32
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
TEPPCO Partners, L.P. (the "Partnership"), a Delaware limited partnership,
was formed in March 1990. The Partnership operates through TE Products Pipeline
Company, Limited Partnership (the "Products OLP") and TCTM, L.P. (the "Crude Oil
OLP"). Collectively the Products OLP and the Crude Oil OLP are referred to as
"the Operating Partnerships." The Partnership owns a 99% interest as the sole
limited partner interest in both the Products OLP and the Crude Oil OLP. Texas
Eastern Products Pipeline Company (the "Company" or "General Partner") owns a 1%
general partner interest in the Partnership and 1% general partner interest in
each Operating Partnership. The General Partner performs all management and
operating functions required for the Partnership and the Operating Partnerships.
The Partnership operates in two industry segments -- refined products and
liquefied petroleum gases ("LPGs") transportation; and crude oil and natural gas
liquids ("NGLs") transportation and marketing. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and Note 15 of the
Notes to Consolidated Financial Statements contained elsewhere herein for
additional segment information.
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 Products OLP, 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.
Effective November 1, 1998, the Crude Oil OLP, through its wholly owned
subsidiary TEPPCO Crude Oil, LLC, acquired substantially all of the assets of
Duke Energy Transport and Trading Company ("DETTCO") from Duke Energy. The
transaction was accounted for under the purchase method of accounting. In
consideration for such assets, Duke Energy received 3,916,547 Class B Limited
Partnership Units ("Class B Units"). The Class B Units are substantially
identical to the 29,000,000 Limited Partner Units, but they are not listed on
the New York Stock Exchange. The Class B Units will be convertible into Limited
Partner Units upon approval by the Limited Partner Unitholders. It is the
Company's intention to seek approval for conversion, however, if conversion is
not approved before March 2000, the holder of the Class B Units will have the
right to sell them to the Partnership at 95.5% of the market price of the
Limited Partner Units at the time of sale. Collectively, the Limited Partner
Units and Class B Units are referred to as "Units."
REFINED PRODUCTS AND LPGS TRANSPORTATION
Operations
The operations of the refined products and LPGs transportation segment are
conducted through the Products OLP. The Products OLP 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.
The Products OLP is one of the largest pipeline common carriers of refined
petroleum products and LPGs in the United States. The Products OLP 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
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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 Products OLP
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 Products OLP'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.
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,
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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 Business Sector 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 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,
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1998 1997 1996
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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
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Subtotal.......................................... 130.5 120.0 115.3
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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
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Subtotal.......................................... 32.0 42.0 41.6
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Mont Belvieu Operations:
LPGs...................................................... 25.1 27.8 22.5
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Total Product Deliveries.......................... 187.6 189.8 179.4
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(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.
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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
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Subtotal.......................................... 130.5 120.0 115.3
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LPGs Mainline Transportation:
Propane................................................... 25.5 34.7 35.2
Butanes................................................... 6.5 7.3 6.4
----- ----- -----
Subtotal.......................................... 32.0 42.0 41.6
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Mont Belvieu Operations:
LPGs...................................................... 25.1 27.8 22.5
----- ----- -----
Total Product Deliveries.......................... 187.6 189.8 179.4
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(1) Primarily diesel fuel, heating oil and other middle distillates.
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 Products OLP'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
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unloading and truck loading facilities. Although the terminal is operated by the
Products OLP, 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 Products OLP has approximately 33 million barrels of LPGs storage
capacity, including storage capacity leased to outside parties, at the Mont
Belvieu complex. The Products OLP'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 Products OLP 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.
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 Pipeline System 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 Products OLP's revenues. During 1997 and 1996, no
single customer accounted for greater than 10% of the Products OLP'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.
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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 Products OLP 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.
CRUDE OIL AND NGLS TRANSPORTATION AND MARKETING
Operations
The Crude Oil OLP, through its wholly owned subsidiary TEPPCO Crude Oil,
LLC ("TCO"), gathers, stores, transports and markets crude oil, NGLs and lube
oils, principally in Oklahoma and Texas. This segment was added to the
Partnership effective November 1, 1998 upon TCO's acquisition of the assets of
DETTCO from Duke Energy.
The Crude Oil OLP generally purchases crude oil at prevailing prices from
producers at the wellhead, aggregates the crude oil into its pipeline system
from its gathering lines and its trucking fleet, and transports the crude oil
for sale to or exchange with customers. The Partnership's margins from its
gathering, transportation and marketing operations are generated by the
difference between the price of crude oil at the point of purchase and the price
of crude oil at the point of sale, minus the associated costs of aggregation and
transportation.
Generally, as the Crude Oil OLP purchases crude oil, it simultaneously
establishes a margin by selling crude oil for physical delivery to third party
users or by entering into a future delivery obligation with respect to futures
contracts on the New York Mercantile Exchange. The Partnership seeks to maintain
a balanced position until it makes physical delivery of the crude oil, thereby
minimizing or eliminating exposure to price fluctuations occurring after the
initial purchase. However, certain basis risks (the risk that price
relationships between delivery points, classes of products or delivery periods
will change) cannot be completely hedged or eliminated. It is the Partnership's
policy not to acquire crude oil, futures contracts or other derivative products
for the purpose of speculating on price changes.
Properties
The Crude Oil OLP is based in Oklahoma City. It operates crude oil
pipelines principally in Oklahoma and Texas, and two trunkline NGL pipelines in
South Texas. It also distributes lube oil to industrial and commercial accounts.
The Crude Oil OLP's crude oil pipelines include two major systems and various
smaller systems. The Red River System, located on the Texas-Oklahoma border, is
the larger system, with 960 miles of pipeline and 750,000 barrels of storage.
The majority of this pipeline's crude oil is delivered to Cushing, Oklahoma via
connecting pipelines or to two local refineries. The South Texas System, located
west of Houston, consists of 550 miles of pipeline and 550,000 barrels of
storage. The majority of the crude oil on this system is delivered on a tariff
basis to the Houston refining complex. Other crude oil assets, located primarily
in Texas and Louisiana, consist of 310 miles of pipeline and 240,000 barrels of
storage. The NGL pipelines are
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located along the Texas Gulf Coast. The Dean NGL Pipeline consists of 338 miles
of pipeline originating in South Texas and terminating at Mont Belvieu, Texas,
and has a capacity of 20,000 barrels per day. The Dean NGL Pipeline is currently
supported by a 17,000 barrel per day take-or-pay commitment through 2002. The
Wilcox NGL Pipeline is 90 miles long, has a capacity of 5,000 barrels per day
and currently transports NGLs for DEFS from two of their processing plants. The
Wilcox NGL Pipeline is currently supported by demand fees that are paid by DEFS
through 2005. Through its wholly owned subsidiary Lubrication Services, LLC
("LSI"), the Crude Oil OLP distributes lube oils to pipeline operators,
gatherers and processing industry participants. LSI's distribution networks are
located in Colorado, Oklahoma, Southwest Kansas, East Texas, and Northwest
Louisiana.
Customers
The Crude Oil OLP purchases crude oil primarily from major integrated oil
companies and independent oil producers. Crude oil sales are primarily to major
integrated oil companies and independent refiners. The loss of any single
customer would not have a material adverse effect on the consolidated financial
position, results of operations and liquidity of the Partnership.
Competition
The Crude Oil OLP's most significant competitors in its pipeline operations
are primarily common carrier and proprietary pipelines owned and operated by
major oil companies, large independent pipeline companies and other companies in
the areas where its pipeline systems deliver crude oil and NGLs. Competition
among common carrier pipelines is based primarily on posted tariffs, quality of
customer service, knowledge of products and markets, and proximity to refineries
and connecting pipelines. The crude oil gathering and marketing business is
characterized by thin margins and intense competition for supplies of lease
crude oil. A decline in domestic crude oil production has intensified
competition among gatherers and marketers. Within the past few years, the number
of companies involved in the gathering of crude oil in the United States has
decreased as a result of business consolidations.
Credit
As crude oil or lube oils are marketed, the Partnership must determine the
amount, if any, of credit to be extended to any given customer. Due to the
nature of individual sales transactions, risk of non-payment and non-performance
by customers is a major consideration in the Crude Oil OLP's business. The Crude
Oil OLP manages its exposure to credit risk through credit analysis, credit
approvals, credit limits and monitoring procedures. The Crude Oil OLP utilizes
letters of credit, prepayments and guarantees for certain of its receivables.
The Crude Oil OLP's credit standing is a major consideration for parties
with whom the Crude Oil OLP does business. In connection with TCO's acquisition
of DETTCO, Duke Energy agreed to provide up to $100 million of guarantee credit
to the Crude Oil OLP through November 2001.
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 $23.4 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
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operations of the Products OLP. Capital expenditures related to the Crude Oil
OLP totaled $0.7 million for the period from November 1, 1998 through December
31, 1998.
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 $47 million. Approximately $20 million is expected to be
used for the Products OLP and $27 million is expected to be used for the Crude
Oil OLP. Substantially all expenditures related to the Products OLP are expected
to be used for life-cycle replacements and to upgrade current facilities.
Approximately $22 million of planned expenditures of the Crude Oil OLP are
expected to be used in revenue-generating and cost-reduction projects, with the
remainder to be used to maintain existing operations. 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 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
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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.
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,
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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 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
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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 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.
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EMPLOYEES
The Partnership does not have any employees, officers or directors. The
General Partner is responsible for the management of the Partnership and
Operating Partnerships. As of December 31, 1998, the General Partner had 740
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 UNITS AND RELATED UNITHOLDER MATTERS
On July 21, 1998, the Partnership announced a two-for-one split of the
Partnership's outstanding Limited Partner Units. The Limited Partner Unit split
entitled Unitholders of record at the close of business on August 10, 1998 to
receive one additional Limited Partner Unit for each Limited Partner Unit held.
All references to the number of Units and per Unit amounts have been restated to
reflect the two-for-one split for all periods presented.
The Limited Partner Units of the Partnership are listed and traded on the
New York Stock Exchange under the symbol TPP. The high and low trading prices of
the Limited Partner Units in 1998 and 1997, respectively, as reported in The
Wall Street Journal, were as follows:
1998 1997
------------------- -------------------
QUARTER HIGH LOW HIGH LOW
- ------- -------- -------- -------- --------
First...................................... $30.3750 $25.0000 $22.0625 $20.1250
Second..................................... 30.6875 25.5000 22.9063 19.8125
Third...................................... 29.4375 25.5000 26.5625 22.4375
Fourth..................................... 30.5625 23.2500 28.2500 25.0313
Based on the information received from its transfer agent and from
brokers/nominees, the Company estimates the number of beneficial Unitholders of
Limited Partner Units of the Partnership as of March 1, 1999 to be approximately
21,500.
The quarterly cash distributions applicable to 1997 and 1998 were as
follows:
AMOUNT
RECORD DATE PAYMENT DATE PER UNIT
- ----------- ------------ --------
April 30, 1997....................... May 9, 1997.......................... $0.375
July 31, 1997........................ August 8, 1997....................... 0.400
October 31, 1997..................... November 7, 1997..................... 0.400
January 30, 1998..................... February 6, 1998..................... 0.425
April 30, 1998....................... May 8, 1998.......................... 0.425
July 31, 1998........................ August 7, 1998....................... 0.450
October 30, 1998..................... November 6, 1998..................... 0.450
January 29, 1999..................... February 5, 1999..................... 0.450
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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 publicly traded master limited partnership that is not
subject to federal income tax. Instead, Unitholders are required to report their
allocable share of the Partnership's income, gain, loss, deduction and credit,
regardless of whether the Partnership makes distributions.
Distributions of cash by the Partnership to a Unitholder will not result in
taxable gain or income except to the extent the aggregate amount distributed
exceeds the tax basis of the Units held by the Unitholder.
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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(1) 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS AND OPERATING DATA)
INCOME STATEMENT DATA:
Operating revenues:
Sales of crude oil and petroleum
products.......................... $214,463 $ -- $ -- $ -- $ --
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
Transportation -- crude oil and
NGLs.............................. 3,392 -- -- -- --
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....... 429,638 222,093 216,025 203,716 197,302
Purchases of crude oil and petroleum
products............................ 212,371 -- -- -- --
Operating expenses..................... 110,363 106,771 105,182 103,938 94,337
Depreciation and amortization.......... 26,938 23,772 23,409 23,286 23,063
-------- -------- -------- -------- --------
Operating income....................... 79,966 91,550 87,434 76,492 79,902
Interest expense -- net................ (28,989) (32,229) (33,534) (34,987) (36,076)
Other income -- net.................... 2,364 1,979 4,748 5,212 2,714
-------- -------- -------- -------- --------
Income before extraordinary item....... 53,341 61,300 58,648 46,717 46,540
Extraordinary loss on debt
extinguishment, net of minority
interest(2)......................... (72,767) -- -- -- --
-------- -------- -------- -------- --------
Net income (loss)...................... $(19,426) $ 61,300 $ 58,648 $ 46,717 $ 46,540
======== ======== ======== ======== ========
Basic and diluted income per Unit:(3)
Before extraordinary item........... $ 1.61 $ 1.95 $ 1.89 $ 1.54 $ 1.57
Extraordinary loss on debt
extinguishment(2)................. (2.21) -- -- -- --
-------- -------- -------- -------- --------
Net income (loss) per Unit.......... $ (0.60) $ 1.95 $ 1.89 $ 1.54 $ 1.57
======== ======== ======== ======== ========
BALANCE SHEET DATA (AT PERIOD END):
Property, plant and equipment -- net... $671,611 $567,681 $561,068 $533,470 $540,577
Total assets........................... 914,969 673,909 671,241 669,915 665,331
Long-term debt (net of current
maturities).......................... 427,722 309,512 326,512 339,512 349,512
Class B Units.......................... 105,036 -- -- -- --
Partners' capital...................... 227,186 302,967 290,311 276,381 269,599
CASH FLOW DATA:
Net cash from operations............... $ 93,215 $ 83,604 $ 86,121 $ 78,456 $ 70,082
Capital expenditures................... (23,432) (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) Data reflects the operations of the fractionator assets effective March 31,
1998, and the operations of the crude oil and NGL assets purchased effective
November 1, 1998.
(2) Extraordinary item reflects the loss related to the early extinguishment of
the First Mortgage Notes on January 27, 1998.
(3) Per Unit amounts for all periods have been adjusted to reflect the
two-for-one split on August 10, 1998. Per Unit calculation includes
3,916,547 Class B Units issued for the acquisition of the crude oil and NGL
assets, effective November 1, 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.
Through its ownership of the Products OLP and the Crude Oil OLP, the
Partnership operates in two industry segments -- refined products and LPGs
transportation; and crude oil and NGLs transportation and marketing. The
Partnership's reportable segments offer different products and services and are
managed separately because each requires different business strategies.
The Products OLP segment 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 Products OLP.
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.
The Crude Oil OLP segment is involved in the transportation and marketing
of crude oil and NGLs. Revenues are earned from the gathering, storage,
transportation and marketing of crude oil, NGLs and lube oils principally in
Oklahoma and Texas. Operations of this segment are included from November 1,
1998, upon the acquisition from Duke Energy.
RESULTS OF OPERATIONS
Summarized below is financial data by business segment (in thousands):
YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
Operating revenues:
Refined Products and LPGs Transportation.................. $211,783 $222,093 $216,025
Crude Oil and NGLs Transportation and Marketing........... 217,855 -- --
-------- -------- --------
Total operating revenues.......................... 429,638 222,093 216,025
-------- -------- --------
Operating income:
Refined Products and LPGs Transportation.................. 78,641 91,550 87,434
Crude Oil and NGLs Transportation and Marketing........... 1,325 -- --
-------- -------- --------
Total operating income............................ 79,966 91,550 87,434
-------- -------- --------
Income before extraordinary item:
Refined Products and LPGs Transportation.................. 52,002 61,300 58,648
Crude Oil and NGLs Transportation and Marketing........... 1,339 -- --
-------- -------- --------
Total income before extraordinary item............ $ 53,341 $ 61,300 $ 58,648
======== ======== ========
For the year ended December 31, 1998, the Partnership reported a net loss
of $19.4 million. The net loss included an extraordinary loss for early
extinguishment of debt of $72.8 million, net of $0.7 million allocated to
minority interest. Excluding the extraordinary loss, net income for the year
would have been $53.3 million, compared with net income of $61.3 million for
1997. The $8.0 million decrease in income before loss on debt
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18
extinguishment resulted primarily from a $11.6 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 $61.3
million, compared with net income of $58.6 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 by business segment.
REFINED PRODUCTS AND LPGS TRANSPORTATION SEGMENT
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%)
======== ======== ======== ==== ====
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
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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 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.
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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.
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 through-put
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.
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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.
CRUDE OIL AND NGLS TRANSPORTATION AND MARKETING SEGMENT
Margin and volume information for the two months ended December 31, 1998 is
presented below:
Margins (dollars in thousands):
Crude oil transportation............................... $ 2,787 51%
Crude oil marketing.................................... 1,253 23%
NGL transportation..................................... 1,062 19%
LSI.................................................... 382 7%
---------- ----
Total margin................................... $ 5,484 100%
========== ====
Barrels per day:
Crude oil transportation............................... 90,963
Crude oil marketing.................................... 278,176
NGL transportation..................................... 11,919
LSI volume (total gallons):.............................. 1,140,000
Margin per barrel:
Crude oil transportation............................... $0.504
Crude oil marketing.................................... $0.071
NGL transportation..................................... $1.515
LSI margin (per gallon):................................. $0.335
Two Months Ended December 31, 1998
The crude oil and NGLs transportation and marketing segment was added to
the Partnership's operations with the acquisition of the DETTCO assets effective
November 1, 1998. The acquisition was accounted for as a purchase for accounting
purposes. Accordingly, only operations from November 1, 1998 have been included
in the Partnership's financial statements. Comparative pro forma financial
information has not been provided as the acquisition was not considered a
significant purchase business combination pursuant to Regulation S-X. Net income
contributed by the crude oil transportation and marketing segment totaled $1.3
million for the two months ended December 31, 1998.
Margin is a more meaningful measure of financial performance than operating
revenues and operating expenses due to the significant fluctuations in revenues
and expense caused by the level of marketing activity. Margin is calculated as
revenues generated from crude oil and lube oil sales and crude oil and NGLs
transportation less the cost of crude oil and lube oil purchases. During the two
months ended December 31, 1998, crude oil transportation and NGL transportation
contributed 51% and 19% of the margin, respectively, while crude oil marketing
operations accounted for 23% of the margin. Operations of LSI contributed $0.4
million, or 7%, of the margin for the two month period ended December 31, 1998.
Operating, general and administrative expenses of the crude oil and NGLs
transportation and marketing segment totaled $3.2 million, or 58% of the margin.
Depreciation and amortization expenses and taxes -- other than income totaled
$1.0 million, or 18% of the margin.
FINANCIAL CONDITION AND LIQUIDITY
Net cash from operations for the year ended December 31, 1998, totaled
$93.2 million, comprised primarily of $80.3 million of income before
extraordinary loss on early extinguishment of debt and charges for depreciation
and amortization, and $12.9 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 $85.1 million of income before charges
for depreciation and amortization, partially offset by $1.5 million used for
working capital changes. The $12.9 million of cash provided by working capital
changes resulted primarily
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from crude oil marketing activity during November and December 1998. Net cash
from operations for the year ended December 31, 1996 totaled $86.1 million,
which was comprised of $82.1 million of income before charges for depreciation
and amortization and $4.0 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, respectively. Cash balances related to the investment of cash and
proceeds from the investment of cash were $57.2 million, $56.1 million and $65.0
million for the years ended December 31, 1998, 1997 and 1996, respectively.
Capital expenditures totaled $23.4 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 $21.1 million, $18.9 million and $12.1 million for each of
the years ended 1998, 1997 and 1996, respectively.
On July 21, 1998, the Partnership announced a two-for-one split of the
Partnership's outstanding Limited Partner Units. The Limited Partner Unit split
entitled Unitholders of record at the close of business on August 10, 1998 to
receive one additional Limited Partner Unit for each Limited Partner Unit held.
All per Limited Partner Unit amounts have been adjusted to reflect the
two-for-one Unit split.
The Partnership paid cash distributions of $56.8 million ($1.75 per Limited
Partner Unit), $49.0 million ($1.55 per Limited Partner Unit) and $45.2 million
($1.45 per Limited Partner Unit) for each of the years ended December 31, 1998,
1997 and 1996, respectively. On January 15, 1999, the Partnership declared a
cash distribution of $0.45 per Limited Partner Unit and Class B Unit for the
quarter ended December 31, 1998. The Class B Unit distribution was prorated for
the 61 day period from issuance on November 1, 1998. The distribution of $16.0
million was paid on February 5, 1999, to Unitholders of record on January 29,
1999.
On January 27, 1998, the Products OLP 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 Products OLP, 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 (including $0.7 million allocated to
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minority interest), 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 Products OLP and
will rank on a parity with all other unsecured and unsubordinated indebtedness
of the Products OLP. 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 Products OLP is guarantor
on the loan.
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 $5.0 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.
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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
Products OLP has completed Phase I; Phase II is nearing completion; and Phase
III is ongoing. The Crude Oil OLP is nearing completion of Phase I. 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, 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
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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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The Partnership may be exposed to market risk through changes in commodity
prices and interest rates as discussed below. The Partnership has no foreign
exchange risks.
The Partnership mitigates exposure to commodity price fluctuations by
maintaining a balanced position between crude oil purchases and sales. As a
hedging strategy to manage crude oil price fluctuations, the Partnership
occasionally enters into futures contracts on the New York Mercantile Exchange,
and makes limited use of other derivative instruments. It is the Partnership's
policy not to acquire crude oil, futures contracts or other derivative products
for the purpose of speculating on price changes. Market risks associated with
commodity derivatives were not material at December 31, 1998.
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.
On November 30, 1998, the Crude Oil OLP entered into a $30 million
Revolving Credit Agreement ("Revolver") with Duke Capital Corporation ("Duke
Capital"), a wholly owned subsidiary of Duke Energy. The Revolver has a
six-month term and bears interest at the one month LIBOR rate plus 0.50%. At
December 31, 1998, there was no outstanding balance under the Revolver.
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.
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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.
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.
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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.
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
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 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 $2,000 per annum.
Messrs. Thacker, Fowler, Mogg and Osborne and Ms. Shaw were not compensated
for their services as directors, and it is not anticipated that any compensation
for service as a director will be paid in the future to directors who are
full-time employees of Duke Energy, the General Partner or any of their
affiliates.
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The following table reflects cash compensation paid or accrued by the
General Partner for the years ended December 31, 1998, 1997 and 1996, with
respect to its Chief Executive Officer and the executive officers (collectively,
the "Named Executive Officers").
SUMMARY COMPENSATION TABLE
LONG TERM COMPENSATION
-----------------------------
AWARDS PAYOUTS
ANNUAL COMPENSATION OTHER ------------- -------------
-------------------------- ANNUAL SECURITIES LTICP AND ALL OTHER
NAME AND BONUS COMPENSATION UNDERLYING 1994 LTIP COMPENSATION
PRINCIPAL POSITION YEAR SALARY($) ($)(1) ($)(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, 1997 145,750 52,000 29,985 -- 25,444 12,960
Chief Financial Officer 1996 142,958 54,800 35,691 -- 16,094 12,780
and 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 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.
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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 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 as of the date of redemption. In the event of a
change of control, all phantom units 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 Units together with a stipulated
number of Performance Units. Each Performance Unit
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30
creates a credit to a participant's Performance Unit account when earnings
exceed a threshold, which was $1.00, $1.25 and $1.875 per Limited Partner Unit
for the awards made in 1994, 1995, and 1997, respectively. No Performance Unit
awards were granted during 1996 and 1998. When earnings for a calendar year
(exclusive of certain special items) exceed the threshold, the excess amount is
credited to the participant's Performance Unit account. The balance in the
account may be used to exercise Unit options granted in connection with the
Performance Units or may be withdrawn two years after the underlying options
expire, usually 10 years from the date of grant. Under the agreement for such
Unit options, the options become exercisable in equal installments over periods
of one, two, and three years from the date of the grant. Options may also be
exercised by normal means once vesting requirements are met.
The following table shows all grants of unit options to the Named Executive
Officers in 1998. No Stock appreciation rights (SARs) were granted to any Named
Executive Officer in 1998 nor were the exercise prices on unit options
previously awarded amended or adjusted.
OPTION/SAR GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS
----------------------------------------------------------------------
GRANT DATE
NUMBER OF PERCENT OF VALUE
SECURITIES TOTAL OPTIONS/ ----------
UNDERLYING SARS GRANTED EXERCISE OR GRANT DATE
OPTIONS/SARS TO EMPLOYEES BASE PRICE EXPIRATION PRESENT
GRANTED(1)(#) IN FISCAL YEAR ($/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 may
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.
The following table provides information concerning the unit options
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 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 for the benefit of all
Unitholders.
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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 Units. 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 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
AGE AND SERVICE CREDIT PERCENTAGE
- --------------- -----------------
34 or less.................................................. 4%
35 to 49.................................................... 5%
50 to 64.................................................... 6%
65 or more.................................................. 7%
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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
(a) Security Ownership of Certain Beneficial Owners
As of March 1, 1999, Duke Energy, through its ownership of the Company and
other subsidiaries, owns 2,500,000 Limited Partner Units, representing 8.62% of
the Limited Partner Units outstanding; and 3,916,547 Class B Units, representing
100% of the Class B Units, or 19.49% of the two classes of Units combined.
(b) Security Ownership of Management
The following table sets forth certain information, as of March 1, 1999,
concerning the beneficial ownership of Limited Partner Units by each director
and Named Executive Officer of the General Partner and by all directors and
officers of the General Partner as a group. Such information is based on data
furnished by the persons named. Based on information furnished to the General
Partner by such persons, no director or officer of the General Partner owned
beneficially, as of March 1, 1999, more than 1% of the Limited Partner Units
outstanding at that date.
NUMBER OF
NAME UNITS(1)
- ---- ---------
Milton Carroll.............................................. 1,000
Carl D. Clay(2)............................................. 3,200
Derrill Cody................................................ 13,000
John P. DesBarres........................................... 20,000
Fred J. Fowler.............................................. 400
Jim W. Mogg................................................. 200
Richard J. Osborne.......................................... 1,000
Ruth G. Shaw................................................ 900
William L. Thacker.......................................... 27,142
Charles H. Leonard.......................................... 3,406
James C. Ruth............................................... 2,974
O. Horton Cunningham(3)..................................... 6,888
David L. Langley............................................ 20,000
Thomas R. Harper(4)......................................... 4,566
Ernest P. Hagan............................................. 12,000
All directors and officers (consisting of 20 people,
including those named above).............................. 116,876
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- ---------------
(1) Unless otherwise indicated, the persons named above have sole voting and
investment power over the Units reported.
(2) Includes 1,800 Units in wife's name.
(3) Includes 200 Units in daughter's name.
(4) Includes 2,150 Units in wife's name.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Partnership is managed and controlled by the General Partner pursuant
to the Partnership Agreements. Under the Partnership Agreements, the General
Partner is reimbursed for all direct and indirect expenses it incurs or payments
it makes on behalf of the Partnership. These expenses include salaries, fees and
other compensation and benefit expenses of employees, officers and directors,
insurance, other administrative or overhead expenses and all other expenses
necessary or appropriate to conduct the Partnership's business. The costs
allocated to the Partnership by the General Partner for administrative services
and overhead totaled $2.7 million in 1998.
The Partnership Agreements provide for incentive distributions payable to
the General Partner out of the Partnership's Available Cash (as defined in the
Partnership Agreements) in the event quarterly distributions to Unitholders
exceed certain specified targets. In general, subject to certain limitations, if
a quarterly distribution exceeds a target of $0.275 per Limited Partner Unit,
the General Partner will receive incentive distributions equal to (i) 15% of
that portion of the distribution per Limited Partner Unit which exceeds the
minimum quarterly distribution amount of $0.275 but is not more than $0.325,
plus (ii) 25% of that portion of the quarterly distribution per Limited Partner
Unit which exceeds $0.325 but is not more than $0.45, plus (iii) 50% of that
portion of the quarterly distribution per Limited Partner Unit which exceeds
$0.45. During 1998, incentive distributions paid to the General Partner totaled
$5.0 million.
In connection with the formation of the Partnership in 1990, the Company
received 2,500,000 Deferred Partnership Interests ("DPIs"). Effective April 1,
1994, the DPIs began participating in distributions of cash and allocations of
profit and loss. As of December 31, 1998, 94% of the DPIs have been converted
into an equal number of Limited Partner Units, and the balance of such DPIs may
be converted immediately prior to the sale of the DPIs by the Company. Pursuant
to its Partnership Agreement, the Partnership has registered the resale of such
Limited Partner Units with the Securities and Exchange Commission. Such Limited
Partner Units may be sold from time to time on the New York Stock Exchange or
otherwise at prices and terms then prevailing or in negotiated transactions. As
of December 31, 1998, no such Limited Partner Units had been sold by the
Company.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Report:
(1) Financial Statements: See Index to Financial Statements on page
F-1 of this report for financial statements filed as part of this report.
(2) Financial Statement Schedules: None
(3) Exhibits.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.1 -- Certificate of Limited Partnership of the Partnership
(Filed as Exhibit 3.2 to the Registration Statement of
TEPPCO Partners, L.P. (Commission File No. 33-32203) and
incorporated herein by reference).
3.2 -- Certificate of Formation of TEPPCO Colorado, LLC (Filed
as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended March
31, 1998 and incorporated herein by reference).
*3.3 -- Second Amended and Restated Agreement of Limited
Partnership of TEPPCO Partners, L.P., dated November 30,
1998.
3.4 -- Amended and Restated Agreement of Limited Partnership of
TE Products Pipeline Company, Limited Partnership,
effective July 21, 1998 (Filed as Exhibit 3.2 to Form 8-K
of TEPPCO Partners, L.P. (Commission File No. 1-10403)
dated July 21, 1998 and incorporated herein by
reference).
*3.5 -- Agreement of Limited Partnership of TCTM, L.P., dated
November 30, 1998.
4.1 -- Form of Certificate representing Limited Partner Units
(Filed as Exhibit 4.1 to the Registration Statement of
TEPPCO Partners, L.P. (Commission File No. 33-32203) and
incorporated herein by reference).
4.2 -- Form of Indenture between TE Products Pipeline Company,
Limited Partnership and The Bank of New York, as Trustee,
dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE
Products Pipeline Company, Limited Partnership's
Registration Statement on Form S-3 (Commission File No.
333-38473) and incorporated herein by reference).
*4.3 -- Form of Certificate representing Class B Units.
10.1 -- Assignment and Assumption Agreement, dated March 24,
1988, between Texas Eastern Transmission Corporation and
the Company (Filed as Exhibit 10.8 to the Registration
Statement of TEPPCO Partners, L.P. (Commission File No.
33-32203) and incorporated herein by reference).
10.2 -- Texas Eastern Products Pipeline Company 1997 Employee
Incentive Compensation Plan executed on July 14, 1997
(Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
September 30, 1997 and incorporated herein by reference).
10.3 -- Agreement Regarding Environmental Indemnities and Certain
Assets (Filed as Exhibit 10.5 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year
ended December 31, 1990 and incorporated herein by
reference).
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EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.4 -- Texas Eastern Products Pipeline Company Management
Incentive Compensation Plan executed on January 30, 1992
(Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
March 31, 1992 and incorporated herein by reference).
10.5 -- Texas Eastern Products Pipeline Company Long-Term
Incentive Compensation Plan executed on October 31, 1990
(Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the year ended
December 31, 1990 and incorporated herein by reference).
10.6 -- Form of Amendment to Texas Eastern Products Pipeline
Company Long-Term Incentive Compensation Plan (Filed as
Exhibit 10.7 to the Partnership's Form 10-K (Commission
File No. 1-10403) for the year ended December 31, 1995
and incorporated herein by reference).
10.7 -- Employees' Savings Plan of Panhandle Eastern Corporation
and Participating Affiliates (Effective January 1, 1991)
(Filed as Exhibit 10.10 to the Partnership's Form 10-K
(Commission File No. 1-10403) for the year ended December
31, 1990 and incorporated herein by reference).
10.8 -- Retirement Income Plan of Panhandle Eastern Corporation
and Participating Affiliates (Effective January 1, 1991)
(Filed as Exhibit 10.11 to Form 10-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the year ended
December 31, 1990 and incorporated herein by reference).
10.9 -- Panhandle Eastern Corporation Key Executive Retirement
Benefit Equalization Plan, adopted December 20, 1993;
effective January 1, 1994 (Filed as Exhibit 10.12 to Form
10-K of Panhandle Eastern Corporation (Commission File
No. 1-8157) for the year ended December 31, 1993 and
incorporated herein by reference).
10.10 -- Employment Agreement with William L. Thacker, Jr. (Filed
as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended
September 30, 1992 and incorporated herein by reference).
10.11 -- Texas Eastern Products Pipeline Company 1994 Long Term
Incentive Plan executed on March 8, 1994 (Filed as
Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended March
31, 1994 and incorporated herein by reference).
10.12 -- Panhandle Eastern Corporation Key Executive Deferred
Compensation Plan established effective January 1, 1994
(Filed as Exhibit 10.2 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
March 31, 1994 and incorporated herein by reference).
10.13 -- Asset Purchase Agreement between Duke Energy Field
Services, Inc. and TEPPCO Colorado, LLC, dated March 31,
1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the
quarter ended March 31, 1998 and incorporated herein by
reference).
10.14 -- Credit Agreement between TEPPCO Colorado, LLC, SunTrust
Bank, Atlanta, and Certain Lenders, dated April 21, 1998
(Filed as Exhibit 10.15 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
March 31, 1998 and incorporated herein by reference).
10.15 -- First Amendment to Credit Agreement between TEPPCO
Colorado, LLC, SunTrust Bank, Atlanta, and Certain
Lenders, effective June 29, 1998 (Filed as Exhibit 10.15
to Form 10-Q of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the quarter ended June 30, 1998 and
incorporated herein by reference).
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EXHIBIT
NUMBER DESCRIPTION
------- -----------
*10.16 -- Contribution Agreement between Duke Energy Transport and
Trading Company and TEPPCO Partners, L.P., dated October
15, 1998.
*10.17 -- Guaranty Agreement by Duke Energy Natural Gas Corporation
for the benefit of TEPPCO Partners, L.P., dated November
30, 1998, effective November 1, 1998.
*10.18 -- Revolving Credit Agreement between TCTM, L.P. as Borrower
and Duke Capital Corporation as Lender, dated November
30, 1998.
*10.19 -- Letter Agreement regarding Payment Guarantees of Certain
Obligations of TCTM, L.P. between Duke Capital
Corporation and TCTM, L.P., dated November 30, 1998.
*10.20 -- Form of Employment Agreement between the Company and O.
Horton Cunningham, Ernest P. Hagan, Thomas R. Harper,
David L. Langley, Charles H. Leonard and James C. Ruth,
dated December 1, 1998.
22.1 -- Subsidiaries of the Partnership (Filed as Exhibit 22.1 to
the Registration Statement of TEPPCO Partners, L.P.
(Commission File No. 33-32203) and incorporated herein by
reference).
*23 -- Consent of KPMG LLP.
*24 -- Powers of Attorney.
*27 -- Financial Data Schedule as of and for the year ended
December 31, 1998.
- ---------------
* Filed herewith.
(b) Reports on Form 8-K filed during the quarter ended December 31, 1998:
Report dated November 30, 1998, on Form 8-K was filed on December 11,
1998, pursuant to Item 5. and Item 7. of such form.
34
37
SIGNATURES
TEPPCO Partners, L.P., pursuant to the requirements of Section 13 or 15(d)
of the Securities Exchange Act of 1934, has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
TEPPCO Partners, L.P.
------------------------------------
(Registrant)
(A Delaware Limited Partnership)
By: Texas Eastern Products Pipeline
Company as General Partner
By: /s/ CHARLES H. LEONARD
----------------------------------
Charles H. Leonard,
Senior Vice President, Chief
Financial
Officer and Treasurer
DATED: March 10, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ WILLIAM L. THACKER* Chairman of the Board, March 10, 1999
- ----------------------------------------------------- President and Chief
William L. Thacker Executive Officer of Texas
Eastern Products Pipeline
Company
/s/ CHARLES H. LEONARD Senior Vice President, Chief March 10, 1999
- ----------------------------------------------------- Financial Officer and
Charles H. Leonard Treasurer of Texas Eastern
Products Pipeline Company
(Principal Accounting and
Financial Officer)
/s/ FRED J. FOWLER* Vice Chairman of the Board of March 10, 1999
- ----------------------------------------------------- Texas Eastern Products
Fred J. Fowler Pipeline Company
/s/ MILTON CARROLL* Director of Texas Eastern March 10, 1999
- ----------------------------------------------------- Products Pipeline Company
Milton Carroll
/s/ CARL D. CLAY* Director of Texas Eastern March 10, 1999
- ----------------------------------------------------- Products Pipeline Company
Carl D. Clay
/s/ DERRILL CODY* Director of Texas Eastern March 10, 1999
- ----------------------------------------------------- Products Pipeline Company
Derrill Cody
/s/ JOHN P. DESBARRES* Director of Texas Eastern March 10, 1999
- ----------------------------------------------------- Products Pipeline Company
John P. DesBarres
35
38
SIGNATURE TITLE DATE
--------- ----- ----
/s/ JIM W. MOGG* Director of Texas Eastern March 10, 1999
- ----------------------------------------------------- Products Pipeline Company
Jim W. Mogg
/s/ RICHARD J. OSBORNE* Director of Texas Eastern March 10, 1999
- ----------------------------------------------------- Products Pipeline Company
Richard J. Osborne
/s/ RUTH G. SHAW* Director of Texas Eastern March 10, 1999
- ----------------------------------------------------- Products Pipeline Company
Ruth G. Shaw
* Signed on behalf of the Registrant and each of these persons:
By: /s/ CHARLES H. LEONARD
-------------------------------------------------
(Charles H. Leonard, Attorney-in-Fact)
36
39
CONSOLIDATED FINANCIAL STATEMENTS
OF TEPPCO PARTNERS, L.P.
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Independent Auditors' Report................................ F-2
Consolidated Balance Sheets as of December 31, 1998 and
1997...................................................... F-3
Consolidated Statements of Income for the years ended
December 31, 1998, 1997 and 1996.......................... F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996.......................... F-5
Consolidated Statements of Partners' Capital for the years
ended December 31, 1998, 1997 and 1996.................... F-6
Notes to Consolidated Financial Statements.................. F-7
F-1
40
INDEPENDENT AUDITORS' REPORT
To the Partners of
TEPPCO Partners, L.P.:
We have audited the accompanying consolidated balance sheets of TEPPCO
Partners, L.P. as of December 31, 1998 and 1997, and the related consolidated
statements of income, partners' capital, and cash flows for each of the years in
the three-year period ended December 31, 1998. These consolidated financial
statements are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of TEPPCO
Partners, L.P. as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1998 in conformity with generally accepted accounting
principles.
KPMG LLP
Houston, Texas
January 15, 1999
F-2
41
TEPPCO PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
ASSETS
DECEMBER 31,
-------------------
1998 1997
-------- --------
Current assets:
Cash and cash equivalents................................. $ 47,423 $ 43,961
Short-term investments.................................... 3,269 2,105
Accounts receivable, trade................................ 113,541 19,826
Inventories............................................... 20,434 15,191
Other..................................................... 3,909 4,173
-------- --------
Total current assets.............................. 188,576 85,256
-------- --------
Property, plant and equipment, at cost (Net of accumulated
depreciation and amortization of $193,858 and $170,063)... 671,611 567,681
Investments................................................. 6,490 10,010
Intangible assets........................................... 36,842 --
Other assets................................................ 11,450 10,962
-------- --------
Total assets...................................... $914,969 $673,909
======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current maturities, First Mortgage Notes.................. $ -- $ 17,000
Accounts payable and accrued liabilities.................. 117,933 9,615
Accounts payable, general partner......................... 2,815 3,735
Accrued interest.......................................... 13,039 10,539
Other accrued taxes....................................... 6,739 6,246
Other..................................................... 7,699 6,740
-------- --------
Total current liabilities......................... 148,225 53,875
-------- --------
First Mortgage Notes........................................ -- 309,512
Senior Notes................................................ 389,722 --
Other long term debt........................................ 38,000 --
Other liabilities and deferred credits...................... 3,407 4,462
Minority interest........................................... 3,393 3,093
Redeemable Class B Units held by related party.............. 105,036 --
Partners' capital (deficit):
General partner's interest................................ (380) 5,760
Limited partners' interests............................... 227,566 297,207
-------- --------
Total partners' capital........................... 227,186 302,967
-------- --------
Commitments and contingencies
Total liabilities and partners' capital........... $914,969 $673,909
======== ========
See accompanying Notes to Consolidated Financial Statements.
F-3
42
TEPPCO PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
Operating revenues:
Sales of crude oil and petroleum products................. $214,463 $ -- $ --
Transportation -- Refined products........................ 119,854 107,304 98,641
Transportation -- LPGs.................................... 60,902 79,371 80,219
Transportation -- Crude oil and NGLs...................... 3,392 -- --
Mont Belvieu operations................................... 10,880 12,815 11,811
Other..................................................... 20,147 22,603 25,354
-------- -------- --------
Total operating revenues.......................... 429,638 222,093 216,025
-------- -------- --------
Costs and expenses:
Purchases of crude oil and petroleum products............. 212,371 -- --
Operating, general and administrative..................... 73,850 66,982 68,799
Operating fuel and power.................................. 27,131 30,151 27,742
Depreciation and amortization............................. 26,938 23,772 23,409
Taxes -- other than income taxes.......................... 9,382 9,638 8,641
-------- -------- --------
Total costs and expenses.......................... 349,672 130,543 128,591
-------- -------- --------
Operating income.................................. 79,966 91,550 87,434
Interest expense............................................ (29,784) (33,707) (34,922)
Interest capitalized........................................ 795 1,478 1,388
Other income -- net......................................... 2,908 2,604 5,346
-------- -------- --------
Income before minority interest and loss on debt
extinguishment.................................. 53,885 61,925 59,246
Minority interest........................................... (544) (625) (598)
-------- -------- --------
Income before loss on debt extinguishment......... 53,341 61,300 58,648
Extraordinary loss on debt extinguishment, net of minority
interest.................................................. (72,767) -- --
-------- -------- --------
Net income (loss)................................. $(19,426) $ 61,300 $ 58,648
======== ======== ========
Basic and diluted income (loss) per Limited Partner and
Class B Unit:
Income before extraordinary loss on debt extinguishment... $ 1.61 $ 1.95 $ 1.89
Extraordinary loss on debt extinguishment................. (2.21) -- --
-------- -------- --------
Net income (loss)......................................... $ (0.60) $ 1.95 $ 1.89
======== ======== ========
Weighted average Limited Partner and Class B Units
outstanding:.............................................. 29,655 29,000 29,000
See accompanying Notes to Consolidated Financial Statements.
F-4
43
TEPPCO PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
--------- -------- --------
Cash flows from operating activities:
Net income (loss)......................................... $ (19,426) $ 61,300 $ 58,648
Adjustments to reconcile net income to cash provided by
operating activities:
Depreciation and amortization.......................... 26,938 23,772 23,409
Extraordinary loss on early extinguishment of debt..... 72,767 -- --
Loss (gain) on sale of property, plant and equipment... (356) 467 --
Equity in loss of affiliate............................ 189 -- --
Decrease (increase) in accounts receivable............. (93,715) (1,500) 1,705
Decrease (increase) in inventories..................... 493 (2,180) 3,997
Decrease (increase) in other current assets............ 264 (802) (226)
Increase (decrease) in accounts payable and accrued
expenses............................................. 106,350 2,322 (3,478)
Other.................................................. (289) 225 2,066
--------- -------- --------
Net cash provided by operating activities......... 93,215 83,604 86,121
--------- -------- --------
Cash flows from investing activities:
Proceeds from cash investments............................ 3,105 25,040 18,584
Purchases of cash investments............................. (748) (6,180) (14,436)
Insurance proceeds related to damaged assets.............. -- 1,046 --
Purchase of fractionator assets and related intangible
assets................................................. (40,000) -- --
Purchase of crude oil and NGL systems..................... (1,989) -- --
Restricted investments designated for property
additions.............................................. -- -- 10,553
Proceeds from the sale of property, plant and equipment... 525 1,377 --
Capital expenditures...................................... (23,432) (32,931) (51,264)
--------- -------- --------
Net cash used in investing activities............. (62,539) (11,648) (36,563)
--------- -------- --------
Cash flows from financing activities:
Principal payment, First Mortgage Notes................... (326,512) (13,000) (10,000)
Prepayment premium, First Mortgage Notes.................. (70,093) -- --
Issuance of Senior Notes.................................. 389,694 -- --
Debt issuance cost, Senior Notes.......................... (3,651) -- --
Issuance of term loan..................................... 38,000 -- --
General partner's contributions........................... 2,122 -- --
Distributions............................................. (56,774) (49,042) (45,174)
--------- -------- --------
Net cash used in financing activities............. (27,214) (62,042) (55,174)
--------- -------- --------
Net increase (decrease) in cash and cash equivalents........ 3,462 9,914 (5,616)
Cash and cash equivalents at beginning of period............ 43,961 34,047 39,663
--------- -------- --------
Cash and cash equivalents at end of period.................. $ 47,423 $ 43,961 $ 34,047
========= ======== ========
Non cash investing and financing activities:
Fair value of crude oil and NGL systems purchased......... $ 109,000 -- --
Liabilities assumed....................................... (5,000) -- --
Issuance of Class B Units................................. 104,000 -- --
Supplemental disclosure of cash flows:
Interest paid during the year (net of capitalized
interest).............................................. $ 26,179 $ 32,084 $ 33,278
See accompanying Notes to Consolidated Financial Statements.
F-5
44
TEPPCO PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(IN THOUSANDS)
GENERAL LIMITED
PARTNER'S PARTNERS'
INTEREST INTERESTS TOTAL
--------- --------- --------
Partners' capital at December 31, 1995...................... $ 3,561 $272,820 $276,381
1996 net income allocation................................ 3,723 54,925 58,648
1996 cash distributions................................... (2,668) (42,050) (44,718)
------- -------- --------
Partners' capital at December 31, 1996...................... 4,616 285,695 290,311
1997 net income allocation................................ 4,740 56,560 61,300
1997 cash distributions................................... (3,596) (44,951) (48,547)
Other..................................................... -- (97) (97)
------- -------- --------
Partners' capital at December 31, 1997...................... 5,760 297,207 302,967
Capital contributions..................................... 1,051 -- 1,051
1998 net loss allocation.................................. (1,740) (18,722) (20,462)
1998 cash distributions................................... (5,451) (50,750) (56,201)
Other..................................................... -- (169) (169)
------- -------- --------
Partners' capital (deficit) at December 31, 1998............ $ (380) $227,566 $227,186
======= ======== ========
See accompanying Notes to Consolidated Financial Statements.
F-6
45
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. PARTNERSHIP ORGANIZATION
TEPPCO Partners, L.P. (the "Partnership"), a Delaware limited partnership,
was formed in March 1990. The Partnership operates through TE Products Pipeline
Company, Limited Partnership (the "Products OLP") and TCTM, L.P. (the "Crude Oil
OLP"). Collectively the Products OLP and the Crude Oil OLP are referred to as
"the Operating Partnerships." The Partnership owns a 99% interest as the sole
limited partner interest in both the Products OLP and the Crude Oil OLP. Texas
Eastern Products Pipeline Company (the "Company" or "General Partner") owns a 1%
general partner interest in the Partnership and 1% general partner interest in
each Operating Partnership. The Company, as general partner, performs all
management and operating functions required for the Partnership pursuant to the
Agreements of Limited Partnership of TEPPCO Partners, L.P. and TE Products
Pipeline Company, Limited Partnership and TCTM, L.P. (the "Partnership
Agreements"). The general partner is reimbursed by the Partnership for all
reasonable direct and indirect expenses incurred in managing 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.
During 1990, the Partnership completed an initial public offering of
26,500,000 Units representing Limited Partner Interests ("Limited Partner
Units") at $10 per Unit. In connection with the formation of the Partnership,
the Company received 2,500,000 Deferred Participation Interests ("DPIs").
Effective April 1, 1994, the DPIs began participating in distributions of cash
and allocations of profit and loss. As of December 31, 1998, 94% of the DPIs
have been converted into an equal number of Limited Partner Units, and the
balance of such DPIs may be converted immediately prior to the sale of the DPIs
by the Company. Pursuant to its Partnership Agreement, the Partnership has
registered the resale of such Limited Partner Units with the Securities and
Exchange Commission. Such Limited Partner Units may be sold from time to time on
the New York Stock Exchange or otherwise at prices and terms then prevailing or
in negotiated transactions. As of December 31, 1998, no such Limited Partner
Units had been sold by the Company.
On July 21, 1998, the Partnership announced a two-for-one split of the
Partnership's outstanding Limited Partner Units. The Limited Partner Unit split
entitled Unitholders of record at the close of business on August 10, 1998 to
receive one additional Limited Partner Unit for each Limited Partner Unit held.
All references to the number of Units and per Unit amounts in the consolidated
financial statements and related notes have been restated to reflect the
two-for-one split for all periods presented.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The financial statements include the accounts of the Partnership on a
consolidated basis. The Company's 1% general partner interest in the Products
OLP and the Crude Oil OLP, is accounted for as a minority interest. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior years have been reclassified to conform to current
presentation.
NEW ACCOUNTING PRONOUNCEMENTS
In October 1996, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") 123, "Accounting for
Stock-Based Compensation." This standard allows a company to adopt a fair value
based method of accounting for its stock-based compensation plans and addresses
the timing and measurement of stock-based compensation expense. The Partnership
has elected to retain the approach of Accounting Principles Board Opinion
("APB") No. 25, "Accounting for Stock issued to Employees," (the intrinsic value
method) for recognizing stock-based expense in the consolidated financial
F-7
46
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
statements. The Partnership adopted SFAS 123 in 1997 with respect to the
disclosure requirements set forth therein for companies retaining the intrinsic
value approach of APB No. 25 (see Note 10).
In December 1997, the Partnership adopted SFAS 128, "Earnings per Share."
This statement established standards for computing and presenting net income per
Unit and requires, among other things, dual presentation of basic and diluted
net income per Unit on the face of the consolidated statements of income. The
Partnership has restated net income per Unit for the year ended December 31,
1996 and included diluted net income per Unit.
In June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income."
This statement establishes standards for reporting and display of comprehensive
income and its components in a full set of financial statements. The Partnership
has not reported comprehensive income due to the absence of such items in all
periods presented. In June 1998, the FASB also issued SFAS 131, "Disclosures
about Segments of an Enterprise and Related Information." This statement
establishes standards for reporting information about operating segments in
annual financial statements and requires that enterprises report selected
information about operating segments in interim reports issued to shareholders.
The Partnership adopted these standards in 1998.
In February 1998, the FASB issued SFAS 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits." This standard revises employers'
disclosures about pension and other post retirement plans but does not change
the measurement or recognition of those plans. The Partnership adopted this
standard in 1998 (see Note 13).
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
expects to adopt this standard effective January 1, 2000, and does not expect
the adoption of this statement to have a material impact on its financial
condition or results of operations.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
ENVIRONMENTAL EXPENDITURES
The Partnership accrues for environmental costs that relate to existing
conditions caused by past operations. Environmental costs include initial site
surveys and environmental studies of potentially contaminated sites, costs for
remediation and restoration of sites determined to be contaminated and ongoing
monitoring costs, as well as fines, damages and other costs, when estimable. The
Partnership's accrued undiscounted environmental liabilities are monitored on a
regular basis by management. Liabilities for environmental costs at a specific
site are initially recorded when the Partnership's liability for such costs,
including direct internal and legal costs, is probable and a reasonable estimate
of the associated costs can be made. Adjustments to initial estimates are
recorded, from time to time, to reflect changing circumstances and estimates
based upon additional information developed in subsequent periods. Estimates of
the Partnership's ultimate liabilities associated with environmental costs are
particularly difficult to make with certainty due to the number of variables
involved, including the early stage of investigation at certain sites, the
lengthy time frames required to complete remediation alternatives available, the
uncertainty of potential recoveries from third parties and the evolving nature
of environmental laws and regulations.
F-8
47
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
BUSINESS SEGMENTS
The Partnership operates in two industry segments: refined products and
liquefied petroleum gases ("LPGs") transportation; and crude oil and natural gas
liquids ("NGLs") transportation and marketing. The Partnership's reportable
segments offer different products and services and are managed separately
because each requires different business strategies.
The crude oil and NGLs transportation segment was acquired as a unit, and
the management at the time of the acquisition was retained. The refined products
and LPGs transportation segment's interstate transportation operations,
including rates charged to customers, are subject to regulations prescribed by
the Federal Energy Regulatory Commission ("FERC"). Refined products, LPGs, crude
oil and NGLs are referred to herein, collectively, as "petroleum products" or
"products."
REVENUE RECOGNITION
Substantially all revenues of the Products OLP are derived from interstate
and intrastate transportation, storage and terminaling of petroleum products.
Transportation revenues are recognized as products are delivered to customers.
Storage revenues are recognized upon receipt of products into storage and upon
performance of storage services. Terminaling revenues are recognized as products
are out-loaded. Revenues from the sale of product inventory are recognized net
of product cost when the products are sold. Fractionation revenues are
recognized ratably over the contract year as products are transferred to Duke
Energy Field Services, Inc. ("DEFS") (see Note 3).
Revenues of the Crude Oil OLP are accrued at the time title to the product
sold transfers to the purchaser, which typically occurs upon receipt of the
product by the purchaser, and purchases are accrued at the time title to the
product purchased transfers to TEPPCO Crude Oil, LLC ("TCO"), which typically
occurs upon receipt of the product by TCO. Except for crude oil purchased from
time to time as inventory, TCO's policy is to purchase only crude oil for which
it has a market to sell and to structure their sales contracts so that crude oil
price fluctuations do not materially affect the margin which they receive. As
TCO purchases crude oil, it establishes a margin by selling crude oil for
physical delivery to third party users or by entering into a future delivery
obligation either physically or a futures contract on the New York Mercantile
Exchange ("NYMEX"). Through these transactions, TCO seeks to maintain a position
that is balanced between crude oil purchases and sales and future delivery
obligations. However, certain basis risks (the risk that price relationships
between delivery points, classes of products or delivery periods will change)
cannot be completely hedged.
INVENTORIES
Inventories consist primarily of petroleum products and crude oil which are
valued at the lower of cost (weighted average cost method) or market. The
Products OLP acquires and disposes of various products under exchange
agreements. Receivables and payables arising from these transactions are usually
satisfied with products rather than cash. The net balances of exchange
receivables and payables are valued at weighted average cost and included in
inventories.
PROPERTY, PLANT AND EQUIPMENT
Additions to property, plant and equipment, including major replacements or
betterments, are recorded at cost. Replacements and renewals of minor items of
property are charged to maintenance expense. Depreciation expense is computed on
the straight-line method using rates based upon expected useful lives of various
classes of assets (ranging from 2% to 20% per annum). Upon sale or retirement of
properties regulated by the FERC, cost less salvage is normally charged to
accumulated depreciation, and no gain or loss is recognized.
F-9
48
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CAPITALIZATION OF INTEREST
In connection with the construction of facilities regulated by the FERC,
interest is capitalized in accordance with a FERC-established method. The rate
used to capitalize interest on borrowed funds was 7.02%, 10.09% and 10.07% for
1998, 1997 and 1996, respectively.
INCOME TAXES
The Partnership is a limited partnership. As a result, the Partnership's
income or loss for federal income tax purposes is included in the tax return of
the individual partners, and may vary substantially from income or loss reported
for financial reporting purposes. Accordingly, no recognition has been given to
federal income taxes for the Partnership's operations. At December 31, 1998 and
1997, the Partnership's reported amount of net assets for financial reporting
purposes exceeded its tax basis by approximately $272 million and $223 million,
respectively.
CASH FLOWS
For purposes of reporting cash flows, all liquid investments with
maturities at date of purchase of 90-days or less are considered cash
equivalents.
NET INCOME PER UNIT
Basic net income per Unit is computed by dividing net income, after
deduction of the general partner's interest, by the weighted average number of
Limited Partner Units and Class B outstanding (a total of 29.7 million Units for
1998, and 29.0 million Units for 1997 and 1996). The general partner's
percentage interest in net income is based on its percentage of cash
distributions from Available Cash for each year (see Note 10). The general
partner was allocated $1.7 million (representing 8.95%) of the net loss for the
year ended December 31, 1998. The general partner was allocated $4.7 million and
$3.7 million (representing 7.73% and 6.35%) of net income for each of the years
ended 1997 and 1996, respectively.
Diluted net income per Unit is similar to the computation of basic net
income per Unit above, except that the denominator was increased to include the
dilutive effect of outstanding Unit options by application of the treasury stock
method. For 1998, 1997 and 1996 the denominator was increased by 45,278 Units,
39,120 Units and 28,456 Units, respectively.
NOTE 3. ACQUISITIONS
Effective March 31, 1998, TEPPCO Colorado, LLC ("TEPPCO Colorado"), a
wholly owned subsidiary of the Products OLP, 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 totaled
approximately $40 million and was accounted for under the purchase method of
accounting.
Effective November 1, 1998, the Crude Oil OLP, through its wholly owned
subsidiary TEPPCO Crude Oil, LLC ("TCO"), acquired substantially all of the
assets of Duke Energy Transport and Trading Company ("DETTCO") from Duke Energy
for approximately $106 million. In consideration for such assets, Duke Energy
received 3,916,547 Class B Limited Partnership Units ("Class B Units"). The
Class B Units are substantially identical to the 29,000,000 Limited Partner
Units, but they are not listed on the New York Stock Exchange. The Class B Units
will be convertible into Limited Partner Units upon approval by the Limited
Partner Unitholders. The Company intends to seek approval for conversion,
however, if conversion is not approved before March 2000, the holder of the
Class B Units will have the right to sell them to the Partnership at 95.5% of
the market price of the Limited Partner Units at the time of sale. As a result
of such option, the Class B Units were not included in partners' capital at
December 31, 1998. Collectively, the Limited Partner Units and Class B Units are
referred to as "Units." The transaction was accounted for under
F-10
49
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the purchase method of accounting. Accordingly, the results of the acquisition
are included in the consolidated statements of income for the period subsequent
to November 1, 1998. During the two months ended December 31, 1998, the Class B
Units were allocated $1.0 million of net income for such period.
The following table presents the unaudited pro forma results of the
Partnership as though the acquisitions of the fractionation facilities and the
DETTCO assets occurred at the beginning of the period (in thousands, except per
Unit amounts).
YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
----------- -----------
Revenues.................................................... $1,412,929 $1,430,451
Operating income............................................ 90,074 105,942
Income before extraordinary loss on debt extinguishment..... 62,781 73,197
Net income (loss)........................................... (9,986) 73,197
Basic and diluted income per Unit before extraordinary
item...................................................... $ 1.71 $ 2.05
Basic and diluted net income (loss) per Unit................ $ (0.28) $ 2.05
NOTE 4. RELATED PARTY TRANSACTIONS
The Partnership has no employees and is managed by the Company. Pursuant to
the Partnership Agreements, the Company is entitled to reimbursement of all
direct and indirect expenses related to business activities of the Partnership
(see Note 1).
For 1998, 1997 and 1996, direct expenses incurred by the general partner in
the amount of $38.8 million, $38.2 million and $36.0 million, respectively, were
charged to the Partnership. Substantially all such costs related to payroll and
payroll related expenses, which included $1.0 million, $1.8 million and $1.9
million of expense for incentive compensation plans for each of the years ended
1998, 1997 and 1996, respectively.
For 1998, 1997 and 1996, expenses for administrative service and overhead
allocated to the Partnership by the general partner (including Duke Energy and
its affiliates) amounted to $2.7 million, $2.7 million and $2.6 million,
respectively. Such costs incurred by the general partner included general and
administrative costs related to business activities of the Partnership.
Effective with the purchase of the fractionation facilities, TEPPCO
Colorado and DEFS entered into a twenty-year Fractionation Agreement, under
which TEPPCO Colorado receives a variable fee for all fractionated volumes
delivered to DEFS. Revenues recognized from the Fractionation Agreement totaled
$5.5 million from April 1, 1998 through December 31, 1998. 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. Expenses related to the Operation and Maintenance Agreement totaled
$0.7 million from April 1, 1998 through December 31, 1998.
Included with the DETTCO assets purchased effective November 1, 1998 was
the 90-mile long Wilcox NGL Pipeline located along the Texas Gulf Coast. The
Wilcox NGL Pipeline transports NGLs for DEFS from two of their processing plants
and is currently supported by demand fees that are paid by DEFS through 2005.
Such fees totaled $0.2 million for the two months ended December 31, 1998.
NOTE 5. INVESTMENTS
SHORT-TERM INVESTMENTS
The Partnership routinely invests cash in liquid short-term investments as
part of its cash management program. Investments with maturities at date of
purchase of 90-days or less are considered cash and cash equivalents. All
short-term investments are classified as held-to-maturity securities and are
stated at
F-11
50
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
amortized cost. At December 31, 1998 and 1997, short-term investments consisted
of $3.3 million and $2.1 million, respectively, of investment-grade corporate
notes, with maturities at such date of less than one-year. The aggregate fair
value of such securities approximates amortized cost at December 31, 1998 and
1997. Such investments at December 31, 1998 included a $0.9 million investment
in Duke Power Company corporate notes.
LONG-TERM INVESTMENTS
At December 31, 1998 and 1997, the Partnership had $6.5 million and $10.0
million, respectively, invested in investment-grade corporate notes, which have
varying maturities until 2003. These securities are classified as
held-to-maturity securities and are stated at amortized cost. The aggregate fair
value of such securities approximates amortized cost at December 31, 1998 and
1997.
NOTE 6. INVENTORIES
Inventories are valued at the lower of cost (based on weighted average cost
method) or market. The major components of inventories were as follows:
DECEMBER 31,
-----------------
1998 1997
------- -------
(IN THOUSANDS)
Gasolines................................................... $ 4,224 $ 3,448
Propane..................................................... 1,503 3,428
Butanes..................................................... 1,654 2,102
MTBE........................................................ 641 630
Crude oil................................................... 5,517 --
Other products.............................................. 3,229 1,473
Materials and supplies...................................... 3,666 4,110
------- -------
Total............................................. $20,434 $15,191
======= =======
During 1998 the Partnership recorded $3.5 million of expense to reduce the
costs of product inventories to market values. The costs of inventories did not
exceed market values at December 31, 1998 and 1997.
NOTE 7. PROPERTY, PLANT AND EQUIPMENT
Major categories of property, plant and equipment were as follows:
DECEMBER 31,
-------------------
1998 1997
-------- --------
(IN THOUSANDS)
Land and right of way....................................... $ 53,901 $ 33,405
Line pipe and fittings...................................... 520,213 443,355
Storage tanks............................................... 105,844 86,425
Buildings and improvements.................................. 7,578 6,101
Machinery and equipment..................................... 151,808 140,798
Construction work in progress............................... 26,125 27,660
-------- --------
Total property, plant and equipment............... $865,469 $737,744
Less accumulated depreciation and amortization............ 193,858 170,063
-------- --------
Net property, plant and equipment................. $671,611 $567,681
======== ========
F-12
51
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Depreciation and amortization expense was $25.5 million, $23.8 million and
$23.4 million for the years ended December 31, 1998, 1997 and 1996,
respectively.
NOTE 8. LONG TERM DEBT
SENIOR NOTES
On January 27, 1998, the Products OLP 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 Products OLP, 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 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 Partnership recorded an extraordinary charge of $73.5 million
during the first quarter of 1998 (including $0.7 million allocated to minority
interest), 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 Products OLP and
will rank on a parity with all other unsecured and unsubordinated indebtedness
of the Products OLP. 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.
At December 31, 1998, the estimated fair value of the Senior Notes was
approximately $406.6 million. Market prices for recent transactions and rates
currently available to the Partnership for debt with similar terms and
maturities were used to estimate fair value.
OTHER LONG TERM DEBT
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. TEPPCO Colorado
paid interest to DEFS at a per annum rate of 5.75% on the amount of the total
purchase price outstanding for the period from March 31, 1998 until April 21,
1998. The SunTrust loan bears interest at a rate of 6.53%, which is payable
quarterly beginning in July 1998. The principal balance of the loan is payable
in full on April 21, 2001. The Products OLP is guarantor on the loan. At
December 31, 1998, the estimated fair value of the loan was approximately $39.3
million. Market prices for recent transactions and rates currently available to
the Partnership for debt with similar terms and maturities were used to estimate
fair value.
WORKING CAPITAL FACILITIES
In connection with the purchase of the DETTCO assets by TCO, the Crude Oil
OLP entered into a $30 million Revolving Credit Agreement ("Revolver") with Duke
Capital Corporation ("Duke Capital"), a wholly owned subsidiary of Duke Energy.
The Revolver, dated November 30, 1998, has a six-month term and bears interest
at the one month LIBOR rate plus 0.50%. The Revolver also has a commitment fee
of $45,000 per annum.
F-13
52
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The outstanding principal balance of the Revolver is payable in full at the
end of its term. The Revolver is to be used by the Crude Oil OLP and its
subsidiaries for working capital and general business needs. At December 31,
1998, there was no outstanding balance under the Revolver.
In connection with the purchase of the DETTCO assets by TCO, Duke Capital
also agreed to guarantee the payment by TCO and its subsidiaries under certain
commercial contracts between TCO and its subsidiaries and third parties. Duke
Capital will provide up to $100 million of guarantee credit to TCO and its
subsidiaries for a period of three years from November 30, 1998. Pursuant to
this agreement, the Partnership has agreed to pay Duke Capital $100,000 per
year.
NOTE 9. CONCENTRATIONS OF CREDIT RISK
The Partnership's primary market areas are located in the Northeast,
Midwest and Southwest regions of the United States. The Partnership has a
concentration of trade receivable balances due from major integrated oil
companies, independent oil companies and other pipelines and wholesalers. These
concentrations of customers may affect the Partnership's overall credit risk in
that the customers may be similarly affected by changes in economic, regulatory
or other factors. The Partnership's customers' historical and future credit
positions are thoroughly analyzed prior to extending credit. The Partnership
manages its exposure to credit risk through credit analysis, credit approvals,
credit limits and monitoring procedures, and for certain transactions may
utilize letters of credit, prepayments and guarantees.
NOTE 10. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH
As discussed in Note 1 above, all per Limited Partner Unit references have
been adjusted to reflect the two-for-one split on August 10, 1998.
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% to the Unitholders pro rata and 2% to the general partner until
there has been distributed with respect to each Limited Partner Unit and Class B
Unit an amount equal to the Minimum Quarterly Distribution ($0.275 per Limited
Partner Unit and Class B Unit) for each quarter. The Company receives
incremental incentive distributions of 15%, 25% and 50% on quarterly
distributions of Available Cash that exceed, $0.275, $0.325 and $0.45 per
Limited Partner Unit and Class B Unit, respectively. During 1998, 1997 and 1996,
incentive distributions paid to the Company totaled $5.0 million, $3.2 million
and $2.3 million, respectively.
For the year ended December 31, 1998, cash distributions totaled $56.8
million, resulting from cash distributions of $0.425 per Limited Partner Unit in
February and May, and $0.45 per Limited Partner Unit in August and November. For
the year ended December 31, 1997, cash distributions totaled $49.0 million,
resulting from cash distributions of $0.375 per Limited Partner Unit in February
and May, and $0.80 per Limited Partner Unit in August and November. For the year
ended December 31, 1996, cash distributions totaled $45.2 million, resulting
from cash distributions of $0.35 per Limited Partner Unit in February and May,
and $0.375 per Limited Partner Unit in August and November. The distribution
increases reflect the Partnership's success in improving cash flow levels.
On February 5, 1999, the Partnership paid a cash distribution of $0.45 per
Limited Partner Unit and Class B Unit for the quarter ended December 31, 1998.
The Class B Unit distribution was prorated for the 61 day period from issuance
on November 1, 1998.
NOTE 11. UNIT OPTION PLAN
During 1994, the Company adopted the Texas Eastern Products Pipeline
Company 1994 Long Term Incentive Plan ("1994 LTIP"). The 1994 LTIP provides key
employees with an incentive award whereby a
F-14
53
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
participant is granted an option to purchase Limited Partner Units together with
a stipulated number of Performance Units. Under the provisions of the 1994 LTIP,
no more than one million options and two million Performance Units may be
granted. Each Performance Unit creates a credit to a participant's Performance
Unit account when earnings exceed a threshold, which was $1.00, $1.25 and $1.875
per Unit for the awards granted in 1994, 1995 and 1997, respectively.
Performance Units grants were 80,000, 70,000 and 11,000 Performance Units during
1994, 1995 and 1997, respectively. No Performance Units 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
Limited Partner 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 Limited Partner 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. A summary of
Limited Partner Unit options granted under the terms of the 1994 LTIP is
presented below:
OPTIONS OPTIONS
OUTSTANDING EXERCISABLE RANGE
----------- ----------- -------------
Outstanding at December 31, 1995................ 106,878 10,210 $13.81-$14.34
Became exercisable............................ -- 35,664 $13.81-$14.34
Exercised..................................... (13,580) (13,580) $13.81-$14.34
------- -------
Outstanding at December 31, 1996................ 93,298 32,294 $13.81-$14.34
Granted....................................... 11,100 -- $21.66
Became exercisable............................ -- 37,674 $13.81-$14.34
Exercised..................................... (11,870) (11,870) $13.81-$14.34
------- -------
Outstanding at December 31, 1997................ 92,528 58,098 $13.81-$21.66
Granted....................................... 111,000 -- $25.69
Became exercisable............................ -- 26,993 $13.81-$21.66
Exercised..................................... (12,732) (12,732) $13.81-$14.34
------- -------
Outstanding at December 31, 1998................ 190,796 72,359 $13.81-$25.69
======= =======
As discussed in Note 2, SFAS 123, "Accounting for Stock-Based
Compensation," allows a company to adopt a fair value based method of accounting
for its stock-based compensation plans. The Partnership has elected to retain
the intrinsic value method of APB No. 25 for recognizing stock-based expense.
The exercise price of all options awarded under the 1994 LTIP equaled the market
price of the Partnership's Units on the date of grant. Accordingly, no
compensation was recognized at the date of grant. Had compensation expense been
determined consistent with SFAS 123, compensation expense related to option
grants would have totaled $31,158, $37,138 and $93,771 during 1996, 1997 and
1998, respectively. Under the provisions of SFAS 123, the pro forma disclosures
above include only the effects of Unit options granted by the Partnership
subsequent to December 31, 1994. During this initial phase-in period, the
disclosures as required by SFAS 123 are not representative of the effects on
reported net income for future years as options vest over several years and
additional awards may be granted in subsequent years.
For purposes of determining compensation costs using the provisions of SFAS
123, the fair value of 1997 and 1998 option grants were determined using the
Black-Scholes option-valuation model. The key input variables used in valuing
the options were: risk-free interest rate -- 6.3% and 5.5% for 1997 and 1998,
respectively; dividend yield -- 7.2% and 7.8% for 1997 and 1998, respectively;
Unit price volatility -- 18% for 1997 and 1998; expected option lives -- five
years and six years for 1997 and 1998, respectively.
F-15
54
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 12. LEASES
The Partnership utilizes leased assets in several areas of its operations.
Total rental expense during 1998, 1997 and 1996 was $4.8 million, $3.9 million
and $2.5 million, respectively. The minimum rental payments under the
Partnership's various operating leases for the years 1999 through 2003 are $6.0
million, $5.4 million, $4.9 million, $3.4 million and $3.3 million,
respectively. Thereafter, payments aggregate $5.9 million through 2007.
In May 1997, the Partnership completed construction to connect the pipeline
system to Colonial Pipeline Company's ("Colonial") pipeline at Beaumont, Texas.
The Partnership entered into a 10-year capacity lease with Colonial, whereby the
Partnership guaranteed a minimum monthly through-put rate for the connection.
The minimum lease payments related to this agreement are included in the amounts
disclosed above.
NOTE 13. EMPLOYEE BENEFITS
RETIREMENT PLANS
The Company's employees are included with other affiliates of Duke Energy
in a noncontributory, trustee-administered pension plan. Through December 31,
1998, the plan provided retirement benefits (i) for eligible employees of
certain subsidiaries, including the Company, that are generally based on an
employee's years of benefit accrual service and highest average eligible
earnings, and (ii) for eligible employees of certain other subsidiaries under a
cash balance formula. In 1998, a significant amount of lump sum payouts were
made from the plan resulting in a settlement gain of $10 million. The Company's
portion of this gain was $0.6 million. Effective January 1, 1999 the benefit
formula under the plan in which the Company participates, was changed to a cash
balance formula. Under a cash balance formula, a plan participant accumulates a
retirement benefit based upon a percentage of current pay, which may vary with
age and years of service, and current interest credits.
During 1998, Duke Energy adopted SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits", which required the
restatement of prior year data. This restatement did not change the net periodic
expense or the funded status of the retirement or post retirement benefit plans.
The components of net pension benefit costs for the years ended December 31,
1998, 1997 and 1996 were as follows (in thousands):
1998 1997 1996
------- ------- -------
Service cost benefit earned during the year............. $ 1,699 $ 1,509 $ 1,414
Interest cost on projected benefit obligation........... 2,041 2,359 2,157
Expected return on plan assets.......................... (1,555) (1,773) (1,641)
Amortization of prior service cost...................... (27) (30) (39)
Amortization of net transition asset.................... (5) (3) --
Settlement gain......................................... (554) -- --
------- ------- -------
Net pension benefits costs.................... $ 1,599 $ 2,062 $ 1,891
======= ======= =======
The assumptions affecting pension expense include:
1998 1997 1996
---- ---- ----
Discount rate............................................... 6.75% 7.25% 7.50%
Salary increase............................................. 4.67% 4.15% 4.80%
Expected long-term rate of return on plan assets............ 9.25% 9.25% 9.18%
F-16
55
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Duke Energy also sponsors employee savings plans which cover substantially
all employees. Plan contributions on behalf of the Company of $1.4 million, $1.4
million and $1.3 million were expensed in 1998, 1997 and 1996, respectively.
OTHER POSTRETIREMENT BENEFITS
Duke Energy and most of its subsidiaries provide certain health care and
life insurance benefits for retired employees on a contributory and
non-contributory basis. Employees become eligible for these benefits if they
have met certain age and service requirements at retirement, as defined in the
plans. Under plan amendments effective late 1998 and early 1999, health care
benefits for future retirees were changed to limit employer contributions and
medical coverage.
Such benefit costs are accrued over the active service period of employees
to the date of full eligibility for the benefits. The net unrecognized
transition obligation, resulting from the implementation of accrual accounting,
is being amortized over approximately 20 years.
Duke Energy is using an investment account under section 401(h) of the
Internal Revenue Code, a retired lives reserve (RLR) and multiple voluntary
employees' beneficiary association (VEBA) trusts under section 501(c)(9) of the
Internal Revenue Code to partially fund post retirement benefits. The 401(h)
vehicles, which provide for tax deductions for contributions and tax-free
accumulation of investment income, partially fund postretirement health care
benefits. The RLR, which has tax attributes similar to 401(h) funding, partially
funds postretirement life insurance obligations. Certain subsidiaries use the
VEBA trusts to partially fund accrued postretirement health care benefits and
fund post retirement life insurance obligations. The components of net
postretirement benefits cost for the years ended December 31, 1998, 1997 and
1996 were as follows (in thousands):
1998 1997 1996
------ ------ ------
Service cost benefit earned during the year................ $ 439 $ 350 $ 240
Interest cost on accumulated postretirement benefit
obligation............................................... 796 703 506
Expected return on plan assets............................. (240) (172) (126)
Amortization of prior service cost......................... 3 4 --
Amortization of net transition asset....................... 202 202 201
Recognized net actuarial loss.............................. 173 68 4
------ ------ ------
Net postretirement benefits costs................ $1,373 $1,155 $ 825
====== ====== ======
The assumptions affecting postretirement benefits expense include:
1998 1997 1996
----- ----- -----
Discount rate............................................... 6.75% 7.25% 7.50%
Salary increase............................................. 4.67% 4.33% 4.84%
Expected long-term rate of return on 401(h) assets.......... 9.25% 9.25% 9.00%
Expected long-term rate of return on RLR assets............. 6.75% 6.75% 6.50%
Expected long-term rate of return on VEBA assets............ 9.25% 9.25% 9.50%
Assumed tax rate............................................ 39.60% 39.60% 39.60%
For measurement purposes, a 5% weighted average rate of increase in the per
capita cost of covered health care benefits was assumed for 1998. The rate was
assumed to decrease gradually to 4.75% for 2005 and remain at that level
thereafter. Assumed health care cost trend rates have a significant effect on
the amounts reported for the health care plans. The below table indicates the
effect on the total service and interest costs
F-17
56
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
component and on the postretirement benefit obligation of a 1% increase or 1%
decrease in the assumed health care cost trend rates in each future year (in
thousands).
1% 1%
INCREASE DECREASE
-------- --------
Effect on total of service and interest cost components..... $159 $(136)
Effect on postretirement benefit obligation................. $404 $(378)
POSTEMPLOYMENT BENEFITS
The Partnership accrues expense for certain benefits provided to former or
inactive employees after employment but before retirement. During 1998, 1997 and
1996, the Partnership recorded $0.5 million, $0.5 million and $0.2 million,
respectively, of expense for such benefits.
NOTE 14. CONTINGENCIES
The Partnership is involved in various claims and legal proceedings
incidental to its business. In the opinion of management, these claims and legal
proceedings will not have a material adverse effect on the Partnership's
consolidated financial position or results of operations.
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 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.
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 $5.0 million (unaudited). A portion of such costs would have been
incurred as part of normal system and application
F-18
57
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
Products OLP has completed Phase I; Phase II is nearing completion; and Phase
III is ongoing. The Crude Oil OLP is nearing completion of Phase I. 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, 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.
Substantially all of the petroleum products transported and stored by the
Products OLP are owned by its customers. At December 31, 1998, the Partnership
had approximately 17.7 million barrels of products in its custody owned by
customers. The Products OLP is obligated for the transportation, storage and
delivery of such products on behalf of its customers. The Partnership maintains
insurance it believes to be adequate to cover product losses through
circumstances beyond its control.
NOTE 15. SEGMENT DATA
The Partnership operates in two industry segments: refined products and
LPGs transportation, which operates through the Products OLP; and crude oil and
NGLs transportation and marketing, which operates through the Crude Oil OLP.
Operations of the Products OLP 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 and other ancillary services. The Products
OLP 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 extending from southeast Texas through the central
and midwestern United States to the northeastern United States.
The Crude Oil OLP gathers, stores, transports and markets crude oil
principally in Oklahoma and Texas; operates two trunkline NGL pipelines in South
Texas; and distributes lube oil to industrial and commercial accounts. The Crude
Oil OLP's gathering, transportation and storage assets include approximately
2,200 miles of pipeline and 1.3 million barrels of storage.
F-19
58
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The accounting policies of the segments are the same as those described in
the summary of significant accounting policies discussed above (see Note 2). The
crude oil and NGLs transportation and marketing segment was added with the
acquisition from DETTCO effective November 1, 1998. The acquisition was
accounted for under the purchase method of accounting.
The below table includes financial information by business segment for the
year ended December 31, 1998. Data for the Crude Oil OLP includes operations for
the two months ended December 31, 1998. Segment data has not been provided for
the years ended December 31, 1997 and 1996, as the Partnership operated as one
business segment prior to November 1, 1998.
PRODUCTS CRUDE OIL
OLP OLP CONSOLIDATED
-------- --------- ------------
(IN THOUSANDS)
Unaffiliated revenues............................... $211,783 $217,855 $429,638
Operating expenses, including power................. 107,102 215,632 322,734
Depreciation and amortization expense............... 26,040 898 26,938
-------- -------- --------
Operating income.......................... 78,641 1,325 79,966
Interest expense.................................... (29,777) (7) (29,784)
Other income, net................................... 3,138 21 3,159
-------- -------- --------
Income before extraordinary item.......... 52,002 1,339 53,341
======== ======== ========
Identifiable assets................................. $694,636 $220,333 $914,969
Accounts receivable, trade.......................... 17,740 95,801 113,541
Accounts payable and accrued liabilities............ $ 8,513 $109,420 $117,933
NOTE 16. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- ------- ------- --------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
1998(1)
- --------
Operating revenues................................... $ 50,205 $51,560 $54,229 $273,644
Operating income..................................... 19,514 18,929 19,722 21,801
Income before extraordinary item(2).................. 13,155 12,546 12,734 14,906
Net income (loss).................................... (59,612) 12,546 12,734 14,906
Basic and diluted income per Limited Partner and
Class B Unit, before extraordinary item(2)(3)...... $ 0.41 $ 0.39 $ 0.39 $ 0.42
Basic and diluted net income (loss) per Limited
Partner and Class B Unit(3)........................ $ (1.87) $ 0.39 $ 0.39 $ 0.42
1997(1)
- --------
Operating revenues................................... $ 55,425 $52,649 $53,305 $ 60,714
Operating income..................................... 24,945 20,516 19,437 26,652
Net income........................................... 17,795 13,125 11,444 18,936
Basic and diluted net income per Limited Partner
Unit............................................... $ 0.57 $ 0.42 $ 0.36 $ 0.60
- ---------------
(1) Per Unit amounts for all periods have been adjusted to reflect the
two-for-one split on August 10, 1998.
(2) Extraordinary item reflects the $73.5 million loss related to the early
extinguishment of the First Mortgage Notes on January 27, 1998.
(3) Per Unit calculation includes 3,916,547 Class B Units issued for the
acquisition of the crude oil and NGL assets, effective November 1, 1998.
F-20
59
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.1 -- Certificate of Limited Partnership of the Partnership
(Filed as Exhibit 3.2 to the Registration Statement of
TEPPCO Partners, L.P. (Commission File No. 33-32203) and
incorporated herein by reference).
3.2 -- Certificate of Formation of TEPPCO Colorado, LLC (Filed
as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended March
31, 1998 and incorporated herein by reference).
*3.3 -- Second Amended and Restated Agreement of Limited
Partnership of TEPPCO Partners, L.P., dated November 30,
1998.
3.4 -- Amended and Restated Agreement of Limited Partnership of
TE Products Pipeline Company, Limited Partnership,
effective July 21, 1998 (Filed as Exhibit 3.2 to Form 8-K
of TEPPCO Partners, L.P. (Commission File No. 1-10403)
dated July 21, 1998 and incorporated herein by
reference).
*3.5 -- Agreement of Limited Partnership of TCTM, L.P., dated
November 30, 1998.
4.1 -- Form of Certificate representing Limited Partner Units
(Filed as Exhibit 4.1 to the Registration Statement of
TEPPCO Partners, L.P. (Commission File No. 33-32203) and
incorporated herein by reference).
4.2 -- Form of Indenture between TE Products Pipeline Company,
Limited Partnership and The Bank of New York, as Trustee,
dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE
Products Pipeline Company, Limited Partnership's
Registration Statement on Form S-3 (Commission File No.
333-38473) and incorporated herein by reference).
*4.3 -- Form of Certificate representing Class B Units.
10.1 -- Assignment and Assumption Agreement, dated March 24,
1988, between Texas Eastern Transmission Corporation and
the Company (Filed as Exhibit 10.8 to the Registration
Statement of TEPPCO Partners, L.P. (Commission File No.
33-32203) and incorporated herein by reference).
10.2 -- Texas Eastern Products Pipeline Company 1997 Employee
Incentive Compensation Plan executed on July 14, 1997
(Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
September 30, 1997 and incorporated herein by reference).
10.3 -- Agreement Regarding Environmental Indemnities and Certain
Assets (Filed as Exhibit 10.5 to Form 10-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the year
ended December 31, 1990 and incorporated herein by
reference).
10.4 -- Texas Eastern Products Pipeline Company Management
Incentive Compensation Plan executed on January 30, 1992
(Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
March 31, 1992 and incorporated herein by reference).
10.5 -- Texas Eastern Products Pipeline Company Long-Term
Incentive Compensation Plan executed on October 31, 1990
(Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the year ended
December 31, 1990 and incorporated herein by reference).
60
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.6 -- Form of Amendment to Texas Eastern Products Pipeline
Company Long-Term Incentive Compensation Plan (Filed as
Exhibit 10.7 to the Partnership's Form 10-K (Commission
File No. 1-10403) for the year ended December 31, 1995
and incorporated herein by reference).
10.7 -- Employees' Savings Plan of Panhandle Eastern Corporation
and Participating Affiliates (Effective January 1, 1991)
(Filed as Exhibit 10.10 to the Partnership's Form 10-K
(Commission File No. 1-10403) for the year ended December
31, 1990 and incorporated herein by reference).
10.8 -- Retirement Income Plan of Panhandle Eastern Corporation
and Participating Affiliates (Effective January 1, 1991)
(Filed as Exhibit 10.11 to Form 10-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the year ended
December 31, 1990 and incorporated herein by reference).
10.9 -- Panhandle Eastern Corporation Key Executive Retirement
Benefit Equalization Plan, adopted December 20, 1993;
effective January 1, 1994 (Filed as Exhibit 10.12 to Form
10-K of Panhandle Eastern Corporation (Commission File
No. 1-8157) for the year ended December 31, 1993 and
incorporated herein by reference).
10.10 -- Employment Agreement with William L. Thacker, Jr. (Filed
as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended
September 30, 1992 and incorporated herein by reference).
10.11 -- Texas Eastern Products Pipeline Company 1994 Long Term
Incentive Plan executed on March 8, 1994 (Filed as
Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended March
31, 1994 and incorporated herein by reference).
10.12 -- Panhandle Eastern Corporation Key Executive Deferred
Compensation Plan established effective January 1, 1994
(Filed as Exhibit 10.2 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
March 31, 1994 and incorporated herein by reference).
10.13 -- Asset Purchase Agreement between Duke Energy Field
Services, Inc. and TEPPCO Colorado, LLC, dated March 31,
1998 (Filed as Exhibit 10.14 to Form 10-Q of TEPPCO
Partners, L.P. (Commission File No. 1-10403) for the
quarter ended March 31, 1998 and incorporated herein by
reference).
10.14 -- Credit Agreement between TEPPCO Colorado, LLC, SunTrust
Bank, Atlanta, and Certain Lenders, dated April 21, 1998
(Filed as Exhibit 10.15 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended
March 31, 1998 and incorporated herein by reference).
10.15 -- First Amendment to Credit Agreement between TEPPCO
Colorado, LLC, SunTrust Bank, Atlanta, and Certain
Lenders, effective June 29, 1998 (Filed as Exhibit 10.15
to Form 10-Q of TEPPCO Partners, L.P. (Commission File
No. 1-10403) for the quarter ended June 30, 1998 and
incorporated herein by reference).
*10.16 -- Contribution Agreement between Duke Energy Transport and
Trading Company and TEPPCO Partners, L.P., dated October
15, 1998.
*10.17 -- Guaranty Agreement by Duke Energy Natural Gas Corporation
for the benefit of TEPPCO Partners, L.P., dated November
30, 1998, effective November 1, 1998.
*10.18 -- Revolving Credit Agreement between TCTM, L.P. as Borrower
and Duke Capital Corporation as Lender, dated November
30, 1998.
61
EXHIBIT
NUMBER DESCRIPTION
------- -----------
*10.19 -- Letter Agreement regarding Payment Guarantees of Certain
Obligations of TCTM, L.P. between Duke Capital
Corporation and TCTM, L.P., dated November 30, 1998.
*10.20 -- Form of Employment Agreement between the Company and O.
Horton Cunningham, Ernest P. Hagan, Thomas R. Harper,
David L. Langley, Charles H. Leonard and James C. Ruth,
dated December 1, 1998.
22.1 -- Subsidiaries of the Partnership (Filed as Exhibit 22.1 to
the Registration Statement of TEPPCO Partners, L.P.
(Commission File No. 33-32203) and incorporated herein by
reference).
*23 -- Consent of KPMG LLP.
*24 -- Powers of Attorney.
*27 -- Financial Data Schedule as of and for the year ended
December 31, 1998.
- ---------------
* Filed herewith.