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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
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FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999 Commission file number: 1-14323
ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0568219
(State or other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
2727 NORTH LOOP WEST, HOUSTON, TEXAS 77008-1037
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code : (713) 880-6500
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Title of each class Name of each exchange on which registered
Common Units New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
None
Indicate by check mark whether the registrant: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K 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. [ ]
Aggregate market value of the Common Units held by non-affiliates of
the registrant, based on closing prices in the daily composite list for
transactions on the New York Stock Exchange on February 25, 2000, was
approximately $203.5 million. This figure assumes that the directors and
executive officers of the General Partner, the Enterprise Products 1998 Unit
Option Plan Trust, and the EPOLP 1999 Grantor Trust were affiliates of the
Registrant.
The registrant had 45,552,915 Common Units outstanding as of March 1,
2000.
ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS
PAGE NO.
PART I
Items 1 and 2. Business and Properties. 1
Item 3. Legal Proceedings. 28
Item 4. Submission of Matters to a Vote of Security Holders. 28
PART II
Item 5. Market for Registrant's Common Equity
and Related Unitholder Matters. 29
Item 6. Selected Financial Data. 31
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation. 32
Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 45
Item 8. Financial Statements and Supplementary Data. 46
Item 9. Changes in and disagreements with Accountants on Accounting
and Financial Disclosure. 46
PART III
Item 10. Directors and Executive Officers of the Registrant. 47
Item 11. Executive Compensation. 49
Item 12. Security Ownership of Certain Beneficial Owners
and Management. 50
Item 13. Certain Relationships and Related Transactions. 51
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 53
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
ENTERPRISE PRODUCTS PARTNERS L.P. ("Enterprise" or the "Company") is a
leading integrated North American provider of processing and transportation
services to domestic and foreign producers of natural gas liquids ("NGL" or
"NGLs") and other liquid hydrocarbons and domestic and foreign consumers of NGLs
and liquid hydrocarbon products. The Company manages a fully integrated and
diversified portfolio of midstream energy assets and is engaged in NGL
processing and transportation through direct and indirect ownership and
operation of NGL fractionators. It also operates and or manages NGL processing
facilities, storage facilities, pipelines, rail transportation facilities, a
methyl tertiary butyl ether ("MTBE") facility, a propylene production complex
and other transportation facilities in which it has a direct and indirect
ownership. As a result of the acquisition of Tejas Natural Gas Liquids, LLC
("TNGL") from Tejas Energy, LLC ("Tejas Energy") now Coral Energy LLC, effective
August 1, 1999, the Company is also engaged in natural gas processing. All
references herein to "Shell", unless the context indicates otherwise, shall
refer collectively to Shell Oil Company, its subsidiaries and affiliates.
The Company is a publicly traded master limited partnership (NYSE,
symbol "EPD") that conducts substantially all of its business through ENTERPRISE
PRODUCTS OPERATING L.P. (the "Operating Partnership"), the Operating
Partnership's subsidiaries, and a number of joint ventures with industry
partners. The Company was formed in April 1998 to acquire, own, and operate all
of the NGL processing and distribution assets of Enterprise Products Company
("EPCO"). The general partner of the Company, Enterprise Products GP, LLC (the
"General Partner"), a majority-owned subsidiary of EPCO, holds a 1.0% general
partner interest in the Company and a 1.0101% general partner interest in the
Operating Partnership.
The principal executive office of the Company is located at 2727 North
Loop West, Houston, Texas, 77008-1038, and the telephone number of that office
is 713-880-6500. References to, or descriptions of, assets and operations of the
Company in this Annual Report include the assets and operations of the Operating
Partnership and its subsidiaries as well as the predecessors of the Company.
Uncertainty of Forward-Looking Statements and Information. This Annual
Report contains various forward-looking statements and information that are
based on the belief of the Company and the General Partner, as well as
assumptions made by and information currently available to the Company and the
General Partner. When used in this document, words such as "anticipate,"
"estimate," "project," "expect," "plan," "forecast," "intend," "could," and
"may," and similar expressions and statements regarding the Company's business
strategy and plans and objectives of the Company for future operations, are
intended to identify forward-looking statements. Although the Company and the
General Partner believe that the expectations reflected in such forward-looking
statements are reasonable, they can give no assurance that such expectations
will prove to be correct. Such statements are subject to certain risks,
uncertainties, and assumptions. If one or more of these risks or uncertainties
materialize, or if underlying assumptions prove incorrect, actual results may
vary materially from those anticipated, estimated, projected, or expected. Among
the key risk factors that may have a direct bearing on the Company's results of
operations and financial condition are: (a) competitive practices in the
industries in which the Company competes, (b) fluctuations in oil, natural gas,
and NGL product prices and production, (c) operational and systems risks, (d)
environmental liabilities that are not covered by indemnity or insurance, (e)
the impact of current and future laws and governmental regulations (including
environmental regulations) affecting the NGL industry in general, and the
Company's operations in particular, (f) loss of a significant customer, and (g)
failure to complete one or more new projects on time or within budget.
Joint Ventures and Subsidiaries. The Operating Partnership owns and
operates gas processing, NGL fractionation, propylene production, isobutane
production, MTBE production, storage, pipeline, and import/export assets. Among
these assets are the following joint ventures and wholly-owned subsidiaries:
JOINT VENTURES
o Baton Rouge Fractionators LLC ("BRF") - an approximate 31.25%
economic interest in a NGL fractionation facility located in
southeastern Louisiana.
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o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0%
economic interest in a propylene concentration unit located in
southeastern Louisiana which is under construction and scheduled
to become operational in the third quarter of 2000.
o Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.7% economic
interest in a NGL pipeline system located in south Louisiana. The
Company's interest in Belle Rose was acquired as a result of the
TNGL acquisition.
o Belvieu Environmental Fuels ("BEF") - a 33.33% economic interest
in a Methyl Tertiary Butyl Ether ("MTBE") production facility
located in southeast Texas.
o Dixie Pipeline Company ("Dixie") - an 11.5% interest in a
corporation owning a 1,301-mile propane pipeline and the
associated facilities extending from Mont Belvieu, Texas to North
Carolina.
o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively,
"EPIK") - a 50% aggregate economic interest in a refrigerated NGL
marine terminal loading facility located in southeast Texas.
o K/D/S Promix LLC ("Promix") - a 33.33% economic interest in a NGL
fractionation facility and related storage facilities located in
south Louisiana. The Company's interest in Promix was acquired as
a result of the TNGL acquisition.
o Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33%
economic interest in a NGL pipeline system located in Louisiana,
Mississippi, and Alabama. As a result of the TNGL acquisition,
the Company acquired an additional 16.67% interest bringing the
total investment in Tri-States to the current 33.33%.
o Venice Energy Services Company, LLC ("VESCO") - a 13.1% economic
interest in a LLC owning a natural gas processing plant,
fractionation facilities, storage, and gas gathering pipelines in
Louisiana.
o Wilprise Pipeline Company, LLC ("Wilprise") - a 33.33% economic
interest in a NGL pipeline system located in southeastern
Louisiana.
WHOLLY-OWNED SUBSIDIARIES
o Cajun Pipeline Company, LLC ("Cajun")- a limited liability
company owning NGL pipelines located in the southeastern United
States.
o Chunchula Pipeline Company, LLC ("Chunchula") - a limited
liability company owning NGL pipelines located in the
southeastern United States.
o Entell NGL Services, LLC ("Entell") - a limited liability company
which markets certain NGLs produced by an Illinois refinery owned
by a division of Equilon Enterprises LLC. From January 1, 1999
through October 31, 1999, Entell leased from a subsidiary of the
Company a NGL transportation and distribution system capable of
distributing products from key NGL sources in southern Louisiana
directly to major NGL markets, including the lower Mississippi
River corridor, Dixie pipeline, Lake Charles, Louisiana and Mont
Belvieu, Texas. The Company's 100% ownership of Entell is due to
the TNGL acquisition. For the period March 1, 1999 through July
31, 1999, Entell was a joint venture equally owned by the
Operating Partnership and TNGL. The Operating Partnership's 50%
economic interest in the income of the joint venture has been
recorded as equity income in unconsolidated affiliates. The
Operating Partnership owned 100% of Entell for the period January
1, 1999 through February 28, 1999.
o Enterprise Lou-Tex NGL Pipeline L.P. ("Lou-Tex NGL") - a limited
partnership formed to construct and own a NGL pipeline system
from Sorrento, Louisiana to Mont Belvieu, Texas. Management
anticipates that construction of this line will begin by the end
of the first quarter of 2000 with completion scheduled early in
the fourth quarter of 2000.
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o Enterprise Lou-Tex Propylene Pipeline L.P. ("Lou-Tex Propylene")
- a limited partnership formed to acquire a 263-mile propylene
pipeline from Concha Chemical Pipeline Company. The pipeline is
currently dedicated to the transportation of chemical grade
propylene from Sorrento, Louisiana to Mont Belvieu, Texas. The
purchase of this pipeline was finalized on February 25, 2000.
o Enterprise NGL Pipelines, LLC ("ENGL Pipelines") - a limited
liability company owning NGL pipelines primarily in Louisiana and
Mississippi. ENGL Pipelines owns the 41.7% economic interest in
Belle Rose and a 16.7% economic interest in Tri-States. When
consolidated with the Operating Partnership's stand-alone 16.7%
economic interest in Tri-States, the Company holds a 33.33%
economic interest.
o Enterprise NGL Private Lines & Storage LLC ("ENGL Private")- a
limited liability company whose primary activity is the
transportation and storage of NGLs in Louisiana and Mississippi
for Company accounts.
o Enterprise Gas Processing LLC ("EGP") - a limited liability
company whose business activities include the processing of
natural gas and extraction of NGLs from natural gas streams. In
addition, EGP fractionates NGL raw make into distinct products
through its investment in Promix.
o Enterprise Products Texas Operating L.P. ("EPTexas") - a limited
partnership owning a 62.5% interest in a Mont Belvieu, Texas NGL
fractionation facility.
o EPOLP 1999 Grantor Trust ("Trust")- a revocable grantor trust
formed in January 1999 to purchase Common Units of the Company to
fund future liabilities of the 1999 Long-Term Incentive Plan. The
Company consolidates the Trust into its financial statements and
discloses the Common Units held by the Trust in a manner similar
to the purchase of treasury stock under the cost method of
accounting.
o HSC Pipeline Partnership, L.P. ("HSC") - a limited partnership
owning NGL pipeline assets in Mont Belvieu, Texas and the Houston
ship channel area. The pipeline assets deliver NGLs to Mont
Belvieu and NGL products to Houston area refineries and
petrochemical companies.
o Propylene Pipeline Partnership, L.P. ("Propylene Pipeline") - a
limited partnership owning interests in propylene pipelines
located in Texas and Louisiana.
o Sorrento Pipeline Company, LLC ("Sorrento") - a limited liability
company owning pipelines that distribute NGL products to
refineries and petrochemical companies in Louisiana and the Dixie
pipeline. The pipelines extend from near Baton Rouge, Louisiana
to New Orleans, Louisiana.
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The following chart shows the organizational structure and ownership of
entities:
[ORGANIZATION CHART INSERTED HERE]
BUSINESS STRATEGY
The business strategy of the Company is to grow its core assets and
maximize the returns to Unitholders. Management intends to pursue this strategy
principally by:
Capitalizing on Expected Increases in NGL Production. The Company
believes production of both oil and natural gas in the Gulf of Mexico will
continue to increase over the next several years. The Company intends to
capitalize on its existing infrastructure, market position, strategic
relationships and financial flexibility in order to expand operations to meet
the anticipated increased demand for NGL processing services. Of particular
significance will be production associated with the development of natural gas
fields in Mobile Bay and the Gulf of Mexico offshore Louisiana, which are
expected to produce natural gas with significantly higher NGL content than
typical domestic production. Management believes the Gulf Coast is the only
major marketplace that has sufficient storage facilities, pipeline distribution
systems and petrochemical and refining demand to absorb this new NGL production.
In connection with the TNGL acquisition, Shell entered into a 20-year natural
gas processing agreement with the Operating Partnership, covering substantially
all its Gulf of Mexico natural gas production.
Expanding through Construction of Identified New Facilities. The
Company is currently participating in the construction of
o a new cryogenic natural gas processing plant in St. Mary's
Parish, Louisiana, known as the Neptune gas plant; and
o a new propylene concentrator adjacent to the Baton Rouge NGL
fractionation facility.
The Company is also planning the construction of a 263-mile Lou-Tex NGL pipeline
from Sorrento, Louisiana to Mont Belvieu, Texas to have a capacity of 50,000
barrels per day, in batch mode, for the transportation of mixed NGLs and NGL
products. The pipeline is being designed to allow for efficient expansion to
approximately 80,000 barrels per day. Construction of the Lou-Tex NGL pipeline
is expected to be completed during the fourth quarter of 2000.
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Investing with Strategic Partners. The Company will continue to pursue
joint investments with oil and natural gas producers that can commit feedstock
volumes to new facilities or with petrochemical companies that agree to purchase
a significant portion of the production from new facilities. The Company
believes commitments from producers to bring NGL volumes to new fractionation
facilities and pipelines are central to establishing the viability of new
investments in the NGL processing and transportation industry.
Expanding Through Acquisitions. The Company will continue to analyze
potential acquisitions, joint ventures or similar transactions with businesses
that operate in complementary markets and geographic regions. In recent years,
major oil and natural gas companies have sold non-strategic assets including
assets in the midstream natural gas industry such as those the Company acquired
from Shell in the TNGL acquisition. Management believes this trend will
continue, and the Company expects independent oil and natural gas companies to
consider similar options.
Managing Commodity Price Exposure. In terms of volume and normalized
gross margin, a substantial portion of the Company's operations are conducted
pursuant to tolling and NGL transportation and storage agreements where it
processes, transports, and stores a raw feedstock or product for a fee and does
not take title to the product. In those situations where the Company does take
title to NGL products, the following scenarios apply:
o In the Company's isomerization merchant activities and to a certain
extent its propylene fractionation business, the Company generally
attempts to match the timing and price of its feedstock purchases with
those of the sales of end products so as to reduce exposure to
fluctuations in commodity prices.
o In the Company's natural gas processing business, to the extent it
takes title to the NGLs removed from the natural gas stream and
reimburses the producer for the reduction in the Btu content and/or
the natural gas used as fuel, the Company's margins are affected by
the prices of NGLs and natural gas. Management from time to time uses
financial instruments to reduce its exposure to the change in the
prices of NGLs and natural gas.
For a general discussion of the Company's commodity risk management policies and
exposures, see Item 7A "Quantitative and Qualitative Disclosures about Market
Risk."
GENERAL
The Company is a leading integrated provider of processing and
transportation services to producers of natural gas and NGLs and to consumers of
NGL products. The Company:
o processes raw natural gas to extract a mixed NGL stream from
commercial natural gas;
o fractionates mixed NGLs produced as by-products of oil and natural gas
production into their component products of ethane, propane,
isobutane, normal butane and natural gasoline;
o separates propane/propylene mix into high purity propylene;
o converts normal butane to isobutane through the process of
isomerization;
o produces MTBE from isobutane and methanol;
o transports NGL products to end users by pipeline and railcar;
o provides underground storage for NGLs and propylene; and
o provides import and export services for NGLs.
The products that the Company processes generally are used as
feedstocks in petrochemical manufacturing, in the production of motor gasoline
and as fuel for residential and commercial heating.
The Company has expanded rapidly since its inception in 1968, primarily
through internal growth, the formation of joint ventures and acquisitions. This
growth reflects the increased demand for NGL processing due to increased
domestic natural gas production and crude oil refining and increased demand for
processed NGLs in the petrochemical industry. Over the last few years the
Company has increased its NGL fractionation capacity by approximately 35%, built
a third isomerization unit that increased its isobutane production capacity by
approximately 60%, increased deisobutanizer capacity by approximately 54%,
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constructed a second propylene fractionation unit which approximately doubled
production capacity and made its investments in the MTBE facility at Mont
Belvieu. The Company's operations are centered on the Gulf Coast of the United
States in Texas, Louisiana, and Mississippi. The Company's largest processing
facility is located in Mont Belvieu, Texas.
Effective August 1, 1999, the Company acquired TNGL from Shell. TNGL
engaged in natural gas processing and NGL fractionation, transportation, storage
and marketing in Louisiana and Mississippi. TNGL's assets included the Shell
Processing Agreement and varying interests in eleven natural gas processing
plants (including one under construction) with a combined gross capacity of 11.0
billion cubic feet per day (Bcfd) and a net capacity of 3.1 Bcfd; four NGL
fractionation facilities with a combined gross capacity of 281,000 barrels per
day (BPD) and net capacity of 131,500 BPD; four NGL storage facilities with
approximately 28.8 million barrels of gross capacity and 8.8 million barrels of
net capacity; and approximately 1,500 miles of NGL pipelines (including an 11.5%
interest in Dixie Pipeline).
Effective July 1, 1999, the Company purchased an additional 25%
ownership interest in the 210,000 BPD fractionation facility located at the
Company's Mont Belvieu complex. Specifically, the Company purchased the
remaining 51% ownership interests in Mont Belvieu Associates ("MBA") which owned
50% of the Mont Belvieu fractionation facility. With this acquisition, the
Company's direct and indirect ownership in this facility increased to 62.5%.
Overall, the Company believes the demand for its services will continue
to increase, principally as a result of expected increases in natural gas
production, particularly in the Gulf of Mexico, and generally increasing
domestic and worldwide petrochemical production. Accordingly, the Company has
initiated several new projects which are currently in construction.
The Company's operating margins are derived from services provided to
tolling customers and from merchant activities. In the Company's toll processing
operations, it does not take title to the product and is simply paid a fee based
on volumes processed, transported, stored or handled. The Company's
profitability from toll processing operations depends primarily on the volumes
of natural gas, NGLs and refinery-sourced propane/propylene mix processed and
transported and the level of associated fees charged to its customers. The
profitability of the Company's toll processing operations is largely unaffected
by short-term fluctuations in the prices for oil, natural gas or NGLs. In the
Company's isomerization merchant activities and to a certain extent its
propylene fractionation business, it takes title to feedstock products and sell
processed end products. The Company's profitability from these merchant
activities is dependent on the prices of feedstocks and end products, which
typically vary on a seasonal basis. In the Company's propylene fractionation
business and isomerization merchant business, the Company generally attempts to
match the timing and price of its feedstock purchases with those of the sales of
end products so as to reduce exposure to fluctuations in commodity prices. The
Company's operating margins from its natural gas processing business are
generally derived from the margins earned on the sale of purity NGL products
extracted from natural gas streams. To the extent it takes title to the NGLs
removed from the natural gas stream and reimburses the producer for the
reduction in the Btu content and/or the natural gas used as fuel, the Company's
margins are affected by the prices of NGLs and natural gas. Management from time
to time uses financial instruments to reduce its exposure to the change in the
prices of NGLs and natural gas.
Historically, the Company has had only one reportable business segment:
NGL Operations. Due to the broadened scope of the Company's operations with the
third quarter of 1999 acquisition of TNGL, effective for fiscal 1999, the
Company's operations are being managed using five reportable business segments.
The five new segments better reflect the earnings and activities in each of the
Company's major lines of business and are:
o Fractionation
o Pipeline
o Octane Enhancement
o Processing
o Other
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For a discussion of the financial results of these operating segments over the
last three fiscal years, see "Management's Discussion and Analysis of Financial
Condition and Results of Operation." For financial data on the operating
segments, please refer to Note 15 of the Notes to Consolidated Financial
Statements.
FRACTIONATION
This operating segment is primarily comprised of the following business areas:
o NGL Fractionation
o Isomerization
o Propylene Fractionation
This segment also includes the Company's equity method investments in BRF, BRPC,
and Promix. In addition, this segment includes the support facilities for the
NGL Fractionation, Isomerization, and Propylene Fractionation units and other
miscellaneous minor plants. A description of the most significant business areas
comprising this segment follows.
NGL FRACTIONATION
General. The three principal sources of NGLs fractionated in the United
States are:
o domestic gas processing plants;
o domestic crude oil refineries; and,
o imports of butane and propane mixtures.
When produced at the wellhead, natural gas consists of a mixture of
hydrocarbons that must be processed to remove NGLs and impurities. Gas
processing plants are located near the production areas and separate pipeline
quality natural gas (principally methane) from NGLs and other materials. After
being extracted in the field, mixed NGLs, sometimes referred to as "y-grade" or
"raw make," are typically transported to a centralized facility for
fractionation. Crude oil and condensate production also contain varying amounts
of NGLs, which are removed during the refining process and are either
fractionated by refiners or delivered to NGL fractionation facilities. Domestic
NGL production has increased in recent years, and the Company believes, based on
published industry data, that this supply growth will continue over the next
several years.
The mixed NGLs delivered from gas plants to centralized fractionation
facilities are typically transported by NGL pipelines and, to a lesser extent,
by rail car or truck. The following table lists the primary NGL pipelines and
related assets which connect the Company's largest NGL fractionation facilities
at Mont Belvieu, Texas to NGL supply sources:
SOURCE PARTIES SERVED AREA OF ORIGINATION
Black Lake Pipeline............. Enterprise/Dynegy North Louisiana
Central Louisiana
East Texas
Chaparral Pipeline ............. Common Carrier West Texas
North Texas
Dean Pipeline .................. Enterprise* South Texas
Enterprise Import/Export Facility Enterprise* Foreign imports
Enterprise Rail/Truck Terminal . Common Carrier United States
Houston Ship Channel Pipeline .. Enterprise* Foreign Imports
Local Refineries
Panola Pipeline ................ Enterprise* East Texas
Seminole Pipeline .............. Common Carrier Rocky Mountains
Mid-Continent
West Texas
West Texas LPG Pipeline ........ Common Carrier West Texas
North Texas
East Texas
- ----------------------------------------------------------------------------
* NGLs from these sources are delivered exclusively to the Company's Mont
Belvieu NGL fractionation facilities.
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NGL fractionation facilities separate mixed NGL streams into discrete
NGL products: ethane, propane, isobutane, normal butane and natural gasoline.
Ethane is primarily used in the petrochemical industry as feedstock for
ethylene, one of the basic building blocks for a wide range of plastics and
other chemical products. Propane is used both as a petrochemical feedstock in
the production of ethylene and propylene and as heating, engine and industrial
fuel. Isobutane is fractionated from mixed butane (a stream of normal butane and
isobutane in solution) or refined from normal butane through the process of
isomerization, principally for use in refinery alkylation to enhance the octane
content of motor gasoline and in the production of MTBE, an oxygenation additive
used in cleaner burning motor gasoline, and in the production of propylene
oxide. Normal butane is used as a petrochemical feedstock in the production of
ethylene and butadiene (a key ingredient in synthetic rubber), as a blendstock
for motor gasoline and to derive isobutane through isomerization. Natural
gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as
motor gasoline blend stock or petrochemical feedstock.
The Company's NGL Fractionation facilities. The Company operates one of
the largest NGL fractionation facilities in the United States with an average
production capacity of 210,000 barrels per day at Mont Belvieu, approximately 25
miles east of Houston. Mont Belvieu is the hub of the domestic NGL industry
because of its proximity to the largest concentration of refineries and
petrochemical plants in the United States and its location on a large
naturally-occurring salt dome that provides for the underground storage of
significant quantities of NGLs. Excluding NGLs fractionated in facilities which
are captive to certain refineries (non-commercial fractionation), approximately
one-half of all NGLs fractionated in the United States are fractionated at Mont
Belvieu, and the Company's fractionation facilities currently account for
approximately 33% of total NGL fractionation capacity at Mont Belvieu.
The Company's Mont Belvieu NGL fractionation facilities include two
fractionation trains. Each train is named after the point of origin of the NGL
pipelines from which the facilities were originally fed. The West Texas
Fractionator was constructed in 1980 with an average production capacity of
35,000 barrels per day and was expanded to 70,000 barrels per day capacity in
1988 and 115,000 barrels per day capacity in 1996. The Seminole Fractionator was
constructed in 1982 with an average production capacity of 60,000 barrels per
day and was expanded to 95,000 barrels per day capacity in 1985.
As a result of the MBA acquisition, the Company owns an effective 62.5%
economic interest in the NGL fractionation facilities at the Mont Belvieu
complex. The remaining interests are owned by Duke Energy (12.5%), Texaco
(12.5%) and Burlington Resources (12.5%). Prior to the MBA acquisition, the
earnings associated with the Company's 49% investment in MBA were recorded as
equity income under this operating segment. The Company operates the facilities
pursuant to an operating agreement that extends for their useful operating life.
The Company also owns and operates NGL fractionation facilities at
Norco, Louisiana and Petal, Mississippi. The Norco facilities were acquired with
the TNGL acquisition. This facility was built in the 1960s and has an average
production capacity of 60,000 barrels per day. It receives raw make via pipeline
from the Yscloskey, Toca, Paradis, and Crawfish gas processing plants. The Petal
facility has an average production capacity of approximately 7,000 barrels per
day. The Petal facility is connected to the Company's Chunchula pipeline system
and serves NGL producers in Mississippi, Alabama and Florida.
The Company's NGL Fractionation Customers and Contracts. In most cases
the Company processes NGLs for a toll processing fee. Fractionation contracts
typically include a base processing fee per gallon subject to adjustment for
changes in natural gas, electricity and labor costs, which are the principal
variable costs in NGL fractionation. NGL producers generally retain title to,
and the pricing risks associated with, the NGL products.
The Company has long-term fractionation agreements with Burlington
Resources, Texaco and Duke Energy each of which is a significant producer of
NGLs and a co-owner of the Mont Belvieu NGL fractionation facility. Burlington
Resources and Texaco have agreed to deliver either a minimum of 39,000 barrels
per day of mixed NGLs or all of their mixed NGLs brought within 50 miles of Mont
Belvieu. Duke Energy has agreed to deliver 26,000 barrels per day of mixed NGLs
as well as additional barrels that exceed its commitments to other facilities.
The Company generally enters into contracts that cover most of the remaining
capacity at the facilities for one to three-year terms with customers such as
Lyondell, Aquila Energy, Enron, Exxon, Williams and Marathon/Ashland.
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The Company, excluding its equity NGLs obtained as compensation for gas
processing services, purchases a small quantity of mixed NGLs from oil and
natural gas producers who prefer to sell at the gas processing plant or the
fractionation facility. The Company resells the separated components of these
NGLs in the spot market or uses them as feedstock for its other operations.
NGL Fractionation Volumes and Utilization Rates. During fiscal 1999,
the Mont Belvieu fractionation facility operated at 75% of capacity. The 1999
utilization rate was lower than the previous year due to a decrease in mixed NGL
volumes being delivered to the Company's facilities for processing. The lower
volumes are the result of more intense competition in the Mont Belvieu
processing area for fractionation services. The Norco fractionator operated at
80% of capacity since the Company acquired it effective August 1, 1999. The
following table shows the volumes of mixed NGLs fractionated and the utilization
at these facilities over this period:
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
Mont Belvieu NGL fractionation facilities:
Average daily production volume (thousands of barrels) 158 166 189 191 157
Average capacity utilization (a) 95% 97% 92% 92% 75%
Tolling volume as a percentage of total volume 86% 90% 96% 96% 87%
Norco fractionation facilities: (b)
Average daily production volume (thousands of barrels) 48
Average capacity utilization 80%
- ------------------------------------------------------------------------------------------------------
(a) The Company completed an expansion of the facilities in November 1996,
which increased capacity from 165,000 barrels per day to 210,000 barrels
per day. This increased production capacity was not fully utilized until
mid-1997. Capacity utilization is based on days the facilities are in
operation and may vary from the stated capacity of the facilities.
(b) The Norco fractionator was acquired in August 1999 as part of the TNGL
acquisition
The Company's equity investments in NGL Fractionation facilities. The
Company has equity investments in two NGL fractionation facilities: BRF and
Promix. The equity earnings from these investments are included in this segment.
BRF is a joint venture with Amoco, ExxonMobil and Williams that owns a
60,000 barrel per day NGL fractionation facility near Baton Rouge, Louisiana.
The Company operates the facility and holds an approximate 31.25% ownership
interest at December 31, 1999. The facility commenced operations in July 1999,
and it is expected that Amoco, ExxonMobil, and Williams will provide an adequate
supply of NGLs produced in Alabama, Mississippi and southern Louisiana including
offshore areas to ensure the plant will operate at full capacity.
Promix is a NGL fractionation facility owned by K/D/S Promix L.L.C.
with a capacity of 145,000 barrels per day. The facility was built during the
mid-1960s and has been expanded twice in the last three years to its present
capacity. The Company owns a 33.33% interest in Promix, which is operated by
Koch. As part of its infrastructure, Promix owns a 315-mile raw make gathering
system that is connected to nine gas processing plants. The Promix facilities
also include five salt dome storage wells which handle raw make, propane,
isobutane, normal butane and natural gasoline and a barge loading facility. The
Company acquired its ownership interest in Promix as part of the TNGL
acquisition.
ISOMERIZATION
General. Isomerization is the process of converting normal butane into
mixed butane, which is subsequently fractionated into isobutane and normal
butane. The demand for commercial isomerization services depends on requirements
for isobutane in excess of naturally occurring isobutane that is produced from
fractionation and refinery operations. The profitability of isomerization
operations is largely dependent upon the volume of fee-based business.
9
Isobutane is principally supplied by NGL fractionation and commercial
isomerization units, such as those the Company operates. The principal sources
of demand for isobutane are refineries for alkylation, petrochemical companies
for the production of propylene oxide and MTBE producers.
The Company's Isomerization facilities. The Company's Mont Belvieu
facility includes three butane isomerization units and eight deisobutanizers
("DIBs") which comprise the largest butane isomerization complex in the United
States. The Company's facilities have an average combined potential production
capacity of 116,000 barrels of isobutane per day and account for more than 70%
of the commercial isobutane production capacity in the United States. The
Company built its first two isomerization units ("Isom I and II") in 1981, each
with a capacity of 13,500 barrels per day. In 1991 and 1992, the capacity of
each of these units was increased to 36,000 barrels per day. The third
isomerization unit ("Isom III") was completed in 1992 with a capacity of 44,000
barrels per day. Isom II has been shut down since July 1999 due to lack of
product demand with a resulting loss of 36,000 barrels per day of capacity. The
Company has the operating flexibility to switch the process streams from its
isomerization units among different DIB units in order to maximize overall plant
efficiency. The Company is also able to process fluoridic, lower cost butanes
from oil refineries, which the Company would otherwise be unable to process, by
first passing those butanes through an associated defluorinator.
The Company's Isomerization Processing Customers and Contracts. The
Company uses its isomerization facilities to convert normal butane to isobutane
for its tolling customers and to meet isobutane sales contracts. The Company's
most significant processing customers typically operate under long-term
contracts. Lyondell accounted for approximately 36.4% of the Company's
isomerization volumes in 1999. The Company's current contract with Lyondell has
a ten-year term which expires in December 2009. Lyondell supplies the normal
butane feedstock and pays the Company a processing fee based on the gallons of
isobutane produced. Lyondell uses the isobutane processed by the Company to
produce propylene oxide and MTBE.
The Company also has significant isomerization processing contracts
with Huntsman, Sun and Mitchell pursuant to which the customers supply the
Company with normal butane feedstock and pay the Company a processing fee based
on the gallons of isobutane produced. Sun and Mitchell use the high purity
isobutane processed for them to meet their feedstock obligations as partners in
the BEF MTBE production facility. The Company can also meet its own obligation
to provide high purity isobutane feedstock to the BEF MTBE facility with
production from its isomerization unit.
Isomerization Volumes and Utilization Rates. The following table
describes the volumes of isobutane produced and the utilization at the Company's
Mont Belvieu facility during the past five years:
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
Average daily toll processing volume (a,b) 57 59 62 57 59
Average daily production volume (a,b) 67 71 67 67 74
Tolling volume as a percentage of total production 86% 84% 92% 86% 81%
Average capacity utilization (b) 58% 61% 57% 57% 71%
Average daily merchant volume (a,c) 44 52 53 41 43
- ------------------------------------------------------------------------------------------------
(a) Thousands of barrels per day
(b) Isom II mothballed in July 1999 reducing operating capacity to 80,000 BPD;
fourth quarter 1999 rate was 94% without Isom II
(c) Average daily merchant volume includes merchant processing volume and sales
of isobutane purchased in the spot market. Beginning with the fourth
quarter of 1999, merchant activities associated with the isomerization
business are reflected in the Processing segment.
Mixed Butane Fractionation (DIBs). The Company also uses its DIB units
to fractionate mixed butane produced from its NGL fractionation and
isomerization facilities and from imports and other outside sources into
isobutane and normal butane. The operating flexibility provided by its multiple
DIBs enables the Company to take advantage of fluctuations in demand and prices
for the different types of butane. The Company also has DIB capacity available
for toll processing of mixed butane streams for third parties.
Imports are the Company's most significant outside source of mixed
butane. The Company leases and operates a NGL import/export facility on the
10
Houston ship channel, one of only two commercial facilities on the Gulf Coast
capable of receiving and unloading world-scale NGL tankers. This facility, which
is connected to the Mont Belvieu facility via a pipeline which is part of the
Company's Houston Ship Channel Distribution System, enables the Company to
import large quantities of mixed butane for processing in its DIBs and to load
fully refrigerated propane and butane on to ocean going ships for export. During
1999, imports from Algeria and Norway accounted for the Company's supply of
mixed butanes from outside sources. The Company believes, because of new
projects in Africa and South America and the lack of storage capacity in the
Middle East, NGL import volumes will remain consistent over the near term.
PROPYLENE PRODUCTION
General. Polymer grade, or high purity, propylene is one of three
grades of propylene sold in the United States and is used in the petrochemical
industry for the production of plastics. High purity propylene is typically over
99.5% pure propylene and is derived by purifying either of the lower grade
propylene feedstocks, refinery grade or chemical grade. Chemical grade propylene
is 92-93% pure propylene and is produced as a by-product of olefin (ethylene)
plants. The supply of chemical grade propylene is insufficient to meet the
demand for high purity propylene; therefore, remaining demand is satisfied by
the purification of refinery grade propylene. Refinery grade propylene, or
propane/propylene mix, is 50-70% pure propylene, with the primary impurity being
propane. Propane/propylene mix is produced in crude oil refinery fluid catalytic
cracking plants and is fractionated to separate propane and other impurities
from the high purity propylene. The fractionation process occurs either at the
crude oil refinery or at a commercial propylene fractionation facility like
those the Company operates.
In 1999, domestic high purity propylene production was approximately
130,000 barrels per day. The domestic high purity propylene production rate
increased in 1999 over the 109,000 barrels per day seen in 1998 as a result of
new facilities coming online. Based on industry data, management believes that
this trend will continue in 2000 with domestic high purity propylene production
forecasted at 150,000 barrels per day. This growth in high purity propylene
production is being absorbed by the polypropylene market. Polypropylene
production accounts for approximately one-half of the demand for high purity
propylene. The volume of high purity propylene being consumed in the
polypropylene market has increased by approximately 32,000 barrels per day since
1997 and is expected to increase an additional 6.1% or 13,800 barrels per day in
2000. Polypropylene has a variety of end uses, including fiber for carpets and
upholstery, packaging film and molded plastic parts for appliance, automotive,
houseware and medical products. Another use for propylene is to produce alkylate
for blending into gasoline.
The Company's Propylene Facilities. In 1979, the Company, together with
Montell (a Shell affiliate), constructed the Company's first propylene
fractionation unit. The unit, which is also called a "splitter," had an initial
average production capacity of 5,500 barrels per day. The facility has been
expanded over the years to a current average propylene production capacity of
16,500 barrels per day. The Company owns a 54.6% interest in the splitter, and
Montell owns the remaining 45.4% interest. The Company leases Montell's
interest. In response to strong demand, the Company constructed a second
propylene fractionation unit in March 1997. The new unit has an average
production capacity of 13,500 barrels per day. The Company is the sole owner of
the second splitter. Together, the splitters have an average production capacity
of 30,000 barrels per day of high purity propylene.
The Company is able to unload barges carrying propane/propylene mix
through its import/export facility on the Houston ship channel. The Company is
also able to receive supplies of propane/propylene mix from its truck and rail
loading facility and from refineries and other propane/propylene mix producers
through its pipeline located along the Houston ship channel.
The Company's Propylene Customers and Contracts. The Company produces
high purity propylene both as a toll processor and for sale pursuant to
long-term agreements with market-based pricing or spot market transactions. The
Company's most significant toll processing contracts are with Equistar and
Huntsman. Pursuant to those contracts, the Company is guaranteed certain minimum
volumes and paid a processing fee based on the pounds of high purity propylene
processed. In addition, the Company has several long-term high purity propylene
sales agreements, the most significant of which is with Montell. Pursuant to the
Montell agreement, the Company agrees to sell Montell 800 million pounds, equal
to approximately 11,000 barrels per day, of high purity propylene each year at
market-based prices. The Company has supplied Montell with propylene since the
first splitter facility was constructed in 1979. The contract is currently
11
scheduled to expire on December 31, 2004. Montell has the option to renew the
contract for another 12 years. To meet its sales obligations, the Company has
entered into several long-term agreements to purchase propane/propylene mix. The
Company's most significant feedstock contracts are with ExxonMobil and Shell.
Propylene Production Volumes and Utilization Rates. The following table
shows the volumes of propylene produced and utilization at the Company's
facilities over the past five years:
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
Average daily production volume (thousands of barrels 16 16 26 26 28
Average capacity utilization (a) 100% 100% 93% 86% 92%
Tolling volumes as a percentage of total volume 35% 33% 47% 47% 42%
- ----------------------------------------------------------------------------------------------------
(a) The Company began operating its second splitter in March 1997 resulting in
an increase in capacity to 30,000 barrels per day. During the last six
months of 1997, average daily production was 29,000 barrels per day.
The Company's equity investments in Propylene Production and Related
facilities. In August 1999, the Company and ExxonMobil Chemical Company
announced that they had formed a joint venture, Baton Rouge Propylene
Concentrator LLC, that will own and operate a propylene fractionation unit
currently under construction. The unit, located in Port Allen, Louisiana, across
the Mississippi River from ExxonMobil's refinery and chemical plant, will
upgrade refinery-grade propylene produced by ExxonMobil and others into chemical
grade propylene. Chemical grade propylene is a basic building block
petrochemical used in plastics, synthetic fibers, and foams. Upon completion of
the project, the facility will have the capacity to produce 22,500 barrels per
day of chemical grade propylene. Construction began in March 1999 with the
forecasted cost to the Company being $19.3 million. Management anticipates that
the facility will become operational in the third quarter of 2000.
12
PIPELINE
This operating segment is primarily comprised of the following business
areas:
o Pipelines
o Houston Ship Channel Import/Export Facility
o Storage
This segment also includes the equity method investments in EPIK, Wilprise,
Tri-States, and Belle Rose.
PIPELINES
General. The Company's facilities include a network of NGL, NGL product
and propylene pipelines in the Gulf Coast area. The following table identifies
the Company's primary pipeline assets as of December 31, 1999:
Company
Ownership
Pipeline System Location Miles Function Percentage Operator
- --------------- -------- ----- -------- ---------- --------
Houston Ship Channel Mont Belvieu to Port 175 Delivers NGLs to Mont Belvieu 100% Company
Distribution System of Houston and NGL products to refineries
and petrochemical companies
Louisiana Pipeline Louisiana 471 Delivers NGL products to 100% except Equilon, Dynegy,
Distribution System refineries, petrochemical for 52-mile and Company
companies, gas processing line that is
facilities and the Dixie owned 33%
Pipeline
Chunchula Pipeline System Alabama/Florida 117 Delivers NGLs to Petal NGL 100% Company
border to Petal, fractionation facility
Mississippi
Lake Charles/Bayport Mont Belvieu to Lake 134 Delivers high purity propylene 50% Company
Propylene Pipeline System Charles, Louisiana from Mont Belvieu to Montell's and
and Bayport, Texas Lake Charles and Bayport ExxonMobil
propylene plants and to
Aristech's La Porte facility
and receives refinery grade
propylene from ExxonMobil at
Beaumont
Tri-States, Belle Rose, Pascagoula, Miss. 239 Delivers raw make from 33.33% Tri-States Williams (Wilprise
and Wilprise Systems to Mobile Bay and Pascagoula and Mobile Bay 41.7% Belle Rose & Tri-States)
Louisiana to Promix and Baton Rouge 33.33% Promix Company(Belle Rose)
Dixie Pipeline System (a) Mont Belvieu to 1,301 Delivers propane from Mont 11.50% Phillips
North Carolina Belvieu and Louisiana to Pipeline
Alabama, Georgia, South
Carolina and North
Carolina
=========
TOTAL FOR ALL PIPELINES 2,437
=========
- ----------------------------------------------------------------------------------------------------------------------------
(a) The Dixie Pipeline System is a cost method investment. Under generally
accepted accounting principles, income is recognized from this investment
as cash dividends are received. The Company records these receipts under
the caption, "Dividend income from unconsolidated affiliates" in the
Statements of Consolidated Operations and are not included in the
determination of segment profit or loss. The investment in Dixie Pipeline,
however, is part of segment assets.
13
Houston Ship Channel Distribution System. The Houston ship channel
distribution system is bi-directional for maximum operating flexibility, market
responsiveness and transportation efficiency. These systems transport feedstocks
to Company facilities for processing and deliver products to petrochemical
plants and refineries. The Houston ship channel distribution system has an
aggregate length of approximately 175 miles and extends west from Mont Belvieu,
along the Houston ship channel to Pierce Junction south of Houston. The Houston
ship channel system includes:
o a combination 6-inch and 8-inch propane/propylene mix pipeline;
o a combination 8-inch and 10-inch isobutane pipeline;
o an 8-inch methanol pipeline; and
o a combination 12-inch and 16-inch NGL import/export pipeline.
The Houston ship channel distribution system serves the refinery and
petrochemical industry concentrated along the Houston ship channel and connects
the Mont Belvieu facilities to a number of major customers and suppliers.
Louisiana Pipeline Distribution System. The Louisiana Pipeline System
is a collection of eleven pipelines in Louisiana aggregating 471 miles in
length. The primary asset of this group is the Sorrento system. As with the
Houston Ship Channel Distribution System, the Sorrento system is bi-directional
for maximum operating flexibility, market responsiveness and transportation
efficiency. The Sorrento system comprises two pipeline subsystems aggregating
183 miles in length that originate from Sorrento, Louisiana and serve the major
refineries and petrochemical companies on the Mississippi River from near Baton
Rouge, Louisiana to near New Orleans, Louisiana. One subsystem is used for
transporting propane, and one is used for transporting butane and natural
gasoline. Propane received in the Sorrento system is delivered to petrochemical
plants or into the Dixie Pipeline. Butane from Mont Belvieu is received from the
Dixie Pipeline at the Company's Breaux Bridge storage facility, and transported
through the Sorrento system to refineries. The Company is the operator of the
Sorrento system.
In addition to the Sorrento system, the Louisiana Pipeline System is
comprised of ten smaller pipelines that principally serve the Company's gas
processing and other facilities. Eight of these lines were acquired in the TNGL
acquisition. With the exception of the BRF raw make line operated by ExxonMobil,
the Yscloskey/Toca pipeline operated by Dynegy, and the Cajun pipeline operated
by the Company, these pipelines are operated by Equilon, an affiliate of Shell.
Chunchula Pipeline System. The Chunchula system originates at the
Alabama-Florida border and extends west to the Company's NGL storage and
fractionation facility in Petal, Mississippi. The Company owns and operates this
117-mile, 6-inch line consisting of the Chunchula Pipeline and the Jay Extension
that gathers NGLs from the Chunchula, Jay and Hatters Pond Fields in Florida and
Alabama for delivery to the Company's facility in Petal, Mississippi for
processing or storage and further distribution.
Lake Charles/Bayport Propylene Pipeline System. The Company operates a
134-mile propylene pipeline system which is used to distribute high purity
propylene from Mont Belvieu to Montell's polypropylene plants in Lake Charles,
Louisiana and Bayport, Texas and Aristech's facility in LaPorte, Texas. A
segment of the pipeline is jointly owned by the Company and Montell, and another
segment of the pipeline is leased from Mobil.
The Company's equity investments in the Tri-States, Wilprise, and Belle
Rose Systems. The Company is participating in pipeline joint ventures which
support the BRF and Promix NGL fractionators. Tri-States, a joint venture with
Amoco, Duke Energy, Koch and Williams, extends approximately 161 miles from
Mobile Bay, Alabama to near Kenner, Louisiana. Wilprise, a joint venture with
Williams and Amoco, extends approximately 30 miles from Kenner to Sorrento,
Louisiana. The Company owns 33.33% of both Tri-States and Wilprise. In addition,
the Company owns 41.7% of Belle Rose. Belle Rose is a joint venture with Gulf
Coast NGL Pipeline and Koch. Belle Rose owns a 48-mile pipeline that extends
from near Kenner, Louisiana to Promix.
The Company's cost method investment in the Dixie System. The Company
owns an 11.5% economic interest in Dixie. The other owners of Dixie are Amoco,
Arco, Chevron, Conoco, ExxonMobil, Phillips, and Texaco. Dixie owns 1,301 miles
of propane product pipeline which move propane supplies from Mont Belvieu and
Louisiana into market areas in Georgia and the Carolinas. Dixie's throughput has
averaged over 35 million barrels per year over the last three years. The
operator of the Dixie System is Phillips. The Company's investment in Dixie is
14
counted as part of segment assets; however, since Dixie is a cost method
investment, the cash dividends received are recorded as part of "Other Income
and Expense" in the Statements of Consolidated Operations of the Company as
dividend income from an unconsolidated affiliate. These cash payments are not
included in the determination of segment operating margin.
Pipeline Acquisitions for fiscal 2000. On February 25, 2000, the
Company announced the closing, effective March 1, 2000, of its acquisition of
certain Louisiana and Texas pipeline assets from Concha Chemical Pipeline
Company ("Concha"), an affiliate of Shell, for approximately $100 million in
cash. The principal asset acquired was the Lou-Tex Propylene Pipeline which is
263 miles of 10" pipeline from Sorrento, Louisiana to Mont Belvieu, Texas. The
Lou-Tex Propylene Pipeline is currently dedicated to the transportation of
chemical grade propylene from Sorrento to the Mont Belvieu area. Also acquired
in this transaction was 27.5 miles of 6" ethane pipeline between Sorrento and
Norco, Louisiana, and a 0.5 million barrel storage cavern at Sorrento,
Louisiana. The acquisition of the Lou-Tex Propylene Pipeline is the first step
in the Company's development of an approximately $180 million, 160,000 barrel
per day Louisiana-to-Texas gas liquids pipeline system. The second step involves
the construction of the 263-mile Lou-Tex NGL Pipeline from Sorrento, Louisiana
to Mont Belvieu, Texas, scheduled for completion in the third quarter of 2000.
This larger system will link growing supplies of NGLs produced in Louisiana and
Mississippi with the principal NGL markets on the United States Gulf Coast.
On February 23, 2000, the Company offered to buy the remaining 88.5%
ownership interests in Dixie from the other seven owners for a total purchase
price of approximately $204.4 million. The offer is subject to the acceptance by
the holders of a minimum of 68.5% of the oustanding ownership interests. The
offer will expire on March 8, 2000 if it is not accepted by such holders. If the
offer is accepted, the purchase would be subject to, among other things,
preparation and execution of a definitive purchase agreement and the obtaining
of requisite regulatory approvals and consents.
Houston Ship Channel Import/Export Facility
General. The Company leases and operates a NGL import facility at the
Oiltanking Houston marine terminal on the Houston ship channel. The Company owns
a 50% interest in EPIK , a joint venture owning NGL export assets at the
terminal. The import/export facility is connected to Mont Belvieu via the
Company's 16-inch bi-directional import/export pipeline. This pipeline enables
NGL tankers to be offloaded at their maximum (10,000 barrels per hour) unloading
rate, thus minimizing laytime and increasing the number of vessels that can be
offloaded. An 8-inch methanol pipeline which is part of the Houston ship channel
distribution system also extends from the facility to Mont Belvieu and enables
methanol to be delivered by ship and then transferred to the MTBE facility.
The Company's equity investment in the EPIK Export Facility. EPIK, a
joint venture with Idemitsu, owns a NGL Product Chiller and related equipment
used for loading refrigerated marine tankers at the import/export facility. The
NGL Product Chiller speeds the loading of tankers at rates up to 5,000 barrels
per hour of refrigerated propane and butane, one of the highest loading rates in
the United States. The Company has a 50% economic interest in EPIK.
Storage
General. NGLs, NGL products, propane/propylene mix and other light
hydrocarbons must be pressurized or refrigerated for storage or transportation
in a liquid state. Above-ground storage of these materials in refrigerated or
pressurized containers is uneconomical in the quantities required for efficient
processing and industrial consumption. For this reason, such materials are
typically stored in underground caverns, or wells, within salt domes or salt
beds. These salt formations provide a medium which is impervious to the stored
products and can contain large quantities of hydrocarbons in a safer manner and
at a significantly lower per-unit cost than any above-ground alternative. Brine
is used to displace the stored products and to maintain pressure in the well as
product volumes fluctuate.
The Company's Primary Storage Facilities. The Company owns nine storage
wells at Mont Belvieu with an aggregate capacity of approximately 20 million
barrels. In addition, the Company owns NGL storage caverns in Breaux Bridge,
Louisiana and Petal, Mississippi with additional capacity of 15 million barrels.
Several of the wells at Mont Belvieu are used to store mixed NGLs and
propane/propylene mix that have been delivered for processing. Such storage
allows the Company to mix various batches of feedstock and maintain a sufficient
supply and stable composition of feedstock to the processing facilities. The
Company also uses these wells to store certain fractionated products for its
customers when they are unable to take immediate delivery. These products
include propane, isobutane, normal butane, mixed butane and high purity
propylene. These storage wells, product handling facilities and pipeline systems
enable the Company to unload feedstocks and load processed products on marine
15
tankers at maximum rates. Some of the Company's processing contracts allow for a
short period of free storage (typically 30 days or less) and impose fees based
on volumes stored for longer periods.
In addition to the storage facilities noted above, this operating segment
contains the following assets acquired in the TNGL acquisition:
o a wholly-owned underground propane storage facility at Sorrento,
Louisiana, operated by Equilon, having a total storage capacity of
786,000 barrels; and
o a 50% interest in an underground propane storage facility at
Hattiesburg, Mississippi, operated by Dynegy, having a storage
capacity of five million barrels.
OCTANE ENHANCEMENT
This operating segment consists of the Company's equity interest in BEF
which owns and operates a facility that produces motor gasoline additives to
enhance octane. This facility currently produces MTBE.
General. MTBE is produced by reacting methanol with isobutylene, which
is derived from isobutane. MTBE was originally used as an octane enhancer in
motor gasoline, partly in response to the lead phase-down program begun in the
mid-1970's. Following implementation of the Clean Air Act Amendments of 1990,
MTBE became a widely-used oxygenate to enhance the clean burning properties of
motor gasoline. Although oxygen requirements can be obtained by using various
oxygenates such as ethanol, ethyl tertiary butyl ether (ETBE) and tertiary amyl
methyl ether (TAME), MTBE has gained the broadest acceptance due to its ready
availability and history of acceptance by refiners. Additionally, motor gasoline
containing MTBE can be transported through pipelines, which is a significant
competitive advantage over alcohol blends.
Substantially all of the MTBE produced in the United States is used in
the production of oxygenated motor gasoline that is required to be used in
carbon monoxide and ozone non-attainment areas designated pursuant to the Clean
Air Act Amendments of 1990 and the California oxygenated motor gasoline program.
Demand for MTBE is primarily affected by the demand for motor gasoline in these
areas. Motor gasoline usage in turn is affected by many factors, including the
price of motor gasoline (which is dependent upon crude oil prices) and general
economic conditions. Historically, the spot price for MTBE has been at a modest
premium to gasoline blend values. Future MTBE demand is highly dependent on
environmental regulation, federal legislation and the actions of individual
states.
The Company's equity investment in Octane Enhancement facilities. The
Company owns a 33.33% interest in BEF, the joint venture that owns the MTBE
production facility located within the Mont Belvieu complex. Both Sun and
Mitchell own 33.33% interests in BEF. The BEF facility was completed in 1994 and
has an average MTBE production capacity of 14,800 barrels per day. EPCO operates
the facility under a long-term contract.
The Company's Octane Enhancement Customers and Contracts. Each of the
owners of BEF is responsible for supplying one-third of the facility's isobutane
feedstock through June 2004. Sun and Mitchell have each contracted to supply
their respective portions of the feedstock from the Company's isomerization
facilities. The methanol feedstock is purchased from third parties under
long-term contracts and transported to Mont Belvieu by a dedicated pipeline
which is part of the Houston Ship Channel Distribution System. Sun has entered
into a contract with BEF under which Sun is required to take all of BEF's
production of MTBE through May 2005. Under the terms of its agreement with BEF,
Sun is required to pay through May 2000, the higher of a floor price
(approximately $1.11 per gallon at December 31, 1999) or a market-based price
for the first 193,450,000 gallons per contract year of production (equivalent to
approximately 12,600 barrels per day) from the BEF facility, subject to
quarterly adjustments on certain excess volumes. Sun is required to pay a
market-based price for volumes produced in excess of 193,450,000 gallons per
contract year. Since the contract year begins on June 1, if the facility
produces at full capacity during the year, it reaches 193,450,000 gallons of
production near the end of March, and sales thereafter through the end of May
are at market-based prices. Generally, the price charged by BEF to Sun for MTBE
has been above the spot market price for MTBE. The average Gulf Coast MTBE spot
price was $.94 per gallon for December 1999 and $.72 per gallon for all of 1999.
Beginning in June 2000, pricing on all volumes will convert to market-based
rates.
16
Recent Regulatory Developments. In November 1998, U.S. Environmental
Protection Agency ("EPA") Administrator Carol M. Browner appointed a Blue Ribbon
Panel (the "Panel") to investigate the air quality benefits and water quality
concerns associated with oxygenates in gasoline, and to provide independent
advice and recommendations on ways to maintain air quality while protecting
water quality. The Panel issued a report on their findings and recommendations
in July 1999. The Panel urged the widespread reduction in the use of MTBE due to
the growing threat to drinking water sources despite that fact that use of
reformulated gasolines have contributed to significant air quality improvements.
The Panel credited reformulated gasoline with "substantial reductions" in toxic
emissions from vehicles and recommended that those reductions be maintained by
the use of cleaner-burning fuels that rely on additives other than MTBE and
improvements in refining processes. The Panel stated that the problems
associated with MTBE can be characterized as a low-level, widespread problem
that had not reached the state of being a public health threat. The Panel's
recommendations are geared towards confronting the problems associated with MTBE
now rather than letting the issue grow into a larger and worse problem. The
Panel did not call for an outright ban on MTBE but stated that its use should be
curtailed significantly. The Panel also encouraged a public educational campaign
on the potential harm posed by gasoline when it leaks into ground water from
storage tanks or while in use. Based on the Panel's recommendations, the EPA is
expected to support a revision of the Clean Air Act of 1990 that maintains air
quality gains and allows for the removal of the requirement for oxygenates in
gasoline.
Several public advocacy and protest groups active in California and
other states have asserted that MTBE contaminates water supplies, causes health
problems and has not been as beneficial as originally contemplated in reducing
air pollution. In California, state authorities negotiated an agreement with the
EPA to implement a program requiring oxygenated motor gasoline at 2.0% for the
whole state, rather than 2.7% only in selected areas. On March 25, 1999, the
Governor of California ordered the phase-out of MTBE in that state by the end of
2002. The order also seeks to obtain a waiver of the oxygenate requirement from
the EPA in order to facilitate the phase-out; however, due to increasing
concerns about the viability of alternative fuels, the California legislature on
October 10, 1999 passed the Sher Bill (SB 989) stating that MTBE should be
banned as soon as feasible rather than by the end of 2002.
Legislation to amend the federal Clean Air Act of 1990 has been
introduced in the U.S. House of Representatives; it would ban the use of MTBE as
a fuel additive within three years. Legislation introduced in the U.S. Senate
would eliminate the Clean Air Act's oxygenate requirement in order to assist the
elimination of MTBE in fuel. No assurance can be given as to whether this or
similar federal legislation ultimately will be adopted or whether Congress or
the EPA might takes steps to override the MTBE ban in California.
Alternative Uses of the BEF facility. In light of these regulatory
developments, the Company is formulating a contingency plan for use of the BEF
facility if MTBE were banned or significantly curtailed. Management is exploring
a possible conversion of the BEF facility from MTBE production to alkylate
production. Alkylate is a high octane, low sulfur, low vapor pressure compound,
produced by the reaction of isobutylene or normal butylene with isobutane, and
used by refiners as a component in gasoline blending. At present the forecast
cost of this conversion would be in the $20 million to $25 million range, with
the Company's share being $6.7 million to $8.3 million. Management anticipates
that if MTBE is banned alkylate demand will rise as producers use it to replace
MTBE as an octane enhancer. Alkylate production would be expected to generate
margins comparable to those of MTBE. Greater alkylate production would be
expected to increase isobutane consumption nationwide and result in improved
isomerization margins for the Company.
Octane Enhancement Volumes and Utilization Rates. The following table
shows the production volumes and utilization at BEF's facility over the past
five years:
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
Average MTBE daily production volume 9.6 13.2 14.4 14.0 13.9
(thousands of barrels)
Average capacity utilization 65% 89% 97% 95% 94%
17
PROCESSING
General. This operating segment consists of the Company's natural gas
processing business and related merchant activities. The Company entered into
the natural gas processing business through the TNGL acquisition. In this
transaction, the Company acquired the Shell Processing Agreement, whereby the
Company has the right to process Shell's current and future production from the
Gulf of Mexico within the state and federal waters off Texas, Louisiana,
Mississippi, Alabama and Florida. This includes natural gas production from the
developments currently referred to as deepwater. Shell is the largest oil and
gas producer and holds one of the largest lease positions in the deepwater Gulf
of Mexico. Based on industry projections, management believes that the Gulf of
Mexico natural gas and associated NGL production will significantly increase in
the coming years as a result of advances in three dimensional seismic and
development systems and continued capital spending by major oil companies
regardless of the commodity environment.
The natural gas processing plants acquired in the TNGL acquisition are
primarily straddle plants which are situated on mainline natural gas pipelines.
Straddle plants allow plant owners to extract NGLs from a natural gas stream
when the market value of the NGLs is higher than the market value of the same
unprocessed natural gas. After extraction, raw make is typically transported to
a centralized facility for fractionation where it is separated into purity NGL
products such as ethane, propane, normal butane, isobutane and natural gasoline.
The purity NGL products can then be used by the Company in its merchant
activities to meet contractual requirements or sold on the spot and forward
markets.
The majority of the operating margins earned by the Company's natural
gas processing operations are based on the relative economic value of the NGLs
extracted by the gas plants compared to the fuel and shrinkage value of the
natural gas consumed to produce the NGLs, less the operating costs of the
natural gas processing plants. Processing contracts based on this type of
arrangement are generally called keepwhole contracts. Specifically, a keepwhole
contract is defined as a natural gas processing arrangement where the processor
(i.e., the Company) generally takes title to the NGLs extracted from natural
gas. The processor reimburses the producer (e.g., Shell or others) for the
market value of the energy extracted from the natural gas stream in the form of
fuel and NGLs based on the BTUs (a measure of heat value) consumed multiplied by
the market value for natural gas. The processor derives a profit margin to the
extent the market value of the NGLs extracted exceeds the market value of fuel
and shrinkage and the operating costs of the natural gas plant.
Generally, in its isomerization merchant activities the Company takes
title to feedstock products and sells processed end products. In the case of its
gas processing facilities, the Company takes title to a portion of the raw make
(such amount defined by contract) that it extracts from the natural gas stream.
The purity NGL products extracted from the raw make are then sold by the Company
in the normal course of business. The Company from time to time uses financial
instruments to reduce its commodity price exposure. For a general discussion on
the Company's commodity risk management policies and exposure, see Item 7A of
this report, "Quantitative and Qualitative Disclosures about Market Risk."
The Company's Natural Gas Processing Plants. The Company owns interests
in and operates the following natural gas processing plants:
o Toca, St. Bernard Parish, Louisiana: a plant constructed in the 1970s
with a throughput capacity of 1.1 billion cubic feet per day. The
plant has two independent trains, a lean oil train with a capacity of
850 million cubic feet per day and a cryogenic train with a capacity
of 250 million cubic feet per day. The ownership of the plant is based
on a combination of fixed gas units and variable NGL production. The
Company's ownership is currently approximately 54%.
o North Terrebonne, Terrebonne Parish, Louisiana: a lean oil plant built
during the mid 1960s with a throughput capacity of 1.3 billion cubic
feet per day. The ownership of the plant is variable based primarily
on the prior year's NGL production. The Company's ownership is
currently 33%. Linked with this gas plant is the Tebone NGL
fractionation facility located in Ascension Parish, Louisiana. The
Tebone NGL fractionation facility was built in the 1960s as well and
receives raw make from the North Terrebone gas processing plant. This
fractionation facility has a current rated capacity of 30,000 barrels
per day.
18
o Calumet, St. Mary Parish, Louisiana: a lean oil plant built during the
early 1970s with a throughput capacity of 1.6 billion cubic feet per
day. Ownership is based on a combination of fixed gas units and
variable NGL production. The Company's ownership is currently
approximately 37%.
o Neptune, St. Mary Parish, Louisiana (under construction): a new
cryogenic plant under construction with a throughput capacity of 300
million cubic feet per day. Operations are scheduled to begin in March
2000. The Company's ownership will be fixed at 66% with Marathon Oil
Company owning the remaining 34%.
The Company holds non-operating interests in the following six natural gas
processing plants:
o Yscloskey, St. Bernard Parish, Louisiana: a lean oil plant built
during the early 1960s with a throughput capacity 1.85 billion cubic
feet per day. The ownership of the plant is variable and is based
entirely on the prior year's NGL production. The Company's ownership
is currently approximately 31%. Dynegy operates the plant.
o Burns Point, St. Mary Parish, Louisiana: a cryogenic plant built in
1982 with a throughput capacity of 160 million cubic feet per day. The
Company's ownership is fixed at 50%. Marathon Oil Company, which
operates the facility, owns the other 50%.
o Sea Robin, Vermillion Parish, Louisiana: a cryogenic plant built
during the 1970s with a throughput capacity of 950 million cubic feet
per day. Ownership is based on a combination of fixed gas and liquids
units and variable NGL production. The Company's ownership is
currently 6.3%. Texaco operates the plant.
o Blue Water, Acadia Parish, Louisiana: a cryogenic plant built during
the late 1970s with a throughput capacity of 950 million cubic feet
per day. The Company's ownership is fixed at 7.4%. The operator of the
plant is ExxonMobil.
o Iowa, Jefferson Davis Parish, Louisiana: a cryogenic plant built
during the mid 1970s with a throughput capacity of 500 million cubic
feet per day. Ownership is based on a combination of fixed gas units
and variable NGL production. The Company's ownership is currently
approximately 2%. The operator of the plant is Texas Eastern
Transmission Company.
o Pascagoula, Mississippi: a cryogenic plant with 1.0 billion cubic feet
per day of capacity in two trains (500 million cubic feet per day
each). The first train commenced operation in February 1999 and the
second is came on line in the fourth quarter of 1999. The Company's
ownership is fixed at 40%. Amoco, which operates the facility, owns
the other 60%.
The Company's Natural Gas Processing and related merchant activity
Contracts and Customers. The primary contracts that are an integral part of the
gas processing business and related merchant activities are as follows:
o As result of the TNGL acquisition effective August 1, 1999, the
Company obtained the Shell Processing Agreement which is a 20-year
exclusive natural gas processing agreement with Shell for the rights
to process its current and future natural gas production from the
state and federal waters of the Gulf of Mexico on a keepwhole basis.
The ability to process the NGL-rich deepwater developments of Shell in
the Gulf of Mexico was one of the leading value drivers of the TNGL
acquisition.
19
Generally, the Shell Processing Agreement grants the Company the
following rights and obligations:
o the exclusive right to process any and all of Shell's Gulf of Mexico
natural gas production from existing and future dedicated leases; plus
o the right to all title, interest, and ownership in the raw make
extracted by the Company's gas processing facilities from Shell's
natural gas production from such leases; with
o the obligation to deliver to Shell the natural gas stream after the
raw make is extracted.
o The Company has also entered into contracts to sell isobutane to Global
Octanes, Texas Petrochemicals, Equistar, Citgo, Crown Central and Texaco.
The Company has long-standing business relationships with Global Octanes
and Texas Petrochemicals. Both of these contracts were renegotiated in 1998
and provide for the delivery of isobutane on the Company's pipeline for a
fee. The term of the Global Octanes contract extends to April 2002, and the
Texas Petrochemicals contract extends to August 2003. Prices under these
contracts generally are based on the spot market price for isobutane at
Mont Belvieu. The Company can meet its sales obligations either by:
o purchasing normal butane in the spot market or utilizing normal butane
inventory from the gas plants and isomerizing it;
o purchasing mixed butane on the spot market, including imports,
and processing it through a DIB; or
o purchasing isobutane in the spot markets or utilizing isobutane
inventory from the gas.
When the price differential between normal butane and isobutane is not
substantial enough to justify isomerization, the Company purchases isobutane (or
uses its own inventory of isobutane from the fractionation facilities) and
delivers it to sales customers who pay market-based prices. Accordingly, the
percentage of isomerization volumes represented by processing customers
increases when the spread between normal butane and isobutane prices is narrow.
Railway Transportation Assets. The Company utilizes a fleet of
approximately 725 rail cars as part of its operations. These assets can be
described as follows:
o a fleet of approximately 270 rail cars under short and
long-term leases used to deliver feedstocks to Mont Belvieu
and transport NGL products throughout the United States;
o a fleet of approximately 400 rail cars on average under
short-term lease by the operations acquired as a result of the
TNGL acquisition for servicing its related merchant activities
(the Company assumed these leases as part of the acquisition);
and,
o a fleet of 55 rail cars in propane service owned by the Company
that were acquired in the TNGL acquisition. Each car has storage
capacity of approximately 30,000 gallons of propane.
The Company also has rail loading/unloading facilities at Mont Belvieu,
Texas, Breaux Bridge, Louisiana and Petal, Mississippi to service its and
customers' rail shipments. The costs of maintaining the rail cars and associated
assets are a cost of the NGL merchant business.
Natural Gas Processing Equity Production Volumes and Utilization Rates.
The throughput capacities of the gas processing facilities are based on
practical limitations. The Company's utilization of the gas processing assets
depends upon general economic and operating conditions. The Company uses its
equity production of NGLs from such facilities as a barometer of activity at the
plants. Equity production is a function of throughput (i.e., higher throughput
rates translate into higher equity volumes) and can be defined as the volume of
NGLs extracted by the processing facilities to which the Company takes title
under the terms of its processing agreements or as result of its plant ownership
interests. For the period August 1, 1999 through December 31, 1999, the equity
volumes produced by the gas processing facilities averaged 67 MBPD. For
comparison purposes, the gas processing facilities averaged 57 MBPD for the full
year of 1999. In 1998, the same assets produced an average of 41 MBPD. The
increase in equity production from 1998 to 1999 is attributable to increased
Gulf of Mexico deepwater production, the start-up of the Pascagoula facility in
1999, and improved pricing of NGLs which justified higher extraction rates.
The Company's cost method investment in VESCO. The Company's investment
in VESCO consists of a 13.1% economic interest in a limited liability company
owning a natural gas processing plant, fractionation facilities, storage, and
gas gathering pipelines in Louisiana. The other owners of VESCO are Chevron,
20
Koch, Venice Gathering, and Dynegy with Dynegy being the operator of the
facilities. The Company's ownership interest in VESCO is the result of the TNGL
acquisition. The primary assets of VESCO (all located in Plaquemines Parish,
Louisiana) are:
o a lean oil plant with 1.0 billion cubic feet per day of capacity;
o a cryogenic plant with 300 million cubic feet per day of capacity;
o a NGL fractionation facility with a capacity of 36,000 barrels per
day;
o eight salt storage dome caverns (one for brine and seven for NGLs)
having a storage capacity of 12 million barrels of NGLs;
o a NGL barge loading and unloading facility and pumps for delivering
ethane to a customer's pipeline;
o approximately 250 miles of regulated pipelines with a throughput
capacity of 810 million cubic feet per day called the Venice Gathering
System; and
o 30,000 horsepower of compression capacity and gas dehydration
facilities.
OTHER
This operating segment is primarily comprised of fee-based marketing
activities. The Company performs NGL marketing services for a small number of
customers for which it charges a commission. The customers served are primarily
located in California, Illinois, Florida, and Washington state. The Company
utilizes the resources of its gas processing merchant business group to perform
these services. Fees charged to customers are based on either a percent of the
final sales price or a fixed-fee per gallon. The Company handles approximately
22,250 barrels per day of various NGL products through its fee-based services
with the period of highest activity occurring during the winter months. This
segment also includes other engineering services, construction equipment rentals
and computer network services that support plant operations.
COMPETITION
The consumption of NGL products in the United States can be separated
among four distinct markets. Petrochemical production provides the largest
end-use market, followed by motor gasoline production, residential and
commercial heating and agricultural uses. There are other hydrocarbon
alternatives, primarily refined petroleum products, which can be substituted for
NGL products in most end uses. In some uses, such as residential and commercial
heating, a substitution of other hydrocarbon products for NGL products would
require a significant expense or delay, but for other uses, such as the
production of motor gasoline, ethylene, industrial fuels and petrochemical
feedstocks, such a substitution can be readily made without significant delay or
expense.
Because certain NGL products compete with other refined petroleum
products in the fuel and petrochemical feedstock markets, NGL product prices are
set by or in competition with refined petroleum products. Increased production
and importation of NGLs and NGL products in the United States may decrease NGL
product prices in relation to refined petroleum alternatives and thereby
increase consumption of NGL products as NGL products are substituted for other
more expensive refined petroleum products. Conversely, a decrease in the
production and importation of NGLs and NGL products could increase NGL product
prices in relation to refined petroleum product prices and thereby decrease
consumption of NGLs. However, because of the relationship of crude oil and
natural gas production to NGL production, the Company believes any imbalance in
the prices of NGLs and NGL products and alternative products would be temporary.
Although competition for NGL product fractionation services is based
primarily on the fractionation fee, the ability of a fractionator to obtain and
distribute product is a function of the existence of the necessary pipelines and
transportation facilities. A fractionator connected to an extensive
transportation and distribution system has direct access to a larger market than
its competitors. Overall, the Company believes it provides a broader range of
services than any of its competitors at Mont Belvieu. In addition, the Company
believes its joint venture relationships enable it to contract for the long-term
utilization of a significant amount of its fractionation facilities with major
producers and consumers of NGLs or NGL products.
21
The Company's Mont Belvieu fractionation facility competes for volumes
of mixed NGLs with three other fractionators at Mont Belvieu: Cedar Bayou
Fractionators, a joint venture between Dynegy and Amoco (205,000 barrels per day
capacity); Gulf Coast Fractionators, a joint venture of Conoco, Mitchell and
Dynegy (110,000 barrels per day capacity); and Diamond-Koch, a joint venture
between Ultramar Diamond, Koch and Union Pacific Resources (reported to be less
than 150,000 barrels per day capacity). ExxonMobil operates a fractionation
facility (110,000 barrels per day capacity) in Hull, Texas that is connected to
Mont Belvieu by pipeline and Phillips Petroleum operates a fractionation
facility (100,000 barrels per day capacity) in Sweeny, Texas that is connected
to Mont Belvieu by pipeline. ExxonMobil and Phillips use their facilities
primarily to process their own NGL production but at certain times these
facilities compete with the fractionators at Mont Belvieu. The Company's
fractionation facilities also compete on a more limited basis with two
fractionators in Conway, Kansas: Williams (107,000 barrels per day capacity) and
Koch (200,000 barrels per day capacity) and with a number of decentralized,
smaller fractionation facilities in Louisiana, the most significant of which are
Promix at Napoleonville, in which the Company owns a one-third interest (145,000
barrels per day capacity), Texaco/Williams at Paradis (45,000 barrels per day
capacity) and TransCanada at Eunice and Riverside (62,000 barrels per day
combined capacity). In recent years, the Conway market has experienced excess
capacity and prices for NGL products that are generally lower than prices at
Mont Belvieu, although prices in Conway tend to strengthen along with demand for
propane in winter months. Finally, a number of producers operate smaller-scale
fractionators at individual field processing facilities.
In the isomerization market, the Company competes primarily with Koch
at Conway, Kansas; Enron at Riverside, Louisiana; and Conoco at Wingate, New
Mexico. Enron and Valero also produce isobutane, primarily for internal
production of MTBE. Competitive factors affecting isomerization operations
include the price differential between normal butane and isobutane as well as
the fees charged for isomerization services, long-term contracts, the
availability of merchant capacity, the ability to produce a higher purity
isobutane product and storage and transportation support.
BEF competes with a number of MTBE producers, including a number of
refiners who produce MTBE for internal consumption in the manufacture of
reformulated motor gasoline. Competitive factors affecting MTBE production
include production costs, long-term contracts, the availability of merchant
capacity and federal and state environmental regulations relating to the content
of motor gasoline.
The Company competes with numerous producers of high purity propylene,
which include many of the major refiners on the Gulf Coast. The Company and
Ultramar Diamond Shamrock are the primary domestic commercial producers of high
purity propylene from refinery-sourced propane/propylene mix. High purity
propylene is also produced as a by-product from steam crackers used in ethylene
production.
Certain of the Company's competitors are major oil and natural gas
companies and other large integrated pipeline or energy companies that have
greater financial resources than the Company. The Company believes its
independence from the major producers of NGLs and petrochemical companies is
often an advantage in its dealings with its customers, but the Company's
continued success will depend upon its ability to maintain strong relationships
with the primary producers of NGLs and consumers of NGL products, particularly
in the form of long-term contracts and joint venture relationships.
The United States Gulf Coast gas processing business is competitive.
The Company encounters competition from fully integrated oil companies, pipeline
companies and their non-regulated affiliates, and independent processors. Each
of these companies have varying levels of financial and personnel resources. The
principal areas of competition include obtaining the gas plant capacities
required to meet the Company's processing needs, obtaining gas supplies where
the Company has excess processing capacity and in the marketing of the final NGL
products. With the TNGL acquisition, the Company has obtained the infrastructure
and experience to effectively compete in this market.
In the Company's fee-based marketing services, the principal methods of
competition revolves around price and quality of service.
22
MAJOR CUSTOMERS OF THE COMPANY
The Company's revenues are derived from a wide customer base. As such,
no single customer accounted for more than 10% of consolidated revenues in
fiscal 1999. For a more complete discussion of significant customers in the last
three fiscal years, see Note 9 of the Notes to the Consolidated Financial
Statements.
SIGNIFICANT AGREEMENT WITH EPCO
The Company has no employees. All management, administrative and
operating functions are performed by employees of EPCO. Operating costs and
expenses include charges for EPCO's employees who operate the Company's various
facilities. Such charges are based upon EPCO's actual salary costs and related
fringe benefits.
In connection with the Company's initial public offering ("IPO") on
July 27, 1998, EPCO, the General Partner and the Company entered into the EPCO
Agreement pursuant to which (i) EPCO agreed to manage the business and affairs
of the Company and the Operating Partnership; (ii) EPCO agreed to employ the
operating personnel involved in the Company's business for which EPCO is
reimbursed by the Company at cost; (iii) the Company and the Operating
Partnership agreed to participate as named insureds in EPCO's current insurance
program, and costs are allocated among the parties on the basis of formulas set
forth in the agreement; (iv) EPCO agreed to grant an irrevocable, non-exclusive
worldwide license to all of the trademarks and trade names used in its business
to the Company; (v) EPCO agreed to indemnify the Company against any losses
resulting from certain lawsuits; and (vi) EPCO agreed to sublease all of the
equipment which it holds pursuant to operating leases relating to an
isomerization unit, a deisobutanizer tower, two cogeneration units and
approximately 100 rail cars to the Company for $1 per year and assigned its
purchase options under such leases to the Company (hereafter referred to as
"Retained Leases"). Pursuant to the EPCO Agreement, EPCO is reimbursed at cost
for all expenses that it incurs in connection with managing the business and
affairs of the Company, except that EPCO is not entitled to be reimbursed for
any selling, general and administrative expenses. In lieu of reimbursement for
such selling, general and administrative expenses, EPCO is entitled to receive
an annual administrative services fee that initially equals $12.0 million. The
General Partner, with the approval and consent of the Audit and Conflicts
Committee of the Company, has the right to agree to increases in such
administrative services fee of up to 10% each year during the 10-year term of
the EPCO Agreement and may agree to further increases in such fee in connection
with expansions of the Company's operations through the construction of new
facilities or the completion of acquisitions that require additional management
personnel. On July 7, 1999, the Audit and Conflicts Committee of the General
Partner authorized an increase in the administrative services fee to $1.1
million per month from the initial $1.0 million per month. The increased fees
were effective August 1, 1999. Beginning in January 2000, the administrative
services fee will increase to $1.55 million per month plus accrued employee
incentive plan costs to compensate EPCO for the additional selling, general, and
administrative charges related to the additional administrative employees
acquired in the TNGL acquisition.
EMPLOYEES
At December 31, 1999, EPCO employed approximately 680 employees
involved in the management and operation of assets owned and operated by the
Company; none of them were members of a union. The Norco facilities are managed
by the Company with the assets operated under contract by union employees of a
Shell affiliate. Shell's relationship with its union employees at Norco can be
characterized as good and the Company believes that this relationship will
continue.
REGULATION
INTERSTATE COMMON CARRIER PIPELINE REGULATION
The Company's Chunchula and Lake Charles/Bayport pipelines are
interstate common carrier oil pipelines subject to regulation by Federal Energy
Regulatory Commission ("FERC") under the October 1, 1977 version of the
Interstate Commerce Act ("ICA").
23
Standards for Terms of Service and Rates. As interstate common
carriers, the Chunchula and Lake Charles/Bayport pipelines provide service to
any shipper who requests transportation services, provided that the products
tendered for transportation satisfy the conditions and specifications contained
in the applicable tariff. The ICA requires the Company to maintain tariffs on
file with the FERC that set forth the rates the Company charges for providing
transportation services on the interstate common carrier pipelines as well as
the rules and regulations governing these services.
The ICA gives the FERC authority to regulate the rates the Company
charges for service on the interstate common carrier pipelines. The ICA
requires, among other things, that such rates be "just and reasonable" and
nondiscriminatory. The ICA permits interested persons to challenge proposed new
or changed rates and authorizes the FERC to suspend the effectiveness of such
rates for a period of up to seven months and to investigate such rates. If, upon
completion of an investigation, the FERC finds that the new or changed rate is
unlawful, it is authorized to require the carrier to refund the revenues in
excess of the prior tariff collected during the pendency of the investigation.
The FERC may also investigate, upon complaint or on its own motion, rates that
are already in effect and may order a carrier to change its rates prospectively.
Upon an appropriate showing, a shipper may obtain reparations for damages
sustained for a period of up to two years prior to the filing of a complaint.
On October 24, 1992, Congress passed the Energy Policy Act of 1992
("Energy Policy Act"). The Energy Policy Act deemed petroleum pipeline rates
that were in effect for the 365-day period ending on the date of enactment or
that were in effect on the 365th day preceding enactment and had not been
subject to complaint, protest or investigation during the 365-day period to be
just and reasonable under the ICA (i.e., "grandfathered"). The Energy Policy Act
also limited the circumstances under which a complaint can be made against such
grandfathered rates. In order to challenge grandfathered rates, a party would
have to show that it was previously contractually barred from challenging the
rates or that the economic circumstances or the nature of the service underlying
the rate had substantially changed or that the rate was unduly discriminatory or
preferential. These grandfathering provisions and the circumstances under which
they may be challenged have received only limited attention from the FERC,
causing a degree of uncertainty as to their application and scope.
The Energy Policy Act required the FERC to issue rules establishing a
simplified and generally applicable ratemaking methodology for petroleum
pipelines, and to streamline procedures in petroleum pipeline proceedings. The
FERC responded to this mandate by issuing Order No. 561, which, among other
things, adopted a new indexing rate methodology for petroleum pipelines. Under
the new regulations, which became effective January 1, 1995, petroleum pipelines
are able to change their rates within prescribed ceiling levels that are tied to
an inflation index. Rate increases made within the ceiling levels will be
subject to protest, but such protests must show that the portion of the rate
increase resulting from application of the index is substantially in excess of
the pipeline's increase in costs. If the indexing methodology results in a
reduced ceiling level that is lower than a pipeline's filed rate, Order No. 561
requires the pipeline to reduce its rate to comply with the lower ceiling. Under
Order No. 561, a pipeline must as a general rule utilize the indexing
methodology to change its rates. The FERC, however, retained cost-of-service
ratemaking, market-based rates, and settlement as alternatives to the indexing
approach, which alternatives may be used in certain specified circumstances.
The Company believes the rates it charges for transportation service on
its interstate pipelines have been grandfathered under the Energy Policy Act and
are thus considered just and reasonable under the ICA. As discussed above,
however, because of the uncertainty related to the application of the Energy
Policy Act's grandfathering provisions to the Company's rates as well as the
novelty and uncertainty related to the FERC's new indexing methodology, the
Company is unable to predict what rates it will be allowed to charge in the
future for service on its interstate common carrier pipelines. Furthermore,
because rates charged for transportation must be competitive with those charged
by other transporters, the rates set forth in the Company's tariffs will be
determined based on competitive factors in addition to regulatory
considerations.
Allowance for Income Taxes in Cost of Service. In a 1995 decision
regarding Lakehead Pipe Line Company ("Lakehead"), FERC ruled that an interstate
pipeline owned by a limited partnership could not include in its cost of service
an allowance for income taxes with respect to income attributable to limited
partnership interests held by individuals. On request in 1996, FERC clarified
that, in order to avoid any effect of a "curative allocation" of income from
individual partners to the corporate partner, an allowance for income taxes paid
by corporate partners must be based on income as reflected on the pipeline's
24
books for earning and distribution rather than as reported for income tax
purposes. Subsequent appeals of these rulings were resolved by a 1997 settlement
among the parties and were never adjudicated. The effect of this policy on the
Company is uncertain. The Company's rates are set using the indexing method and
have been grandfathered. It is possible that a party might challenge the
Company's grandfathered rates on the basis that the creation of the Company
constituted a substantial change in circumstances, potentially lifting the
grandfathering protection. Alternatively, a party might contend that, in light
of the Lakehead ruling and creation of the Company, the Company's rates are not
just and reasonable. While it is not possible to predict the likelihood that
such challenges would succeed at FERC, if such challenges were to be raised and
succeed, application of the Lakehead ruling would reduce the Company's
permissible income tax allowance in any cost of service, and rates, to the
extent income is attributable to partnership interests held by individual
partners rather than corporations.
INTRASTATE COMMON CARRIER REGULATION
The Sorrento NGL products pipeline, the Yscloskey and Toca-to-Norco
petroleum products pipeline, the Norco-to-Sorrento and the Tebone-to-Vulcan,
Sorrento, Norco, and Geismar ethane pipelines and the Norco-to-Sorrento propane
pipeline are intrastate common carrier pipelines that are subject to various
Louisiana state laws and regulations that affect the terms of service and rates
for such services. The Company's Houston Ship Channel pipeline and the remainder
of its Louisiana pipelines are intrastate private carriers not subject to rate
regulation.
OTHER STATE AND LOCAL REGULATION
The Company's activities are subject to various state and local laws
and regulations, as well as orders of regulatory bodies pursuant thereto,
governing a wide variety of matters, including marketing, production, pricing,
community right-to-know, protection of the environment, safety and other
matters.
COGENERATION
The Company cogenerates electricity for internal consumption and heat
for a process-related hot oil system at Mont Belvieu. If this electricity were
sold to third parties, the Company's Mont Belvieu cogeneration facilities could
be certified as qualifying facilities under the Public Utility Regulatory Policy
Act of 1978 ("PURPA"). Subject to compliance with certain conditions under
PURPA, this certification would exempt the Company from most of the regulations
applicable to electric utilities under the Federal Power Act and the Public
Utility Holding Company Act, as well as from most state laws and regulations
concerning the rates, finances, or organization of electric utilities. However,
since such electric power is consumed entirely by the Company's plant
facilities, the Company's cogeneration activities are not subject to public
utility regulation under federal or Texas law.
ENVIRONMENTAL MATTERS
General. The operations of the Company are subject to federal, state
and local laws and regulations relating to release of pollutants into the
environment or otherwise relating to protection of the environment. The Company
believes its operations and facilities are in general compliance with applicable
environmental regulations.
However, risks of process upsets, accidental releases or spills are
associated with the Company's operations and there can be no assurance that
significant costs and liabilities will not be incurred, including those relating
to claims for damage to property and persons.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the environment, such
as emissions of pollutants, generation and disposal of wastes and use and
handling of chemical substances. The usual remedy for failure to comply with
these laws and regulations is the assessment of administrative, civil and, in
some instances, criminal penalties or, in rare circumstances, injunctions. The
Company believes the cost of compliance with environmental laws and regulations
will not have a material adverse effect on the results of operations or
financial position of the Company. However, it is possible that the costs of
compliance with environmental laws and regulations will continue to increase,
and thus there can be no assurance as to the amount or timing of future
expenditures for environmental compliance or remediation, and actual future
expenditures may be different from the amounts currently anticipated. In the
25
event of future increases in costs, the Company may be unable to pass on those
increases to its customers. The Company will attempt to anticipate future
regulatory requirements that might be imposed and plan accordingly in order to
remain in compliance with changing environmental laws and regulations and to
minimize the costs of such compliance.
Solid Waste. The Company currently owns or leases, and has in the past
owned or leased, properties that have been used over the years for NGL
processing, treatment, transportation and storage and for oil and natural gas
exploration and production activities. Solid waste disposal practices within the
NGL industry and other oil and natural gas related industries have improved over
the years with the passage and implementation of various environmental laws and
regulations. Nevertheless, a possibility exists that hydrocarbons and other
solid wastes may have been disposed of on or under various properties owned by
or leased by the Company during the operating history of those facilities. In
addition, a small number of these properties may have been operated by third
parties over whom the Company had no control as to such entities' handling of
hydrocarbons or other wastes and the manner in which such substances may have
been disposed of or released. State and federal laws applicable to oil and
natural gas wastes and properties have gradually become more strict and,
pursuant to such laws and regulations, the Company could be required to remove
or remediate previously disposed wastes or property contamination including
groundwater contamination. The Company does not believe that there presently
exists significant surface and subsurface contamination of the Company
properties by hydrocarbons or other solid wastes.
The Company generates both hazardous and nonhazardous solid wastes
which are subject to requirements of the federal Resource Conservation and
Recovery Act ("RCRA") and comparable state statutes. From time to time, the
Environmental Protection Agency ("EPA") has considered making changes in
nonhazardous waste standards that would result in stricter disposal requirements
for such wastes. Furthermore, it is possible that some wastes generated by the
Company that are currently classified as nonhazardous may in the future be
designated as "hazardous wastes," resulting in the wastes being subject to more
rigorous and costly disposal requirements. Such changes in the regulations may
result in additional capital expenditures or operating expenses by the Company.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, and similar state
laws, impose liability without regard to fault or the legality of the original
conduct, on certain classes of persons, including the owner or operator of a
site and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the EPA and, in some cases,
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. Although "petroleum" is excluded from CERCLA's definition of a
"hazardous substance," in the course of its ordinary operations the Company will
generate wastes that may fall within the definition of a "hazardous substance."
The Company 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
has not received any notification that it may be potentially responsible for
cleanup costs under CERCLA.
Clean Air Act--General. The operations of the Company are subject to
the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act
were adopted in 1990 and contain provisions that may result in the imposition of
certain pollution control requirements with respect to air emissions from the
operations of the pipelines and the processing and storage facilities. For
example, the Mont Belvieu processing and storage facility is located in the
Houston-Galveston ozone non-attainment area, which is categorized as a "severe"
area and, therefore, is subject to more restrictive regulations for the issuance
of air permits for new or modified facilities. The Houston-Galveston area is
among nine areas in the country in this "severe" category. One of the other
consequences of this non-attainment status is the potential imposition of lower
limits on the emissions of certain pollutants, particularly oxides of nitrogen
which are produced through combustion, as in the gas turbines at the Mont
Belvieu processing facility. Regulations imposing these new requirements on
existing facilities will not be promulgated until the end of 2000, and,
therefore, it is not possible at this time to assess the impact these
requirements may have on the Company's operations. Failure to comply with these
air statutes or the implementing regulations may lead to the assessment of
administrative, civil or criminal penalties, and/or result in the limitation or
cessation of construction or operation of certain air emission sources. As part
of the regular overall evaluation of its current operations, the Company is
updating certain of its operating permits. The Company believes its operations,
including its processing facilities, pipelines and storage facilities, are in
substantial compliance with applicable air requirements.
Clean Air Act--Fuels. See discussion of Octane Enhancement -
Recent Regulatory Developments.
26
Clean Water Act. The Federal Water Pollution Control Act, also known as
the Clean Water Act, and similar state laws require containment of potential
discharges of contaminants into federal and state waters. Regulations
promulgated pursuant to these laws require that entities such as the Company
that discharge into federal and state waters obtain National Pollutant Discharge
Elimination System ("NPDES") and/or state permits authorizing these discharges.
The Clean Water Act and analogous state laws provide penalties for releases of
unauthorized contaminants into the water and impose substantial liability for
the costs of removing spills from such waters. In addition, the Clean Water Act
and analogous state laws require that individual permits or coverage under
general permits be obtained by covered facilities for discharges of stormwater
runoff. The Company believes it will be able to obtain, or be included under,
these Clean Water Act permits and that compliance with the conditions of such
permits will not have a material effect on the Company.
Underground Storage Requirements. The Company currently owns and
operates underground storage caverns that have been created in naturally
occurring salt domes in Texas, Louisiana and Mississippi. These storage caverns
are used to store NGLs, NGL products, propane/propylene mix and propylene.
Surface brine pits and brine disposal wells are used in the operation of the
storage caverns. All of these facilities are subject to strict environmental
regulation by state authorities under the Texas Natural Resources Code and
similar statutes in Louisiana and Mississippi. Regulations implemented under
such statutes address the operation, maintenance and/or abandonment of such
underground storage facilities, pits and disposal wells, and require that
permits be obtained. Failure to comply with the governing statutes or the
implementing regulations may lead to the assessment of administrative, civil or
criminal penalties. The Company believes its salt dome storage operations,
including the caverns, brine pits and brine disposal wells, are in substantial
compliance with applicable statutes.
SAFETY REGULATION
The Company's pipelines are subject to regulation by the U.S.
Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as
amended ("HLPSA"), relating to the design, installation, testing, construction,
operation, replacement and management of pipeline facilities. The HLPSA covers
crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any
entity which owns or operates pipeline facilities to comply with the regulations
under the HLPSA, to permit access to and allow copying of records and to make
certain reports and provide information as required by the Secretary of
Transportation. The Company believes its pipeline operations are in substantial
compliance with applicable HLPSA requirements; however, due to the possibility
of new or amended laws and regulations or reinterpretation of existing laws and
regulations, there can be no assurance that future compliance with the HLPSA
will not have a material adverse effect on the Company's results of operations
or financial position.
The workplaces associated with the processing and storage facilities
and the pipelines operated by the Company are also subject to the requirements
of the federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. The Company believes it has operated in substantial compliance with
OSHA requirements, including general industry standards, record keeping
requirements and monitoring of occupational exposure to regulated substances.
In general, the Company expects expenditures will increase in the
future to comply with likely higher industry and regulatory safety standards
such as those described above. Such expenditures cannot be accurately estimated
at this time, although the Company does not expect that such expenditures will
have a material adverse effect on the Company.
TITLE TO PROPERTIES
Real property held by the Company falls into two basic categories: (a)
parcels that it owns in fee, such as the land at the Mont Belvieu complex and
Petal fractionation and storage facility, and (b) parcels in which its interest
derives from leases, easements, rights-of-way, permits or licenses from
landowners or governmental authorities permitting the use of such land for
Company operations. The fee sites upon which the major facilities are located
have been owned by the Company or its predecessors in title for many years
without any material challenge known to the Company relating to title to the
land upon which the assets are located, and the Company believes it has
satisfactory title to such fee sites. The Company has no knowledge of any
27
challenge to the underlying fee title of any material lease, easement,
right-of-way or license held by it or to its title to any material lease,
easement, right-of-way, permit or lease, and the Company believes it has
satisfactory title to all of its material leases, easements, rights-of-way and
licenses.
ITEM 3. LEGAL PROCEEDINGS.
EPCO has indemnified the Company against any litigation pending as of
the date of its formation. The Company is sometimes named as a defendant in
litigation relating to its normal business operations. Although the Company
insures itself against various business risks, to the extent management believes
it is prudent, there is no assurance that the nature and amount of such
insurance will be adequate, in every case, to indemnify the Company against
liabilities arising from future legal proceedings as a result of its ordinary
business activity. Management is aware of no significant litigation, pending or
threatened, that would have a significant adverse effect on the Company's
financial position or results of operations
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during
1999.
28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS
The following table sets forth the high and low sale prices per Common
Unit (as reported under the symbol "EPD" on the New York Stock Exchange), the
amount of cash distributions paid per Common Unit and Subordinated Unit and the
record and payment dates related to such cash distributions. The Common Units
began trading on July 28, 1998.
Cash Distributions
--------------------------------------------------------------------------
Price Range Per Common Per Subordinated Record Payment
High Low Unit Unit Date Date
-------------------------------------------------------------------------------------------------
1998
- ----
Third Quarter $ 22.063 $ 14.625
Fourth Quarter $ 18.375 $ 13.750 $ 0.32 $ 0.32 October 30,1998 November 12, 1998
1999
- ----
First Quarter $ 18.500 $ 14.938 $ 0.45 $ 0.45 January 29,1999 February 11, 1999
Second Quarter $ 18.625 $ 15.063 $ 0.45 $ 0.07 April 30, 1999 May 12, 1999
Third Quarter $ 20.688 $ 17.875 $ 0.45 $ 0.37 July 30, 1999 August 11, 1999
Fourth Quarter $ 20.375 $ 17.000 $ 0.45 $ 0.45 October 29, 1999 November 10, 1999
2000
- ----
First Quarter $ 20.500 $ 18.250 $ 0.50 $ 0.50 January 31, 2000 February 10, 2000
(through February 25, 2000)
The Company intends, to the extent there is sufficient available cash
from Operating Surplus, as defined by the Partnership Agreement, to distribute
to each holder of Common Units at least a minimum quarterly distribution of
$0.45 per Common Unit. The minimum quarterly distribution is not guaranteed and
is subject to adjustment as set forth in the Partnership Agreement. With respect
to each quarter during the subordination period, which will generally not end
before June 30, 2003, the Common Unitholders will generally have the right to
receive the minimum quarterly distribution, plus any arrearages thereon, and the
General Partner will have the right to receive the related distribution on its
interest before any distributions of available cash from Operating Surplus are
made to the Subordinated Unitholders.
From its inception through the fourth quarter 1999, the Company paid
its minimum quarterly distribution of $.45 per Common Unit. The $.32 cash
distribution made during the fourth quarter 1998 was based upon the minimum
quarterly distribution of $0.45 per Unit adjusted to take into account the
65-day period of the third quarter during which the Company was a public entity.
On January 17, 2000, the Company declared an increase in its quarterly cash
distribution to $0.50 per Unit. This represents a $0.05 per unit, or an 11.1%,
increase from its previous distribution rate of $0.45 per Unit. The distribution
was paid on Feb. 10, 2000 to Common and Subordinated Unitholders of record at
the close of business on Jan. 31, 2000. The increase is attributable to the
growth in cash flow that the Company has achieved through the completion of new
projects, improved operating results, and accretive acquisitions. Although the
payment of such quarterly distributions are not guaranteed, the Company
currently expects that it will continue to pay comparable cash distributions in
the future.
As of February 4, 2000, there were approximately 198 Unitholders of
record of the Company's Common Units.
Recent Sales of Unregistered Securities
On August 1, 1999, the Company acquired TNGL from Tejas Energy (now
Coral Energy LLC) an affiliate of Shell, in exchange for 14.5 million
non-distribution bearing, convertible special partner Units of the Company (the
"Special Units") and cash payment of $166 million. Coral Energy also has the
right to acquire up to 6.0 million additional Special Units if the volumes of
natural gas processed by the Company for Shell reach certain agreed upon levels
in 2000 and 2001. The 14.5 million Special Units will automatically convert into
Common Units on a one-for-one basis as follows: 1.0 million on August 1, 2000
29
(or the day following the record date for distributions for the second quarter
of 2000); 5.0 million units on August 1, 2001; and 8.5 million on August 1,
2002. If all of the 6.0 million contingent Units are issued, they would convert
into Common Units on August 1, 2002 (1.0 million Units) and August 1, 2003 (5.0
million Units).
No underwriter was involved in the transaction, and the issuance of the
convertible Special Units was not registered under the Securities Act of 1933 in
reliance upon the exemption provided by Section 4(2) thereof. The Company is
entitled to rely upon Section 4(2) in connection with this transaction because
it was a privately negotiated transaction with a single accredited investor.
30
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth for the periods and at the dates
indicated, selected historical financial data for the Company. The selected
historical financial data (except for EBITDA of unconsolidated affiliates) have
been derived from the Company's audited financial statements for the periods
indicated. The selected historical income statement data for each of the three
years in the period ended December 31, 1999 and the selected balance sheet data
as of December 31, 1999 and 1998 should be read in conjunction with the audited
financial statements for such periods included elsewhere in this report. EBITDA
of unconsolidated affiliates has been derived from the financial statements of
such entities for the periods indicated. See also "Management's Discussion and
Analysis of Financial Condition and Results of Operation." The dollar amounts in
the table below, except per Unit data, are in thousands.
For the Year Ended December 31,
------------------------------------------------------------------------
1995 1996 1997 1998 1999 (6)
------------------------------------------------------------------------
INCOME STATEMENT DATA:
Revenues from consolidated operations $ 790,080 $ 999,506 $ 1,020,281 $ 738,902 $ 1,332,979
Equity in income of unconsolidated affiliates 12,274 15,756 15,682 15,671 13,477
------------------------------------------------------------------------
Total 802,354 1,015,262 1,035,963 754,573 1,346,456
Operating costs and expenses (1) 719,389 907,524 938,392 685,884 1,201,605
------------------------------------------------------------------------
Operating margin 82,965 107,738 97,571 68,689 144,851
Selling, general and administrative expenses(1,2) 21,120 23,070 21,891 18,216 12,500
------------------------------------------------------------------------
Operating income 61,845 84,668 75,680 50,473 132,351
Interest expense (27,567) (26,310) (25,717) (15,057) (16,439)
Interest income 554 2,705 1,934 772 886
Interest income from unconsolidated affiliates 809 1,667
Dividend income from unconsolidated affiliates 3,435
Other income (expense), net 305 364 793 358 (379)
------------------------------------------------------------------------
Income before extraordinary charge and
minority interest 35,137 61,427 52,690 37,355 121,521
Extraordinary charge on early
extinguishment of debt - - - (27,176) -
------------------------------------------------------------------------
Income before minority interest 35,137 61,427 52,690 10,179 121,521
Minority interest (351) (614) (527) (102) (1,226)
========================================================================
Net income $ 34,786 $ 60,813 $ 52,163 $ 10,077 $ 120,295
========================================================================
Basic Net income per Unit (3) $0.63 $1.10 $0.94 $0.17 $ 1.79
Number of Units used for basic EPU (in 000s) 54,962.8 54,962.8 54,962.8 60,124.4 66,710.4
Diluted Net income per Unit (3) $ 1.64
Number of Units used for diluted EPU (in 000s) 72,788.5
Dividends declared per Common Unit $0.77 $ 1.85
BALANCE SHEET DATA (AT PERIOD END):
Total assets $ 610,931 $ 711,151 $ 697,713 $ 741,037 $ 1,494,952
Long-term debt 281,656 255,617 230,237 90,000 295,000
Combined equity/Partners' equity 198,815 266,021 311,885 562,536 789,465
OTHER FINANCIAL DATA:
Cash flows from operating activities $ 12,212 $ 91,431 $ 57,795 $ (20,294) $ 168,810
Cash flows from investing activities (9,233) (57,725) (30,982) (50,695) (265,221)
Cash flows from financing activities 11,995 (24,930) (26,551) 61,238 77,538
EBITDA (4) 65,406 87,109 79,882 55,472 147,050
EBITDA of unconsolidated affiliates(5) 18,520 25,012 24,372 23,912 23,425
31
Notes to Selected Financial Data Table
(1) Certain 1995 through 1998 amounts have been reclassified to conform to the
1999 presentation.
(2) 1998 and 1999 expenses are lower than 1997 amounts due to the adoption of
the EPCO agreement.
(3) Basic net income per Unit is computed by dividing the limited partners' 99%
interest in Net income by the weighted average of the number of Common and
Subordinated Units outstanding. Diluted net income per Unit is computed by
dividing the limited partners' 99% interest in Net income by the weighted
average of the number of Common, Subordinated, and Special Units
outstanding.
(4) EBITDA is defined as net income plus depreciation and amortization and
interest expense less equity in income of unconsolidated affiliates.
Interest expense (excluding amortization of loan costs) was $14.7 million
and $14.9 million in 1998 and 1999, respectively. EBITDA should not be
considered as an alternative to net income, operating income, cash flow
from operations or any other measure of financial performance presented in
accordance with generally accepted accounting principals. EBITDA is not
intended to represent cash flow and does not represent the measure of cash
available for distribution, but provides additional information for
evaluating the Company's ability to make the minimum quarterly
distribution. Management uses EBITDA to assess the viability of projects
and to determine overall rate of returns on alternative investment
opportunities. Because EBITDA excludes some, but not all, items that affect
net income and this measure may vary among companies, the EBITDA data
presented above may not be comparable to similarly titled measures of other
companies. EBITDA for 1998 excludes the extraordinary charge of $27,176
million related to the early extinguishment of debt.
(5) Represents the Company's pro rata share of net income plus depreciation and
amortization and interest expense of the unconsolidated affiliates.
(6) 1999 amounts reflect the impact of the TNGL and MBA acquisitions. The TNGL
acquisition was effective August 1, 1999 with the MBA acquisition effective
July 1, 1999.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION.
The following discussion and analysis should be read in conjunction
with the audited consolidated financial statements and notes thereto of
Enterprise Products Partners L.P. ("Enterprise" or the "Company") included
elsewhere herein.
GENERAL
The Company (i) processes natural gas; (ii) fractionates for a
processing fee mixed NGLs produced as by-products of oil and natural gas
production into their component products: ethane, propane, isobutane, normal
butane and natural gasoline; (iii) converts normal butane to isobutane through
the process of isomerization; (iv) produces MTBE from isobutane and methanol;
and (v) transports NGL products to end users by pipeline and railcar. The
Company also separates high purity propylene from refinery-sourced
propane/propylene mix and transports high purity propylene to plastics
manufacturers by pipeline. Products processed by the Company generally are used
as feedstocks in petrochemical manufacturing, in the production of motor
gasoline and as fuel for residential and commercial heating.
The Company's NGL processing operations are concentrated in the Texas,
Louisiana, and Mississippi Gulf Coast area. A large portion is concentrated in
Mont Belvieu, Texas, which is the hub of the domestic NGL industry and is
adjacent to the largest concentration of refineries and petrochemical plants in
the United States. The facilities the Company operates at Mont Belvieu include:
(i) one of the largest NGL fractionation facilities in the United States with an
average production capacity of 210,000 barrels per day; (ii) the largest butane
isomerization complex in the United States with an average isobutane production
capacity of 80,000 barrels per day; (iii) one of the largest MTBE production
facilities in the United States with an average production capacity of 14,800
barrels per day; and (iv) two propylene fractionation units with an average
combined production capacity of 31,000 barrels per day. The Company owns all of
the assets at its Mont Belvieu facility except for the NGL fractionation
facility, in which it owns an effective 62.5% economic interest (see Recent
Acquisitions below); one of the propylene fractionation units, in which it owns
a 54.6% interest and controls the remaining interest through a long-term lease;
the MTBE production facility, in which it owns a 33.33% interest; and one of its
three isomerization units and one deisobutanizer which are held under long-term
leases with purchase options. The Company also owns and operates approximately
28 million barrels of storage capacity at Mont Belvieu and 7 million barrels of
storage capacity in Petal, Mississippi that are an integral part of its
processing operations. In addition, the Company owns and operates a NGL
fractionation facility in Petal, Mississippi with an average production capacity
of 7,000 barrels per day. The Company also leases and operates one of only two
commercial NGL import/export terminals on the Gulf Coast.
32
As a result of the Tejas Natural Gas Liquids, LLC ("TNGL") acquisition,
the Company acquired, effective August 1, 1999:
o a 20-year natural gas processing agreement with Shell for the rights to
process its current and future natural gas production from the state and
federal waters of the Gulf of Mexico ("Shell Processing Agreement");
o varying interests in 11 natural gas processing plants (including one under
construction) with a combined gross capacity of 11.0 billion cubic feet per
day ("Bcfd") and net capacity of 3.1 Bcfd;
o four NGL fractionation facilities with a combined gross capacity of 281,000
BPD and net capacity of 131,500 BPD; and
o four NGL storage facilities with approximately 28.8 million barrels of
gross capacity and 8.8 million barrels of net capacity.
Lastly, the Company has operating and non-operating ownership interests
in over 2,400 miles of NGL pipelines along the Gulf Coast (including an 11.5%
interest in the 1,301 mile Dixie Pipeline). All references herein to "Shell",
unless the context indicates otherwise, shall refer collectively to Shell Oil
Company, its subsidiaries and affiliates.
Recent Acquisitions
TNGL Acquisition. As noted above, effective August 1, 1999, the Company
acquired TNGL from Tejas Energy, LLC ("Tejas Energy"), now Coral Energy LLC, an
affiliate of Shell, in exchange for 14.5 million non-distribution bearing,
convertible special partner units ("Special Units") of the Company and a cash
payment of $166 million. The Company also agreed to issue up to 6.0 million
non-distribution bearing, convertible special units ("Contingency Units") to
Shell in the future if the volumes of natural gas that the Company processes for
Shell reach certain agreed upon levels in 2000 and 2001. The businesses acquired
from Shell include natural gas processing and NGL fractionation, transportation
and storage in Louisiana and Mississippi and its NGL supply and merchant
business. The assets acquired include varying interests in 11 natural gas
processing plants, four NGL fractionation facilities, and four NGL storage
facilities and operator and non-operator ownership interests in approximately
1,500 miles of NGL pipelines. The Company accounted for this acquisition using
the purchase method.
The Company's major customer related to the TNGL assets is Shell. Under
the terms of the Shell Processing Agreement, the Company has the right to
process substantially all of Shell's current and future natural gas production
from the Gulf of Mexico. This includes natural gas production from the
developments currently referred to as deepwater. Generally, the Shell Processing
Agreement grants the Company the following rights and obligations:
o the exclusive right to process any and all of Shell's Gulf of Mexico
natural gas production from existing and future dedicated leases; plus
o the right to all title, interest, and ownership in the raw make
extracted by the Company's gas processing facilities from Shell's
natural gas production from such leases; with
o the obligation to deliver to Shell the natural gas stream after the
raw make is extracted.
Natural gas processing plants are generally located near the production
area. When produced at the wellhead, natural gas generally must be processed to
separate the merchantable, pipeline quality natural gas (principally methane),
from NGLs and other impurities. Wet or rich natural gas normally must be
processed to render the natural gas acceptable for transport in the nation's gas
pipeline distribution system and to meet specifications required by local
natural gas distribution companies. After being extracted in the field, mixed
NGLs, sometimes referred to as "y-grade" or "raw make" are typically transported
to a central facility for fractionation and subsequent sale.
Mont Belvieu NGL Fractionation facility. Effective July 1, 1999, a
subsidiary of the Operating Partnership acquired an additional 25% interest in
the Mont Belvieu NGL fractionation facility from Kinder Morgan Operating LP "A"
("Kinder Morgan") for a purchase price of approximately $41.2 million in cash
and the assumption of $4 million in debt. An additional 0.5% interest in the
same facility was purchased from EPCO for a cash purchase price of $0.9 million.
This acquisition (referred to as the "MBA acquisition") increased the Company's
effective economic interest in the Mont Belvieu NGL fractionation facility from
37.0% to 62.5%. As a result of this acquisition, the results of operations after
July 1, 1999 were consolidated rather than included in equity in earnings of
unconsolidated affiliates.
33
INDUSTRY ENVIRONMENT
Because certain NGL products compete with other refined petroleum
products in the fuel and petrochemical feedstock markets, NGL product prices are
set by or in competition with refined petroleum products. Increased production
and importation of NGLs and NGL products in the United States may decrease NGL
product prices in relation to refined petroleum alternatives and thereby
increase consumption of NGL products as NGL products are substituted for other
more expensive refined petroleum products. Conversely, a decrease in the
production and importation of NGLs and NGL products could increase NGL product
prices in relation to refined petroleum product prices and thereby decrease
consumption of NGLs. However, because of the relationship of crude oil and
natural gas production to NGL production, the Company believes any imbalance in
the prices of NGLs and NGL products and alternative products would be temporary.
When the price of crude oil nears a multiple of ten (or higher) to the
price of natural gas (i.e., crude oil $20 per barrel and natural gas $2 per
thousand cubic feet ("MCF")), NGL pricing has been strong due to increased use
in manufacturing petrochemicals. In 1999, the industry experienced a multiple of
approximately nine (i.e., crude oil averaged $19.29 per barrel (based on
averages of published Cushing Oklahoma prices) and natural gas averaged $2.27
per MCF (based on averages of published Henry Hub prices)), which caused
petrochemical manufacturing demand to change from a preference for crude oil
derivatives to a reliance on NGLs. In 1998, when the multiple was approximately
seven, petrochemical manufacturing demand relied on crude oil derivatives which
depressed NGL prices. This change resulted in the increasing of both the
production and pricing of NGLs. In the NGL industry, revenues and cost of goods
sold can fluctuate significantly up or down based on current NGL prices.
However, operating margins will generally remain constant except for the effect
of inventory price adjustments or increased operating expenses.
RESULTS OF OPERATION OF THE COMPANY
Historically, the Company has had only one reportable business segment:
NGL Operations. Due to the broadened scope of the Company's operations with the
acquisition of TNGL in the third quarter of 1999, the Company's operations are
being managed using the following five reportable business segments to better
reflect the earnings and activities in each of the Company's major lines of
business:
o Fractionation
o Pipeline
o Processing
o Octane Enhancement
o Other
Fractionation includes NGL fractionation, polymer grade propylene
fractionation and butane isomerization (converting normal butane into high
purity isobutane) services. Pipeline consists of pipeline, storage and
import/export terminal services. Processing includes the natural gas processing
business and its related NGL merchant activities. Octane Enhancement represents
the Company's 33.33% ownership interest in a facility that produces motor
gasoline additives to enhance octane (currently producing MTBE). The Other
operating segment consists of fee-based marketing services and other plant
support functions.
The management of the Company evaluates segment performance on the basis of
gross operating margin. Gross operating margin reported for each segment
represents earnings before depreciation, lease expense obligations retained by
the Company's largest Unitholder, EPCO, and general and administrative expenses.
In addition, segment gross operating margin is exclusive of interest expense,
interest income (from unconsolidated affiliates or others), dividend income from
unconsolidated affiliates, minority interest, extraordinary charges and other
income and expense transactions. The Company's equity earnings from
unconsolidated affiliates are included in segment gross operating margin.
Segment gross operating margin is inclusive of intersegment revenues. Such
revenues, which have been eliminated from the consolidated totals, are recorded
at arms-length prices which are intended to approximate the prices charged to
external customers. Segment assets consists of property, plant and equipment and
the amount of investments in and advances to equity and cost method investees.
34
The Company's gross operating margins by segment (in thousands) along
with a reconciliation to consolidated operating income over the past three years
were as follows:
Year Ended December 31,
-------------------------------------------------------
1997 1998 1999
-------------------------------------------------------
Gross Operating Margin by segment:
Fractionation $ 100,770 $ 66,627 $ 106,267
Pipeline 23,909 27,334 27,038
Processing (3,778) (652) 36,799
Octane enhancement 9,305 9,801 8,183
Other (1,496) (3,483) 908
-------------------------------------------------------
Gross Operating margin total 128,710 99,627 179,195
Depreciation and amortization 17,684 18,579 23,664
Retained lease expense, net 13,300 12,635 10,557
Loss (gain) on sale of assets 155 (276) 123
Selling, general, and
administrative expenses 21,891 18,216 12,500
=======================================================
Consolidated operating income $ 75,680 $ 50,473 $ 132,351
=======================================================
The Company's significant plant production and other volumetric data
(in thousands of barrels per day) over the past three years are follows:
Year Ended December 31,
1997 1998 1999
--------------------------------------------------------
Plant production data:
Fractionation:
Mont Belvieu NGL Fractionation 189 191 157
Mont Belvieu Isomerization 67 67 74
Mont Belvieu Propylene Production 26 26 28
Norco NGL Fractionation (a) - - 48
Processing
Gas Processing Plants (equity production) (a) - - 67
Octane enhancement
MTBE production 14 14 14
Other volumetric data:
Pipeline:
Houston Ship Channel Distribution System 92 107 99
Louisiana Pipeline Distribution System 37 40 104
- -----------------------------------------------------------------------------------------------------------------
(a) Assets acquired in TNGL acquisition effective August 1, 1999, rates shown
are post-acquisition
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Revenues, Costs and Expenses and Operating Income. The Company's
revenues increased by 78.4% to $1,346.5 million in 1999 compared to $754.6
million in 1998. The Company's costs and expenses increased by 75.2% to $1,201.6
million in 1999 versus $685.9 million in 1998. Operating income before selling,
general and administrative expenses ("SG&A") increased 110.9% to $144.9 million
in 1999 from $68.7 million in 1998. The principal factor behind the $76.2
million increase in operating income before SG&A was the TNGL acquisition.
Earnings attributable to these assets from the date of acquisition, August 1,
35
1999, through December 31, 1999 added approximately $48.4 million in gross
operating margin to the Company's financial performance. The other primary
source of the increase was an overall improvement in NGL product prices in 1999
over 1998 levels.
Fractionation. The Company's gross operating margin for the Fractionation
segment increased to $106.3 million in 1999 from $66.6 million in 1998. The
increase is associated with a number of factors including:
o an overall improvement in the isomerization business due to an
increase in production volumes and higher pricing in the first half of
1999;
o the addition of the Norco NGL fractionation facility operating results
(acquired in the TNGL acquisition);
o higher earnings in the propylene production business stemming from a
rebound in propylene prices and an increase in propylene production;
and
o the MBA acquisition on the financial results of the Mont Belvieu NGL
fractionation business.
Of the $39.7 million increase in 1999 gross operating margin, $19.6 million is
attributable to the improvement in the isomerization business. The primary
reason for this improvement is an increase in production rates, which were
accompanied by exceptional pricing conditions in the first half of 1999. The
normal butane spread averaged 2.2 cents per gallon in the first of half 1999 and
0.7 cents per gallon for 1999 as a whole compared to 1.1 cents per gallon for
1998. The Company's gross operating margin on its propylene production
facilities increased $11.2 million in 1999 generally due to increases in polymer
grade propylene prices and higher production rates. Spot prices of polymer grade
propylene averaged 13.9 cents per pound in 1999 compared to an average of 11.6
cents per pound for 1998. Also, the gross operating margin on the Company's Mont
Belvieu NGL fractionation facilities increased $2.7 million. This increase is
primarily attributable to the consolidation of an additional 25% of the
operations of the Mont Belvieu NGL fractionation facility as a result of the MBA
acquisition. Lastly, the Norco NGL fractionation facility contributed $11.3
million in gross operating margin since its acquisition effective August 1,
1999.
In addition to the major business areas mentioned above, this segment
reflects equity earnings from MBA, BRF, Promix and BRPC. As noted previously,
MBA was acquired effective July 1, 1999. Prior to this date, the Company
recorded its share of earnings from MBA as equity income in an unconsolidated
affiliate. For the period prior to the acquisition date, the Company recorded
$1.3 million in equity income from MBA. The BRF facility commenced operations in
July 1999. The Company recorded a loss of $0.3 million from BRF operations
during 1999 primarily due to operating and other startup expenses incurred prior
to the commencement of operations. Also, the Company recorded $0.6 million in
equity income from Promix. Promix is engaged in the business of transporting,
fractionating, storing and exchanging NGLs in southern Louisiana and was
acquired in the TNGL acquisition. Pre-startup equity earnings from BRPC, a joint
venture with ExxonMobil to build a propylene concentrator unit near Baton Rouge,
Louisiana, were insignificant. The BRPC facility is scheduled to start
operations in the third quarter of 2000.
Pipeline. The Company's gross operating margin for the Pipeline segment
was $27.0 million in 1999 as compared to $27.3 million in 1998. Earnings
generated from the Louisiana Pipeline Distribution System increased $3.2 million
on an increase in pipeline volumes. Throughput volumes increased from 40
thousand barrels per day ("MBPD") in 1998 to 48 MBPD in 1999 on the pre-TNGL
acquisition system. With the post-TNGL acquisition volumes added, the throughput
(on a prorata basis from August 1, 1999) increased to 104 MBPD. The increase in
earnings from the Louisiana System was offset by declines in the Company's
Houston Ship Channel Distribution system of $0.5 million and at the Company's
import terminal of $1.5 million. The decrease for both the Houston Ship Channel
Distribution System on the Company's import terminal are generally attributable
to lower butane import volumes.
The gross operating margin of this segment includes equity income from
EPIK, Wilprise, Tri-States and Belle Rose. Equity income attributable to this
segment increased from $0.8 million in 1998 to $3.7 million in 1999. Equity
income from EPIK increased to $1.2 million in 1999 from $0.7 million in 1998.
The increase is attributable to 1999's earnings being for a full fiscal year
whereas the 1998 results were for July 1998 through December 1998. The Company
recorded a combined $1.1 million in equity income from the Wilprise, Tri-States,
and Belle Rose Systems. Individually, equity earnings from Wilprise, Tri-States,
and Belle Rose were $0.2 million, $1.0 million, and a loss of $29 thousand,
respectively. The Belle Rose system was acquired in the TNGL acquisition.
36
The remaining $1.4 million increase in equity income is attributable to
Entell. The Operating Partnership formed Entell in March 1999 as a pipeline
joint venture with TNGL with each member having a 50% ownership interest. As a
result of the TNGL acquisition, the Company acquired the remaining 50% ownership
interest of Entell and now consolidates the operations of Entell with those of
the Operating Partnership. For the period March 1, 1999 through August 1, 1999,
the Company recorded its earnings from Entell as equity income in an
unconsolidated affiliate.
Processing. The Company's gross operating margin for Processing was
$36.8 million in 1999 compared to a loss of $0.7 million in 1998. Of the
increase, $36.4 million is due to the gas processing operations acquired in the
TNGL acquisition effective August 1, 1999. The gas processing operations
benefited from a favorable NGL pricing environment where the ratio of crude oil
to natural gas prices averaged 10 to 1 during the fourth quarter of 1999.
Octane Enhancement. The Company's gross operating margin for Octane
Enhancement decreased to $8.2 million in 1999 from $9.8 million in 1998. This
segment consists entirely of the Company's equity earnings and investment in
BEF, a joint venture facility that currently produces MTBE. The decrease in
equity earnings from BEF can be attributed a $4.5 million non-cash write-off in
January 1999 of the unamortized balance of deferred start-up costs. The
Company's share of this non-cash charge was $1.5 million.
Other. The Company's gross operating margin for the Other segment was
$0.9 million in 1999 compared to a loss of $3.5 million in 1998. Beginning in
1999, this segment includes fee-based marketing services. The Company acquired
its fee-based marketing services business as part of the TNGL acquisition. For
the period August 1, 1999 through December 31, 1999, this business earned $0.6
million. Apart from this portion of the segment's operations, the gross margin
contribution of the other aspects of this segment were insignificant in both
1999 and 1998.
Selling, general and administrative expenses. SG&A expenses decreased
to $12.5 million in 1999 from $18.2 million in 1998. SG&A expenses of the
Company are covered by the administrative services fee found in EPCO agreement.
On July 7, 1999, the Audit and Conflicts Committee of the General Partner
authorized an increase in the administrative services fee to $1.1 million per
month from the initial $1.0 million per month. The increased fees were effective
August 1, 1999. Beginning in January 2000, the administrative services fee will
increase to $1.55 million per month plus accrued employee incentive plan costs
to compensate EPCO for the additional SG&A charges related to the additional
administrative employees acquired in the TNGL acquisition.
Interest expense. The Company's interest expense increased to $16.4
million in 1999 compared to $15.1 million in 1998. While average debt levels
remained generally consistent in 1999 compared to 1998, interest expense
increased due to the amortization of loan origination costs. The Company's debt
service costs will increase in the future as a result of additional borrowings
for possible acquisitions and working capital needs. For a more complete
discussion of the Company's debt management strategy, see "Bank Credit
Facilities" and "December 1999 Universal Shelf Registration" under the Liquidity
and Capital Resources section of this report.
Dividend income from unconsolidated affiliates. The Company's
investment in Dixie and VESCO are recorded using the cost method as prescribed
by generally accepted accounting principles. In accordance with these
guidelines, the Company records as dividend income the cash distributions from
these investments as opposed to showing equity earnings. Both the Dixie and
VESCO investments were acquired as part of the TNGL acquisition. For 1999, the
Company recorded dividend income from Dixie and VESCO in the amounts of $0.8
million and $2.6 million, respectively.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Revenues, Costs and Expenses and Operating income. The Company's
revenues decreased by 27.2% to $754.6 million in 1998 compared to $1,036.0
million in 1997. The Company's costs and expenses, excluding selling, general,
and administrative charges, decreased as well to $685.9 million in 1998 from
$938.4 million in 1997. Both revenues and costs of goods sold decreased
dramatically from 1997 to 1998 due to sharp declines in average NGL prices
during most of 1998. For example, isobutane prices decreased from an average of
46.9 cents per gallon in 1997 to 32.1 cents per gallon in 1998. Operating income
37
before SG&A decreased 29.6% to $68.7 million in 1998 from $97.6 million in 1997.
The reduced operating income in 1998 is mainly due to the effect of declining
NGL prices on inventory values and merchant values during 1998.
Fractionation. The Company's gross operating margin for the
Fractionation segment declined 33.9% to $66.6 million in 1998 from $100.8
million in 1997. The decrease can be attributed to a number of factors
including:
o for the isomerization business, inventory write-downs, loss of
marketing profits due to lower butane price spreads, and the decline
of revenues on merchant activities;
o for the propylene production business, declines in the prices of high
purity and refinery grade propylene, reduced production volumes, and
write-downs on feedstock inventory; and
o for the Mont Belvieu NGL fractionation business, lower toll processing
fees charged to customers.
The majority of the $34.2 million decline in Fractionation gross operating
margin was caused by a $28.0 million decrease in the isomerization business for
the reasons outlined above. From a pricing standpoint, the butane price spreads
(i.e., the difference between the average prices of isobutane and normal butane)
decreased from 3.3 cents per gallon in 1997 to 1.1 cents per gallon in 1998 as a
result of the preference for crude-oil-derivative petrochemical feedstocks over
NGLs. As a sign of further weakness in NGL prices, the Company's gross operating
margin on its propylene production facilities dropped $7.4 million in 1998 from
1997 levels. As with other NGL products, the pricing of propylene fell during
1998. For example, spot prices of polymer grade propylene dropped from an
average of 19.8 cents per pound in 1997 to 11.6 cents per pound in 1998.
The gross operating margin for the Mont Belvieu fractionation
facilities declined to $3.2 million in 1998 from $3.5 million in 1997 (excluding
the positive effect of $1.3 million in overhead expenses and support facility
cost reimbursements from joint venture partners in 1998). If not for the partial
offset of lowered operating expenses, the gross operating margin on the
fractionation facilities would have dropped by $1.9 million in 1998 due to lower
toll processing fees. On average, these fees were 2.3 cents per gallon in 1997
versus 2.1 cents per gallon in 1998. The lower NGL fractionation fees impacted
equity income from MBA as well causing a decrease of $1.2 million from $6.4
million in 1997 to $5.2 million in 1998.
Pipeline. The Company's gross operating margin for the Pipeline segment
increased 14.2% to $27.3 million in 1998 from $23.9 million in 1997. Of the $3.4
million increase, $1.5 million is attributable to higher throughput rates on the
Houston Ship Channel Distribution System due to higher butane import volumes.
Another $0.7 million of the increase is associated with a 8.1% increase in
volumes on the Louisiana Pipeline Distribution System. Lastly, part of the 1998
increase stems from the Company's investment in EPIK, which began operations in
June 1998. EPIK generated $0.7 million in equity income for the period June 1998
through December 1998.
Processing. The Company's gross operating margin for Processing
improved from a loss of $3.8 million in 1997 to a loss of $0.7 million in 1998.
The decrease is primarily attributable to lower operating expenses associated
with the Company's rail car activity.
Octane Enhancement. The Company's gross operating margin for Octane
Enhancement improved to $9.8 million in 1998 from $9.3 million in 1997. This
segment consists entirely of the Company's equity earnings and investment in
BEF, a joint venture owning a facility that currently produces MTBE. The
improvement in equity earnings from BEF can be attributed to decreased debt
service costs.
Selling, general and administrative expenses. SG&A expenses decreased
to $18.2 million in 1998 from $21.9 million in 1997. This decrease was primarily
due to the adoption of the EPCO Agreement in July 1998 in conjunction with the
Company's IPO which fixed the reimbursable SG&A expenses at $1.0 million per
month.
Interest expense. Interest expense was $15.1 million in 1998 and $25.7
million in 1997. The $10.6 million decline was primarily due to a decrease in
the average debt outstanding during the first seven months of 1998 as compared
to the same period of 1997, and the prepayment of debt in conjunction with the
IPO in July 1998.
Prepayment Penalties on Extinguishment of Debt. The Company incurred a
$27.2 million extraordinary loss during the third quarter of 1998 in connection
with the early extinguishment of debt assumed from EPCO in connection with the
38
IPO. The extraordinary loss was equal to remaining unamortized debt origination
costs associated with such debt and make-whole premiums payable in connection
with the repayment of such debt.
PRO FORMA IMPACT OF TNGL AND MBA ACQUISITIONS
As noted above under Recent Acquisitions, the Company acquired TNGL and
MBA in fiscal 1999. As a result of these acquisitions, revenues, operating costs
and expenses, interest expense, and other amounts shown on the Statements of
Consolidated Operations for 1999 have increased significantly over the amounts
shown for 1998. The following table presents certain unaudited pro forma
information for the years ended December 31, 1997, 1998 and 1999 as if the
acquisition of TNGL and the Mont Belvieu fractionator facility from Kinder
Morgan and EPCO been made as of the beginning of the periods presented:
1997 1998 1999
--------------------------------------------
Revenues $ 1,867,200 $ 1,354,400 $ 1,714,222
============================================
Net income $ 93,925 $ 14,728 $ 135,037
============================================
Allocation of net income to
Limited partners $ 92,986 $ 14,581 $ 133,687
============================================
General Partner $ 939 $ 147 $ 1,350
============================================
Units used in earnings per Unit calculations
Basic 54,963 60,124 66,710
============================================
Diluted 69,463 74,624 81,210
============================================
Income per Unit before extraordinary
item and minority interest
Basic $ 1.71 $ 0.69 $ 2.02
============================================
Diluted $ 1.35 $ 0.56 $ 1.66
============================================
Net income per Unit
Basic $ 1.69 $ 0.24 $ 2.00
============================================
Diluted $ 1.34 $ 0.20 $ 1.65
============================================
LIQUIDITY AND CAPITAL RESOURCES
General. The Company's primary cash requirements, in addition to normal
operating expenses, are debt service, maintenance capital expenditures,
expansion capital expenditures, and quarterly distributions to the partners. The
Company expects to fund future cash distributions and maintenance capital
expenditures with cash flows from operating activities. Capital expenditures for
future expansion activities and asset acquisitions are expected to be funded
with cash flows from operating activities and borrowings under the revolving
bank credit facilities.
Cash flows from operating activities were a $168.8 million inflow for
1999 compared to a $20.3 million outflow for the comparable period of 1998. Cash
flows from operating activities primarily reflect the effects of net income,
depreciation and amortization, extraordinary items, equity income of
unconsolidated affiliates and changes in working capital. Net income increased
significantly as a result of improved overall margins and the TNGL acquisition.
Depreciation and amortization increased a combined $6.1 million in 1999
primarily as a result of additional capital expenditures and the TNGL and Mont
Belvieu fractionator acquisitions (the "acquisitions") in the third quarter of
1999. Amortization expense increased by $2.5 million primarily due to the
39
amortization of the intangible asset associated with the Shell Processing
Agreement. The Shell Processing Agreement and the excess cost associated with
the MBA acquisition will be amortized over a 20-year period at approximately
$3.1 million per year. The net effect of changes in operating accounts from year
to year is generally the result of timing of NGL sales and purchases near the
end of the period.
Cash outflows used in investing activities were $265.2 million in 1999
and $50.7 million for the comparable period of 1998. Cash outflows included
capital expenditures of $21.2 million for 1999 and $8.4 million for 1998.
Included in the capital expenditures amounts are maintenance capital
expenditures of $2.4 million for 1999 and $7.7 million for 1998. Investing cash
outflows in 1999 also included $61.9 million in advances to and investments in
unconsolidated affiliates versus $26.8 million for 1998. The $35.1 million
increase stems primarily from contributions made to the Wilprise, Tri-States,
BRF, and BRPC joint ventures located in Louisiana. Also, the Company received
$20.0 million in payments on notes receivable from the BEF and MBA notes
purchased during 1998 with the proceeds of the Company's IPO. In conjunction
with the acquisition of the MBA interest in the Mont Belvieu fractionation
facility, $5.8 million was received during the third quarter 1999 from MBA for
the balance of the Company's note receivable. The $6.5 million outstanding
balance of notes receivable from unconsolidated affiliates relates to the
participation in the BEF note. This balance will be collected in equal
installments of approximately $3.2 million each at the end of February 2000 and
May 2000.
Cash outflows for investing activities also include the cash payments
related to the acquisitions. Per the terms of the TNGL acquisition, $166.0
million was paid to Tejas Energy in September 1999. Likewise, $42.1 million was
paid to Kinder Morgan and EPCO to purchase their collective 51% interest in MBA.
As described in Note 16 of the Notes to the Consolidated Financial Statements,
on February 25, 2000 the Company announced the acquisition of the Lou-Tex
Propylene Pipeline and other assets effective March 1, 2000 from Concha Chemical
Pipeline Company ("Concha"), an affiliate of Shell, for approximately $100
million in cash. The pipeline consists of 263 miles of 10" pipeline from
Sorrento, Louisiana to Mont Belvieu, Texas. It is currently dedicated to the
transportation of chemical grade propylene from Sorrento to the Mont Belvieu
area. The acquisition of the Lou-Tex Propylene Pipeline is the first step in the
Company's development of an approximately $180 million, 160,000 barrel per day
Louisiana-to-Texas gas liquids pipeline system. The second step involves the
construction of the 263-mile Lou-Tex NGL Pipeline from Sorrento, Louisiana to
Mont Belvieu, Texas, scheduled for completion in the third quarter of 2000. This
larger system will link growing supplies of NGLs produced in Louisiana and
Mississippi with the principal NGL markets on the United States Gulf Coast.
On February 23, 2000, the Company offered to buy the remaining 88.5%
ownership interests in Dixie from the other seven owners for a total purchase
price of approximately $204.4 million. The offer is subject to the acceptance by
the holders of a minimum of 68.5% of the oustanding ownership interests. The
offer will expire on March 8, 2000 if it is not accepted by such holders. If the
offer is accepted, the purchase would be subject to, among other things,
preparation and execution of a definitive purchase agreement and the obtaining
of requisite regulatory approvals and consents.
Cash flows from financing activities were a $77.5 million inflow in
1999 versus a $61.2 million inflow for 1998. Cash flows from financing
activities are affected primarily by repayments of long-term debt, borrowings
under the long-term debt agreements and distributions to the partners. The 1998
period reflects the transactions that occurred in the IPO in July 1998. The 1999
period includes $215 million in long-term debt borrowings associated with the
TNGL and Mont Belvieu fractionation facility acquisition. Cash flows from
financing activities for 1999 also reflected the net purchase of $4.7 million of
Common Units by a consolidated trust.
The Operating Partnership is planning to borrow $54 million in March
2000 from the Mississippi Business Finance Corporation ("MBFC") to reimburse the
Company's portion of construction costs of the Pascagoula gas processing plant.
MBFC will issue $54 million in taxable industrial development bonds underwritten
by First Union Securities, Inc. and Banc of America Securities, LLC. The Company
will act as guarantor of the MBFC bonds with the Operating Partnership making
payments of principal and interest to MBFC. Interest on the bonds will be paid
semiannually with final maturity of the bonds in March 2010.
Future Capital Expenditures. The Company estimates that its share of
capital expenditures in the projects of its unconsolidated affiliates will be
approximately $8.9 million in fiscal 2000 (including $7.8 million for the BRPC
propylene fractionator). In addition, the Company forecasts that $103.2 million
will be spent in 2000 on capital projects that will be recorded as property,
plant, and equipment (including $79.8 million for construction of the Lou-Tex
NGL Pipeline and $14.3 million for the construction of processing facilities
acquired from TNGL). The Company expects to finance these expenditures out of
operating cash flows, borrowings under its bank credit facilities, and offerings
of debt and/or equity securities. As of December 31, 1999, the Company had $9.5
million in outstanding purchase commitments attributable to its capital
projects. Of this amount, $1.7 million is associated with capital projects which
40
will be recorded as additional investments in unconsolidated affiliates for
accounting purposes.
DISTRIBUTIONS AND DIVIDENDS FROM UNCONSOLIDATED AFFILIATES
Distributions from unconsolidated affiliates. The Company received $6.0
million in distributions from its equity method investees in 1999 compared to
$9.1 million in 1998. Distributions to the Company from MBA were $1.9 million in
1999 and $5.7 million in 1998. The level of distributions from MBA is lower in
1999 versus 1998 due to a decrease in NGL fractionation margins and the
acquisition of MBA by the Operating Partnership effective July 1, 1999.
Distributions from BEF were $0.3 million in 1999 versus $2.4 million in 1998.
Distributions from BEF are lower in 1999 due to downtime associated with
maintenance activities. Distributions from EPIK were $2.1 million in 1999 versus
$1.0 million for 1998. EPIK was formed in the second quarter of 1998 and had no
distributions until the third quarter of 1998. The Company received $0.8 million
collectively from its newly acquired equity investments in Promix and Belle
Rose. The Promix and Belle Rose distributions to the Company were $0.7 million
and $0.1 million, respectively. Lastly, prior to its consolidation in August
1999 the Company received $0.8 million from Entell.
Dividends received from unconsolidated affiliates. The Company received
$3.4 million in cash dividend payments from its cost method investments in Dixie
and VESCO. Specifically, dividends paid by Dixie and VESCO were $0.8 million and
$2.6 million, respectively. As noted before, distributions received from these
investments are recorded by the Company as "Dividend income from unconsolidated
affiliates" in the Statements of Consolidated Operations.
BANK CREDIT FACILITIES
In December 1999, the Company and Operating Partnership filed an $800
million universal shelf registration statement (see discussion regarding the
"December 1999 Universal Shelf Registration" below) covering the issuance of an
unspecified amount of equity or debt securities or a combination thereof. The
Company expects to issue public debt under the shelf registration statement
during fiscal 2000. Management intends to use the proceeds from such debt
offering to repay all outstanding bank credit facilities and for other general
corporate purposes.
$200 Million Bank Credit Facility. In July 1998, the Operating
Partnership entered into a $200 million bank credit facility that includes a $50
million working capital facility and a $150 million revolving term loan
facility. The $150 million revolving term loan facility includes a sublimit of
$30 million for letters of credit. As of December 31, 1999, the Company has
borrowed $129 million under the bank credit facility which is due in July 2000.
The Company's obligations under this bank credit facility are unsecured
general obligations and are non-recourse to the General Partner. Borrowings
under this bank credit facility will bear interest at either the bank's prime
rate or the Eurodollar rate plus the applicable margin as defined in the
facility. This bank credit facility will expire in July 2000 and all amounts
borrowed thereunder shall be due and payable at that time. There must be no
amount outstanding under the working capital facility for at least 15
consecutive days during each fiscal year. The Company elects the basis for the
interest rate at the time of each borrowing. Interest rates ranged from 5.94% to
8.75% during 1999, and the weighted-average interest rate at December 31, 1999
was 6.74%.
As amended on July 28, 1999, this credit agreement relating to the
facility contains a prohibition on distributions on, or purchases or redemptions
of, Units if any event of default is continuing. In addition, this bank credit
facility contains various affirmative and negative covenants applicable to the
ability of the Company to, among other things, (i) incur certain additional
indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain
limitations, (iv) make investments, (v) engage in transactions with affiliates
and (vi) enter into a merger, consolidation or sale of assets. The bank credit
facility requires that the Operating Partnership satisfy the following financial
covenants at the end of each fiscal quarter: (i) maintain Consolidated Tangible
Net Worth (as defined in the bank credit facility) of at least $250 million,
(ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to
Consolidated Interest Expense (as defined in the bank credit facility) for the
previous 12-month period of at least 3.5 to 1.0 and (iii) maintain a ratio of
Total Indebtedness (as defined in the bank credit facility) to EBITDA of no more
41
than 3.0 to 1.0. The Company was in compliance with these restrictive covenants
at December 31, 1999.
A "Change of Control" constitutes an Event of Default under this bank
credit facility. A Change of Control includes any of the following events: (i)
Dan L. Duncan (and/or certain affiliates) cease to own (a) at least 51% (on a
fully converted, fully diluted basis) of the economic interest in the capital
stock of EPCO or (b) an aggregate number of shares of capital stock of EPCO
sufficient to elect a majority of the board of directors of EPCO; (ii) EPCO
ceases to own, through a wholly owned subsidiary, at least 65% of the
outstanding membership interest in the General Partner and at least a majority
of the outstanding Common Units; (iii) any person or group beneficially owns
more than 20% of the outstanding Common Units (excluding certain affiliates of
EPCO or Shell); (iv) the General Partner ceases to be the general partner of the
Company or the Operating Partnership; or (v) the Company ceases to be the sole
limited partner of the Operating Partnership.
$350 Million Bank Credit Facility. Also in July 1999, the Operating
Partnership entered into a $350 million bank credit facility that includes a $50
million working capital facility and a $300 million revolving term loan
facility. The $300 million revolving term loan facility includes a sublimit of
$10 million for letters of credit. The initial proceeds of this loan were used
to finance the acquisition of TNGL and the MBA ownership interests.
Borrowings under the bank credit facility will bear interest at either
the bank's prime rate or the Eurodollar rate plus the applicable margin as
defined in the facility. The bank credit facility will expire in July 2001 and
all amounts borrowed thereunder shall be due and payable at that time. There
must be no amount outstanding under the working capital facility for at least 15
consecutive days during each fiscal year. The Company elects the basis for the
interest rate at the time of each borrowing. Interest rates ranged from 6.88% to
7.31% during 1999, and the weighted-average interest rate at December 31, 1999
was 7.10%.
Limitations on certain actions by the Company and financial covenant
requirements of this bank credit facility are substantially consistent with
those existing for the $200 Million Bank Credit Facility as described above. The
Company was in compliance with the restrictive covenants at December 31, 1999.
Long-term debt consisted of the following:
(in thousands of dollars) AT DECEMBER 31,
1998 1999
-------------------------------------
Borrowings under:
$200 Million Bank Credit Facility $ 90,000 $ 129,000
$350 Million Bank Credit Facility 166,000
-------------------------------------
Total 90,000 295,000
Less current maturities of long-term debt 129,000
=====================================
Long-term debt $ 90,000 $ 166,000
=====================================
At December 31, 1999, the Company had $40 million of standby letters of
credit available, and approximately $24.3 million of letters of credit were
outstanding under letter of credit agreements with the banks.
December 1999 Universal Shelf Registration. On December 21, 1999, the
Company announced that it had filed an $800.0 million "universal shelf"
registration statement (the "Registration Statement") with the Securities and
Exchange Commission for the proposed sale of debt and equity securities over the
next two years. This registration statement pertains to debt securities of the
Operating Partnership and Common Units of the Company. The purpose and timing of
the Registration Statement is to give the Company flexibility to quickly respond
to attractive financing opportunities in the capital markets and its need for
capital as it pursues a growth strategy and manages debt obligations. The
Company expects to manage its debt obligations for an appropriate mix of
short-term and long-term indebtedness and fixed coupon versus floating rate
debt. At the time the Company offers debt or equity securities for sale, it will
provide a prospectus supplement that will contain specific information about the
terms of any such offering.
42
The net proceeds from any sale of debt or equity securities would be
used for funding future business acquisitions, investment in growth projects,
refinancing existing debt or other Company purposes including, but not limited
to, providing working capital or the repurchasing of Common Units. This
Registration Statement may also apply to the issuance of Common Units to satisfy
conversion of the 14.5 million convertible Special Units, which the Company
issued in the acquisition of TNGL. During the next two years, 6.0 million of
these units will convert into Common Units.
Fiscal 2000 offering of debt securities. In connection with the
Registration Statement, the Operating Partnership is contemplating the issuance
of up to $350 million in debt securities in fiscal 2000. The notes would be
unsecured; rank equally with all of the Operating Partnership's existing and
future senior debt; would be senior to any future subordinated debt; and would
be effectively junior to the Operating Partnership's secured indebtedness and
other liabilities. If the transaction occurs, the Operating Partnership would
issue the notes under an indenture containing certain restrictive covenants
restricting its ability, with certain exceptions, to incur debt secured by liens
and engage in sale/leaseback transactions. The Company would be the guarantor of
the notes. The Operating Partnership's debt securities would be an unsecured
senior obligation of the Company. The Operating Partnership would use the net
proceeds of the debt offering to retire all outstanding indebtedness under the
Company's $200 Million and $350 Million Bank Credit Facilities and for other
general corporate purposes.
For a more detailed description of the Registration Statement, the
Company hereby incorporates by reference the Form S-3 filed by the Company on
December 21, 1999 and all associated supplements and filings.
Debt Ratings. In January 2000, the Company received investment grade
debt ratings from Standard & Poor's and Moody's Investor Services relating to
the potential debt securities of the Operating Partnership covered under the
Registration Statement and Bank Revolvers A and B. Standard & Poor's issued a
"BBB" rating to the Company's two bank revolvers and a preliminary "BBB" senior
unsecured debt rating to the $800 million universal shelf registration.
Generally, a company given a Standard & Poor's rating of "BBB" or higher is
regarded as having financial security characteristics that outweigh its
vulnerabilities, and is highly likely to have the ability to meet financial
commitments. The outlook for the Standard & Poor's ratings is stable. Moody's
Investor Services issued a rating of "Baa3" to the Company's bank revolvers and
a first-time senior unsecured debt rating of "Baa3" with a stable outlook to the
$800 million universal shelf registration. A ranking of "Baa3" from Moody's
Investor Services entails that a company offers adequate financial security;
however, certain protective elements may be lacking or may be characteristically
unreliable over any great length of time. A ranking of "Baa3" as opposed to
"Baa" means that a company ranks on the lower end of its rating category. As a
result of the acquisition of the favorable debt ratings, the Company was allowed
to reduce its Eurodollar interest rates on the $200 Million and $350 Million
Bank Credit Facilities by .125% in accordance with the terms of the revolvers.
1999 LONG-TERM INCENTIVE PLAN
Effective January 1, 2000, Enterprise Products GP, LLC, the general
partner of the Company, adopted the 1999 Long-Term Incentive Plan (the "Plan").
Under the Plan, non-qualified incentive options to purchase a fixed number of
Common Units may be granted to key employees of EPCO who perform management,
administrative or operational functions for the Company under the EPCO
Agreement. The exercise price per Unit, vesting and expiration terms, and rights
to receive distributions on Units granted are determined by the Company for each
grant agreement. Upon the exercise of an option, the Company may deliver the
Units or pay an amount in cash equal to the excess of the fair market value of a
Unit and the exercise price of the option. On January 1, 2000, 225,000 options
were granted at a weighted average price of $17.50 per Unit of which none had
been exercised at February 18, 2000. The Plan is primarily funded by the Units
purchased by the Trust. Since the Common Units held by the Trust were previously
unallocated, they were excluded from the earnings per Unit calculation. If the
Plan would have been adopted at January 1, 1999, earnings per Unit would have
been $1.81 basic and $1.66 diluted.
MTBE PRODUCTION
General. The Company owns a 33.33% economic interest in the BEF
partnership that owns the MTBE production facility located within the Company's
Mont Belvieu complex. The production of MTBE is driven by oxygenated fuels
programs enacted under the federal Clean Air Act Amendments of 1990 and other
legislation. Any changes to these programs that enable localities to opt out of
these programs, lessen the requirements for oxygenates or favor the use of
43
non-isobutane based oxygenated fuels reduce the demand for MTBE and could have
an adverse effect on the Company's results of operations.
Recent Regulatory Developments. See discussion of Octane Enhancement -
Recent Regulatory Developments above.
Alternative Uses of the BEF facility. In light of these regulatory
developments, the Company is formulating a contingency plan for use of the BEF
facility if MTBE were banned or significantly curtailed. Management is exploring
a possible conversion of the BEF facility from MTBE production to alkylate
production. At present the forecast cost of this conversion would be in the $20
million to $25 million range, with the Company's share being $6.7 million to
$8.3 million. Management anticipates that if MTBE is banned alkylate demand will
rise as producers use it to replace MTBE as an octane enhancer. Alkylate
production would be expected to generate spot market margins comparable to those
of MTBE. Greater alkylate production would be expected to increase isobutane
consumption nationwide and result in improved isomerization margins for the
Company.
RESULTS OF YEAR 2000 READINESS PROGRAM
Successful Outcome of Year 2000 Readiness Program. Management is
pleased to announce that the Company's efforts at preparing its computer systems
for the Year 2000 were successful and that no significant problems were
encountered. The Year 2000 Readiness team reported that all systems functioned
properly as the date changed from December 31, 1999 to January 1, 2000. The
Company is also pleased to note that no problems were reported to it by its
customers or vendors as a result of the Year 2000 issue. The Company continues
to be vigilant in monitoring its systems for any potential Year 2000 problems
that may arise in the short-term. There is no assurance that residual Year 2000
issues will not arise in the future which could have a material adverse effect
on the operations of the Company.
History of Year 2000 Readiness Program and Costs. In 1997, EPCO began
assessing the impact of Year 2000 compliance issues on the software and hardware
used by the Company. A team was assembled to review and document the status of
EPCO's and the Company's systems for Year 2000 compliance. The key information
systems reviewed include the Company's pipeline Supervisory Control and Data
Acquisition ("SCADA") system, plant, storage, and other pipeline operating
systems. In connection with each of these areas, consideration was given to
hardware, operating systems, applications, data base management, system
interfaces, electronic transmission, and outside vendors. As of November 1, 1999
work was complete in all areas.
Pursuant to the EPCO Agreement, any selling, general and administrative
costs related to Year 2000 compliance issues were covered by the annual
administrative services fee paid by the Company to EPCO. Consequently, only
those costs incurred in connection with Year 2000 compliance which relate to
operational information systems and hardware were paid directly by the Company.
EPCO spent approximately $340,000 in connection with Year 2000
compliance. The Company incurred expenditures of approximately $1,026,000 in
connection with finalizing its Year 2000 compliance project (principally the
SCADA system). These cost estimates do not include the internal costs of EPCO's
or the Company's previously existing resources and personnel that might have
been partially used for Year 2000 compliance or cost of normal system upgrades
which also included various Year 2000 compliance features or fixes. Such
internal costs were determined to be insignificant to the total estimated cost
of Year 2000 compliance for both entities.
ACCOUNTING STANDARDS
On June 6, 1999, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standard ("SFAS") No. 137, "Accounting
for Derivative Instruments and Hedging Activities-Deferral of the Effective Date
of FASB Statement No. 133-an amendment of FASB Statement No. 133" which
effectively delays the application of SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" for one year, to fiscal years beginning
after June 15, 2000. Management is currently studying SFAS No. 133 for possible
impact on the consolidated financial statements when it is adopted in 2001.
44
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to financial market risks, including changes in
interest rates with respect to its debt obligations and changes in commodity
prices. The Company may use derivative financial instruments (i.e., futures,
forwards, swaps, options, and other financial instruments with similar
characteristics) to mitigate these risks. The Company does not use derivative
financial instruments for speculative (or trading) purposes.
Beginning with the fourth quarter of 1999, the Company adopted a
commercial policy to manage exposures to the risks generated by the NGL
businesses acquired in the TNGL acquisition. The objective of the policy is to
assist the Company in achieving its profitability goals while maintaining a
portfolio of conservative risk, defined as remaining with the position limits
established by the Board of Directors of the General Partner. The Company will
enter into risk management transactions to manage price risk, basis risk,
physical risk or other risks related to energy commodities on both a short-term
(less than 30 days) and long-term basis, not to exceed 18 months. The General
Partner has established a Risk Committee (the "Committee") that will oversee
overall strategies associated with physical and financial risks. The Committee
will approve specific commercial policies of the Company subject to this policy,
including authorized products, instruments and markets. The Committee is also
charged with establishing specific guidelines and procedures for implementing
the policy and ensuring compliance with the policy.
Interest rate risk. At December 31, 1999 and 1998, the Company had no
derivative instruments in place to cover any potential interest rate risk on its
variable rate debt obligations. Variable interest rate debt obligations do
expose the Company to possible increases in interest expense and decreases in
earnings if interest rates were to rise. All of the Company's long-term debt is
at variable interest rates.
If the weighted average base interest rates selected on long-term debt
in 1999 were to have been 10% higher than the weighted average of the actual
base interest rates selected, assuming no changes in weighted average variable
debt levels, interest expense would have increased by approximately $1.4 million
with a corresponding decrease in earnings before minority interest. For 1998, if
the weighted average base rates had been 10% higher than those actually
selected, interest expense would have been $0.2 million higher with a
corresponding decrease in earnings before minority interest.
At December 31, 1999 and 1998, the Company had $5.2 million and $24.1
million invested in cash and cash equivalents, respectively. All cash equivalent
investments other than cash are highly liquid, have original maturities of less
than three months, and are considered to have insignificant interest rate risk.
Commodity price risk. The Company is exposed to commodity price risk
through its NGL businesses acquired in the TNGL acquisition effective August 1,
1999. In order to effectively manage this risk, the Company may enter into
swaps, forwards, commodity futures, options and other derivative commodity
instruments with similar characteristics that are permitted by contract or
business custom to be settled in cash or with another financial instrument. The
purpose of these risk management activities is to hedge exposure to price risks
associated with natural gas, NGL inventories, commitments and certain
anticipated transactions. The table below presents the hypothetical changes in
fair values arising from immediate selected potential changes in the quoted
market prices of derivative commodity instruments outstanding at December 31,
1999. Gain or loss on these derivative commodity instruments would be offset by
a corresponding gain or loss on the hedged commodity positions, which are not
included in the table. The fair value of the commodity futures at December 31,
1999 and February 25, 2000 was estimated at $0.5 million payable and $2.8
million payable, respectively, based on quoted market prices of comparable
contracts and approximate the gain or loss that would have been realized if the
contracts had been settled at the balance sheet date. The increase in fair value
of the commodity futures payable is primarily due to an increase in volumes
hedged, change in composition of commodities hedged and higher NGL product
prices.
45
(Millions of Dollars) No Change 10% Increase 10% Decrease
--------- ------------ ------------
Impact of changes in quoted Fair Fair Increase Fair Increase
Market prices on: Value Value (Decrease) Value (Decrease)
- -----------------------------------------------------------------------------------------------------------------
Commodity futures
At December 31, 1999 $ (0.5) $ 1.2 $ 1.7 $ (2.2) $ (1.7)
At February 25, 2000 $ (2.8) $ (3.1) $ (0.3) $ (2.4) $ 0.4
For a further discussion of the risk management activities and
accounting for derivative commodity and other financial instruments, please see
Notes 12 and 14 to the Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required hereunder is included in this report as set
forth in the "Index to Financial Statements" page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE.
None.
46
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
COMPANY MANAGEMENT
The General Partner manages and operates the activities of the Company.
Notwithstanding any limitation on its obligations or duties, the General Partner
is liable, as the general partner of the Company, for all debts of the Company
(to the extent not paid by the Company), except to the extent that indebtedness
or other obligations incurred by the Company are made specifically non-recourse
to the General Partner. Whenever possible, the General Partner intends to make
any such indebtedness or other obligations non-recourse to the General Partner.
At least two of the members of the Board of Directors of the General
Partner who are neither officers, employees or security holders of the General
Partner nor directors, officers, employees or security holders of any affiliate
of the General Partner serve on the Audit and Conflicts Committee, which has the
authority to review specific matters as to which the Board of Directors believes
there may be a conflict of interests in order to determine if the resolution of
such conflict proposed by the General Partner is fair and reasonable to the
Company. Any matters approved by the Audit and Conflicts Committee are
conclusively deemed to be fair and reasonable to the Company, approved by all
partners of the Company and not a breach by the General Partner or its Board of
Directors of any duties they may owe the Company or the Unitholders. In
addition, the Audit and Conflicts Committee reviews the external financial
reporting of the Company, recommends engagement of the Company's independent
public accountants, reviews the Company's procedures for internal auditing and
the adequacy of the Company's internal accounting controls and approves any
increases in the administrative service fee payable under the EPCO Agreement.
As is commonly the case with publicly-traded limited partnerships, the
Company does not directly employ any of the persons responsible for managing or
operating the Company. In general, the management of EPCO, the majority-owner of
the General Partner, manages and operates the Company's business pursuant to the
EPCO Agreement.
DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER
Set forth below is the name, age, and position of each of the directors
and executive officers of the General Partner. Each director and officer is
elected for a one-year term.
Name Age Position with General Partner
- ------------------------------ ----- ------------------------------------------
Dan L. Duncan (1) 67 Director and Chairman of the Board
O.S. Andras (1) 64 Director, President, and Chief Executive
Officer
Randa L. Duncan 38 Director and Group Executive Vice President
Gary L. Miller 51 Director, Executive Vice President, Chief
Financial Officer, and Treasurer
Charles R. Crisp 52 Director
Dr. Ralph S. Cunningham (2) 59 Director
Curtis R. Frasier (1) 44 Director
Lee W. Marshall, Sr.(2) 67 Director
Stephen H. McVeigh (1) 49 Director
Richard H. Bachmann (1) 47 Executive Vice President, Chief Legal
Officer and Secretary
Albert W. Bell 61 Executive Vice President and President &
Chief Operating Officer of Petrochemical
Division
William D. Ray 64 Executive Vice President
A.J. "Jim" Teague 54 Executive Vice President and President &
Chief Operating Officer of NGL Division
Charles E. Crain 66 Senior Vice President
Michael Falco 63 Senior Vice President
Michael A. Creel 46 Senior Vice President
(1) Member of Executive Committee
(2) Member of Audit and Conflicts Committee
47
Dan L. Duncan was elected as Chairman of the Board and a Director of
the General Partner in April 1998. Mr. Duncan joined EPCO in 1969 and has served
as Chairman of the Board of EPCO since 1979. He served as President of EPCO from
1970 to 1979 and Chief Executive Officer from 1982 to 1985.
O. S. Andras was elected as President, Chief Executive Officer and a
Director of the General Partner in April 1998. Mr. Andras has served as
President and Chief Executive Officer of EPCO since 1996. Mr. Andras served as
President and Chief Operating Officer of EPCO from 1982 to 1996 and Executive
Vice President of EPCO from 1981 to 1982. Before joining EPCO, he was employed
by The Dow Chemical Company in various capacities from 1960 to 1981, including
Director of Hydrocarbons.
Randa L. Duncan was elected as Group Executive Vice President and a
director of the General Partner in April 1998. Ms. Duncan has served as Group
Executive Vice President of EPCO since 1994. Before joining EPCO, she was an
attorney with the firms of Butler & Binion from 1988 to 1991 and Brown, Sims,
Wise and White from 1991 until 1994. Ms. Duncan is the daughter of Dan L.
Duncan.
Gary L. Miller was elected as Executive Vice President, Chief
Financial Officer, Treasurer and Director of the General Partner in April 1998.
Mr. Miller has served as Executive Vice President, Chief Financial Officer and
Treasurer of EPCO since 1990. He served as Senior Vice President, Controller and
Treasurer of EPCO from 1988 to 1990. From 1983 to 1988 he served as Vice
President, Treasurer and Controller of EPCO. Before joining EPCO, he was
employed by Wanda Petroleum, where he was Assistant Controller from 1977 to
1980.
Charles R. Crisp was elected as a Director of the General Partner in
November, 1999. Mr. Crisp has served as President and Chief Executive Officer of
Coral Energy, LLC, an affiliate of Shell since 1998. From 1996 to 1998 he was
with Houston Industries, serving as President and Chief Operating Officer of its
domestic power generation group. From 1988 to 1996 he was President and Chief
Executive Officer of Tejas Gas Corporation. Prior to joining Tejas Gas, he held
various engineering, operations and management positions with Conoco, Perry Gas
and Enron's Houston Pipeline Company.
Dr. Ralph S. Cunningham was elected as a Director of the General
Partner in April 1998. Dr. Cunningham retired in 1997 from Citgo Petroleum
Corporation, where he had served as President and Chief Executive Officer since
1995. Dr. Cunningham served as Vice Chairman of Huntsman Corporation from 1994
until 1995 and as President of Texaco Chemical Company from 1990 through 1994.
Prior to joining Texaco Chemical Company, Dr. Cunningham held various executive
positions with Clark Oil & Refining and Tenneco. He started his career in
Exxon's refinery operations. He holds Ph.D., M.S. and B.S. degrees in Chemical
Engineering. Dr. Cunningham serves as a director of Huntsman Corporation, Tetra
Technologies, Inc. and Agrium, Inc. and served as a director of EPCO from 1987
to 1997.
Curtis R. Frasier was elected as Director of the General Partner in
November 1999. Mr. Frasier is Chief Operating, Administrative and Legal Officer
of Coral Energy, LLC, a Shell affiliate. He has served in various capacities in
the Shell organization since 1982 and previously served as President of Shell
Midstream Enterprises. He also served as Shell's Manager of Supply Operations
following assignments in the London office beginning in the Legal Department of
Shell's corporate office.
Lee W. Marshall, Sr. was elected as a Director of the General Partner
in April 1998. Mr. Marshall has been the Chief Executive Officer and principal
stockholder of Bison International, Inc., and Bison Resources, LLC since 1991.
Previously, Mr. Marshall was Executive Vice President and Chief Financial
Officer of Wolverine Exploration Company and held senior management positions
with Union Pacific Resources and Tenneco Oil.
Stephen H. McVeigh was elected as Director of the General Partner in
November 1999. Mr. McVeigh is the Manager of Production and Surveillance for
Shell Offshore Inc. operations in the Gulf of Mexico. From 1997 to 1999, he
served as Chief Operating Officer from Altura Energy Ltd., the joint venture
partnership between Shell and Amoco for the Permian Basin. His 26-year career at
Shell has involved various engineering, planning and managerial assignments in
Shell's domestic exploration and production business.
48
Richard H. Bachmann was elected as Executive Vice President and Chief
Legal Officer of the General Partner in January, 1999. Before joining EPCO, he
was a partner with the firms of Snell & Smith P.C. from 1993 to 1998 and Butler
& Binion from 1988 to 1993.
Albert W. Bell was elected as Executive Vice President of the General
Partner in April 1998 and serves as the President and Chief Operating Officer of
the Petrochemical Division. Mr. Bell has served as Executive Vice President,
Business Management of EPCO since 1994. Mr. Bell joined EPCO in 1980 as
President of its Canadian subsidiary. Mr. Bell transferred to EPCO in Houston in
1988 as Vice President, Business Development and was promoted to Senior Vice
President, Business Management in 1992. Prior to joining EPCO, he was employed
by Continental Emsco Supply Company, Ltd. and Amoco Canada Petroleum Company,
Ltd.
William D. Ray was elected as Executive Vice President, Marketing and
Supply of the General Partner in April 1998. Mr. Ray has served as EPCO's
Executive Vice President, Marketing and Supply since 1985. Mr. Ray served as
Vice President, Supply and Distribution of EPCO from 1971 to 1973 and as EPCO's
Senior Vice President, Supply, Marketing and Distribution from 1973 to 1979.
Prior to joining EPCO in 1971, Mr. Ray was employed by Wanda Petroleum from 1958
to 1969 and Koch as Vice President, Marketing and Supply from 1969 to 1971.
A.J. ("Jim") Teague was elected as Executive Vice President of the
General Partner in November, 1999 and serves as the President and Chief
Operating Officer of the NGL Division of the Company. From 1998 to 1999 he
served as President of Tejas Natural Gas Liquids, LLC, an affiliate of Shell.
From 1997 to 1998 he was President of Marketing and Trading for Mapco, Inc. From
1972 to 1996, he held a variety of positions with The Dow Chemical Company,
including Vice President, Feedstocks.
Charles E. Crain was elected as Senior Vice President, Operations of
the General Partner in April 1998 and has served as Senior Vice President,
Operations of EPCO since 1991. Mr. Crain joined EPCO in 1980 as Vice President,
Process Operations. Prior to joining EPCO, Mr. Crain held positions with Shell,
Air Products & Chemicals and Tenneco Chemicals.
Michael Falco was elected Senior Vice President of the General Partner
in April 1998. Mr. Falco had served as EPCO's Senior Vice President in the
business management area since 1992. Previously, Mr. Falco had a 21 year career
with Tenneco Oil Company, holding a variety of positions in NGL supply and crude
oil and refined products supply including 6 years as Vice President of Tenneco
Oil.
Michael A. Creel was elected Senior Vice President of the General
Partner in November 1999 with responsibilities in investor relations,
information technology and corporate risk. From 1997 to 1999 he held a series of
positions, including Senior Vice President, Chief Financial Officer and
Treasurer, with Tejas Energy, LLC. From 1991 to 1997 he served as Vice President
and Treasurer of NorAm Energy Corp., Treasurer of Enron Oil & Gas Company, and
was employed by Enron Corp. in various capacities, including Assistant
Treasurer. From 1973 to 1991 he held management positions in accounting and
finance within the energy and financial industries.
ITEM 11. EXECUTIVE COMPENSATION.
The Company has no executive officers. The Company is managed by the
General Partner, the executive officers of which are employees of, and the
compensation of whom is paid by, EPCO. Pursuant to the EPCO Agreement, EPCO is
reimbursed at cost for all expenses that it incurs managing the business and
affairs of the Company, except that EPCO is not entitled to be reimbursed for
any selling, general, and administrative expenses. In lieu of reimbursement for
such selling, general, and administrative expenses, EPCO is entitled to receive
an annual administrative services fee that currently equals $13.2 million. The
Company paid EPCO $12.5 million in administrative services fees under the EPCO
Agreement during 1999.
The General Partner, with the approval and consent of the Audit and
Conflicts Committee, has the right to agree to increases in such administrative
services fee of up to 10% each year during the 10-year term of the EPCO
agreement and may agree to further increases in such fee in connection with
expansions of the Company's operations through the construction of new
facilities or the completion of acquisitions that require additional management
49
personnel. In accordance with this policy, on July 7, 1999, the Audit and
Conflicts Committee of the General Partner authorized an increase in the
administrative services fee to $1.1 million per month in accordance with the
EPCO Agreement from the initial rate of $1.0 million per month. The increased
fees were effective August 1, 1999. Beginning in January 2000, the
administrative services fee will increase to $1.55 million per month plus
accrued employee incentive plan costs to compensate EPCO for the additional
selling, general, and administrative charges related to the additional
administrative employees acquired in the TNGL acquisition.
COMPENSATION OF DIRECTORS
No additional remuneration is paid to employees of EPCO or the General
Partner who also serve as directors of the General Partner. Each independent
director receives $24,000 annually, for which each agrees to participate in four
regular meetings of the Board of Directors and four Audit and Conflicts
Committee meetings. Each independent director also receives $500 for each
additional meeting in which he participates. In addition, each independent
director is reimbursed for his out-of-pocket expenses in connection with
attending meetings of the Board of Directors or committees thereof. Each
director is fully indemnified by the Company for his actions associated with
being a director to the extent permitted under Delaware law.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The following table sets forth certain information as of February 14,
2000, regarding the beneficial ownership of (a) the Common Units, (b) the
Subordinated Units and (c) the Special Units of the Company by all directors of
the General Partner, each of the named executive officers, all directors and
executive officers as a group and all persons known by the General Partner to
own beneficially more than 5% of the Common Units.
Percentage of Percentage of Percentage of Percentage
of
Common Common Subordinated Subordinated Special Special Total Total
Units Units Units Units Units Units Units Units
Beneficially Beneficially Beneficially Beneficially Beneficially Beneficially Beneficially Beneficially
Owned Owned Owned Owned Owned Owned Owned Owned
----- ----- ----- ----- ----- ----- ----- -----
EPCO (1) 33,552,915 73.7% 21,409,870 100.0% 0.0% 0.0% 54,962,785 67.5%
Coral Energy LLC (2) - 0.0% - 0.0% 14,500,000 100.0% 14,500,000 17.8%
Dan Duncan (1) 33,552,915 73.7% 21,409,870 100.0% - 0.0% 54,962,785 67.5%
O.S. Andras 140,600 0.3% - 0.0% - 0.0% 140,600 0.2%
Randa L. Duncan - 0.0% - 0.0% - 0.0% - 0.0%
Gary L. Miller - 0.0% - 0.0% - 0.0% - 0.0%
Charles R. Crisp - 0.0% - 0.0% - 0.0% - 0.0%
Dr. Ralph S. Cunningham - 0.0% - 0.0% - 0.0% - 0.0%
Curtis R.Frasier - 0.0% - 0.0% - 0.0% - 0.0%
Lee W. Marshall, Sr. - 0.0% - 0.0% - 0.0% - 0.0%
Stephen H. McVeigh - 0.0% - 0.0% - 0.0% - 0.0%
All directors and
executive
officers as a group
(16 persons) 33,708,524 74.0% 21,409,870 100.0% - 0.0% 55,118,394 67.7%
- -----------------------------------------------------------------------------------------------------------------------------------
(1) EPCO holds the Units through its wholly-owned subsidiary EPC Partners
II, Inc. Mr. Duncan owns 57.1% of the voting stock of EPCO and,
accordingly, exercises sole voting and dispositive power with respect
to the Units held by EPCO. The remaining shares of EPCO capital stock
are held primarily by trusts for the benefit of the members of Mr.
Duncan's family, including Randa L. Duncan, a director and executive
officer of the Company. The address of EPCO is 2727 North Loop West,
Houston, Texas 77008.
(2) Special Units were issued to Coral Energy LLC (formerly Tejas Energy
LLC) as part of the TNGL acquisition
(3) For a discussion of the Company's Partners' Equity and the Units in
general, see Note 7 of the Notes to the Consolidated Financial
50
Statements. Subordinated Units and Special Units are non-voting.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Under the federal securities laws, the General Partner, the General
Partner's directors, executive (and certain other) officers, and any persons
holding more than ten percent of the Common Units are required to report their
ownership of Common Units and any changes in that ownership to the Company and
the SEC. Specific due dates for these reports have been established by
regulation and the Company is required to disclose in this report any failure to
file by these dates in 1999. Due to clerical and record keeping errors, Form 4
reports with respect to November 1998 for EPCO (5 transactions) and Dan L.
Duncan (5 transactions) were filed in January 1999, a Form 4 report (1
transaction) with respect to November 1999 for Richard H. Bachmann was filed in
January 2000, and Form 4 reports with respect to December 1999 for EPCO (5
transactions) and Dan L. Duncan (5 transactions) were filed in February 2000.
The Company believes that all of these filings were satisfied by the
General Partner, the General Partner's directors and officers, and ten percent
holders. As of February 18, 2000, the Company believes that the General Partner,
and all of the General Partner's directors and officers and any ten percent
holders are current in their filings. In making these statements, the Company
has relied on the written representations of the General Partner, the General
Partner's directors and officers, and ten percent holders and copies of reports
that they have filed with the SEC.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
OWNERSHIP INTERESTS OF EPCO AND ITS AFFILIATES IN THE COMPANY
At December 31, 1999, EPC Partners II, Inc., a wholly owned subsidiary
of EPCO, owned 33,552,915 Common Units and 21,409,870 Subordinated Units,
representing a 40.8% interest and a 26.0% interest, respectively, in the
Company. In addition, the General Partner owned a combined 2% interest in the
Company and the Operating Partnership. In addition, another affiliate of EPCO,
Enterprise Products 1998 Unit Option Plan Trust (the "1998 Trust") owned
1,035,504 Common Units as of December 31, 1999. The 1998 Trust was formed for
the purpose of granting options in the Company's securities to management and
certain key employees. The 1998 Trust may purchase additional Units on the open
market or through privately negotiated transactions.
OWNERSHIP INTERESTS OF OTHER AFFILIATES OF THE COMPANY
Another affiliate of the Company, EPOLP 1999 Grantor Trust (the
"Trust"), was formed to fund liabilities of a long-term incentive employee
benefit plan. As of December 31, 1999, the Trust had purchased 267,200 Common
Units.
Related Party Transactions with Shell
As a result of the TNGL acquisition, Shell, through its subsidiary
Coral Energy LLC (formerly Tejas Energy, LLC), acquired an ownership interest in
the Company and its General Partner. At December 31, 1999, Shell owned
approximately 17.6% of the Company and 30.0% of the General Partner.
The Company's major customer related to the TNGL assets is Shell. Under
the terms of the Shell Processing Agreement, the Company has the right to
process substantially all of Shell's current and future natural gas production
from the Gulf of Mexico. This includes natural gas production from the
developments currently referred to as deepwater. Generally, the Shell Processing
Agreement grants the Company the following rights and obligations:
o the exclusive right to process any and all of Shell's Gulf of Mexico
natural gas production from existing and future dedicated leases; plus
o the right to all title, interest, and ownership in the raw make
extracted by the Company's gas processing facilities from Shell's
natural gas production from such leases; with
o the obligation to deliver to Shell the natural gas stream after the
raw make is extracted.
51
In addition to the Shell Processing Agreement, the Company acquired
short-term leases on approximately 400 rail cars on average from Shell for
servicing the gas processing business activities. Such lease costs totaled
approximately $1.7 million in 1999.
RELATED PARTY TRANSACTIONS WITH EPCO AND UNCONSOLIDATED AFFILIATES
The Company, the Operating Partnership, the General Partner, EPCO and
certain other parties have entered into various documents and agreements that
generally govern the business of the Company and its affiliates. Such documents
and agreements are not the result of arm's-length negotiations, and there can be
no assurance that it, or that any of the transactions provided for therein, are
effected on terms at least as favorable to the parties to such agreement as
could have been obtained from unaffiliated third parties.
The Company has an extensive ongoing relationship with EPCO and its
affiliates. These relationships include the following:
(i) All management, administrative and operating functions for the
Company are performed by officers and employees of EPCO pursuant to the terms of
the EPCO Agreement. Under the EPCO Agreement, EPCO employs the operating
personnel involved in the Company's business and is reimbursed at cost.
(ii) EPCO is and will continue as operator of the plants and facilities
owned by BEF and EPIK and in connection therewith will charge such entities for
actual salary costs and related fringe benefits. As operator of such facilities,
EPCO also is entitled to be reimbursed for the cost of providing certain
management services to such entities, which costs totaled $0.8 million in the
aggregate for the year ended December 31, 1999.
(iii) EPCO and the Company have entered into an agreement pursuant to
which EPCO provides trucking services to the Company.
(iv) EPCO retains the Retained Leases and, pursuant to the terms of the
EPCO Agreement, subleases all of the facilities covered by the Retained Leases
to the Company for $1 per year and has assigned its purchase options under the
Retained Leases to the Company. EPCO is liable for the lease payments under the
Retained Leases.
(v) Pursuant to the EPCO Agreement, the Company and the Operating
Partnership participate as named insureds in EPCO's current insurance program,
and costs attributable thereto are allocated among the parties on the basis of
formulas set forth in such agreement.
(vi) Pursuant to the EPCO Agreement, EPCO licenses certain trademarks
and tradenames to the Company and indemnifies the Company for certain lawsuits
and claims.
(vii) In the normal course of its business, the Company engages in
transactions with BEF and other subsidiaries and divisions of EPCO involving the
buying and selling of NGL products.
For a description of certain historical related party transactions
between Shell, EPCO, the Company and their affiliates, see Note 10 of Notes to
Consolidated Financial Statements.
52
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Financial Statements" set forth on page F-1.
(A)(3) EXHIBITS
*3.1 Form of Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L.P. (Exhibit 3.1 to Registration Statement
on Form S-1, File No. 333-52537, filed on May 13, 1998).
*3.2 Form of Amended and Restated Agreement of Limited Partnership of
Enterprise Products Operating L.P. (Exhibit 3.2 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*3.3 LLC Agreement of Enterprise Products GP (Exhibit 3.3 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*3.4 Second Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L.P. dated September 17, 1999. (The Company
incorporates by reference the above document included in the Schedule
13D filed September 27, 1999 by Tejas Energy LLC ; filed as Exhibit 99.7
on Form 8-K dated October 4, 1999).
*3.5 First Amended and Restated Limited Liability Company Agreement of
Enterprise Products GP, LLC dated September 17, 1999. (Exhibit 99.8 on
Form 8-K/A-1 filed October 27, 1999).
*4.1 Form of Common Unit certificate (Exhibit 4.1 to Registration Statement
on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*4.2 $200 million Credit Agreement among Enterprise Products Operating L.P.,
the Several Banks from Time to Time Parties Hereto, Den Norske Bank ASA,
and Bank of Tokyo-Mitsubishi, Ltd., Houston Agency as Co-Arrangers, The
Bank of Nova Scotia, as Co-Arranger and as Documentation Agent and The
Chase Manhattan Bank as Co-Arranger and as Agent dated as of July 27,
1998 as Amended and Restated as of September 30, 1998. (Exhibit 4.2 on
Form 10-K for year ended December 31, 1998, filed March 17, 1999).
*4.3 First Amendment to $200 million Credit Agreement dated July 28, 1999
among Enterprise Products Operating L.P. and the several banks thereto.
(Exhibit 99.9 on Form 8-K/A-1 filed October 27, 1999).
*4.4 $350 million Credit Agreement among Enterprise Products Operating L.P.,
BankBoston, N.A., Societe Generale, Southwest Agency and First Union
National Bank, as Co-Arrangers, The Chase Manhattan Bank, as Co-Arranger
and as Administrative Agent, The First National Bank of Chicago, as
Co-Arranger and as Documentation Agent, The Bank of Nova Scotia, as
Co-Arranger and Syndication Agent, and the Several Banks from Time to
Time parties hereto with First Union Capital Markets acting as Managing
Agent and Chase Securities Inc. acting as Lead Arranger and Book Manager
dated July 28, 1999 (Exhibit 99.10 on Form 8-K/A-1 filed October 27,
1999).
*4.5 Unitholder Rights Agreement among Tejas Energy LLC, Tejas Midstream
Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products
Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC
and EPC Partners II, Inc. dated September 17, 1999. (The Company
incorporates by reference the above document included in the Schedule
13D filed September 27, 1999 by Tejas Energy LLC; filed as Exhibit 99.5
on Form 8-K dated October 4, 1999).
*10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline
Partnership, L.P., Chunchula Pipeline Company, LLC, Propylene Pipeline
Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise Products
53
Texas Operating L.P. dated June 1, 1998 (Exhibit 10.1 to Registration
Statement on Form S-1/A, File No: 333-52537, filed on July 8, 1998).
*10.2 Form of EPCO Agreement between Enterprise Products Partners L.P.,
Enterprise Products Operating L.P., Enterprise Products GP, LLC and
Enterprise Products Company (Exhibit 10.2 to Registration Statement on
Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*10.3 Transportation Contract between Enterprise Products Operating L.P. and
Enterprise Transportation Company dated June 1, 1998 (Exhibit 10.3 to
Registration Statement on Form S-1/A, File No. 333-52537, filed on July
8, 1998).
*10.4 Venture Participation Agreement between Sun Company, Inc. (R&M), Liquid
Energy Corporation and Enterprise Products Company dated May 1, 1992
(Exhibit 10.4 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.5 Partnership Agreement between Sun BEF, Inc., Liquid Energy Fuels
Corporation and Enterprise Products Company dated May 1, 1992 (Exhibit
10.5 to Registration Statement on Form S-1, File No. 333-52537, filed on
May 13, 1998).
*10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu
Environmental Fuels and Sun Company, Inc. (R&M) dated August 16, 1995
(Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.7 Articles of Partnership of Mont Belvieu Associates dated July 17, 1985
(Exhibit 10.7 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.8 First Amendment to Articles of Partnership of Mont Belvieu Associates
dated July 15, 1996 (Exhibit 10.8 to Registration Statement on Form S-1,
File No. 333-52537, filed on May 13, 1998).
*10.9 Propylene Facility and Pipeline Agreement between Enterprise
Petrochemical Company and Hercules Incorporated dated December 13, 1978
(Exhibit 10.9 to Registration Statement on Form S-1, File No. 333-52537,
dated May 13, 1998).
*10.10 Restated Operating Agreement for the Mont Belvieu Fractionation
Facilities Chambers County, Texas between Enterprise Products Company,
Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin
Petroleum Company dated July 17, 1985 (Exhibit 10.10 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
*10.11 Ratification and Joinder Agreement relating to Mont Belvieu Associates
Facilities between Enterprise Products Company, Texaco Producing Inc.,
El Paso Hydrocarbons Company, Champlin Petroleum Company and Mont
Belvieu Associates dated July 17, 1985 (Exhibit 10.11 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
*10.12 Amendment to Propylene Facility and Pipeline Sales Agreement between
HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1,
1993 (Exhibit 10.12 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.13 Amendment to Propylene Facility and Pipeline Agreement between HIMONT
U.S.A., Inc. and Enterprise Products Company dated January 1, 1995
(Exhibit 10.13 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.14 Fourth Amendment to Conveyance of Gas Processing Rights between Tejas
Natural Gas Liquids, LLC and Shell Oil Company, Shell Exploration &
Production Company, Shell Offshore Inc., Shell Deepwater Development
Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas Inc.
dated August 1, 1999. (Exhibit 10.14 to Form 10-Q filed on November 15,
1999).
54
*99.1 Contribution Agreement between Tejas Energy LLC, Tejas Midstream
Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products
Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC
and EPC Partners II, Inc. dated September 17, 1999. (The Company
incorporates by reference the above document included in the Schedule
13D filed September 27, 1999 by Tejas Energy LLC; filed as Exhibit 99.4
on Form 8-K dated October 4, 1999).
*99.2 Registration Rights Agreement between Tejas Energy LLC and Enterprise
Products Partners L.P. dated September 17, 1999. (The Company
incorporates by reference the above document included in the Schedule
13D filed September 27, 1999 by Tejas Energy LLC ; filed as Exhibit 99.6
on Form 8-K dated October 4, 1999).
21.1 List of Subsidiaries of the Company
27.1 Financial Data Schedule
- ---------------------
* Asterisk indicates exhibits incorporated by reference as indicated; all
other exhibits are filed herewith
(B) REPORTS ON FORM 8-K
The Company filed three Form 8-Ks during the quarter ending December
31, 1999.
On October 4, 1999, a Form 8-K was filed whereby the Company summarized
the Unitholder Rights Agreement and other material agreements associated with
the TNGL acquisition. This filing incorporated by reference certain material
documents associated with the acquisition.
On October 27, 1999, a Form 8-K/A-1 was filed whereby the Company
disclosed certain historical financial information of TNGL for the years ended
1996, 1997, and 1998. In addition, this filing contained other documentation
relating to the TNGL acquisition.
On November 29, 1999, a Form 8-K/A-2 was filed whereby the Company
disclosed preliminary unaudited pro forma condensed financial information
regarding the TNGL acquisition for the period ending December 31, 1998 and for
the nine months ending September 30, 1999.
55
INDEX TO FINANCIAL STATEMENTS
PAGE
ENTERPRISE PRODUCTS PARTNERS L.P.
Independent Auditors' Report .........................................F-2
Consolidated Balance Sheets as of December 31, 1998 and 1999..........F-3
Statements of Consolidated Operations
for the Years Ended December 31, 1997, 1998 and 1999 .............F-4
Statements of Consolidated Cash Flows
for the Years Ended December 31, 1997, 1998 and 1999..............F-5
Statements of Consolidated Partners' Equity
for the Years Ended December 31, 1997, 1998 and 1999 .............F-6
Notes to Consolidated Financial Statements ...........................F-7
SUPPLEMENTAL SCHEDULE:
Schedule II - Valuation and Qualifying Accounts
All schedules, except the one listed above, have been omitted because they are
either not applicable, not required or the information called for therein
appears in the consolidated financial statements or notes thereto.
F-1
INDEPENDENT AUDITORS' REPORT
Enterprise Products Partners L.P.:
We have audited the accompanying consolidated balance sheets of Enterprise
Products Partners L.P. (the "Company") as of December 31, 1998 and 1999, and the
related statements of consolidated operations, consolidated cash flows and
consolidated partners' equity for each of the years in the three-year period
ended December 31, 1999. Our audits also included the consolidated financial
statement schedule of the Company listed in the Index to the Financial
Statements. These consolidated financial statements and schedule are the
responsibility of the management of the Company. Our responsibility is to
express an opinion on these consolidated financial statements and schedule 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, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 1998
and 1999, and the results of its operations and its cash flows for each of the
years in the three-year period ended December 31, 1999 in conformity with
generally accepted accounting principles. Also, in our opinion, such
consolidated financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2000
F-2
ENTERPRISE PRODUCTS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
DECEMBER 31,
-------------------------------------
ASSETS 1998 1999
-------------------------------------
CURRENT ASSETS
Cash and cash equivalents $ 24,103 $ 5,230
Accounts receivable - trade, net of allowance for doubtful accounts of
$15,871 in 1999 57,288 262,348
Accounts receivable - affiliates 15,546 56,075
Inventories 17,574 39,907
Current maturities of participation in notes receivable from
unconsolidated affiliates 14,737 6,519
Prepaid and other current assets 8,445 14,459
-------------------------------------
Total current assets 137,693 384,538
PROPERTY, PLANT AND EQUIPMENT, NET 499,793 767,069
INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES 91,121 280,606
PARTICIPATION IN NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES 11,760
INTANGIBLE ASSETS, NET OF ACCUMULATED AMORTIZATION OF $1,343 61,619
OTHER ASSETS
670 1,120
=====================================
TOTAL $ 741,037 $ 1,494,952
=====================================
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 129,000
Accounts payable - trade $ 36,586 69,294
Accounts payable - affiliate 64,780
Accrued gas payables 27,183 216,348
Accrued expenses 7,540 33,522
Other current liabilities 11,462 18,176
-------------------------------------
Total current liabilities 82,771 531,120
LONG-TERM DEBT 90,000 166,000
OTHER LONG-TERM LIABILITIES 296
MINORITY INTEREST 5,730 8,071
COMMITMENTS AND CONTINGENCIES
PARTNERS' EQUITY
Common Units (45,552,915 Units outstanding at December 31, 1998
and 1999) 433,082 428,707
Subordinated Units (21,409,870 Units outstanding at December 31, 1998
and 1999) 123,829 131,688
Special Units (14,500,000 Units outstanding at December 31, 1999) 225,855
Treasury Units acquired by Trust, at cost (267,200 Units outstanding at
December 31, 1999) (4,727)
General Partner 5,625 7,942
-------------------------------------
Total Partners' Equity 562,536 789,465
=====================================
TOTAL $ 741,037 $ 1,494,952
=====================================
See Notes to Consolidated Financial Statements
F-3
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
(Amounts in Thousands, Except per Unit Amounts)
YEARS ENDED DECEMBER 31,
--------------------------------------------------------
1997 1998 1999
--------------------------------------------------------
REVENUES
Revenues from consolidated operations $ 1,020,281 $ 738,902 $ 1,332,979
Equity income in unconsolidated affiliates 15,682 15,671 13,477
--------------------------------------------------------
Total 1,035,963 754,573 1,346,456
COST AND EXPENSES
Operating costs and expenses 938,392 685,884 1,201,605
Selling, general and administrative 21,891 18,216 12,500
--------------------------------------------------------
Total 960,283 704,100 1,214,105
--------------------------------------------------------
OPERATING INCOME 75,680 50,473 132,351
--------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (25,717) (15,057) (16,439)
Interest income from unconsolidated affiliates 809 1,667
Dividend income from unconsolidated affiliates 3,435
Interest income - other 1,934 772 886
Other, net 793 358 (379)
--------------------------------------------------------
Other income (expense) (22,990) (13,118) (10,830)
--------------------------------------------------------
INCOME BEFORE EXTRAORDINARY ITEM
AND MINORITY INTEREST 52,690 37,355 121,521
Extraordinary charge on early extinguishment of debt (27,176)
--------------------------------------------------------
INCOME BEFORE MINORITY INTEREST 52,690 10,179 121,521
MINORITY INTEREST (527) (102) (1,226)
========================================================
NET INCOME $ 52,163 $ 10,077 $ 120,295
========================================================
ALLOCATION OF NET INCOME TO:
Limited partners $ 51,641 $ 9,976 $ 119,092
========================================================
General partner $ 522 $ 101 $ 1,203
========================================================
BASIC EARNINGS PER COMMON UNIT
Income before extraordinary item and
minority interest per common unit $ 0.95 $ 0.62 $ 1.80
========================================================
Net income per common unit $ 0.94 $ 0.17 $ 1.79
========================================================
DILUTED EARNINGS PER COMMON UNIT
Income before extraordinary item and
minority interest per common unit $ 0.95 $ 0.62 $ 1.65
========================================================
Net income per common unit $ 0.94 $ 0.17 $ 1.64
========================================================
See Notes to Consolidated Financial Statements
F-4
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Amounts in Thousands)
YEAR ENDED DECEMBER 31,
------------------------------------------------------
1997 1998 1999
------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 52,163 $ 10,077 $ 120,295
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Extraordinary item - early extinguishment of debt 27,176
Depreciation and amortization 17,684 19,194 25,315
Equity in income of unconsolidated affiliates (15,682) (15,671) (13,477)
Leases paid by EPCO 4,010 10,557
Minority interest 527 102 1,226
(Gain) loss on sale of assets 155 (276) 123
Net effect of changes in operating accounts 2,948 (64,906) 24,771
------------------------------------------------------
Operating activities cash flows 57,795 (20,294) 168,810
------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (33,636) (8,360) (21,234)
Proceeds from sale of assets 1,887 8
Business acquisitions, net of cash acquired (208,095)
Participation in notes receivable from unconsolidated affiliates:
Purchase of notes receivable (33,725)
Collection of notes receivable 7,228 19,979
Unconsolidated affiliates:
Investments in and advances to (4,625) (26,842) (61,887)
Distributions received 7,279 9,117 6,008
------------------------------------------------------
Investing activities cash flows (30,982) (50,695) (265,221)
------------------------------------------------------
FINANCING ACTIVITIES
Net proceeds from sale of common units 243,296
Long-term debt borrowings 598 90,000 350,000
Long-term debt repayments (25,978) (257,413) (154,923)
Net decrease in restricted cash (1,171) 4,522
Cash dividends paid to partners (21,645) (111,758)
Cash dividends paid to minority interest by Operating Partnership (1,140)
Units acquired by consolidated trust (4,727)
Cash contributions from EPCO to minority interest 2,478 86
------------------------------------------------------
Financing activities cash flows (26,551) 61,238 77,538
------------------------------------------------------
CASH CONTRIBUTIONS FROM (TO) EPCO (6,299) 14,913
------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (6,037) 5,162 (18,873)
CASH AND CASH EQUIVALENTS, JANUARY 1
24,978 18,941 24,103
======================================================
CASH AND CASH EQUIVALENTS , DECEMBER 31 $ 18,941 $ 24,103 $ 5,230
======================================================
(Excluding restricted cash of $4,522 in 1997)
See Notes to Consolidated Financial Statements
F-5
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY
(Amounts in Thousands)
LIMITED PARTNERS
------------------------------------------------
COMMON SUBORDINATED SPECIAL TREASURY GENERAL
UNITS UNITS UNITS UNITS PARTNER TOTAL
--------------------------------------------------------------------------------------------
Consolidated Partners' Equity,
January 1, 1997 $ 160,783 $ 102,578 $ 2,660 $ 266,021
Net income 31,527 20,114 522 52,163
Cash distributions to EPCO (3,807) (2,429) (63) (6,299)
--------------------------------------------------------------------------------------------
Consolidated Partners' Equity,
December 31, 1997 188,503 120,263 3,119 311,885
Net income 5,641 4,335 101 10,077
Cash contributions from EPCO 7,519 4,813 2,581 14,913
Leases paid by EPCO after
public offering 2,701 1,269 40 4,010
Proceeds from sale of
Common Units 243,296 243,296
Cash distributions to Unitholders (14,578) (6,851) (216) (21,645)
--------------------------------------------------------------------------------------------
Consolidated Partners' Equity,
December 31, 1998 433,082 123,829 5,625 562,536
Net income 71,038 33,409 14,645 1,203 120,295
Leases paid by EPCO
after public offering 6,580 3,097 774 106 10,557
Special Units issued to Tejas
Energy, LLC in connection
with TNGL acquisition 210,436 2,126 212,562
Cash distributions to Unitholders (81,993) (28,647) (1,118) (111,758)
Units acquired by consolidated trust (4,727) (4,727)
--------------------------------------------------------------------------------------------
Consolidated Partners' Equity,
December 31, 1999 $ 428,707 $ 131,688 $ 225,855 $ (4,727) $ 7,942 $ 789,465
============================================================================================
See Notes to Consolidated Financial Statements
F-6
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ENTERPRISE PRODUCTS PARTNERS L.P. (the "Company") was formed on April 9, 1998 as
a Delaware limited partnership to own and operate the natural gas liquids
("NGL") business of Enterprise Products Company ("EPCO"). The Company is the
limited partner and owns 98.9899% of Enterprise Products Operating L.P. (the
"Operating Partnership"), which directly or indirectly owns or leases and
operates NGL facilities. Enterprise Products GP, LLC (the "General Partner") is
the general partner and owns 1.0101% of the Operating Partnership and 1% of the
Company. Both the Company and the General Partner are subsidiaries of EPCO.
Prior to their consolidation, EPCO and its affiliated companies were controlled
by members of a single family, who collectively owned at least 90% of each of
the entities for all periods prior to the formation of the Company. As of April
30, 1998, the owners of all the affiliated companies exchanged their ownership
interests for shares of EPCO. Accordingly, each of the affiliated companies
became a wholly owned subsidiary of EPCO or was merged into EPCO as of April 30,
1998. In accordance with generally accepted accounting principles, the
consolidation of the affiliated companies with EPCO was accounted for as a
reorganization of entities under common control in a manner similar to a pooling
of interests.
Under terms of a contract entered into on May 8, 1998 between EPCO and the
Operating Partnership, EPCO contributed all of its NGL assets through the
Company and the General Partner to the Operating Partnership and the Operating
Partnership assumed certain of EPCO's debt. As a result, the Company became the
successor to the NGL operations of EPCO.
Effective July 27, 1998, the Company filed a registration statement pursuant to
an initial public offering of 12,000,000 Common Units. The Common Units sold for
$22 per unit. The Company received approximately $243.3 million after
underwriting commissions of $16.8 million and expenses of approximately $3.9
million.
The accompanying consolidated financial statements include the historical
accounts and operations of the NGL business of EPCO, including NGL operations
conducted by affiliated companies of EPCO prior to their consolidation with
EPCO. Investments in which the Company owns 20% to 50% and exercises significant
influence over operating and financial policies are accounted for using the
equity method. All significant intercompany accounts and transactions have been
eliminated in consolidation.
Certain reclassifications have been made to the prior years' financial
statements to conform to the presentation of the current period financial
statements.
INVENTORIES, consisting of NGLs and NGL products, are carried at the lower of
average cost or market.
EXCHANGES are movements of NGL products between parties to satisfy timing and
logistical needs of the parties. NGLs and NGL products borrowed from the Company
under such agreements are included in inventories, and NGLs and NGL products
loaned to the Company under such agreements are accrued as a liability in
accrued gas payables.
PROPERTY, PLANT AND EQUIPMENT is recorded at cost and is depreciated using the
straight-line method over the asset's estimated useful life. Maintenance,
repairs and minor renewals are charged to operations as incurred. Additions,
improvements and major renewals are capitalized. The cost of assets retired or
sold, together with the related accumulated depreciation, is removed from the
accounts, and any gain or loss on disposition is included in income.
INTANGIBLE ASSETS include the values assigned to a 20-year natural gas
processing agreement and the excess cost of the purchase price over the fair
market value of the assets acquired from Mont Belvieu Associates. The $54.0
million in intangibles related to the natural gas processing agreement is being
amortized over the life of the agreement. For the year 1999, approximately
F-7
$1.1 million of such amortization was charged to expense. The $8.7 million
excess cost of the purchase price over the fair market value of the assets
acquired from Mont Belvieu Associates is being amortized over 20 years. For the
year 1999, approximately $0.2 million of such amortization was charged to
expense.
EXCESS COST OVER UNDERLYING EQUITY IN NET ASSETS denotes the excess of the
Company's cost over the underlying equity in net assets of K/D/S Promix, LLC and
is being amortized using the straight-line method over 20 years. Such
amortization is reflected in the equity earnings from unconsolidated affiliates
and aggregated $0.2 million in 1999 and none for prior periods. The unamortized
excess was approximately $7.8 million at December 31, 1999 and is included in
investments in and advances to unconsolidated affiliates.
EXCESS COST AND LONG-LIVED ASSETS held and used by the Company are reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. The Company has not
recognized any impairment losses for the periods presented.
REVENUE is recognized when products are shipped or services are rendered.
USE OF ESTIMATES AND ASSUMPTIONS by management 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 are required for the preparation of
financial statements in conformity with generally accepted accounting
principles. Actual results could differ from these estimates.
FEDERAL INCOME TAXES are not provided because the Company and its predecessors
either had elected under provisions of the Internal Revenue Code to be a Master
Limited Partnership or Subchapter S Corporation or were organized as other types
of pass-through entities for federal income tax purposes. As a result, for
federal income taxes purposes, the owners are individually responsible for the
taxes on their allocable share of the consolidated taxable income of the
Company. State income taxes are not material.
ENVIRONMENTAL COSTS for remediation are accrued based on estimates of known
remediation requirements. Such accruals are based on management's best estimate
of the ultimate costs to remediate the site. Ongoing environmental compliance
costs are charged to expense as incurred, and expenditures to mitigate or
prevent future environmental contamination are capitalized. Environmental costs,
accrued environmental liabilities and expenditures to mitigate or eliminate
future environmental contamination for each of the years in the three-year
period ended December 31, 1999 were not significant to the consolidated
financial statements. The Company's estimated liability for environmental
remediation is not discounted.
CASH FLOWS are computed using the indirect method. For cash flow purposes, the
Company considers all highly liquid debt instruments with an original maturity
of less than three months at the date of purchase to be cash equivalents. All
cash presented as restricted cash in the Company's financial statements was due
to requirements of the Company's debt agreements.
HEDGES, such as swaps, forwards and other contracts to manage the price risks
associated with inventories, commitments and certain anticipated transactions
are occasionally entered into by the Company. The Company defers the impact of
changes in the market value of these contracts until such time as the hedged
transaction is completed. At that time, the impact of the changes in the fair
value of these contracts is recognized. To qualify as a hedge, the item to be
hedged must expose the Company to commodity or interest rate risk and the
hedging instrument reduce that exposure. Any contracts held or issued that did
not meet the requirements of a hedge would be recorded at fair value in the
balance sheet and any changes in that fair value recognized in income. If a
contract designated as a hedge of commodity risk is terminated, the associated
gain or loss is deferred and recognized in income in the same manner as the
hedged item. Also, a contract designated as a hedge of an anticipated
transaction that is no longer likely to occur would be recorded at fair value
and the associated changes in fair value recognized in income.
DOLLAR AMOUNTS (except per Unit amounts) presented in the tabulations within the
notes to the Company's financial statements are stated in thousands of dollars,
unless otherwise indicated.
F-8
RECENT STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS include the following: On
June 6, 1999, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standard ("SFAS") No. 137, "Accounting for Derivative
Instruments and Hedging Activities-Deferral of the Effective Date of FASB
Statement No. 133-an amendment of FASB Statement No. 133" which effectively
delays the application of SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities" for one year, to fiscal years beginning after June 15,
2000. Management is currently studying SFAS No. 133 for possible impact on the
consolidated financial statements when it is adopted in 2001.
EARNINGS PER UNIT is based on the amount of income allocated to limited partners
and the weighted-average number of Units outstanding during the period.
Specifically, basic earnings per Unit is calculated by dividing the amount of
income allocated to limited partners by the weighted-average number of Common
Units and Subordinated Units outstanding during the period. Diluted earnings per
Unit is based on the amount of income allocated to limited partners and the
weighted-average number of Common Units, Subordinated Units, and Special Units
outstanding during the period. The Special Units are excluded from the
computation of basic earnings per Unit because, under the terms of the Special
Units, they do not share in income nor are they entitled to unit distributions
until they are converted to Common Units. At December 31, 1999, such tests have
not been met.
2. ACQUISITIONS
ACQUISITION OF TEJAS NATURAL GAS LIQUIDS, LLC
Effective August 1, 1999, the Company acquired Tejas Natural Gas Liquids, LLC
("TNGL") from a subsidiary of Tejas Energy, LLC, an affiliate of Shell Oil
Company . All references hereafter to "Shell", unless the context indicates
otherwise, shall refer collectively to Shell Oil Company, its subsidiaries and
affiliates. TNGL engages in natural gas processing and NGL fractionation,
transportation, storage and marketing in Louisiana and Mississippi. TNGL's
assets include a 20-year natural gas processing agreement with Shell for the
rights to process Shell's current and future natural gas production from the
state and federal waters of the Gulf of Mexico ("Shell Processing Agreement")
and varying interests in eleven natural gas processing plants (including one
under construction) with a combined gross capacity of 11.0 billion cubic feet
per day (Bcfd) and a net capacity of 3.1 Bcfd; four NGL fractionation facilities
with a combined gross capacity of 281,000 barrels per day (BPD) and net capacity
of 131,500 BPD; four NGL storage facilities with approximately 28.8 million
barrels of gross capacity and 8.8 million barrels of net capacity; and
approximately 1,500 miles of NGL pipelines.
The TNGL acquisition was purchased with a combination of $166 million in cash
and the issuance of 14.5 million non-distribution bearing, convertible Special
Units. The $166 million cash portion of the purchase price was funded with
borrowings under the Company's $350 million bank credit facility. The Special
Units were valued within a range provided by an independent investment banker
using both present value and Black Scholes Model methodologies. The
consideration for the acquisition was determined by arms-length negotiation
among the parties.
The acquisition was accounted for under the purchase method of accounting and,
accordingly, the purchase price has been allocated to the assets acquired and
liabilities assumed based on their estimated fair value at August 1, 1999 as
follows (in millions):
Current Assets $ 124.3
Investments 128.6
Property 216.9
Intangible asset 54.0
Liabilities (147.4)
==========
Total purchase price $ 376.4
==========
The $54.0 million intangible asset is the value assigned to the Shell Processing
Agreement and is being amortized over the life of the agreement. For the year
ending December 31, 1999, approximately $1.1 million of such amortization was
charged to expense. The assets, liabilities and results of operations of TNGL
are included with those of the Company as of August 1, 1999. Historical
information for periods prior to August 1, 1999 do not reflect any impact
associated with the TNGL acquisition.
F-9
Shell has the opportunity to earn an additional 6.0 million non-distribution
bearing, convertible special Contingency Units over the next two years upon the
achievement of certain gas production thresholds under the Shell Processing
Agreement. If such special Contingency Units are issued, the purchase price and
the value of the natural gas processing agreement will be adjusted accordingly.
ACQUISITION OF KINDER MORGAN AND EPCO INTEREST IN MONT BELVIEU FRACTIONATION
FACILITY
Effective July 1, 1999, the Company acquired Kinder Morgan Operating LP "A"'s
25% indirect ownership interest and EPCO's 0.5% indirect ownership interest in a
210,000 BPD NGL fractionation facility located in Mont Belvieu, Texas for
approximately $42 million in cash and the assumption of approximately $ 4
million of debt. The $42 million in cash was funded with borrowings under the
Company's $350 million bank credit facility.
The acquisition was accounted for under the purchase method of accounting and,
accordingly, the purchase price has been allocated to the assets purchased and
liabilities assumed based on their estimated fair value at July 1, 1999 as
follows (in millions):
Property $ 36.2
Intangible asset 8.7
Liabilities (3.7)
==========
Total purchase price $ 41.2
==========
The intangible asset represents the excess cost of purchase price over the fair
market value of the assets acquired and is being amortized over 20 years. For
the year ending December 31, 1999, approximately $0.2 million of such
amortization was charged to expense.
F-10
PRO FORMA EFFECT OF ACQUISITIONS
The balances included in the consolidated balance sheets related to the current
year acquisitions are based upon preliminary information and are subject to
change as additional information is obtained. Material changes in the
preliminary allocations are not anticipated by management.
The following table presents unaudited pro forma information for the years ended
December 31, 1997, 1998 and 1999 as if the acquisition of TNGL and the Mont
Belvieu fractionator facility from Kinder Morgan and EPCO been made as of the
beginning of the periods presented:
1997 1998 1999
--------------------------------------------
Revenues $ 1,867,200 $ 1,354,400 $ 1,714,222
============================================
Net income $ 93,925 $ 14,728 $ 135,037
============================================
Allocation of net income to
Limited partners $ 92,986 $ 14,581 $ 133,687
============================================
General Partner $ 939 $ 147 $ 1,350
============================================
Units used in earnings per Unit calculations
Basic 54,963 60,124 66,710
============================================
Diluted 69,463 74,624 81,210
============================================
Income per Unit before extraordinary
item and minority interest
Basic $ 1.71 $ 0.69 $ 2.02
============================================
Diluted $ 1.35 $ 0.56 $ 1.66
============================================
Net income per Unit
Basic $ 1.69 $ 0.24 $ 2.00
============================================
Diluted $ 1.34 $ 0.20 $ 1.65
============================================
3. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment and accumulated depreciation are as follows:
ESTIMATED
USEFUL LIFE
IN YEARS 1998 1999
--------------------------------------
Plants and pipelines 5-35 $ 613,264 $ 875,773
Underground and other storage facilities 5-35 89,064 103,578
Transportation equipment 3-35 1,773 2,117
Land 12,362 14,748
Construction in progress 3,879 32,810
---------------------------
Total 720,342 1,029,026
Less accumulated depreciation 220,549 261,957
===========================
Property, plant and equipment, net $ 499,793 $ 767,069
===========================
F-11
Depreciation expense for the years ended December 31, 1997, 1998 and 1999 was
$17.7 million, $18.6 million and $22.4 million, respectively.
4. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
At December 31, 1999, the Company's significant unconsolidated affiliates
accounted for by the equity method included the following:
Belvieu Environmental Fuels ("BEF") - a 33.33% economic interest in a Methyl
Tertiary Butyl Ether ("MTBE") production facility located in southeast Texas.
Baton Rouge Fractionators LLC ("BRF") - an approximate 31.25% economic interest
in a natural gas liquid ("NGL") fractionation facility located in southeastern
Louisiana.
Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% economic interest in
a propylene concentration unit located in southeastern Louisiana which is under
construction and scheduled to become operational in the third quarter of 2000.
EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50%
aggregate economic interest in a refrigerated NGL marine terminal loading
facility located in southeast Texas.
Wilprise Pipeline Company, LLC ("Wilprise") - a 33.33% economic interest in a
NGL pipeline system located in southeastern Louisiana.
Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% economic
interest in a NGL pipeline system located in Louisiana, Mississippi, and
Alabama.
Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.7% economic interest in a NGL
pipeline system located in south Louisiana.
K/D/S Promix LLC ("Promix") - a 33.33% economic interest in a NGL fractionation
facility and related storage facilities located in south Louisiana.
The Company's investments in and advances to unconsolidated affiliates also
includes Venice Energy Services Company, LLC ("VESCO") and Dixie Pipeline
Company ("Dixie"). The VESCO investment consists of a 13.1% economic interest in
a LLC owning a natural gas processing plant, fractionation facilities, storage,
and gas gathering pipelines in Louisiana. The Dixie investment consists of an
11.5% interest in a corporation owning a 1,301-mile propane pipeline and the
associated facilities extending from Mont Belvieu, Texas to North Carolina.
These investments are accounted for using the cost method.
During 1999, the Company acquired the remaining interest in Mont Belvieu
Associates , 51%, ("MBA") and Entell NGL Services, LLC, 50%, ("Entell").
Accordingly, after the acquisition of the remaining interest, the aforementioned
entities became wholly owned subsidiaries of the Company and are included as a
consolidated entity from that point forward.
F-12
Investments in and advances to unconsolidated affiliates at:
AT DECEMBER 31,
-----------------------------------
1998 1999
-----------------------------------
Accounted for on equity basis:
BEF $ 50,079 $ 63,004
Promix 50,496
BRF 17,896 36,789
Tri-States 55 28,887
EPIK 5,667 15,258
Belle Rose 12,064
BRPC 11,825
Wilprise 4,873 9,283
MBA 12,551
Accounted for on cost basis:
VESCO 33,000
Dixie 20,000
===================================
Total $ 91,121 $ 280,606
===================================
Equity in income (loss) of unconsolidated affiliates for the year ended
December 31:
1997 1998 1999
--------------------------------------------------------
BEF $ 9,305 $ 9,801 $ 8,183
MBA 6,377 5,213 1,256
BRF (91) (336)
BRPC 16
EPIK 748 1,173
Wilprise 160
Tri-States 1,035
Promix 630
Belle Rose (29)
Other 1,389
========================================================
Total $ 15,682 $ 15,671 $ 13,477
========================================================
At December 31, 1999, the Company's share of accumulated earnings of
unconsolidated affiliates that had not been remitted to the Company was
approximately $39.9 million.
Following is selected financial data for the most significant investments of the
Company:
F-13
BEF
BEF is owned equally (33.33%) by Mitchell Gas Services, L.P. ("Mitchell"),
Sunoco and the Company. Mitchell Energy & Development Corp. is Mitchell's
ultimate parent company, and Sun Company, Inc. ("Sun") is Sunoco's ultimate
parent company.
Following is condensed financial data for BEF:
AT DECEMBER 31,
-------------------------------
1998 1999
-------------------------------
BALANCE SHEET DATA:
Current assets $ 34,268 $ 44,261
Property, plant, and equipment, net 172,281 161,390
Other assets 13,684 8,313
===============================
Total assets $ 220,233 $ 213,964
===============================
Current liabilities $ 54,326 $ 41,317
Long-term debt 19,556
Other liabilities 1,798 4,323
Partners' equity 144,553 168,324
===============================
Total liabilities and partners' equity $ 220,233 $ 213,964
===============================
YEARS ENDED DECEMBER 31,
------------------------------------------------------
1997 1998 1999
------------------------------------------------------
INCOME STATEMENT DATA:
Revenues $ 233,218 $ 182,001 $ 193,219
Expenses 205,300 152,600 168,669
======================================================
Net income $ 27,918 $ 29,401 $ 24,550
======================================================
BEF's owners are required under isobutane supply contracts to provide their pro
rata share of BEF's monthly isobutane requirements. If the MTBE plant's
isobutane requirements exceed 450,000 barrels for any given month, each of the
owners retains the right, but not the obligation, to supply at least one-third
of the additional isobutane needed. The purchase price for the isobutane (which
generally approximates the established market price) is based on contracts
between the owners.
BEF has a ten-year off-take agreement through May 2005 under which Sun is
required to purchase all of the plant's MTBE production. Through May 31, 2000,
Sun pays the higher of a contractual floor price or market price (as defined
within the agreement) for floor production (193,450,000 gallons per year) and
the market price for production in excess of 193,450,000 gallons per year,
subject to quarterly adjustments on certain excess volumes. At floor production
levels, the contractual floor price is a price sufficient to cover essentially
all of BEF's operating costs plus principal and interest payments on its bank
term loan. Market price is (a) toll fee price (cost of feedstock plus
approximately $0.484 per gallon during the first two contract years ended May
31, 1997) and (b) at Sun's option, the toll fee price (cost of feedstock plus
approximately $0.534 per gallon) or the U.S. Gulf Coast Posted Contract Price
for the period from June 1, 1997 through May 31, 2000. For purposes of computing
the toll fee price, the feedstock component is based on the Normal Butane Posted
Price for the month plus the average purchase price paid by BEF to acquire
methanol consumed by the facility during the month. In addition, the floor or
market price determined above will be increased by $0.03 per gallon in the third
and fourth contract years and by about $0.04 per gallon in the fifth contract
year. Beginning June 1, 2000, through the remainder of the agreement, the price
for all production will be based on a market-related negotiated price.
F-14
The contracted floor price paid by Sun for production in 1997, 1998 and 1999
exceeded the spot market price for MTBE. At December 31, 1999, the floor price
paid for MTBE by Sun was $1.11 per gallon. The average Gulf Coast MTBE spot
market price was $.94 per gallon for December 1999 and $.72 per gallon for all
of 1999.
Substantially all revenues earned by BEF are from the production of MTBE which
is sold to Sun. This concentration could impact BEF's exposure to credit risk;
however, such risk is reduced since Sun has an equity interest in BEF.
Management believes BEF is exposed to minimal credit risk. BEF does not require
collateral for its receivables from Sun.
Long-term debt of BEF consists of a five-year, floating interest rate (London
Interbank Offered Rate ["LIBOR"] plus .0875%) bank term note payable ($19.6
million in current maturities outstanding at December 31, 1999) which is due in
equal quarterly installments of $9.8 million through May 31, 2000. The
weighted-average interest rate on this debt for the year ended December 31, 1999
was 6.20%. The debt is non-recourse debt to the partners.
The bank term loan agreement contains restrictive covenants prohibiting or
limiting certain actions of BEF, including partner distributions, and requiring
certain actions by BEF, including the maintenance of specified levels of
leverage, as defined, and approval by the banks of certain contracts.
Distributions to partners in the amount of $0.8 million were made for the year
ended December 31, 1999. In addition, the loan agreement requires BEF to
restrict a certain portion of cash to pay for the plant's turnaround maintenance
and long-term debt service. At December 31, 1998 and 1999, cash of $11.1 million
and $6.7 million, respectively, was restricted under terms of the loan
agreement. BEF was in compliance with the restrictive covenants at December 31,
1999. The long-term debt is collateralized by substantially all of BEF's assets.
RECENT REGULATORY DEVELOPMENTS
In November 1998, U.S. Environmental Protection Agency ("EPA") Administrator
Carol M. Browner appointed a Blue Ribbon Panel (the "Panel") to investigate the
air quality benefits and water quality concerns associated with oxygenates in
gasoline, and to provide independent advice and recommendations on ways to
maintain air quality while protecting water quality. The Panel issued a report
on their findings and recommendations in July 1999. The Panel urged the
widespread reduction in the use of MTBE due to the growing threat to drinking
water sources despite that fact that use of reformulated gasolines have
contributed to significant air quality improvements. The Panel credited
reformulated gasoline with "substantial reductions" in toxic emissions from
vehicles and recommended that those reductions be maintained by the use of
cleaner-burning fuels that rely on additives other than MTBE and improvements in
refining processes. The Panel stated that the problems associated with MTBE can
be characterized as a low-level, widespread problem that had not reached the
state of being a public health threat. The Panel's recommendations are geared
towards confronting the problems associated with MTBE now rather than letting
the issue grow into a larger and worse problem. The Panel did not call for an
outright ban on MTBE but stated that its use should be curtailed significantly.
The Panel also encouraged a public educational campaign on the potential harm
posed by gasoline when it leaks into ground water from storage tanks or while in
use. Based on the Panel's recommendations, the EPA is expected to support a
revision of the Clean Air Act of 1990 that maintains air quality gains and
allows for the removal of the requirement for oxygenates in gasoline.
Several public advocacy and protest groups active in California and other states
have asserted that MTBE contaminates water supplies, causes health problems and
has not been as beneficial as originally contemplated in reducing air pollution.
In California, state authorities negotiated an agreement with the EPA to
implement a program requiring oxygenated motor gasoline at 2.0% for the whole
state, rather than 2.7% only in selected areas. On March 25, 1999, the Governor
of California ordered the phase-out of MTBE in that state by the end of 2002.
The order also seeks to obtain a waiver of the oxygenate requirement from the
EPA in order to facilitate the phase-out; however, due to increasing concerns
about the viability of alternative fuels, the California legislature on October
10, 1999 passed the Sher Bill (SB 989) stating that MTBE should be banned as
soon as feasible rather than by the end of 2002.
Legislation to amend the federal Clean Air Act of 1990 has been introduced in
the U.S. House of Representatives; it would ban the use of MTBE as a fuel
additive within three years. Legislation introduced in the U.S. Senate would
eliminate the Clean Air Act's oxygenate requirement in order to assist the
F-15
elimination of MTBE in fuel. No assurance can be given as to whether this or
similar federal legislation ultimately will be adopted or whether Congress or
the EPA might takes steps to override the MTBE ban in California.
ALTERNATIVE USES OF THE BEF FACILITY
In light of these regulatory developments, the Company is formulating a
contingency plan for use of the BEF facility if MTBE were banned or
significantly curtailed. Management is exploring a possible conversion of the
BEF facility from MTBE production to alkylate production. Alkylate is a high
octane, low sulfur, low vapor pressure compound, produced by the reaction of
isobutylene or normal butylene with isobutane, and used by refiners as a
component in gasoline blending. At present the forecast cost of this conversion
would be in the $20 million to $25 million range, with the Company's share being
$6.7 million to $8.3 million. Management anticipates that if MTBE is banned
alkylate demand will rise as producers use it to replace MTBE as an octane
enhancer. Alkylate production would be expected to generate spot market margins
comparable to those of MTBE. Greater alkylate production would be expected to
increase isobutane consumption nationwide and result in improved isomerization
margins for the Company.
PROMIX
Promix is a limited liability company whose owners are Koch Hydrocarbon
Southeast ("KHSE"), a subsidiary of Koch Industries, Inc. ("KII"), Dow
Hydrocarbons and Resources, Inc. ("DHRI"), a subsidiary of Dow Chemical Company,
and the Company. Promix is engaged in the business of transporting,
fractionating, storing and exchanging natural gas liquids in southern Louisiana.
KHSE is the managing member responsible for the daily operations and management
of Promix.
The following is condensed unaudited financial data for Promix for the year
ended and as of December 31, 1999. The Company has included in equity income
from unconsolidated affiliates that portion of earnings related to the period
from August 1, 1999 through December 31, 1999 in proportion to its ownership
interest.
BALANCE SHEET DATA:
Current assets $ 28,890
Property, plant, and equipment, net 117,885
==================
Total assets $ 146,775
==================
Current liabilities $ 18,121
Members' equity 128,654
==================
Total liabilities and members' equity $ 146,775
==================
INCOME STATEMENT DATA:
Revenues $ 36,098
Expenses 26,975
==================
Net income $ 9,123
==================
BRF
BRF is a joint venture among Amoco Louisiana Fractionator Company, Williams
Mid-Stream Natural Gas Liquids, Inc., Exxon Chemical Louisiana LLC ("Exxon") and
the Company. The ownership interests in BRF are based on amounts contributed by
each member to fund certain capital expenditures. Exxon funded a small portion
of the construction costs but has contributed other NGL assets. At December 31,
1999, the Company owned an approximate 31.25% economic interest in BRF.
F-16
BRF is a NGL fractionation facility near Baton Rouge, Louisiana, which has a
60,000 barrel per day capacity. The Company is the operator of the facility,
which will service NGL production from the Mobile/Pascagoula and Louisiana
areas. Operations commenced in July 1999. Operating losses prior to the
commencement of operations are the result of certain start-up expenses incurred
during the development stage.
Following is the condensed financial data for BRF:
AT DECEMBER 31,
--------------------------------
1998 1999
--------------------------------
BALANCE SHEET DATA:
Current assets $ 2,386 $ 12,617
Property, plant, and equipment, net 58,618 89,035
Other assets 3 854
================================
Total assets $ 61,007 $ 102,506
================================
Current liabilities $ 8,222 $ 6,799
Members' equity 52,785 95,707
================================
Total liabilities and members' equity $ 61,007 $ 102,506
================================
YEAR ENDED DECEMBER 31,
--------------------------------
1998 1999
--------------------------------
INCOME STATEMENT DATA:
Revenues $ 6,746
Expenses $ 330 7,820
================================
Net income $ (330) $ (1,074)
================================
F-17
TRI-STATES
Tri-States is a limited liability company owning a 80,000 barrel per day
161-mile common-carrier pipeline that will deliver natural gas liquids from
three gas processing plants in Alabama and Mississippi to fractionators in
Louisiana. The owners of Tri-States are Amoco Tri-States NGL Pipeline Company
(16.67%), Koch Pipeline Southeast, Inc. (16.67%), Gulf Coast NGL Pipeline,
L.L.C.(16.67%), WSF-NGL Pipeline Company, Inc. ("Williams")(16.67%) and the
Company (33.33%). Williams is the operator of the Tri-States pipeline.
The following is condensed unaudited financial data for Tri-States:
AT DECEMBER 31,
-------------------------------
1998 1999
-------------------------------
BALANCE SHEET DATA:
Current assets $ 63 $ 8,056
Property, plant, and equipment, net 84,854
===============================
Total assets $ 63 $ 92,910
===============================
Current liabilities $ 68 $ 1,430
Members' equity (5) 91,480
===============================
Total liabilities and members' equity $ 63 $ 92,910
===============================
YEAR ENDED
DECEMBER 31,
1999
------------------
INCOME STATEMENT DATA:
Revenues $ 8,101
Expenses 4,954
==================
Net income $ 3,147
==================
F-18
The following table represents the aggregated unaudited condensed financial data
for the Company's other equity investments in unconsolidated affiliates for the
periods ending December 31, 1997, 1998 and 1999.
1998 1999
-------------------------------------
BALANCE SHEET DATA:
Current assets $ 11,355 $ 12,937
Property, plant and equipment, net 69,281 116,030
Other assets 1,687
=====================================
Total assets $ 82,323 $ 128,967
=====================================
Current liabilities $ 5,413 $ 6,525
Long-term debt 11,790
Other liabilities 130
Members' and partners' equity 64,990 122,442
=====================================
Total liabilities and equity $ 82,323 $ 128,967
=====================================
1997 1998 1999
----------------------------------------------------
INCOME STATEMENT DATA:
Revenues $ 33,646 $ 35,843 $ 27,897
Expenses 23,034 24,480 21,932
====================================================
Net income $ 10,612 $ 11,363 $ 5,965
====================================================
5. NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES
At December 31, 1999, the Company holds a participation interest in the bank
loan of BEF for $6.5 million. The BEF note receivable bears interest at a
floating rate per annum at LIBOR plus 0.0875% and matures on May 31, 2000. The
Company will receive quarterly principal payments of approximately $3.3 million
plus interest from BEF during the term of the loan.
6. LONG-TERM DEBT
In December 1999, the Company and Operating Partnership filed a $800 million
universal shelf registration (the "Registration Statement") covering the
issuance of an unspecified amount of equity or debt securities or a combination
thereof. The Company expects to issue public debt under the shelf registration
statement during fiscal 2000. Management intends to use the proceeds from such
debt offering to repay all outstanding bank credit facilities and for other
general corporate purposes.
$200 MILLION BANK CREDIT FACILITY. In July 1998, the Operating Partnership
entered into a $200 million bank credit facility that includes a $50 million
working capital facility and a $150 million revolving term loan facility. The
$150 million revolving term loan facility includes a sublimit of $30 million for
letters of credit. As of December 31, 1999, the Company has borrowed $129
million under the bank credit facility which is due in July 2000.
The Company's obligations under this bank credit facility are unsecured general
obligations and are non-recourse to the General Partner. Borrowings under this
bank credit facility will bear interest at either the bank's prime rate or the
Eurodollar rate plus the applicable margin as defined in the facility. This bank
credit facility will expire in July 2000 and all amounts borrowed thereunder
shall be due and payable at that time. There must be no amount outstanding under
F-19
the working capital facility for at least 15 consecutive days during each fiscal
year. The Company elects the basis for the interest rate at the time of each
borrowing. Interest rates ranged from 5.94% to 8.75% during 1999, and the
weighted-average interest rate at December 31, 1999 was 6.74%.
As amended on July 28, 1999, this credit agreement relating to the facility
contains a prohibition on distributions on, or purchases or redemptions of,
Units if any event of default is continuing. In addition, this bank credit
facility contains various affirmative and negative covenants applicable to the
ability of the Company to, among other things, (i) incur certain additional
indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain
limitations, (iv) make investments, (v) engage in transactions with affiliates
and (vi) enter into a merger, consolidation or sale of assets. The bank credit
facility requires that the Operating Partnership satisfy the following financial
covenants at the end of each fiscal quarter: (i) maintain Consolidated Tangible
Net Worth (as defined in the bank credit facility) of at least $250 million,
(ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to
Consolidated Interest Expense (as defined in the bank credit facility) for the
previous 12-month period of at least 3.5 to 1.0 and (iii) maintain a ratio of
Total Indebtedness (as defined in the bank credit facility) to EBITDA of no more
than 3.0 to 1.0. The Company was in compliance with these restrictive covenants
at December 31, 1999.
A "Change of Control" constitutes an Event of Default under this bank credit
facility. A Change of Control includes any of the following events: (i) Dan L.
Duncan (and/or certain affiliates) cease to own (a) at least 51% (on a fully
converted, fully diluted basis) of the economic interest in the capital stock of
EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to
elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own,
through a wholly owned subsidiary, at least 65% of the outstanding membership
interest in the General Partner and at least a majority of the outstanding
Common Units; (iii) any person or group beneficially owns more than 20% of the
outstanding Common Units (excluding certain affiliates of EPCO or Shell ); (iv)
the General Partner ceases to be the general partner of the Company or the
Operating Partnership; or (v) the Company ceases to be the sole limited partner
of the Operating Partnership.
$350 MILLION BANK CREDIT FACILITY. Also in July 1999, the Operating Partnership
entered into a $350 million bank credit facility that includes a $50 million
working capital facility and a $300 million revolving term loan facility. The
$300 million revolving term loan facility includes a sublimit of $10 million for
letters of credit. The initial proceeds of this loan were used to finance the
acquisition of TNGL and the MBA ownership interests.
Borrowings under the bank credit facility will bear interest at either the
bank's prime rate or the Eurodollar rate plus the applicable margin as defined
in the facility. The bank credit facility will expire in July 2001 and all
amounts borrowed thereunder shall be due and payable at that time. There must be
no amount outstanding under the working capital facility for at least 15
consecutive days during each fiscal year. The Company elects the basis for the
interest rate at the time of each borrowing. Interest rates ranged from 6.88% to
7.31% during 1999, and the weighted-average interest rate at December 31, 1999
was 7.10%.
Limitations on certain actions by the Company and financial covenant
requirements of this bank credit facility are substantially consistent with
those existing for the $200 Million Bank Credit Facility as described above. The
Company was in compliance with the restrictive covenants at December 31, 1999.
Long-term debt consisted of the following:
AT DECEMBER 31,
1998 1999
--------------------------------
Borrowings under:
$200 Million Bank Credit Facility $ 90,000 $ 129,000
$350 Million Bank Credit Facility 166,000
--------------------------------
Total 90,000 295,000
Less current maturities of long-term debt 129,000
================================
Long-term debt $ 90,000 $ 166,000
================================
At December 31, 1999, the Company had $40 million of standby letters of credit
available, and approximately $24.3 million of letters of credit were outstanding
under letter of credit agreements with the banks.
F-20
Extraordinary Item - Early Extinguishment of Debt
On July 31, 1998, the Company used $243.3 million of proceeds from the sale of
Common Units and $13.3 million of borrowings from the $200 million bank credit
facility to retire $256.6 million of debt that was assumed from EPCO. In
connection with the repayment of the debt, the Company was required to pay a
"make-whole payment" of $26.3 million to the lenders. The $26.3 million (plus
$0.9 million of unamortized debt costs) is included in the consolidated
statement of operations for the year ended December 31, 1998 as "Extraordinary
item--early extinguishment of debt."
7. CAPITAL STRUCTURE AND EARNINGS PER UNIT
SECOND AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF THE COMPANY. The
Second Amended and Restated Agreement of Limited Partnership of the Company (the
"Partnership Agreement") contains specific provisions for the allocation of net
earnings and losses to the Common Units, Subordinated Units, Special Units and
the General Partner. The Partnership Agreement also sets forth the calculation
to be used to determine the amount and priority of cash distributions that the
Common Unitholders, Subordinated Unitholders and the General Partner will
receive.
The Partnership Agreement generally authorizes the Company to issue an unlimited
number of additional limited partner interests and other equity securities of
the Company for such consideration and on such terms and conditions as shall be
established by the General Partner in its sole discretion without the approval
of the Unitholders. During the Subordination Period, however, the Company may
not issue equity securities ranking senior to the Common Units for an aggregate
of more than 22,775,000 Common Units (except for Common Units upon conversion of
Subordinated Units, pursuant to employee benefit plans, upon conversion of the
general partner interest as a result of the withdrawal of the General Partner or
in connection with acquisitions or capital improvements that are accretive on a
per Unit basis) or an equivalent number of securities ranking on a parity with
the Common Units, without the approval of the holders of at least a Unit
Majority. A Unit Majority is defined as at least a majority of the outstanding
Common Units (during the Subordination Period), excluding Common Units held by
the General Partner and its affiliates, and at least a majority of the
outstanding Common Units (after the Subordination Period).
SUBORDINATED UNITS. The Subordinated Units have no voting rights until converted
into Common Units at the end of the Subordination Period (as defined below). The
Subordination Period for the Subordinated Units will generally extend until the
first day of any quarter beginning after June 30, 2003 when the Conversion Test
has been satisfied. Generally, the Conversion Test will have been satisfied when
the Company has paid from Operating Surplus and generated from Adjusted
Operating Surplus the minimum quarterly distribution on all Units for the three
preceding four-quarter periods. Upon expiration of the Subordination Period, all
remaining Subordinated Units will convert into Common Units on a one-for-one
basis and will thereafter participate pro rata with the other Common Units in
distributions of Available Cash.
If the Conversion Test has been met for any quarter ending on or after June 30,
2001, 25% of the Subordinated Units will convert into Common Units. If the
Conversion Test has been met for any quarter ending on or after June 30, 2002,
an additional 25% of the Subordinated Units will convert into Common Units. The
early conversion of the second 25% of Subordinated Units may not occur until at
least one year following the early conversion of the first 25% of Subordinated
Units.
SPECIAL UNITS. The 14.5 million Special Units issued do not accrue distributions
and are not entitled to cash distributions until their conversion into Common
Units, which occurs automatically with respect to 1.0 million Units on August 1,
2000 (or the day following the record date for determining units entitled to
receive distributions in the second quarter of 2000), 5.0 million Units on
August 1, 2001 and 8.5 million Units on August 1, 2002.
Shell has the opportunity to earn an additional 6 million non-distribution
bearing, convertible Contingency Units over the next two years based on certain
performance criteria. Shell will earn 3 million convertible Contingency Units if
at any point during calendar year 2000 (or extensions thereto due to force
majeure events), gas production by Shell from its offshore Gulf of Mexico
F-21
producing properties and leases is 950 million cubic feet per day for 180
not-necessarily-consecutive days or 375 billion cubic feet on a cumulative
basis. Shell will earn another 3 million convertible Contingency Units if at any
point during calendar year 2001 (or extensions thereto due to force majuere
events) such gas production is 900 million cubic feet per day for 180
not-necessarily-consecutive days or 350 billion cubic feet on a cumulative
basis. If either or both of the preceding performance tests is not met but
Shell's offshore Gulf of Mexico gas production reaches 725 billion cubic feet on
a cumulative basis in calendar years 2000 and 2001 (or extensions thereto due to
force majeure events), Shell would still earn 6 million non-distribution
bearing, convertible Contingency Units. If all of the Contingency Units are
earned, 1 million Contingency Units would convert into Common Units on August 1,
2002 and 5 million Contingency Units would convert into Common Units on August
1, 2003. The Contingency Units do not accrue distributions and are not entitled
to cash distributions until conversion into Common Units.
Under the rules of the New York Stock Exchange, conversion of the Special Units
into Common Units requires approval of the Company's Unitholders. The General
Partner has agreed to call a special meeting of the Unitholders for the purpose
of soliciting such approval. EPC Partners II, Inc. ("EPC II"), which owns in
excess of 81% of the outstanding Common Units, has agreed to vote its Units in
favor of such approval, which will satisfy the approval requirement.
UNITS ACQUIRED BY TRUST. During the first quarter of 1999, the Company
established a revocable grantor trust (the "Trust") to fund future liabilities
of a long-term incentive plan. At December 31, 1999, the Trust had purchased a
total of 267,200 Common Units (the "Trust Units") which are accounted for in a
manner similar to treasury stock under the cost method of accounting. The Trust
Units are considered outstanding and will receive distributions; however, they
are excluded from the calculation of net income per Unit.
EARNINGS PER UNIT. The Company has no dilutive securities that would require
adjustment to net income for the computation of diluted earnings per Unit. The
following is a reconciliation of the number of units used in the computation of
basic and diluted earnings per Unit for all periods presented.
1997 1998 1999
--------------------------------------
Weighted average number of Common
and Subordinated Units outstanding 54,963 60,124 66,710
Weighted average number of Special
Units to be converted to Common Units 6,078
--------------------------------------
Units used to compute diluted
earnings per Unit 54,963 60,124 72,788
======================================
The contingent Special Units (described above) to be issued upon achieving
certain performance criteria have been excluded from diluted earnings per Unit
because such tests have not been met at December 31, 1999.
8. DISTRIBUTIONS
The Company intends, to the extent there is sufficient available cash from
Operating Surplus, as defined by the Partnership Agreement, to distribute to
each holder of Common Units at least a minimum quarterly distribution of $0.45
per Common Unit. The minimum quarterly distribution is not guaranteed and is
subject to adjustment as set forth in the Partnership Agreement. With respect to
each quarter during the subordination period, which will generally not end
before June 30, 2003, the Common Unitholders will generally have the right to
receive the minimum quarterly distribution, plus any arrearages thereon, and the
General Partner will have the right to receive the related distribution on its
interest before any distributions of available cash from Operating Surplus are
made to the Subordinated Unitholders.
On January 17, 2000, the Company declared an increase in its quarterly cash
distribution to $0.50 per Unit.
F-22
The following is a summary of cash distributions to partnership interests since
the initial public offering of the Company's Units:
Cash Distributions
---------------------------------------------------------------
Per Common Per Subordinated Record Payment
Unit Unit Date Date
---------------------------------------------------------------
1998
Fourth Quarter $0.32 $0.32 October 30,1998 November 12, 1998
1999
First Quarter $0.45 $0.45 January 29, 1999 February 11, 1999
Second Quarter $0.45 $0.07 April 30, 1999 May 12, 1999
Third Quarter $0.45 $0.37 July 30, 1999 August 11, 1999
Fourth Quarter $0.45 $0.45 October 29, 1999 November 10, 1999
2000
First Quarter $0.50 $0.50 January 31, 2000 February 10, 2000
(through February 25, 2000)
9. MAJOR CUSTOMERS
Montell owns a 45.4% undivided interest in a plant and the related pipeline
system and it leases such undivided interest in these facilities to the Company.
The agreement with Montell expires in 2004. There are two successive options to
extend the term for 12 years each remaining under the original agreement.
Revenues from sales to Montell were approximately $147.6 million and $102.2
million in 1997 and 1998, respectively. In addition, the Company had supply,
transportation, and storage contracts with Texas Petrochemicals that generated
$107.3 million in revenues in 1997. No single customer accounted for more than
10% of consolidated revenues during 1999.
10. RELATED PARTY TRANSACTIONS
The Company has no employees. All management, administrative and operating
functions are performed by employees of EPCO. Operating costs and expenses
include charges for EPCO's employees who operate the Company's various
facilities. Such charges are based on EPCO's actual salary costs and related
fringe benefits. Because the Company's operations constitute the most
significant portion of EPCO's consolidated operations, selling, general and
administrative expenses reported in the accompanying statements of consolidated
operations for all periods before the public offering include all such expenses
incurred by EPCO less amounts directly incurred by other subsidiaries or
operating divisions of EPCO.
In connection with the initial public offering, EPCO, the General Partner and
the Company entered into the EPCO Agreement pursuant to which (i) EPCO agreed to
manage the business and affairs of the Company and the Operating Partnership;
(ii) EPCO agreed to employ the operating personnel involved in the Company's
business for which EPCO is reimbursed by the Company at cost; (iii) the Company
and the Operating Partnership agreed to participate as named insureds in EPCO's
current insurance program, and costs are allocated among the parties on the
basis of formulas set forth in the agreement; (iv) EPCO agreed to grant an
irrevocable, nonexclusive worldwide license to all of the trademarks and trade
names used in its business to the Company; (v) EPCO agreed to indemnify the
Company against any losses resulting from certain lawsuits; and (vi) EPCO agreed
to sublease all of the equipment which it holds pursuant to operating leases
relating to an isomerization unit, a deisobutanizer tower, two cogeneration
units and approximately 100 rail cars to the Company for $1 per year and
assigned its purchase options under such leases to the Company (hereafter
referred to as "Retained Leases".)
Pursuant to the EPCO Agreement, EPCO is reimbursed at cost for all expenses that
it incurs in connection with managing the business and affairs of the Company,
except that EPCO is not entitled to be reimbursed for any selling, general and
administrative expenses. In lieu of reimbursement for such selling, general and
administrative expenses, EPCO receives an annual administrative services fee
that initially equaled $12.0 million. The General Partner, with the approval and
F-23
consent of the Audit and Conflicts Committee of the Company, can agree to
increases in such administrative services fee of up to 10% each year during the
ten-year term of the EPCO Agreement and may agree to further increases in such
fee in connection with expansions of the Company's operations through the
construction of new facilities or the completion of acquisitions that require
additional management personnel. On July 7, 1999, the Audit and Conflicts
Committee of the General Partner authorized an increase in the administrative
services fee to $1.1 million per month from the initial $1.0 million per month.
The increased fees were effective August 1, 1999. Beginning in January 2000, the
administrative services fee will increase to $1.55 million per month plus
accrued employee incentive plan costs to compensate EPCO for the additional
selling, general, and administrative charges related to the additional
administrative employees acquired in the TNGL acquisition.
EPCO also operates most of the plants owned by the unconsolidated affiliates and
charges them for actual salary costs and related fringe benefits. In addition,
EPCO charged the unconsolidated affiliates for management services provided;
such charges aggregated $1.1 million for 1997, $1.7 million for 1998 and $0.8
million for 1999. Since EPCO pays the rental charges for the Retained Leases,
such payments are considered a contribution by EPCO for the benefit of each
partnership interest and are included as such in Partners' Equity, and a
corresponding charge for the rental expense is included in the consolidated
statements of operations. Rental expense, included in operating costs and
expenses, for the Retained Leases was $13.3 million, $11.3 million (of which
$4.0 million occurred after the public offering) and $10.6 million for 1997,
1998 and 1999, respectively.
The Company also has transactions in the normal course of business with the
unconsolidated affiliates and other subsidiaries and divisions of EPCO. Such
transactions include the buying and selling of NGL products, loading of NGL
products and transportation of NGL products by truck.
As a result of the TNGL acquisition, Shell acquired an ownership interest in the
Company and its General Partner. At December 31, 1999, Shell owned approximately
17.6% of the Company and 30.0% of the General Partner. The Company's major
customer related to the TNGL assets is Shell. Under the terms of the Shell
Processing Agreement, the Company has the right to process substantially all of
Shell's current and future natural gas production from the Gulf of Mexico. This
includes natural gas production from the developments currently referred to as
deepwater. Generally, the Shell Processing Agreement grants the Company the
exclusive right to process any and all of Shell's Gulf of Mexico natural gas
production from existing and future dedicated leases; plus the right to all
title, interest, and ownership in the raw make extracted by the Company's gas
processing facilities from Shell's natural gas production from such leases; with
the obligation to deliver to Shell the natural gas stream after the raw make is
extracted. In addition to the Shell Processing Agreement, the Company acquired a
short-term lease for 425 rail cars from Shell for servicing the gas processing
business activities.
Following is a summary of significant transactions with related parties:
FOR THE YEARS ENDED
DECEMBER 31,
-------------------------------------
1997 1998 1999
-------------------------------------
Revenues from NGL products sold to:
Unconsolidated affiliates $44,392 $36,474 $40,439
Shell 56,301
EPCO and its subsidiaries 19,029 19,531 9,148
Cost of NGL products purchased from:
Unconsolidated affiliates 8,453 9,270 14,212
Shell 188,570
EPCO and its subsidiaries 6,495 5,293 29,365
Operating expenses charged for trucking
of NGL products 7,606 4,704 6,282
Administrative service fee charged by EPCO 5,129 12,500
F-24
11. COMMITMENTS AND CONTINGENCIES
STORAGE COMMITMENTS
The Company stores NGL products for EPCO and various third parties. Under the
terms of the storage agreements, the Company is generally required to redeliver
to the owner its NGL products upon demand. The Company is insured for any
physical loss of such NGL products due to catastrophic events. At December 31,
1999, NGL products aggregating 230 million gallons were due to be redelivered to
the owners under various storage agreements.
LEASE COMMITMENTS
The Company leases certain equipment and processing facilities under
noncancelable operating leases. Minimum future rental payments on such leases
with terms in excess of one year at December 31, 1999 are as follows:
2000 $ 5,629
2001 4,609
2002 4,606
2003 4,606
2004 4,607
Thereafter 4,607
============
Total minimum obligations $ 28,664
============
Lease expense charged to operations (including Retained Leases) for the years
ended December 31, 1997, 1998 and 1999 was approximately $29.6 million , $18.5
million and $20.2 million, respectively.
GAS PURCHASE COMMITMENTS
The Company has annual renewable gas purchase contracts with four suppliers. As
of December 31, 1999, the Company is required to make daily purchases as
follows: 8,000 million British Thermal Units ("MMBTU") per day through March 31,
2000, 5,000 MMBTU per day through July 31, 2000 and 5,000 MMBTU per day through
October 31, 2000. The cost of these natural gas purchase commitments approximate
market value at the time of delivery.
CAPITAL EXPENDITURE COMMITMENTS
As of December 31, 1999, the Company had capital expenditure commitments
totaling approximately $9.5 million, of which $1.7 million relates to the
construction of projects of unconsolidated affiliates.
LITIGATION
EPCO has indemnified the Company against any litigation pending as of the date
of its formation. The Company is sometimes named as a defendant in litigation
relating to its normal business operations. Although the Company insures itself
against various business risks, to the extent management believes it is prudent,
there is no assurance that the nature and amount of such insurance will be
adequate, in every case, to indemnify the Company against liabilities arising
from future legal proceedings as a result of its ordinary business activity.
Management is aware of no significant litigation, pending or threatened, that
would have a significantly adverse effect on the Company's financial position or
results of operations.
F-25
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following disclosure of estimated fair value was determined by the Company,
using available market information and appropriate valuation methodologies.
Considerable judgment, however, is necessary to interpret market data and
develop the related estimates of fair value. Accordingly, the estimates
presented herein are not necessarily indicative of the amounts that the Company
could realize upon disposition of the financial instruments. The use of
different market assumptions and/or estimation methodologies may have a material
effect on the estimated fair value amounts.
The Company enters into swaps and other contracts to hedge the price risks
associated with inventories, commitments and certain anticipated transactions.
The Company does not currently hold or issue financial instruments for trading
purposes. The swaps and other contracts are with established energy companies
and major financial institutions. The Company believes its credit risk is
minimal on these transactions, as the counterparties are required to meet
stringent credit standards. There is continuous day-to-day involvement by senior
management in the hedging decisions, operating under resolutions adopted by the
board of directors.
At December 31, 1999, the Company had open positions covering 24.0 billion cubic
feet of natural gas extending into December 2000 related to the swaps described
above. The fair value of these swap contracts at December 31, 1999 was estimated
at $0.5 million payable by the Company based on quoted market prices of
comparable contracts and approximate the gain or loss that would have been
realized if the contracts had been settled at the balance sheet date.
Cash and Cash Equivalents, Accounts Receivable, Participation in Notes
Receivable from Unconsolidated Affiliates, Accounts Payable and Accrued Expenses
are carried at amounts which reasonably approximate their fair value at year end
due to their short-term nature.
Long-term debt is carried at an amount that reasonably approximates its fair
value at year end due to its variable interest rates.
13. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
YEAR ENDED DECEMBER 31,
1997 1998 1999
-------------------------------------------------------
(Increase) decrease in:
Accounts receivable $ 29,024 $ 3,699 $ (152,363)
Inventories 7,329 1,361 7,471
Prepaid and other current assets 917 (342) (7,523)
Other assets 127 46 (1,971)
Increase (decrease) in:
Accounts payable (3,320) (40,005) (6,276)
Accrued gas payable (26,955) (18,485) 189,166
Accrued expenses (5,526) (1,098) (10,776)
Other current liabilities 1,352 (10,082) 6,747
Other liabilities 296
=======================================================
Net effect of changes in operating accounts $ 2,948 $ (64,906) $ 24,771
=======================================================
Cash payments for interest, net of $2,005,
$180 and $153 capitalized in 1997,
1998 and 1999, respectively $ 28,352 $ 6,971 $ 15,780
=======================================================
F-26
During 1998, the Company contributed $1.9 million (at net book value) of plant
equipment to an unconsolidated affiliate as part of its investment therein. On
August 1, 1999, the Company issued 14.5 million non-distribution bearing,
convertible Special Units and $166 million in cash in exchange for the equity
interest in TNGL and assumed approximately $4 million of debt in connection with
the acquisition of additional interest in MBA.
14. CONCENTRATION OF CREDIT RISK
A substantial portion of the Company's revenues are derived from natural gas
processing and the fractionation, isomerization, propylene production,
marketing, storage and transportation of NGLs to various companies in the NGL
industry, located in the United States. Although this concentration could affect
the Company's overall exposure to credit risk since these customers might be
affected by similar economic or other conditions, management believes the
Company is exposed to minimal credit risk, since the majority of its business is
conducted with major companies within the industry and much of the business is
conducted with companies with whom the Company has joint operations. The Company
generally does not require collateral for its accounts receivable.
The Company is subject to a number of risks inherent in the industry in which it
operates, primarily fluctuating gas and liquids prices and gas supply. The
Company's financial condition and results of operations will depend
significantly on the prices received for NGLs and the price paid for gas
consumed in the NGL extraction process. These prices are subject to fluctuations
in response to changes in supply, market uncertainty and a variety of additional
factors that are beyond the control of the Company. In addition, the Company
must continually connect new wells through third-party gathering systems which
serve the gas plants in order to maintain or increase throughput levels to
offset natural declines in dedicated volumes. The number of wells drilled by
third parties will depend on, among other factors, the price of gas and oil, the
energy policy of the federal government, and the availability of foreign oil and
gas, none of which is in the Company's control.
15. SEGMENT INFORMATION
Historically, the Company has had only one reportable business segment: NGL
Operations. Due to the broadened scope of the Company's operations with the
third quarter of 1999 acquisition of TNGL, effective for fiscal 1999, the
Company's operations are being managed using five reportable business segments.
The five new segments are: Fractionation, Pipeline, Processing, Octane
Enhancement, and Other.
Operating segments are components of a business about which separate financial
information is available that is evaluated regularly by the chief operating
decision maker in deciding how to allocate resources and in assessing
performance. Generally, financial information is required to be reported on the
basis that it is used internally for evaluating segment performance and deciding
how to allocate resources to segments.
The management of the Company evaluates segment performance on the basis of
gross operating margin. Gross operating margin reported for each segment
represents earnings before depreciation and amortization, lease expense
obligations retained by the Company's largest Unitholder, EPCO, and general and
administrative expenses. In addition, segment gross operating margin is
exclusive of interest expense, interest income (from unconsolidated affiliates
or others), dividend income from unconsolidated affiliates, minority interest,
extraordinary charges and other income and expense transactions. The Company's
equity earnings from unconsolidated affiliates are included in segment gross
operating margin. Segment assets consists of property, plant and equipment and
the amount of investments in and advances to unconsolidated affiliates.
Segment gross operating margin is inclusive of intersegment revenues. Such
revenues, which have been eliminated from the consolidated totals, are recorded
at arms-length prices which are intended to approximate the prices charged to
external customers.
The five new segments are Fractionation, Pipeline, Processing, Octane
Enhancement and Other. Fractionation includes NGL fractionation, polymer grade
propylene fractionation and butane isomerization (converting normal butane into
high purity isobutane) services. Pipeline consists of pipeline, storage and
import/export terminal services. Processing includes the natural gas processing
business and its related NGL merchant activities. Octane Enhancement represents
F-27
the Company's 33.33% ownership interest in a facility that produces motor
gasoline additives to enhance octane (currently producing MTBE). The Other
operating segment consists of fee-based marketing services and other plant
support functions.
Information by operating segment, together with reconciliations to the
consolidated totals, is presented in the following table:
Operating Segments Adjustments
------------------------------------------------------------------------
Octane and Consolidated
Fractionation Pipelines Processing Enhancement Other Eliminations Totals
----------------------------------------------------------------------------------------------------
Revenues from
external customers
1999 $275,646 $ 16,180 $1,081,487 $ 8,183 $ 731 $ (35,771) $ 1,346,456
1998 273,781 19,344 506,630 9,801 (54,983) 754,573
1997 339,721 15,924 729,376 9,305 (58,363) 1,035,963
Intersegment revenues
1999 118,103 43,688 216,720 444 (378,955) -
1998 162,379 37,574 90 383 (200,426) -
1997 129,230 40,202 164 360 (169,956) -
Total revenues
1999 393,749 59,868 1,298,207 8,183 1,175 (414,726) 1,346,456
1998 436,160 56,918 506,720 9,801 383 (255,409) 754,573
1997 468,951 56,126 729,540 9,305 360 (228,319) 1,035,963
Gross operating margin by segment
1999 106,267 27,038 36,799 8,183 908 179,195
1998 66,627 27,334 (652) 9,801 (3,483) 99,627
1997 100,770 23,909 (3,778) 9,305 (1,496) 128,710
Segment assets
1999 362,198 249,453 122,495 113 32,810 767,069
1998 288,159 207,432 181 142 3,879 499,793
Investments in and advances to
Unconsolidated affiliates
1999 99,110 85,492 33,000 63,004 280,606
1998 30,447 10,595 50,079 91,121
Two customers provided more than 10% of revenues in 1997. Only one customer
provided more than 10% of revenues in 1998. No single customer provided more
than 10% of revenues in 1999.
All consolidated revenues were earned in the United States.
F-28
A reconciliation of segment gross operating margin to consolidated income before
extraordinary item and minority interest follows:
1997 1998 1999
------------------------------------------
Total segment gross operating margin $ 128,710 $ 99,627 $ 179,195
Depreciation and amortization (17,684) (18,579) (23,664)
Retained lease expense, net (13,300) (12,635) (10,557)
Gain (loss) on sale of assets (155) 276 (123)
Selling, general and administrative (21,891) (18,216) (12,500)
------------------------------------------
Consolidated operating income 75,680 50,473 132,351
Interest expense (25,717) (15,057) (16,439)
Interest income from unconsolidated affiliates 809 1,667
Dividend income from unconsolidated affiliates 3,435
Interest income - other 1,934 772 886
Other, net 793 358 (379)
------------------------------------------
Consolidated income before extraordinary item
and minority interest $ 52,690 $ 37,355 $ 121,521
==========================================
16. SUBSEQUENT EVENTS
Effective January 1, 2000, Enterprise Products GP, LLC, the general partner of
the Company, adopted the 1999 Long-Term Incentive Plan (the "Plan"). Under the
Plan, non-qualified incentive options to purchase a fixed number of Common Units
may be granted to key employees of EPCO who perform management, administrative
or operational functions for the Company under the EPCO Agreement. The exercise
price per Unit, vesting and expiration terms, and rights to receive
distributions on Units granted are determined by the Company for each grant
agreement. Upon the exercise of an option, the Company may deliver the Units or
pay an amount in cash equal to the excess of the fair market value of a Unit and
the exercise price of the option. On January 1, 2000, 225,000 options were
granted at a weighted average price of $17.50 per Unit of which none had been
exercised at February 25, 2000. The Plan is primarily funded by the Units
purchased by the Trust. Since the Common Units held by the Trust were previously
unallocated, they were excluded from the earnings per Unit calculation. If the
Plan would have been adopted at January 1, 1999, earnings per Unit would have
been $1.78 basic and $1.63 diluted.
On February 25, 2000, the Company announced the closing, effective March 1,
2000, of its acquisition of certain Louisiana and Texas pipeline assets from
Concha Chemical Pipeline Company ("Concha"), an affiliate of Shell, for
approximately $100 million in cash. The principal asset acquired was the Lou-Tex
Propylene Pipeline which is 263 miles of 10" pipeline from Sorrento, Louisiana
to Mont Belvieu, Texas. The Lou-Tex Propylene Pipeline is currently dedicated to
the transportation of chemical grade propylene from Sorrento to the Mont Belvieu
area. Also acquired in this transaction was 27.5 miles of 6" ethane pipeline
between Sorrento and Norco, Louisiana, and a 0.5 million barrel storage cavern
at Sorrento, Louisiana. The acquisition of the Lou-Tex Propylene Pipeline is the
first step in the Company's development of an approximately $180 million,
160,000 barrel per day Louisiana-to-Texas gas liquids pipeline system. The
second step involves the construction of the 263-mile Lou-Tex NGL Pipeline from
Sorrento, Louisiana to Mont Belvieu, Texas, scheduled for completion in the
third quarter of 2000 at an estimated cost of $82.5 million. This larger system
will link growing supplies of NGLs produced in Louisiana and Mississippi with
the principal NGL markets on the United States Gulf Coast.
On February 23, 2000, the Company offered to buy the remaining 88.5% ownership
interests in Dixie from the other seven owners for a total purchase price of
approximately $204.4 million. The offer is subject to the acceptance by the
holders of a minimum of 68.5% of the oustanding ownership interests. The offer
will expire on March 8, 2000 if it is not accepted by such holders. If the offer
is accepted, the purchase would be subject to, among other things, preparation
and execution of a definitive purchase agreement and the obtaining of requisite
regulatory approvals and consents.
F-29
17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
--------------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 1998:
Revenues $ 193,339 $ 211,397 $ 168,791 $ 181,046
Operating income 6,138 19,008 11,865 13,462
Income (loss) before extraordinary item
and minority interest (319) 15,399 9,802 12,473
Extraordinary item and minority interest 3 (154) (27,002) (125)
Net income (loss) (316) 15,245 (17,200) 12,348
Net income Per Unit, basic
Earnings (loss) before extraordinary item $ (0.01) $ 0.27 $ 0.15 $ 0.18
Extraordinary item (0.42)
--------------------------------------------------------------------------
Net income (loss) $ (0.01) $ 0.27 $ (0.27) $ 0.18
==========================================================================
Net income per Unit, diluted $ (0.01) $ 0.27 $ (0.27) $ 0.18
==========================================================================
FOR THE YEAR ENDED DECEMBER 31, 1999:
Revenues $ 148,877 $ 177,479 $ 445,027 $ 575,073
Operating income 12,068 21,069 40,002 59,212
Income before minority interest 10,561 19,350 36,716 54,894
Minority interest (106) (196) (370) (554)
Net income 10,455 19,154 36,346 54,340
Net income per Unit, basic $ 0.16 $ 0.28 $ 0.54 $ 0.81
==========================================================================
Net income per Unit, diluted $ 0.16 $ 0.28 $ 0.47 $ 0.66
==========================================================================
As a result of the TNGL acquisition and MBA acquisition, the Company's earnings
increased significantly in the third quarter of 1999 over the second quarter of
1999. The TNGL acquisition was effective August 1, 1999 and the MBA acquisition
was effective July 1, 1999.
Certain 1998 amounts have been restated to conform to the 1999 presentation.
F-30
18. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP
The Operating Partnership and its subsidiaries and joint ventures conduct
substantially all of the business of the Company. The Operating Partnership,
along with the Company, was formed in April 1998 to acquire, own, and operate
all of the NGL processing and distribution assets of EPCO. The General Partner
holds a 1.0101% interest in the Operating Partnership and a 1.0% interest in the
Company. The Company owns a 98.9899% interest in the Operating Partnership.
Following is the condensed financial information for the Operating Partnership:
BALANCE SHEET DATA: AS OF DECEMBER 31,
--------------------------------
1998 1999
--------------------------------
Current assets $ 137,693 $ 382,298
Noncurrent assets 603,344 1,115,142
================================
Total assets $ 741,037 $ 1,497,440
================================
Current liabilities $ 82,771 $ 530,759
Noncurrent liabilities 90,000 166,296
Minority Interest 993 1,032
Partners' equity 567,273 799,353
================================
Total liabilities and partners' equity $ 741,037 $ 1,497,440
================================
INCOME STATEMENT DATA:
YEAR ENDED DECEMBER 31,
------------------------------------------------
1997 1998 1999
------------------------------------------------
Revenues $ 1,035,963 $ 754,573 $ 1,346,456
================================================
Operating Income 75,680 50,473 132,351
================================================
Income before extraordinary item and
minority interest 52,690 37,355 121,840
Extraordinary item (27,176)
------------------------------------------------
Income before minority interest 52,690 10,179 121,840
Minority interest (78) (122) (110)
------------------------------------------------
Net income of Operating Partnership $ 52,612 $ 10,057 $ 121,730
Reconciliation of net income of Operating
Partnership to net income of the Company:
Trust dividend income eliminated in
in consolidation (319)
Minority interest (449) 20 (1,116)
================================================
Net income of the Company $ 52,163 $ 10,077 $ 120,295
================================================
The number and dollar amount of reconciling items between the financial
statements of the Company and the Operating Partnership are insignificant. The
primary reconciling items between the balance sheet of the Operating Partnership
and the Company are the Operating Partnership's investment in the Trust (which
is eliminated in consolidation with the Company) and minority interest. The
differences in net income are the dividends recognized by the Trust (which are
eliminated in consolidation) and minority interest as shown above.
F-31
SCHEDULE II
ENTERPRISE PRODUCTS PARTNERS, L.P.
VALUATION AND QUALIFYING ACCOUNTS
(AMOUNTS IN MILLIONS OF DOLLARS)
Additions
-----------------------
Balance at Charged to Charged to
beginning of Costs and other Balance at end
Description period expenses accounts Deductions of period
- ----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1997:
Reserve for inventory losses $ 1.2 $ 5.0 $ (5.4)(a) $ 0.8
Year ended December 31, 1998:
Reserve for inventory losses 0.8 10.0 (10.1)(a) 0.8
Year ended December 31, 1999:
Allowance for doubtful
accounts receivable - trade 3.0 12.9 (b) 15.9
Reserve for inventory losses 0.8 7.3 ( 5.2)(a) 2.9
- ----------------------------------------------------------------------------------------------------------------------
(a) Generally denotes net underground NGL storage well product losses
(b) As a result of the TNGL acquisition, the Company acquired a $12.9 million
allowance for doubtful accounts from TNGL. Historically, the Company did
not experience any significant losses from bad debts and therefore did not
require an allowance account.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized, in the City of Houston,
State of Texas, on the 1st day of March, 2000.
ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)
By: ENTERPRISE PRODUCTS GP, LLC,
as General Partner
By: /s/ O.S. Andras
-------------------------
Name: O.S. Andras
Title: President and Chief Executive Officer
of Enterprise Products GP, LLC
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 indicated below on the 1st day of March, 2000.
Signature Title
--------- -----
/s/ Dan L. Duncan Chairman of the Board and Director
- ------------------
Dan L. Duncan
/s/ O.S. Andras President, Chief Executive Officer and
- ------------------
O.S. Andras Director
/s/ Randa L. Duncan Group Executive Vice President and
- --------------------- Director
Randa L. Duncan
/s/ Gary L. Miller Executive Vice President, Chief Financial
- --------------------- Officer, Treasurer and Director (Principal
Gary L. Miller
Financial and Accounting Officer)
/s/ Charles R. Crisp Director
- --------------------
Charles R. Crisp
/s/ Dr. Ralph S. Cunningham Director
- ---------------------------
Dr. Ralph S. Cunningham
/s/ Curtis R. Frasier Director
- ---------------------
Curtis R. Frasier
/s/ Lee W. Marshall, Sr. Director
- ------------------------
Lee W. Marshall, Sr.
/s/ Stephen H. McVeigh Director
- -----------------------
Stephen H. McVeigh
EXHIBIT 21.1
ENTERPRISE PRODUCTS PARTNERS L.P.
LIST OF SUBSIDIARIES OF THE COMPANY
Enterprise Products Operating L.P., a Delaware limited partnership
Sorrento Pipeline Company, LLC, a Texas limited liability company
Chunchula Pipeline Company, LLC, a Texas limited liability company
Cajun Pipeline Company, LLC, a Texas limited liability company
HSC Pipeline Partnership, L.P., a Texas limited partnership
Propylene Pipeline Partnership, L.P., a Texas limited partnership
Enterprise Products Texas Operating, L.P., a Texas limited partnership
Entell NGL Services, LLC, a Delaware limited liability company
Enterprise Lou-Tex Propylene Pipeline L.P., a Texas limited partnership
Enterprise Lou-Tex NGL Pipeline L.P., a Texas limited partnership
Enterprise NGL Private Lines & Storage LLC, a Delaware limited liability company
Enterprise NGL Pipelines, LLC, a Delaware limited liability company
Enterprise Gas Processing LLC, a Delaware limited liability company
Enterprise Norco LLC, a Delaware limited liability company
Enterprise Fractionation LLC, a Delaware limited liability company
EPOLP 1999 Grantor Trust