UNITED STATES
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, 2000 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
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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. [ ]
The 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 March 19, 2001, was approximately
$348.5 million. This figure assumes that the directors and executive officers of
the General Partner, the Enterprise Products 1998 Unit Option Plan Trust,
Enterprise Products 2000 Rabbi Trust and the EPOLP 1999 Grantor Trust were
affiliates of the Registrant.
The registrant had 45,524,515 Common Units outstanding as of March 22,
2001.
ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS
Page No.
PART I
Glossary ii
Items 1 and 2. Business and Properties. 1
Item 3. Legal Proceedings. 24
Item 4. Submission of Matters to a Vote of Security Holders. 24
PART II
Item 5. Market for Registrant's Common Equity
and Related Unitholder Matters. 25
Item 6. Selected Financial Data. 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation. 27
Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 43
Item 8. Financial Statements and Supplementary Data. 45
Item 9. Changes in and disagreements with Accountants on Accounting
and Financial Disclosure. 45
PART III
Item 10. Directors and Executive Officers of the Registrant. 46
Item 11. Executive Compensation. 50
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. 54
i
Glossary
The following abbreviations, acronyms or terms used in this Form 10-K are
defined below:
Acadian Acadian Gas, LLC
Aristech Aristech Chemical Corporation and affiliates
Basell Basell polyolefins and affiliates (formerly Montell)
Bcfd Billion cubic feet per day
BEF Belvieu Environmental Fuels, a joint venture of EPOLP
Belle Rose Belle Rose NGL Pipeline LLC, a joint venture of EPOLP
BP BP Amoco PLC and affiliates
BPD Barrels per day
BRF Baton Rouge Fractionators LLC, a joint venture of
EPOLP
BRPC Baton Rouge Propylene Concentrator, LLC, a joint
venture of EPOLP
Btu British thermal units
Burlington Resources Burlington Resources Inc. and affiliates
CERCLA Comprehensive Environmental Response, Compensation
and Liability Act
Company Enterprise Products Partners L.P. and subsidiaries
Conoco Conoco, Inc. and affiliates
Coral Energy Coral Energy LLC, an affiliate of Shell
DIB Deisobutanizer
Dixie Dixie Pipeline Company, a joint venture of EPOLP
Duke Energy Duke Energy Corporation and affiliates
Dynegy Dynegy Inc. and affiliates
EBITDA Earnings before Interest, Taxes, Depreciation and
Amortization
Energy Policy Act Energy Policy Act of 1992
Enron Enron Corp. and affiliates
EPA United States Environmental Protection Agency
EPCO Enterprise Products Company, an affiliate of the
Company
EPE El Paso Energy Partners L.P. and affiliates
EPIK EPIK Terminalling L.P. and EPIK Gas Liquids, LLC,
collectively, a joint venture of EPOLP
EPOLP Enterprise Products Operating L.P. (or "Operating
Partnership"), a subsidiary of the Company
EPU Earnings per Unit
Equistar A joint venture of Lyondell Chemical Company,
Millenium Chemicals, Inc. and Occidental Petroleum
Corporation
ETBE Ethyl Tertiary Butyl Ether
ExxonMobil ExxonMobil Corporation and affiliates
FERC Federal Energy Regulatory Commission
General Partner Enterprise Products GP, LLC, the general partner of
the Company and EPOLP
HLPSA Hazardous Liquid Pipeline Safety Act
Huntsman Huntsman Corporation and affiliates
ICA Interstate Commerce Act
Kinder Morgan Kinder Morgan Operating LP "A"
Koch Koch Industries Inc. and affiliates
Lakehead Lakehead Pipe Line Company
LIBOR London Interbank Offering Rate
Manta Ray Manta Ray Offshore Gathering Company, L.L.C.
MBA Mont Belvieu Associates
MBA acquisition Refers to the acquisition of an additional interest
in the Mont Belvieu NGL fractionation facility from
Kinder Morgan and EPCO effective July 1, 1999
MBFC Mississippi Business Finance Corporation
MBPD Thousand barrels per day
Mitchell Mitchell Energy and Development Corp. and affiliates
ii
MLP Denotes Enterprise Products Partners L.P. as
guarantor of certain debt obligations of its
Operating Partnership
MMBbls Millions of barrels
Moray Moray Pipeline Company, LLC
MTBE Methyl tertiary butyl ether
Nautilus Nautilus Pipeline Company, L.L.C.
Nemo Nemo Gathering Company, L.L.C.
NGL or NGLs Natural gas liquid(s)
NPDES National Pollutant Discharge Elimination System
NYSE New York Stock Exchange
Operating Partnership Enterprise Products Operating L.P. and subsidiaries
OSHA Occupational Safety and Health Act
Phillips Phillips Petroleum Company and affiliates
Promix K/D/S Promix LLC, a joint venture of EPOLP
PTR Plant thermal reduction
PURPA Public Utility Regulatory Policy Act of 1978
RCRA Federal Resource Conservation and Recovery Act
Sailfish Sailfish Pipeline Company, LLC
SEP Shell Exploration and Production Company
SFAS Statement of Financial Accounting Standards
SG&A Selling, general and administrative costs
Shell Shell Oil Company, its subsidiaries and affiliates
Stingray Stingray Pipeline Company, LLC
Sun Sunoco, Inc. and affiliates
TAME Tertiary Amyl Methyl Ether
Tejas Energy Tejas Energy, LLC, an affiliate of Shell
Texaco Texaco Inc. and affiliates
TNGL Tejas Natural Gas Liquids, LLC, a subsidiary of
Tejas Energy
TNGL acquisition Refers to the acquisition of TNGL from Shell
effective August 1, 1999
Tri-States Tri-States NGL Pipeline LLC, a joint venture of EPOLP
Ultramar Diamond Ultramar Diamond Shamrock and affiliates
Valero Valero Energy Corporation and affiliates
VESCO Venice Energy Services Company, LLC, a joint venture
of EPOLP
West Cameron West Cameron Dehydration, LLC
Williams Williams Companies, Inc. and affiliates
Wilprise Wilprise Pipeline Company, LLC, a joint venture of
EPOLP
1998 Trust Enterprise Products 1998 Unit Option Plan Trust, an
affiliate of EPCO
1999 Trust EPOLP 1999 Grantor Trust, a wholly-owned subsidiary
of EPOLP
2000 Trust Enterprise Products 2000 Rabbi Trust, an affiliate
of EPCO
iii
PART I
Items 1 and 2. Business and Properties.
Summary
The Company is a leading integrated North American provider of natural
gas processing and natural gas liquids fractionation, transportation and storage
services to producers of NGLs and consumers of NGL products. 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 EPCO. The general partner of the Company, Enterprise Products GP, LLC,
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 document include the assets and operations of the Operating
Partnership and its subsidiaries.
The Company (i) processes natural gas into a merchantable and
transportable form of energy that meets industry quality specifications by
removing NGLs and impurities; (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.
Beginning in the first quarter of 2001, the Company will enter the natural gas
pipeline business (see "Acquisitions" on page 2 of this Form 10-K).
The Company's NGL 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: (a) one of
the largest NGL fractionation facilities in the United States with a net
processing capacity of 131 MBPD; (b) the largest commercial butane isomerization
complex in the United States with a potential isobutane production capacity of
116 MBPD; (c) a MTBE production facility with a net production capacity of 5
MBPD; and (d) two propylene fractionation units with a combined production
capacity of 31 MBPD. 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% interest; 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 33.3% interest; and one
of its three isomerization units and one deisobutanizer which are held under
long-term leases with purchase options.
The Company's operations in Louisiana and Mississippi include varying
interests in twelve natural gas processing plants with a combined capacity of
11.6 Bcfd and net capacity of 3.2 Bcfd, six NGL fractionation facilities with a
combined net processing capacity of 159 MBPD and a propylene fractionation
facility with a net capacity of 7 MBPD.
The Company owns, operates or has an interest in approximately 65.0
million barrels of gross storage capacity (44.3 million barrels of net capacity)
in Texas, Louisiana and Mississippi that are an integral part of its processing
operations. The Company also leases and operates one of only two commercial NGL
import/export terminals on the Gulf Coast. In addition, the Company has
operating and non-operating ownership interests in over 2,900 miles of NGL
pipelines.
1
The Company's operating margins are derived from services provided to
its 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. In the
Company's isobutane merchant activities and to a certain extent its propylene
fractionation business, it takes title to feedstock products and sells processed
end products. The Company's profitability from these merchant activities is
dependent on the prices of feedstocks and end products, which may vary on a
seasonal basis. In the Company's propylene fractionation business and isobutane
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 "PTR" or "shrinkage"), the Company's margins
are affected by the prices of NGLs and natural gas. The Company uses financial
instruments to reduce its exposure to the change in the prices of NGLs and
natural gas.
Uncertainty of Forward-Looking Statements and Information. This annual
report on Form 10-K 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,"
"believe," "would," "may" and similar expressions and statements regarding the
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 due to weather and other
natural and market forces, (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.
In addition, the Company's expectations regarding its future capital
expenditures as described in "Liquidity and Capital Resources" are only its
forecasts regarding these matters. These forecasts may be substantially
different from actual results due to the factors described in the previous
paragraph as well as uncertainties related to the following: (a) the accuracy of
the Company's estimates regarding its spending requirements, (b) the occurrence
of any unanticipated acquisition opportunities, (c) the need to replace any
unanticipated losses in capital assets, (d) changes in the strategic direction
of the Company and (e) unanticipated legal, regulatory and contractual
impediments with regards to its construction projects.
Acquisitions
Effective August 1, 1999, the Company acquired TNGL from Shell, in
exchange for 14.5 million non-distribution bearing, convertible special
partnership Units of the Company and $166 million in cash (the "TNGL
acquisition"). The Company also agreed to issue up to 6.0 million additional
non-distribution bearing special partnership Units to Shell in the future if the
volumes of natural gas that the Company processes for Shell reach agreed upon
levels in 2000 and 2001. The first 3.0 million of these additional special
partnership Units were issued on August 1, 2000. 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.
2
The assets acquired include varying interests in eleven natural gas processing
plants, four NGL fractionation facilities, four NGL storage facilities, operator
and non-operator ownership interests in approximately 1,500 miles of NGL
pipelines and a 20-year natural gas processing agreement with Shell.
The Company has recently announced and/or completed the acquisition of
three Louisiana-based natural gas pipeline systems:
- Acadian Gas, LLC ("Acadian") for $226 million;
- Stingray Pipeline Company, LLC ("Stingray") and West Cameron
Dehydration, LLC ("West Cameron") for approximately $25.1
million; and
- Sailfish Pipeline Company, LLC ("Sailfish") and Moray Pipeline
Company, LLC ("Moray") for approximately $88.1 million.
The Company has executed a definitive agreement with the seller of Acadian with
closing expected in the first quarter of 2001. The Stingray, West Cameron,
Sailfish and Moray acquisitions closed on January 29, 2001. The acquisition of
these natural gas pipeline systems represents a strategic investment for the
Company and allows for entry into the natural gas gathering, transportation,
marketing and storage business. Management believes that these assets have
attractive growth attributes given the expected long-term increase in natural
gas demand for industrial and power generation uses. In addition, these assets
extend the Company's midstream energy service relationship with long-term NGL
customers (producers, petrochemical suppliers and refineries) and offer
additional fee-based cash flows and opportunities for enhanced services to
customers. For additional information regarding these 2001 acquisitions, see
page 12 of this Form 10-K.
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 gas companies
have sold non-strategic assets including assets in the midstream natural gas
industry in which the Company operates. Management believes that this trend will
continue, and the Company expects independent oil and natural gas companies to
consider similar options.
The Company's Operations
The Company's operations are segregated into five reportable business
segments:
- Fractionation
- Pipeline
- Processing
- Octane Enhancement
- Other
The Fractionation segment is primarily comprised of the following three
business areas: NGL Fractionation, Isomerization and Propylene Fractionation.
The Fractionation 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
facilities and other miscellaneous minor plants. Pipelines includes the
Company's pipeline systems, storage facilities and the Houston Ship Channel
Import/Export terminal. The Pipeline segment also includes the Company's equity
method investments in EPIK, Wilprise, Tri-States, Belle Rose and Dixie. The
Processing segment consists of the Company's natural gas processing business and
related merchant activities. Octane Enhancement is comprised of the Company's
equity interest in BEF, which owns and operates a facility that produces motor
gasoline additives to enhance octane (currently producing MTBE). The Other
segment is primarily comprised of fee-based marketing services and other
operational support activities including engineering and plant-based information
technology functions.
See Note 15 of the Notes to Consolidated Financial Statements for
additional segment information including revenues from external customers,
segment profit and loss and segment assets.
3
Fractionation
NGL Fractionation
The Company's NGL Fractionation operations include seven NGL
fractionators with a combined gross processing capacity of 558 MBPD and net
processing capacity of 290 MBPD. A summary of the Company's NGL fractionation
facilities at December 31, 2000 is as follows:
NGL Gross Net
Fractionation Capacity Ownership Capacity
Facility Location (MBPD) Interest (MBPD)
- ----------------- -------------- ------------- -------------- ------------
Mont Belvieu Texas 210 62.5% 131
Norco Louisiana 70 100.0% 70
BRF Louisiana 60 32.2% 19
Promix Louisiana 145 33.3% 48
Tebone Louisiana 30 33.4% 10
Venice Louisiana 36 13.1% 5
Petal Mississippi 7 100.0% 7
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Total 558 290
============= ============
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 a heating, engine and industrial
fuel. Isobutane is fractionated from mixed butane (a stream of normal butane and
isobutane) 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 primarily used as motor
gasoline blend stock or petrochemical feedstock.
The three principal sources of mixed NGLs fractionated in the United
States are (i) domestic gas processing plants, (ii) domestic crude oil
refineries and (iii) 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 impurities and render the gas suitable for pipeline
transportation. Gas processing plants are located near the production areas and
separate pipeline quality natural gas (principally methane) from mixed NGLs and
other components. After being extracted in the field, mixed NGLs are transported
to a centralized facility for fractionation. Mixed NGL recovery by gas
processing plants represents the most important source of throughput for the
Company's NGL fractionators and is generally governed by the degree to which NGL
prices exceed the cost (principally that of natural gas as a raw material
feedstock and as a fuel) of separating the mixed NGLs from the purified natural
gas stream. When operating and extraction costs of gas processing plants are
higher than the incremental value of the NGL products that would be gained in
fractionation, mixed NGL recovery levels by these facilities (and hence NGL
fractionation volumes) may be reduced. For a complete discussion of the
Company's gas plants, see Processing on page 14 of this Form 10-K. Crude oil and
condensate production also contain varying amounts of NGLs, which are removed
during the refining process and are either fractionated by the refiners
themselves or delivered to third party NGL fractionation facilities like those
owned by the Company. The mixed NGLs delivered from domestic gas processing
plants and domestic crude oil refineries to the Company's NGL fractionation
facilities are typically transported by NGL pipelines and, to a lesser extent,
by railcar and truck. The Company takes delivery of mixed NGL imports through
its Houston ship channel NGL import/export facility which is connected to Mont
Belvieu via pipeline.
In general, the Company's NGL fractionation business processes mixed
NGL streams for a toll processing fee charged to its third-party and merchant
business customers. Overall, results of operations of this business area are
dependent upon the volume of mixed NGLs processed and the level of toll
4
processing fees charged to customers and exhibit little to no seasonal
variation. NGL fractionation toll processing arrangements 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. The NGL fractionation revenues earned from the Company's related
merchant business are based primarily on the mixed NGL volumes flowing from
Company and affiliate-owned gas processing plants. Lastly, NGL producers
generally retain title to, and the pricing risks associated with, the NGL
products.
Management believes that sufficient volumes of mixed NGLs, especially
those originating from the Company's and/or its affiliate's gas processing
plants, will be available for fractionation in the foreseeable future. These gas
processing plants are expected to benefit from anticipated increases in natural
gas production from emerging deepwater developments in the Gulf of Mexico
offshore Louisiana. Deepwater natural gas production has historically had a
higher concentration of NGLs than continental shelf or domestic land-based
production. In addition, significant volumes of mixed NGLs are contractually
committed to the Company's facilities by third-party customers.
NGL Fractionation Facilities
During 2000, the Company's NGL fractionation facilities processed mixed
NGLs at an average rate of 213 MBPD or 73% of capacity, both amounts on a net
basis. The table below shows net processing volumes and capacity (both in MBPD)
and the corresponding overall utilization rates of the Company's NGL
fractionation facilities for the last three years:
NGL Fractionation For Year Ended December 31,
Facility 2000 1999 1998
- -------------------------------------------------------------------------------
Mont Belvieu (a) 106 78 71
Norco 47 48 -
BRF 15 13 -
Promix 34 30 -
Other (b) 11 15 2
----------------------------------------------
Total Processing Volume 213 184 73
Net Capacity (c) 290 264 86
Utilization 73% 70% 85%
- -------------------------------------------------------------------------------
(a) Net volumes increased in 1999 and 2000 due to increased ownership of
facilities resulting from the MBA acquisition in July 1999
(b) Includes Venice, Tebone and Petal NGL fractionation facilities
(c) Capacities have been adjusted for acquisitions
Mont Belvieu NGL Fractionation facility. The Company operates one of
the largest NGL fractionation facilities in the United States with a gross
processing capacity of 210 MBPD at Mont Belvieu, Texas (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. The Company owns an effective 62.5% interest in the NGL fractionation
facilities at the Mont Belvieu complex.
At the Mont Belvieu NGL fractionation facilities, 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 MBPD of mixed NGLs or all of their
mixed NGLs brought within 50 miles of the Mont Belvieu facility. Duke Energy has
agreed to deliver 26 MBPD of mixed NGLs to Mont Belvieu as well as additional
barrels that exceed its commitments to other NGL fractionation facilities. The
Company generally enters into contracts that cover most of the remaining
capacity at the Mont Belvieu facilities for one to three-year terms with
customers that are producers and/or consumers of NGLs.
5
In January 2001, the Company entered into a five-year agreement to
exchange NGLs produced at the Sea Robin natural gas processing plant for
finished NGL products at the Company's Mont Belvieu complex. The NGLs will be
exchanged via the Company's recently completed Lou-Tex NGL Pipeline (see page 11
for information regarding this pipeline). As a result of this agreement, the
Company will utilize its Mont Belvieu NGL fractionation facility to process the
mixed NGLs received from the Sea Robin plant into finished NGL products. Initial
net processing volumes are expected to be 10 MBPD and are anticipated to
increase to over 13 MBPD by the end of 2001.
Norco NGL Fractionation facility. The Company owns and operates a NGL
fractionation facility at Norco, Louisiana. The Norco facility receives mixed
NGLs via pipeline from the Yscloskey, Toca, Paradis and Crawfish gas processing
plants and has an average processing capacity of 70 MBPD.
BRF NGL Fractionation facility. The Company operates and has a 32.2%
interest in BRF, which owns a 60 MBPD NGL fractionation facility and related
transportation assets located near Baton Rouge, Louisiana. The BRF facility
processes mixed NGLs received from BP, ExxonMobil and Williams, all of which are
partners with the Company in BRF, through long-term fractionation agreements.
The mixed NGLs provided by the partners originate from Alabama, Mississippi and
southern Louisiana including offshore Gulf of Mexico areas.
Promix NGL Fractionation facility. The Company operates and has a 33.3%
interest in Promix, which owns a 145 MBPD NGL fractionation facility located
near Napoleonville, Louisiana. The Promix assets include a 315-mile mixed NGL
gathering system connected to nine gas processing plants, five salt dome storage
wells which handle mixed NGLs, propane, isobutane, normal butane and natural
gasoline and a barge loading facility. Promix receives mixed NGLs from gas
processing plants located in southern Louisiana.
Tebone NGL Fractionation facility. The Company operates and has a 33.4%
interest in a captive NGL fractionation facility located near Geismar,
Louisiana. This facility serves the Company's gas processing facilities in North
Terrebonne, Louisiana and has a gross processing capacity of 30 MBPD.
Venice NGL Fractionation facility. The Company has a 13.1% interest in
VESCO, which owns a captive 36 MBPD NGL fractionation facility located near
Venice, Louisiana. This facility serves VESCO's gas processing operations
located in southern Louisiana and is operated by Dynegy.
Petal NGL Fractionation facility. The Company owns and operates a NGL
fractionation facility at Petal, Mississippi with a processing capacity of 7
MBPD. The Petal plant is connected to the Company's Chunchula pipeline system
and serves NGL producers in Mississippi, Alabama and Florida.
6
Isomerization
The Company's isomerization facilities include three butamer reactor
units and eight associated DIBs located in Mont Belvieu, Texas which comprise
the largest commercial isomerization complex in the United States. The Company's
facilities have an average combined potential production capacity of 116 MBPD of
isobutane and account for more than 70% of the commercial isobutane production
capacity in the United States. The Company owns the isomerization facilities
with the exception of one of the butamer reactor units, which it holds through a
long-term lease. The facilities are operated by the Company. During the second
quarter of 2000, the Company refurbished one of its butamer reactors that had
been shut down since July 1999 resulting in improved operational flexibility
during periods of excess demand. This unit, accounting for 36 MBPD of capacity,
was active only during the second quarter of 2000. The following table shows
isobutane production and capacity (both in MBPD) and overall utilization for the
last three years:
For Year Ended December 31,
Mont Belvieu Facility 2000 1999 1998
- -------------------------------------------------------------------------------
Production 74 74 67
Capacity (a) 86 98 116
Utilization 86% 76% 58%
- -------------------------------------------------------------------------------
(a) The 1999 capacity figure reflects Isom II (36 MBPD of capacity) being
shutdown for the last half of the year. The 2000 capacity has been adjusted
for the two months that Isom II ran during the early summer and its
subsequent placement into standby status thereafter.
Commercial isomerization units convert normal butane into mixed butane,
which is subsequently fractionated into isobutane and normal butane. The demand
for commercial isomerization services depends upon the industry's requirements
for (i) isobutane in excess of naturally occurring isobutane produced from NGL
fractionation and refinery operations and (ii) high purity isobutane. Isobutane
demand is marginally higher in the spring and summer months due to the demand
for isobutane-based clean fuel additives such as MTBE in the production of motor
gasoline. The results of operations of this business area are generally
dependent upon the volume of normal and mixed butanes processed and the level of
processing fees charged to customers. The principal uses of isobutane are for
alkylation and in the production of MTBE and propylene oxide.
The Company uses its isomerization facilities to convert normal butane
into isobutane for its toll processing customers, including its isobutane
merchant business. The Company's largest third-party toll processing customers
operate under long-term contracts under which they supply normal butane
feedstock and pay the Company a toll processing fee based on the volume of
isobutane produced. The largest of these customers in 2000 were Lyondell,
Huntsman, Sun and Mitchell. Sun and Mitchell use the high purity isobutane
produced for them to meet their feedstock obligations as partners in the BEF
MTBE facility. The Company also meets its obligation to provide high purity
isobutane feedstock to the BEF MTBE facility with production from the
isomerization units. During 2000, 59 MBPD of isobutane production was
attributable to third-party toll processing customers.
The balance of isobutane production during 2000, or 15 MBPD, relates to
merchant activities associated with isobutane sales contracts. In general, the
merchant business (which is part of the Processing segment) meets the
requirements of its isobutane sales contracts by either purchasing isobutane in
the spot market or paying the isomerization business to process Company-held
inventories of normal and/or mixed butanes. The isomerization business area
collects a toll processing fee from the merchant business based on the volume of
normal and mixed butanes processed. The normal and mixed butane inventories are
primarily derived from imports and NGL fractionation operations. Management
believes that it will have access to sufficient volumes of normal and mixed
butanes in the foreseeable future to meet the needs of its isobutane merchant
activities. For a further discussion of the Company's merchant activities, see
Processing on page 14 of this Form 10-K.
Propylene Fractionation
The Company's propylene fractionation business consists of two polymer
grade propylene facilities (Splitters I and II) and one chemical grade propylene
plant (BRPC) with a combined gross production capacity of 54 MBPD and a net
7
capacity of 38 MBPD. The following table summarizes the propylene fractionation
business assets at December 31, 2000:
Gross Net
Propylene Capacity Ownership Capacity
Facility Location (MBPD) Interest (MBPD)
- ---------------------- --------------- -------------- ------------- --------------
Splitter I (a) Texas 17 100.0% 17
Splitter II Texas 14 100.0% 14
BRPC Louisiana 23 30.0% 7
-------------- --------------
Total 54 38
============== ==============
- ----------------------------------------------------------------------------------------
(a) The Company owns 54.6% with Basell owning the remaining 45.4%. The Company
leases Basell's interest.
In general, propylene fractionation plants separate refinery grade
propylene (a mixture of propane and propylene) into either polymer grade
propylene or chemical grade propylene along with by-products of propane and
mixed butane. Polymer grade propylene is derived by processing either refinery
grade or chemical grade propylene feedstocks. Approximately one-half of the
demand for polymer grade propylene is attributable to polypropylene, which has a
variety of end uses, including packaging film, fiber for carpets and upholstery
and molded plastic parts for appliance, automotive, houseware and medical
products. Chemical grade propylene is produced either as a by-product of olefin
(ethylene) plants or from the processing of refinery grade propylene. Chemical
grade propylene is a basic petrochemical used in plastics, synthetic fibers and
foams.
During 2000, the Company's propylene fractionation facilities produced
at an average rate of 33 MBPD or 94% of capacity, both amounts on a net basis.
The table below shows net production volumes and capacity (both in MBPD) and the
corresponding overall utilization rates of the Company's propylene fractionation
facilities for the last three years:
For Year Ended December 31,
Facility 2000 1999 1998
- -------------------------------------------------------------------------------
Splitter I & II 29 28 26
BRPC 4 - -
----------------------------------------------
Total 33 28 26
Capacity (a) 35 31 31
Utilization 94% 90% 84%
- -------------------------------------------------------------------------------
(a) 2000 capacity adjusted for start-up of BRPC unit in July 2000
Splitter I and II Propylene Fractionation facilities. The Company
operates two polymer grade propylene fractionation facilities at Mont Belvieu,
Texas with a gross capacity of 31 MBPD. The Company owns 54.6% of Splitter I and
100.0% of Splitter II. The Company leases the remaining 45.4% interest in
Splitter I from a customer, Basell (formerly Montell).
Results of operations for the Company's polymer grade propylene plants
are generally dependent upon (i) long-term toll processing arrangements and (ii)
merchant activities. The Company's largest toll processing customers during 2000
were Equistar and Huntsman. In general, pursuant to contracts with these
companies, the Company is guaranteed certain minimum volumes and paid a toll
processing fee based on the throughput of refinery grade propylene used to
produce polymer grade propylene. In the Company's propylene merchant business,
the Company has several long-term polymer grade propylene sales agreements, the
largest of which is with Basell. The Basell agreement stipulates that the
Company will sell a certain quantity of polymer grade propylene to Basell at
market-based prices through 2004. In order to meet its merchant obligations, the
Company has entered into several long-term agreements to purchase refinery grade
propylene. The Company reduces the commodity price exposure in the merchant
portion of this business by matching the volumes and pricing mechanisms required
8
under sales contracts with its supply contracts. During 2000, 12 MBPD of polymer
grade propylene production was associated with toll processing operations while
17 MBPD was attributable to merchant activities.
The Company is able to unload barges carrying refinery grade propylene
through its import/export terminal located on the Houston ship channel. The
Company is also able to receive supplies of refinery grade propylene from its
Mont Belvieu truck and rail loading facility and from refineries and other
producers through its pipeline located along the Houston ship channel. In turn,
polymer grade propylene is shipped to customers by truck or pipeline. Both toll
processing demand and merchant requirements are generally constant throughout
the year and exhibit little seasonality, except to the extent that either of the
facilities is impacted by downtime attributable to maintenance and/or economic
reasons.
BRPC Propylene Fractionation facility. The Company operates and owns a
30.0% interest in BRPC, which owns a 23 MBPD chemical grade propylene production
facility located near Baton Rouge, Louisiana. The unit, located across the
Mississippi River from ExxonMobil's refinery and chemical plant, fractionates
refinery grade propylene produced by ExxonMobil into chemical grade propylene
for a toll processing fee. Results of operations of BRPC are dependent upon the
volume of refinery grade propylene throughput and the level of toll processing
fees charged. Due to the relatively consistent flow of feedstock and
fixed-nature of the toll processing fees charged, results of operations for BRPC
exhibit little seasonality (except to the extent that volumes are affected by
downtime associated with maintenance or other economic reasons). The BRPC
facility commenced operations in the third quarter of 2000 and averaged 4 MBPD
(on an net basis) of chemical grade propylene production during the period in
which it was operational.
Pipeline
The Company's Pipeline segment includes its ownership interests in a
2,942-mile network of transportation and distribution pipeline systems and
related hydrocarbon storage facilities and import/export assets. At December 31,
2000, the Company's major pipeline systems were as follows:
Major NGL & Petroleum Liquid
Pipeline Systems Miles
- ----------------------------------------------------------- ---------------
Dixie Pipeline 1,301
Louisiana Pipeline System 471
Lou-Tex Propylene Pipeline System 291
Tri-States, Belle Rose and Wilprise Pipeline Systems 247
Lou-Tex NGL Pipeline System 206
Houston Ship Channel Pipeline System 175
Lake Charles/Bayport Propylene Pipeline System 134
Chunchula Pipeline System 117
---------------
Total Major Pipeline Systems 2,942
===============
The maximum number of barrels that these systems can transport per day
depends upon the operating balance achieved at a given time between various
segments of the system. Because the balance is dependent upon the mix of
products to be shipped and the demand levels at the various delivery points, the
exact capacity of the systems cannot be stated. As shown in the following table,
total pipeline throughput averaged 367 MBPD in 2000, 264 MBPD in 1999 and 200
MBPD in 1998 (all amounts on a net basis).
9
For Year Ended December 31,
Description 2000 1999 1998
- ---------------------------------------------------------------------------------------------------
Dixie Pipeline 14 14 -
Louisiana Pipeline System 115 74 40
Lou-Tex Propylene Pipeline System (a) 23 - -
Tri-States, Belle Rose and Wilprise Pipeline Systems 42 41 -
Lou-Tex NGL Pipeline System (b) 30 - -
Houston Ship Channel Pipeline System 106 99 107
Lake Charles/Bayport Propylene Pipeline System 5 5 7
Chunchula Pipeline System 6 7 5
EPIK Export Facility (c) 17 10 10
Houston Ship Channel NGL import facility 9 14 31
--------------------------------------
Total Throughput MBPD 367 264 200
======================================
- ---------------------------------------------------------------------------------------------------
(a) Volumes reflect the period in which the Company owned the asset (i.e.,
March 2000 through December 2000)
(b) Pipeline commenced operations in late November 2000
(c) 2000 volumes higher than 1999 due to installation of new NGL product
chiller unit in the fourth quarter of 1999
The Company's pipelines transport mixed NGLs and liquid hydrocarbons to
the Company's NGL fractionation plants; distribute NGL purity products and
propylene to petrochemical plants and refineries; and deliver propane to
customers along the 1,301-mile Dixie pipeline. The pipelines provide
transportation services to customers on a fee basis. As such, results of
operations for this business area are generally dependent upon the volume of
product transported and the level of fees charged to customers (which include
the Company's merchant businesses). Taken as a whole, this business area does
not exhibit a significant degree of seasonality; however, volumes on the Dixie
pipeline are higher in the November through March timeframe due to the increased
use of propane for heating in the southeastern United States. In addition,
volumes on the Lou-Tex NGL pipeline will generally increase during the April
through September period due to gasoline blending considerations.
The Company's hydrocarbon storage facilities and NGL import/export
terminal are integral parts of its pipeline operations. In general, storage
wells are used to store mixed NGLs and refinery grade propylene that have been
delivered to Company facilities for processing. Such storage allows the Company
to mix various batches of feedstock and maintain a sufficient supply and stable
composition of feedstock to its processing facilities. The Company also uses the
wells to store certain fractionated products for its customers when they are
unable to take immediate delivery. The profitability of storage operations is
primarily dependent upon the volume of material stored and the level of storage
fees charged to customers. 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. Intersegment revenues for the Pipeline
segment include those fees charged to the Company's various merchant businesses
for use of the storage facilities. The Company owns and operates storage wells
at Mont Belvieu, Texas with an aggregate capacity of 21 MMBbls (including the
recent purchase of a storage well from Equistar mentioned below under "Major
Pipeline Acquisitions in 2001"). The Company's Louisiana storage assets consist
of facilities located at or near Breaux Bridge, Napoleonville, Sorrento and
Venice having a gross capacity of 33 MMBbls and a net capacity of 14.8 MMBbls.
The Company's Mississippi storage assets are comprised of facilities located at
or near Petal and Hattiesburg, Mississippi with a gross capacity of 12 MMBbls
and a net capacity of 9.5 MMBbls. Of the facilities located in Louisiana and
Mississippi, the Company operates those located in Breaux Bridge, Louisiana and
Petal, Mississippi. Koch, Dynegy and Equilon (an affiliate of Shell) operate the
remaining facilities.
The Company leases and operates a NGL import facility at the Oiltanking
Houston marine terminal on the Houston ship channel that enables NGL tankers to
be offloaded at their maximum unloading rate (10,000 barrels per hour), thus
minimizing laytime and increasing the number of vessels that can be offloaded. A
methanol pipeline, which is part of the Houston Ship Channel Pipeline System,
extends from the import facility to Mont Belvieu and enables methanol to be
delivered by ship or barge and then transported to the Company's MTBE facility
at Mont Belvieu where it is consumed in the MTBE process. In addition, the
Company owns a combined 50% interest in EPIK, a joint venture with Idemitsu,
which owns NGL export assets at the terminal including a NGL product chiller and
related equipment used for loading refrigerated marine tankers. The NGL product
10
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. Traditionally, EPIK's export volumes are higher during the winter months
due to increased propane exports by Idemitsu and other parties. The
profitability of import and export activities depends primarily upon the volumes
unloaded and loaded and the level of fees associated with each activity.
Major Pipeline Systems
Dixie Pipeline. The Dixie Pipeline is a 1,301-mile propane pipeline
which moves propane supplies from Mont Belvieu, Texas and Louisiana to markets
in the southeastern United States. At December 31, 2000, the Company owned a
19.9% interest in Dixie (with 8.4% of its interest being purchased from Conoco
for $19.4 million in October 2000). The other owners of Dixie are BP, Chevron,
ExxonMobil, Phillips and Texaco with Phillips serving as operator.
Louisiana Pipeline System. The Louisiana Pipeline System is a 471-mile
Company-owned network of nine NGL pipelines located in Louisiana. This system is
used to transport propane, butanes and natural gasoline and serves a variety of
customers including major refineries and petrochemical companies along the
Mississippi River corridor in southern Louisiana. This system also provides
transportation services for the Company's gas processing and other facilities
located in the Louisiana area. The Company operates 233 miles of the system, and
Equilon operates the remainder.
Lou-Tex Propylene Pipeline System. The Lou-Tex Propylene Pipeline
System consists of a 263-mile pipeline used to transport propylene from
Sorrento, Louisiana to Mont Belvieu, Texas. Currently, this system is used to
transport chemical grade propylene for third parties from production facilities
in Louisiana to customers in Texas. This system also includes storage facilities
and a 28-mile NGL pipeline. The purchase of this system, effective March 1, 2000
from Concha Chemical Pipeline Company (an affiliate of Shell), was completed at
a cost of approximately $100 million. The Company owns and operates these
assets.
Tri-States, Belle Rose and Wilprise Pipeline Systems. The Company is
participating in pipeline joint ventures which supply mixed NGLs to the BRF and
Promix NGL fractionators. They are as follows:
- The Company owns a 33.3% interest in Tri-States, which owns a
169-mile NGL pipeline that extends from Mobil Bay, Alabama to
near Kenner, Louisiana. Tri-States is a joint venture with BP,
Duke Energy, Koch and Williams with Williams acting as operator
of the assets.
- The Company operates and owns a 41.7% interest in Belle Rose,
which owns a 48-mile NGL pipeline that extends from near Kenner,
Louisiana to the Promix NGL fractionation facility in
Napoleonville, Louisiana. Belle Rose is a joint venture with Gulf
Coast NGL Pipeline and Koch.
- The Company owns a 37.4% interest in Wilprise, which owns a
30-mile NGL pipeline that extends from near Kenner, Louisiana to
Sorrento, Louisiana. Wilprise is a joint venture with Williams
and BP with Williams acting as operator of the assets.
Lou-Tex NGL Pipeline System. The Lou-Tex NGL Pipeline System consists
of a recently completed 206-mile NGL pipeline used (i) to provide transportation
services for NGL products and refinery grade propylene between the Louisiana and
Texas markets and (ii) to transport mixed NGLs from the Company's Louisiana gas
processing facilities to the Mont Belvieu NGL fractionation facility.
Construction of this system was completed during the fourth quarter of 2000 at a
cost of approximately $87.9 million. The Company operates and owns the system.
Houston Ship Channel Pipeline System. The Houston Ship Channel Pipeline
System is a collection of NGL and petrochemical pipelines aggregating 175 miles
in length used to deliver feedstocks to Company facilities for processing and to
deliver products to petrochemical plants and refineries. This system also
connects the Company's Mont Belvieu facilities to its NGL import/export terminal
located on the Houston ship channel. This system extends west from Mont Belvieu
and runs along the Houston ship channel to Pierce Junction, which is south of
Houston, Texas. Beginning in April 2001, management anticipates that this
pipeline system will be used to transport to the Oiltanking Houston marine
terminal approximately 15 MBPD of MTBE production from the BEF facility that had
been previously transported by a third-party pipeline system. The Company
operates and owns this pipeline system.
11
Lake Charles/Bayport Propylene Pipeline System. The Lake
Charles/Bayport Propylene Pipeline System is a 134-mile propylene pipeline
system used to distribute polymer grade propylene from Mont Belvieu to Basell'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 Basell, and another segment of the pipeline is leased
from ExxonMobil.
Chunchula Pipeline System. The Chunchula Pipeline System is a 117-mile
NGL pipeline system extending from the Alabama-Florida border to the Company's
storage and NGL fractionation facilities near Petal, Mississippi. The system
gathers NGLs from production areas in Florida and Alabama and delivers them to
the Petal NGL fractionation facility for processing or storage and further
distribution. The Company owns and operates this pipeline.
Major Pipeline Acquisitions in 2001
The Company has recently announced and/or completed the acquisition of
three Louisiana-based natural gas pipeline systems:
- Acadian Gas, LLC ("Acadian");
- Stingray Pipeline Company, LLC ("Stingray") and West Cameron
Dehydration, LLC ("West Cameron"); and
- Sailfish Pipeline Company, LLC ("Sailfish") and Moray Pipeline
Company, LLC ("Moray").
The acquisition of these natural gas pipeline systems represents a strategic
investment for the Company and allows for entry into the natural gas gathering,
transportation, marketing and storage business. Management believes that these
assets have attractive growth attributes given the expected long-term increase
in natural gas demand for industrial and power generation uses. In addition,
these assets extend the Company's midstream energy service relationship with
long-term NGL customers (producers, petrochemical suppliers and refineries) and
offer additional fee-based cash flows and opportunities for enhanced services to
customers.
Acadian. On September 25, 2000, the Company announced that it had
executed a definitive agreement to purchase Acadian from Coral Energy, an
affiliate of Shell, for $226 million in cash, inclusive of working capital. The
acquisition of Acadian integrates its natural gas pipeline systems in South
Louisiana with the Company's Gulf Coast natural gas processing and NGL
fractionation, pipeline and storage system. The Acadian acquisition gives the
Company an extensive intrastate natural gas pipeline system with access to both
supply and markets; positions the Company to compete for incremental natural gas
supplies from new discoveries onshore, the offshore Louisiana continental shelf
and Gulf of Mexico deepwater developments; and enables the Company to take
advantage of growing industrial and petrochemical demand (including new
gas-fired power generation projects) along with additional natural gas
processing opportunities.
Acadian's assets are comprised of the 438-mile Acadian, 577-mile
Cypress and 27-mile Evangeline natural gas pipeline systems, which together have
over 1.0 Bcfd of capacity. These natural gas pipeline systems are wholly-owned
by Acadian with the exception of the Evangeline system in which Acadian holds an
approximate 49.5% interest. The system includes a leased natural gas storage
facility at Napoleonville, Louisiana. Completion of this transaction is subject
to certain conditions, including regulatory approvals. The purchase is expected
to be completed during the first quarter of 2001.
Stingray, West Cameron, Sailfish and Moray (collectively, the "El Paso
acquisition"). On January 29, 2001, the Company completed the purchase of 50% of
the membership interests of Stingray and West Cameron, together with some
offshore lateral pipelines for approximately $25.1 million in cash from
affiliates of El Paso Energy Partners L.P. ("EPE") and Coastal Corp. Shell
purchased the remaining 50% membership interests of both Stingray and West
Cameron for an equal amount of cash. In addition, the Company purchased from EPE
100% of the membership interests of Sailfish and Moray for approximately $88.1
million in cash.
Collectively, the Company acquired interests in five natural gas
gathering and transmission pipeline systems in the Gulf of Mexico totaling
approximately 737 miles of pipeline with an aggregate gross capacity of 2.85
Bcfd. These pipelines and their associated assets are strategically located to
12
serve continental shelf and deepwater developments in the central Gulf of
Mexico. As with the Acadian acquisition, the El Paso acquisition broadens the
Company's midstream business by providing additional services to customers, and
it benefits from increased natural gas production from deepwater Gulf of Mexico
development. Management believes that the assets acquired from EPE complement
and integrate well with those of the Acadian acquisition.
Stingray owns a 375-mile FERC-regulated two phase natural gas pipeline
system that transports natural gas and injected condensate from the High Island,
West Cameron, East Cameron, Vermillion and Garden Banks areas in the Gulf of
Mexico to onshore transmission systems at Holly Beach and Cameron Parish,
Louisiana. West Cameron is an unregulated dehydration facility located at and
connected to the onshore terminal of Stingray. Shell is the operator of the
Stingray and West Cameron facilities.
Sailfish owns a 25.67% interest in Manta Ray Offshore Gathering
Company, L.L.C. ("Manta Ray") and Nautilus Pipeline Company, L.L.C.
("Nautilus"). Moray owns a 33.92% interest in the Nemo Gathering Company, L.L.C.
("Nemo"). Manta Ray (which is jointly owned by Sailfish, Shell and Marathon Gas
Transmission Company Inc.) owns 237 miles of unregulated natural gas
transmission lines primarily located on the outer continental shelf offshore
Louisiana. Nautilus (which is owned by Sailfish, Shell and Marathon Gas
Transmission Company Inc.) owns 101 miles of FERC-regulated natural gas
pipelines and related facilities extending from points offshore Louisiana to
interconnecting pipelines near the Garden City and Neptune gas processing
facilities. Nemo (which is jointly owned by Moray and Shell) is a development
stage enterprise that is constructing and will operate an offshore Louisiana
natural gas gathering pipeline and related facilities that will connect certain
Shell offshore platform assets to Manta Ray. Management believes that these
assets have a significant upside potential, since Shell and Marathon have
dedicated production from over 1,000 square miles of offshore natural gas leases
to these systems and only a small portion of this total has been developed to
date. Shell is the operator of the Manta Ray, Nautilus and Nemo systems.
Equistar storage facility. In addition to the natural gas pipeline
acquisitions, the Company announced on February 1, 2001 that it had acquired a
NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million.
The salt dome storage cavern, which is located near the Company's Mont Belvieu,
Texas complex, has a capacity of one million barrels. The purchase also includes
adjacent acreage which would support the development of additional storage
capacity.
13
Processing
The Company's Processing segment consists of its natural gas processing
business and related merchant activities. At the core of the Company's natural
gas processing business are twelve natural gas processing plants located on the
Louisiana and Mississippi Gulf Coast with gross natural gas processing capacity
of 11.61 Bcfd or net capacity of 3.21 Bcfd based on the Company's current
ownership interest. The NGL production from these facilities, along with that
from the Mont Belvieu isomerization facilities, supports the merchant activities
included in this operating segment.
The following table lists the natural gas processing facilities in
which the Company has an ownership interest:
Gross Gas Net Gas Company
Gas Processing Processing Ownership
Processing Capacity Capacity Interest in
Facility Location (Bcf/day) (Bcf/day) Facility Operator
- -----------------------------------------------------------------------------------------------------------------------
Yscloskey St. Bernard Parish, Louisiana 1.85 0.60 32.6% Dynegy
Calumet St. Mary Parish, Louisiana 1.60 0.57 35.4% EPOLP
North Terrebonne Terrebonne Parish, Louisiana 1.30 0.43 33.4% EPOLP
Venice Plaquemines Parish, Louisiana 1.30 0.17 13.1% Dynegy
Toca St. Bernard Parish, Louisiana 1.10 0.61 55.5% EPOLP
Pascagoula Pascagoula, Mississippi 1.00 0.40 40.0% BP
Sea Robin Vermillion Parish, Louisiana 0.95 0.06 6.4% Texaco
Blue Water Acadia Parish, Louisiana 0.95 0.07 7.4% ExxonMobil
Iowa Jefferson Davis Parish, Louisiana 0.50 0.01 2.0% Texas Eastern
Patterson II St. Mary Parish, Louisiana 0.60 0.01 2.0% Duke Energy
Neptune St. Mary Parish, Louisiana 0.30 0.20 66.0% EPOLP
Burns Point St. Mary Parish, Louisiana 0.16 0.08 50.0% Marathon
-----------------------------
Total Gas Processing Capacity 11.61 3.21
=============================
The Company's natural gas processing facilities are primarily straddle
plants which are situated on mainline natural gas pipelines which bring
unprocessed Gulf of Mexico natural gas production onshore. 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, mixed NGLs are typically transported to a centralized facility
for fractionation 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 Venice gas plant is part of a larger processing complex owned by
VESCO. Along with the Venice gas plant, VESCO owns a NGL fractionation facility
(previously mentioned under the Fractionation segment), storage assets and gas
gathering pipelines located in Louisiana. The other owners of VESCO are Chevron,
Koch, Venice Gathering and Dynegy. The Company owns 13.1% of VESCO.
The natural gas 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 and is
generally measured in terms of equity NGL production. Production of NGLs is
generally a function of throughput (i.e., higher natural gas throughput rates
translate into higher equity NGL production). Equity NGL production can be
defined as the volume of NGLs extracted by the gas processing plants to which
the Company takes title under the terms of its processing agreements or as
result of plant ownership interests. Equity NGL production can be negatively
affected by high fuel costs and/or low purity NGL product prices.
The Company's equity NGL production was 72 MBPD in 2000 compared with
67 MBPD in 1999. For comparison purposes only, Shell equity NGL production from
these facilities was 41 MBPD in 1998. The 1999 volume is for the period the
14
Company owned the assets after the TNGL acquisition. For the entire year of
1999, equity NGL production (for both Shell and the Company) from the facilities
was 57 MBPD. The increase in equity production from 1999 to 2000 is due to
growing levels of natural gas production available for processing, higher NGL
content natural gas and new processing facilities, such as the Company's Neptune
plant. 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 market prices for NGLs which justified higher
extraction rates.
Management believes that natural gas and associated NGL production from
the Gulf of Mexico 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 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 gas
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 (known
as "shrinkage") 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
the fuel and shrinkage and the operating costs of the natural gas plant. The gas
processing business does not generally exhibit a high degree of seasonality.
The most significant contract affecting this operating segment is the
20-year Shell Processing Agreement that grants the Company 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 (on a
keepwhole basis). 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.
Generally, the Shell Processing Agreement grants the Company the following
rights and obligations:
- 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 mixed NGL
stream 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 mixed NGL stream is extracted.
As noted previously, this segment also includes the results of the
Company's merchant activities. Generally, in its isobutane 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 mixed NGLs (such amount defined by contract) that it extracts
from the natural gas stream. The purity NGL products extracted from the mixed
NGL stream 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 Form 10-K, "Quantitative
and Qualitative Disclosures about Market Risk."
In its isobutane merchant business, the Company has entered into
contracts to sell isobutane. The Company can meet its sales obligations either
by:
o purchasing normal butane in the spot market or utilizing normal
butane inventory from equity gas plant production 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 equity gas plant production.
15
When the price differential between normal butane and isobutane is not
substantial enough to economically justify isomerization, the Company purchases
isobutane or uses its own inventory of isobutane for delivery to its sales
customers who pay market-based prices.
The Company utilizes a fleet of approximately 625 railcars in its
merchant activities, the majority of which are under short and long-term leases.
The railcars are used to deliver feedstocks to Company facilities and transport
NGL products throughout the United States. The Company also has rail
loading/unloading facilities at Mont Belvieu, Texas, Breaux Bridge, Louisiana
and Petal, Mississippi. These facilities service the Company's as well as
customers' rail shipments. The costs of maintaining the railcars and associated
assets are a cost of the NGL merchant business.
Octane Enhancement
The Company's Octane Enhancement segment consists of its 33.3% interest
in BEF, which owns and operates a facility that produces motor gasoline
additives to enhance octane. The BEF facility currently produces MTBE and is
located within the Company's Mont Belvieu, Texas complex. The gross capacity of
the MTBE facility is approximately 15 MBPD with a net capacity of 5 MBPD. For
the years 2000, 1999 and 1998, net production averaged 5 MBPD or near capacity.
The other owners of BEF are Sun and Mitchell. EPCO operates the facility under a
long-term contract.
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, ETBE and 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.
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 Pipeline System. As
mentioned previously in the Pipeline segment discussion, management anticipates
that BEF's MTBE production will be transported using this same pipeline system
beginning in April 2001.
BEF has a ten-year off-take agreement with Sun under which they are
required to purchase all of the plant's MTBE production through September 2004.
Through May 31, 2000, Sun was required to pay for the MTBE using the following
pricing structure:
- for the first 193,450,000 gallons of MTBE produced per contract
year, the higher of (i) a contractual floor price or (ii) a toll
or spot market-related price (as defined within the agreement);
and
- a spot market-related price for all volumes in excess of this
amount.
The floor price was a price sufficient to cover essentially all of BEF's
operating costs plus principal and interest payments on its bank term loan. In
general, Sun paid the floor price during the periods in which it was in effect.
16
Beginning June 1, 2000 through the remainder of the agreement, the pricing on
all MTBE delivered to Sun changed to a market-related negotiated price which
generally approximates Gulf Coast MTBE spot prices. The market-related
negotiated price is subject to fluctuations in commodity prices for MTBE. MTBE
spot prices are generally stronger during the April to September period of each
year which corresponds with the summer driving season.
Recent Regulatory Developments. The production of MTBE is driven by
oxygenated fuels programs enacted under the federal Clean Air Amendments of 1990
and other legislation. Any changes to these programs that enable localities to
elect to not participate in these programs, lessen the requirements for
oxygenates or favor the use of non-isobutane based oxygenated fuels would reduce
the demand for MTBE. On March 25, 1999, the Governor of California ordered the
phase-out of MTBE in California by the end of 2002 due to allegations by several
public advocacy and protest groups that MTBE contaminates water supplies, causes
health problems and has not been as beneficial in reducing air pollution as
originally contemplated. In addition, legislation to amend the federal Clean Air
Act has been introduced in the U.S. House of Representatives to 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
foster the elimination of MTBE in fuel. No assurance can be given as to whether
this or similar legislation ultimately will be adopted or whether the U.S.
Congress or the EPA might take steps to override the MTBE ban in California.
Alternative Uses of the BEF facility. In light of the regulatory
climate, the owners of BEF are formulating a contingency plan for use of the BEF
facility if MTBE were banned or significantly curtailed. The owners of BEF are
exploring a possible conversion of the BEF facility from MTBE production to
alkylate production. One conversion alternative is expected to result in similar
operating margin as that currently anticipated from the facility if it were to
remain in MTBE service. If this approach were taken, the cost to convert the
facility would range from $20 million to $25 million, with the Company's share
being $6.7 million to $8.3 million. A second conversion alternative would
increase both production capacity and overall margin and cost between $50
million and $90 million, with the Company's share being $16.7 million to $30
million. Management anticipates that if MTBE is banned alkylate demand will rise
as producers use it to replace MTBE as an octane enhancer. Greater alkylate
production would be expected to increase isobutane consumption nationwide and
result in improved isomerization margins for the Company.
Other
This operating segment is primarily comprised of fee-based marketing
services. The Company performs NGL marketing services for a small number of
clients for which it charges a commission. The clients served are primarily
located in the states of California, Illinois and Washington. The Company
utilizes the resources of its gas processing merchant business group to perform
these services. Commissions are based on either a percentage of the final sales
price negotiated on behalf of the client or a fixed-fee per gallon based on the
volume sold for the client. The Company handles approximately 30,000 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 various 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
17
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 fractionation services is based primarily
on the fractionation fee, the ability of a NGL fractionator to obtain and
distribute product is a function of the existence of the necessary pipeline
transportation and storage facilities. A NGL 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. In addition, the Company believes
its joint venture relationships enable it to contract for the long-term
utilization of a significant amount of its NGL fractionation facilities with
major producers and consumers of NGLs or NGL products.
The Company's Mont Belvieu NGL fractionation facility competes for
volumes of mixed NGLs with three other NGL fractionators at Mont Belvieu: Cedar
Bayou Fractionators, a joint venture between Dynegy and BP (205 MBPD capacity);
Gulf Coast Fractionators, a joint venture of Conoco, Mitchell and Dynegy (110
MBPD capacity); and Diamond-Koch, a joint venture between Ultramar Diamond, Koch
and Duke Energy (reported to be 160 MBPD capacity). ExxonMobil operates a NGL
fractionation facility (110 MBPD capacity) in Hull, Texas that is connected to
Mont Belvieu by pipeline and Phillips operates a NGL fractionation facility (100
MBPD 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 NGL
fractionators at Mont Belvieu.
The Company's NGL fractionation facilities also compete on a more
limited basis with two NGL fractionators in Conway, Kansas: Williams (107 MBPD
capacity) and Koch (200 MBPD capacity) and with a number of decentralized,
smaller NGL fractionation facilities in Louisiana, the most significant of which
are Promix at Napoleonville, in which the Company owns a one-third interest (145
MBPD capacity), Texaco/Williams at Paradis (45 MBPD capacity) and EPE at Eunice
and Riverside (62 MBPD 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 NGL 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 market price differential between normal butane and isobutane as
well as the fees charged for isomerization services, long-term contracts, the
availability of commercial 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 commercial
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 is in
direct competition with Diamond-Koch which also has polymer grade propylene
production facilities in Mont Belvieu, Texas. Both the Company and Diamond-Koch
facilities process refinery grade propylene produced by third party refineries.
The Company's ability to attract feedstock is enhanced by its distribution
system capabilities which include pipelines, a dock for unloading barges and a
tank truck and railcar unloading facility. The Company's facilities use an
integrated heat pump system, supplemented by electric drivers. This provides for
very efficient operating costs and flexibilities. The Company is able to attract
feedstock from a variety of suppliers by providing service to match the
suppliers logistic requirements. The Company has entered into long-term sale and
18
processing agreements with key customers and is able to be competitive in price
due to its lower operating costs and variable feedstock supply. The Company has
developed delivery systems to its key customers which meet or exceed those of
its competitors.
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,
intrastate pipeline companies, major interstate pipeline companies and their
non-regulated affiliates, and independent processors. Each of these companies
has 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 at the
tailgate of the Company's fractionation facilities. Overall competition is
impacted by supply and demand for both natural gas as a feedstock and finished
NGL products. In the Company's fee-based marketing services, the principal
methods of competition revolve around price and quality of service.
Employees
At December 31, 2000, EPCO employed 782 employees involved in the
management and operation of assets owned and operated by the Company none of
whom were members of a union. The Norco facilities are managed by the Company
with the assets operated under contract by union employees of Shell. Shell's
relationship with its union employees at Norco can be characterized as good and
the Company believes that this good relationship will continue.
Major Customers of the Company
The Company's revenues are derived from a wide customer base and no
single customer accounted for more than 10% of consolidated revenues in fiscal
2000. For a more complete discussion of significant customers in the last three
fiscal years, see Note 15 of the Notes to the Consolidated Financial Statements.
Regulation
Interstate Common Carrier Pipeline Regulation
The Company's Chunchula, Lou-Tex Propylene, Lou-Tex NGL 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").
Standards for Terms of Service and Rates. As interstate common
carriers, the Chunchula, Lou-Tex Propylene, Lou-Tex NGL 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
19
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 term 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 Chunchula
and Lake Charles/Bayport pipelines are covered by the grandfathered provisions
of the Energy Policy Act.
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 are 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
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.
20
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 significant 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 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
21
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 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, 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 more strict requirements on existing
facilities were issued in December, 2000. These regulations mandate 90%
reductions in oxides of nitrogen emissions from point sources such as the gas
turbines at the Company's Mont Belvieu processing facility. The technical
practicality and economic reasonableness of requiring existing gas turbines to
achieve such reductions, as well as the substantive basis for setting the 90%
reduction requirements, have been challenged under state law in litigation filed
in the District Court of Travis County, Texas, on January 19, 2001, by the
Company as part of a coalition of major Houston-Galveston area industries. In
addition to the Company, the plaintiffs in this case are the BCCA Appeal Group,
Equistar Chemicals, LP, Lyondell Chemical Company, Lyondell-CITGO Refining L.P.
and Reliant Energy, Incorporated; named as defendants are the Texas Natural
Resource Conservation Commission and its chairman, commissioners and executive
director. The suit seeks a ruling that these regulations are invalid and void
and asks for a temporary injunction to stay their effectiveness pending final
judgment in the case. If these regulations stand as issued, they would require
substantial redesign and modification of the Mont Belvieu facilities to achieve
the mandated reductions; however, the precise impact of these requirements on
the Company's operations cannot be determined until this litigation is resolved.
Regardless of the outcome of this litigation, the capital expenditures for
making the required modifications would be spread over the years leading up to
the compliance deadline, which could be as early as 2005.
Failure to comply with 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. The Company believes its operations, including its
processing facilities, pipelines and storage facilities, are in substantial
compliance with applicable air requirements.
22
Clean Air Act--Fuels. See discussion of Octane Enhancement - Recent
Regulatory Developments.
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 an impact 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 significant 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
23
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
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. See the discussion of litigation the Company has instituted
in connection with air pollution control regulations in the Houston-Galveston
area on page 22 of this Form 10-K. Other than this litigation, management is
aware of no significant litigation, pending or threatened, that may 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 Unitholders during the
fourth quarter of 2000.
24
PART II
Item 5. Market for Registrant's Common Equity and Related Unitholder Matters
The following table sets forth, for the periods indicated, the high and
low prices per Common Unit (as reported under the symbol "EPD" on the New York
Stock Exchange) and the amount of quarterly cash distributions paid per Common
and Subordinated Unit.
Cash Distributions
--------------------------------------------------------------------
Per
Price Range Per Common Subordinated Record Payment
High Low Unit Unit Date Date
-------------------------------------------------------------------------------------------------
1999 First Quarter $ 18.500 $ 14.938 $ 0.450 $ 0.450 Jan. 29, 1999 Feb. 11, 1999
- --------
Second Quarter $ 18.625 $ 15.063 $ 0.450 $ 0.070 Apr. 30, 1999 May 12, 1999
Third Quarter $ 20.688 $ 17.875 $ 0.450 $ 0.370 Jul. 30, 1999 Aug. 11, 1999
Fourth Quarter $ 20.375 $ 17.000 $ 0.450 $ 0.450 Oct. 29, 1999 Nov. 10, 1999
2000 First Quarter $ 20.875 $ 18.250 $ 0.500 $ 0.500 Jan. 31, 2000 Feb. 10, 2000
- --------
Second Quarter $ 22.750 $ 19.500 $ 0.500 $ 0.500 Apr. 28, 2000 May 10, 2000
Third Quarter $ 28.938 $ 22.125 $ 0.525 $ 0.525 Jul. 31, 2000 Aug. 10, 2000
Fourth Quarter $ 31.875 $ 23.500 $ 0.525 $ 0.525 Oct. 31, 2000 Nov. 10, 2000
2001 First Quarter $ 36.800 $ 26.500 $ 0.550 $ 0.550 Jan. 31, 2001 Feb. 9, 2001
- --------(through March 19, 2001)
On January 17, 2000, the Company declared an increase in its quarterly
cash distribution to $0.50 per Unit. This amount was subsequently raised to
$0.525 per Unit on July 17, 2000 and $.550 per Unit on December 7, 2000. The
increases are 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 cash
distributions is not guaranteed, the Company currently expects that it will
continue to pay comparable cash distributions in the future.
As of March 12, 2001, there were approximately 228 Unitholders of
record which includes an estimated 8,500 beneficial owners of the Company's
Common Units.
25
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, 2000 and the selected balance sheet data
as of December 31, 2000 and 1999 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. Certain
reclassifications have been made to prior year's financial statements to conform
to the current year presentation.
For the Year Ended December 31,
------------------------------------------------------------------------
2000 1999 1998 1997 1996
------------------------------------------------------------------------
Income Statement Data:
Revenues from consolidated operations (1) $ 3,049,020 $ 1,332,979 $ 738,902 $ 1,020,281 $ 999,506
Equity in income of unconsolidated affiliates 24,119 13,477 15,671 15,682 15,756
------------------------------------------------------------------------
Total 3,073,139 1,346,456 754,573 1,035,963 1,015,262
Operating costs and expenses (1) 2,801,060 1,201,605 685,884 938,392 907,524
------------------------------------------------------------------------
Operating margin 272,079 144,851 68,689 97,571 107,738
Selling, general and administrative expenses (2) 28,345 12,500 18,216 21,891 23,070
------------------------------------------------------------------------
Operating income 243,734 132,351 50,473 75,680 84,668
Interest expense (33,329) (16,439) (15,057) (25,717) (26,310)
Interest income 3,748 886 772 1,934 2,705
Interest income from unconsolidated affiliates 1,787 1,667 809
Dividend income from unconsolidated affiliates 7,091 3,435
Other income (expense), net (272) (379) 358 793 364
------------------------------------------------------------------------
Income before extraordinary chargeand
minority interest 222,759 121,521 37,355 52,690 61,427
Extraordinary charge on early
extinguishment of debt (27,176)
------------------------------------------------------------------------
Income before minority interest 222,759 121,521 10,179 52,690 61,427
Minority interest (2,253) (1,226) (102) (527) (614)
------------------------------------------------------------------------
Net income $ 220,506 $ 120,295 $ 10,077 $ 52,163 $ 60,813
========================================================================
Basic net income per Unit $ 3.25 $ 1.79 $ 0.17 $ 0.94 $ 1.10
(3)
Number of Units for basic EPU (in 000s) 67,107.5 66,710.4 60,124.4 54,962.8 54,962.8
Diluted net income per Unit (3) $ 2.64 $ 1.64 $ 0.17 $ 0.94 $ 1.10
Number of Units for diluted EPU (in 000s) 82,443.6 72,788.5 60,124.4 54,962.8 54,962.8
Dividends declared per Common Unit $ 2.10 $ 1.85 $ 0.77 N/A N/A
Balance Sheet Data (at period end):
Total assets $ 1,951,521 $ 1,494,952 $ 741,037 $ 697,713 $ 711,151
Long-term debt 404,000 295,000 90,000 230,237 255,617
Combined equity/Partners' equity 935,959 789,465 562,536 311,885 266,021
Other Financial Data:
Cash flows from operating activities $ 360,688 $ 177,953 $ (9,442) $ 65,254 $ 98,585
Cash flows from investing activities (268,798) (271,229) (59,182) (38,261) (64,879)
Cash flows from financing activities (36,711) 74,403 59,503 (26,731) (24,930)
EBITDA (4) 267,026 147,050 55,472 79,882 87,109
EBITDA of unconsolidated affiliates (5) 35,549 23,425 23,912 24,372 25,012
26
Notes to Selected Financial Data Table
(1) The increase in 2000 revenues and expenses is primarily due to the impact
of the TNGL and MBA acquisitions. The TNGL acquisition was effective August
1, 1999 with the MBA acquisition effective July 1, 1999.
(2) 1998 and 1999 expenses are lower than 1997 amounts due to the adoption of
the EPCO agreement. The increase in 2000 expenses over 1999 is primarily
due to the additional staff and resources deemed necessary to support the
Company's ongoing expansion activities resulting from acquisitions and
various capital expenditures.
(3) Basic net income per Unit is computed by dividing the limited partners' 99%
interest in Net income (after deducting for any incentive income
allocations to the General Partner) 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
(after deducting for any incentive income allocations to the General
Partner) 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 $29.6 million,
$14.9 million and $14.7 million in 2000, 1999 and 1998, 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 $27.2 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.
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 the
Company included elsewhere herein as well as the other portions of this report
on Form 10-K. In particular, the reader should review "Uncertainty of
Forward-Looking Statements and Information" found on page 2 of this report on
Form 10-K for information regarding forward-looking statements made in this
discussion and certain risks inherent in the Company's business. Other risks
involved in the Company's business are discussed under Item 7A "Quantitative and
Qualitative Disclosures about Market Risk" beginning on page 43 of this report.
Current Business Environment
During most of 2000, the U.S. NGL industry benefited from a steady
demand for NGLs, petroleum liquids and MTBE as a result of the strong U.S.
economy and firm international demand. Overall, the Company enjoyed outstanding
earnings in 2000 in all of its business segments despite the tighter processing
margins encountered late in the fourth quarter. The Company's solid performance
in 2000 is the result of an integrated NGL system that allows the Company to
extract margins through its access to multiple supplies and markets.
The near term enthusiasm of the U.S. NGL industry was somewhat dampened
at the end of last year as the cost of natural gas (which is the most
significant variable operating expense of most facilities) soared to all time
record levels in the fourth quarter of 2000 and first quarter of 2001. Natural
gas prices increased from an average of $2.49/MMBtu in the first quarter of 2000
to $5.22/MMBtu in the fourth quarter of 2000 (with December 2000 being the
highest of the year at $5.97/MMBtu). In January 2001, the price of natural gas
reached record levels of approximately $10/MMBtu (or $60 per barrel on a crude
oil equivalent). Generally, as the cost of natural gas increases, certain
facilities may become too expensive to operate and are consequently shutdown
temporarily. In the case of a natural gas processing plant, high natural gas
prices may result in the cost of fuel and shrinkage exceeding the value of the
NGLs extracted leading either to shutdown of the facility or to operate at
decreased extraction rates (i.e., to operate in "rejection mode").
Because the Company has an integrated NGL system, the Company's natural
gas processing plants continued to operate at high levels during the fourth
quarter of 2000 when many of its competitors were in rejection mode or shutdown.
In December 2000, the Company maintained an equity NGL production rate of 67
MBPD, or about 90% of the full NGL extraction rate. At the beginning of January
2001, with natural gas prices climbing to near $10/MMBtu, it finally became
uneconomic to run the Company's natural gas processing facilities at these high
extraction rates. As a result of minimal or no NGL extraction, natural gas
volumes downstream of the processing plants became higher in NGL content than
27
allowed by pipeline specifications. The natural gas pipeline operators responded
by issuing operational flow orders that threatened to shut-in some of the rich
natural gas from the deepwater developments unless the NGL content of these
natural gas streams was reduced to lower levels. In order to meet the
specifications of the natural gas pipeline operators, the Company and producers
negotiated interim reductions in fuel and shrinkage costs to levels that were
significantly below the prevailing cost of natural gas. With these interim
provisions in place, the Company's gas processing plants increased NGL
extraction rates with the objective to lower the NGL content of the natural gas
to a level satisfactory to the pipeline operators.
As natural gas prices increased to unprecedented levels in January
2001, refiners switched to burning propane as fuel and sold their natural gas
into the spot markets. In late December 2000 and January 2001, petrochemical
demand softened as petrochemical companies elected to deplete their NGL raw
material inventories and their finished product inventories of ethylene and
propylene and optimized their ethylene production from cracking naptha.
Management believes that the petrochemical companies can take this position for
only a short time and these companies will return to the NGL marketplace to
purchase ethane later in the first quarter of 2001 due to their needs for
greater ethylene production.
As a result of reduced supplies of NGLs from gas processing facilities
and refineries in December 2000 and extending into the first quarter of 2001,
U.S. Gulf Coast fractionation and pipeline volumes (including those at the
Company's facilities) declined. This situation, however, also created regional
shortages of NGLs, especially propane, which resulted in large regional pricing
differences. This provided the Company with opportunities to serve these
supply-short markets through the sale of inventory by its Processing merchant
business.
Management believes that the gas processing business will have a
challenging first quarter of 2001. The current processing environment does,
however, present opportunities to take advantage of the Company's integrated NGL
system. Looking back over the last year, the Company's NGL production has
significantly increased over 1999 levels as a result of steadily growing levels
of natural gas production available for processing, higher NGL content natural
gas and new processing facilities such as the Company's Neptune plant. Neptune
commenced operations in February 2000 and added approximately 7 MBPD of equity
NGL production for the year. For 2000, equity NGL production averaged 72 MBPD
versus 67 MBPD in 1999. Management believes that the Company's equity NGL
production volumes will continue to increase in 2001 as a result of gas
production from several new Gulf of Mexico gas fields scheduled to come on-line
in which the Company holds gas processing rights, the most significant of which
is Shell's deepwater Brutus development (with an expected equity NGL production
of 10 MBPD by the end of 2001). Management's belief is based in part on the
premise that natural gas prices will continue to moderate over the coming months
(see First Quarter 2001 natural gas prices in the table on page 30); however, if
fuel costs return to the record levels seen in January 2001, equity NGL
production rates may actually decline in 2001.
The highly competitive environment in which the Company's Mont Belvieu
NGL fractionators operate has continued to suppress NGL fractionation fees at
these facilities. The Company has and is continuing to aggressively acquire new
and reacquire previous NGL fractionation customers, along with offering
competitively-priced bundled service packages involving transportation,
fractionation and other services. These service packages allow the Company to
take advantage of its presence throughout the entire Gulf Coast NGL value chain.
As a result of these efforts, gross processing volumes at the Mont Belvieu NGL
fractionation facility increased to 170 MBPD in 2000 from 156 MBPD in 1999. With
the completion of the Lou-Tex NGL Pipeline in the fourth quarter of 2000, the
Company is positioned to fully utilize its Mont Belvieu NGL fractionation
facilities to process NGL's from Louisiana starting in the first quarter of
2001. In January 2001, the Company announced that it had entered into a
long-term agreement to exchange NGLs produced at the Sea Robin natural gas
processing plant in Vermilion Parish, Louisiana, for finished NGL products at
Mont Belvieu using the Lou-Tex NGL Pipeline. Initial gross processing volumes
are expected to be 16 MBPD and are forecast to increase to over 20 MBPD by the
end of 2001.
The demand for commercial isomerization services depends upon the
industry's requirements for (i) isobutane in excess of naturally occurring
isobutane produced from NGL fractionation and refinery operations and (ii) high
purity isobutane. The market for the Company's services was firm throughout most
of 2000 due to the continued need for isobutane for alkylation and the
production of propylene oxide and MTBE. As part of its commercial isomerization
business, the Company produces the high purity isobutane used in the production
of MTBE at the BEF facility. Isobutane demand from the BEF facility was
28
temporarily curtailed due to a maintenance outage at the MTBE plant that began
in early December 2000. With the startup of the BEF plant in mid-February 2001,
management anticipates that the demand for its commercial isomerization services
will return to normal levels.
During the third quarter of 2000, the rapid price increase for
propylene experienced during the first half of 2000 began to reverse. During the
first half, propylene prices were driven by the dramatic increases in crude oil
and NGL prices. These factors contributed to similar increases in the cost for
ethylene and propylene from steam crackers and for refinery grade propylene
produced by refineries. In addition, the price spike in motor gasoline, natural
gas and propane created a very competitive market for refinery grade propylene
which is used in the production of alkylate (which is blended into motor
gasoline), substituted for natural gas as refinery fuel and blended into propane
streams for the fuels market. With the perceived stabilization and softening in
crude oil and natural gas prices, propylene buyers have been successful in
achieving price reductions by reducing purchases and consuming inventory.
Contract prices for polymer grade propylene increased from approximately 19.5
cents per pound at the beginning of 2000 to 27.5 cents per pound by the end of
June. By the end of December, the contract price had slipped to 23.5 cents per
pound. Management anticipates that prices will continue to soften in early 2001
with the price leveling out to that seen at the beginning of 2000. The Company
is exposed to these price decreases only to the extent that it sells product
pursuant to long-term agreements having market-based pricing or transactions on
the spot market (see page 8 for a discussion of propylene merchant business
contracts).
During 2000, the favorable domestic economy supported strong demand for
the Company's pipeline transportation services as NGL feedstocks and products
were consumed at record levels throughout the Gulf Coast region. The Company's
pipeline volumes increased significantly to 367 MBPD in 2000 from 264 MBPD in
1999 primarily due to volumes attributable to the assets acquired in the TNGL
acquisition, the purchase of the Lou-Tex Propylene Pipeline in March 2000 and
the completion of the Lou-Tex NGL Pipeline in November 2000. As noted above,
pipeline volumes weakened as NGL production from gas processing facilities
decreased in late 2000 and January 2001 in reaction to the high natural gas
prices. This trend began to reverse itself in February 2001 as natural gas
prices declined and processing volumes at the Company's gas processing
facilities increased.
The Company anticipates using the Lou-Tex NGL Pipeline to provide
transportation services for NGL products and mixed propane/propylene streams
between the Louisiana and Texas markets in addition to transporting NGL
production from Louisiana gas processing facilities to Mont Belvieu for
fractionation. Management believes that the Company's pipeline system and
storage assets in the Louisiana to Mont Belvieu, Texas corridor and its
import/export terminal on the Houston Ship Channel provide the Company with the
infrastructure for continued success in the NGL marketplace.
During the second quarter of 2000, BEF's MTBE operations (classified
under the "Octane Enhancement" business segment) benefited from higher crude oil
prices as well as a tight international MTBE supply environment. Due to
contractual arrangements, BEF began selling its MTBE at market-related prices in
April 2000 at a time when MTBE market prices were increasing significantly due
to their indirect link to crude oil prices (which were on the increase), MTBE
supply imbalances between Europe and the United States (due to the temporary
diversion of Middle East MTBE production to Europe) and domestic gasoline
refining demand in anticipation of the normal summer driving season. The
combination of these external factors resulted in the market price for MTBE
increasing to near record levels in the second quarter of 2000 peaking at an
average $1.58 per gallon in June. During the third quarter, MTBE market prices
deflated rapidly as imports returned to the domestic market and as gasoline
refiners trimmed oxygenate usage (due to the end of the summer driving season)
and depleted MTBE inventories in anticipation of falling crude oil prices. By
October 2000, MTBE prices had hit a low of $0.98 per gallon.
As MTBE prices weakened during the latter half of 2000, feedstock costs
began to increase (primarily due to the rise in natural gas prices mentioned
previously) resulting in negative operating margins. In order to reduce its
exposure to negative margins, BEF management elected to reschedule routine
annual maintenance activities that had been originally planned for the spring of
2001 to be performed during December 2000 and January 2001. The facility
restarted operations in mid-February 2001 with the return of positive operating
margins. Management anticipates that MTBE prices will strengthen in the next few
months as refiners begin purchasing MTBE in preparation of gasoline blending
requirements for the upcoming summer driving season.
29
The following table illustrates selected average quarterly prices for
natural gas, crude oil, selected NGL products and polymer grade propylene since
the first quarter of 1999:
Polymer
Natural Normal Grade
Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene,
$/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound
-----------------------------------------------------------------------------------------
(a) (b) (a) (a) (a) (a) (a)
Fiscal 1999:
First quarter $1.70 $13.05 $0.20 $0.24 $0.29 $0.31 $0.12
Second quarter $2.12 $17.66 $0.27 $0.31 $0.37 $0.38 $0.13
Third quarter $2.56 $21.74 $0.34 $0.42 $0.49 $0.49 $0.16
Fourth quarter $2.52 $24.54 $0.30 $0.41 $0.52 $0.52 $0.19
Fiscal 2000:
First quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21
Second quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26
Third quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26
Fourth quarter $5.22 $31.98 $0.49 $0.67 $0.75 $0.73 $0.24
Fiscal 2001:
First quarter (c) $8.02 $29.66 $0.44 $0.57 $0.67 $0.71 $0.23
- -------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL and polymer grade propylene prices represent an
average of index prices
(b) Crude Oil price is representative of West Texas Intermediate
(c) Natural gas prices averaged $9.87 per MMBtu during January and
moderated to $6.17 per MMBtu during February. The first quarter 2001
prices reflect January and February only.
Results of Operation of the Company
The Company has five reportable operating segments: Fractionation,
Pipeline, Processing, Octane Enhancement and Other. Fractionation includes NGL
fractionation, butane isomerization (converting normal butane into high purity
isobutane) and polymer grade propylene fractionation 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 33.3% 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" or "margin"). Gross
operating margin reported for each segment represents operating income before
depreciation and amortization, lease expense obligations retained by EPCO, gains
and losses on the sale of assets and selling, 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.
30
The Company's gross operating margin by segment (in thousands of
dollars) along with a reconciliation to consolidated operating income over the
past three years were as follows:
For the Year Ended December 31,
-------------------------------------------------------
2000 1999 1998
-------------------------------------------------------
Gross Operating Margin by segment:
Fractionation $ 129,376 $ 110,424 $ 66,627
Pipeline 56,099 31,195 27,334
Processing 122,240 28,485 (652)
Octane enhancement 10,407 8,183 9,801
Other 2,493 908 (3,483)
-------------------------------------------------------
Gross Operating Margin total 320,615 179,195 99,627
Depreciation and amortization 35,621 23,664 18,579
Retained lease expense, net 10,645 10,557 12,635
Loss (gain) on sale of assets 2,270 123 (276)
Selling, general and administrative expenses 28,345 12,500 18,216
-------------------------------------------------------
Consolidated operating income $ 243,734 $ 132,351 $ 50,473
=======================================================
Certain 1999 amounts have been reclassified to conform with the 2000
presentation.
The Company's significant plant production and other volumetric data
(in thousands of barrels per day on a net basis) for the last three years were
as follows:
For the Year Ended December 31,
-------------------------------------------------------
2000 1999 1998
-------------------------------------------------------
Plant production data:
NGL Production 72 67 n/a
NGL Fractionation 213 184 73
Isomerization 74 74 67
Propylene Fractionation 33 28 26
MTBE 5 5 5
Major Pipelines 367 264 200
In order to more accurately compare operating rates between the 2000
and 1999 periods, the 1999 volumes associated with the assets acquired from TNGL
have been adjusted to reflect the period in which the Company owned them.
Recent Acquisitions
1999 Acquisitions. The Company completed two acquisitions during the
third quarter of 1999. Effective August 1, 1999, the Company acquired TNGL from
Shell, in exchange for 14.5 million non-distribution bearing, convertible
special partnership Units of the Company and $166 million in cash. The Company
also agreed to issue up to 6.0 million additional non-distribution bearing
special partnership Units to Shell in the future if the volumes of natural gas
that the Company processes for Shell reach agreed upon levels in 2000 and 2001.
The first 3.0 million of these additional special partnership Units were issued
on August 1, 2000.
The TNGL businesses acquired include natural gas processing and NGL
fractionation, transportation and storage in Louisiana and Mississippi and its
NGL supply and merchant business. TNGL has varying interests in eleven natural
gas processing plants, four NGL fractionation facilities, four NGL storage
facilities, approximately 1,500 miles of pipelines and is party to the Shell
Processing Agreement, a 20 year natural gas processing agreement.
The Company accounted for this acquisition using the purchase method.
The purchase price allocation for the 20-year natural gas processing agreement
(classified as an Intangible Asset on the balance sheet) was a net $84.6 million
31
and $52.9 million at December 31, 2000 and 1999, respectively. During 2000, the
asset's recorded value was increased to reflect the 3.0 million additional
special partnership Units issued to Shell on August 1, 2000, purchase accounting
adjustments and related amortization.
Effective July 1, 1999, the Company acquired an additional 25% interest
in the Mont Belvieu NGL fractionation facility from Kinder Morgan for a purchase
price of $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 $0.9
million in cash. This acquisition (referred to as the "MBA acquisition")
increased the Company's effective 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
income from unconsolidated affiliates.
The results of operations for the year ended December 31, 1999 include
five month's impact of the TNGL businesses acquired from Shell and six month's
impact of the additional ownership interest in the Mont Belvieu NGL
fractionation facility acquired from Kinder Morgan and EPCO. See Note 2 to the
Consolidated Financial Statements for selected pro forma financial data
reflecting these transactions as if they had occurred on January 1, 1999 and
1998.
2001 Acquisitions. The Company has recently announced and/or completed
the acquisition of three Louisiana-based natural gas pipeline systems:
- Acadian Gas, LLC ("Acadian");
- Stingray Pipeline Company, LLC ("Stingray") and West Cameron
Dehydration, LLC ("West Cameron"); and
- Sailfish Pipeline Company, LLC ("Sailfish") and Moray Pipeline
Company, LLC ("Moray").
The acquisition of these natural gas pipeline systems represents a strategic
investment for the Company and allows for entry into the natural gas gathering,
transportation, marketing and storage business. Management believes that these
assets have attractive growth attributes given the expected long-term increase
in natural gas demand for industrial and power generation uses. In addition,
these assets extend the Company's midstream energy service relationship with
long-term NGL customers (producers, petrochemical suppliers and refineries) and
offer additional fee-based cash flows and opportunities for enhanced services to
customers.
Acadian. On September 25, 2000, the Company announced that it had
executed a definitive agreement to purchase Acadian from Coral Energy, an
affiliate of Shell, for $226 million in cash, inclusive of working capital. The
acquisition of Acadian integrates its natural gas pipeline systems in South
Louisiana with the Company's Gulf Coast natural gas processing and NGL
fractionation, pipeline and storage system. The Acadian acquisition gives the
Company an extensive intrastate natural gas pipeline system with access to both
supply and markets; positions the Company to compete for incremental natural gas
supplies from new discoveries onshore, the offshore Louisiana continental shelf
and Gulf of Mexico deepwater developments; enables the Company to take advantage
of growing industrial and petrochemical demand (including new gas-fired power
generation projects) along with additional natural gas processing opportunities.
Acadian's assets are comprised of the 438-mile Acadian, 577-mile
Cypress and 27-mile Evangeline natural gas pipeline systems, which together have
over one billion cubic feet ("Bcf") per day of capacity. These natural gas
pipeline systems are wholly-owned by Acadian with the exception of the
Evangeline system in which Acadian holds an approximate 49.5% economic interest.
The system includes a leased natural gas storage facility at Napoleonville,
Louisiana. Completion of this transaction is subject to certain conditions,
including regulatory approvals. The purchase is expected to be completed during
the first quarter of 2001.
Stingray, West Cameron, Sailfish and Moray (collectively, the "El Paso
acquisition"). On January 29, 2001, the Company announced that it had completed
the purchase of 50% of the membership interests of Stingray and West Cameron,
together with some offshore lateral pipelines for approximately $25.1 million in
cash from affiliates of El Paso Energy Partners L.P. ("EPE") and Coastal Corp.
Shell purchased the remaining 50% membership interests of both Stingray and West
Cameron for an equal amount of cash. In addition, the Company purchased from EPE
100% of the membership interests of Sailfish and Moray for approximately $88.1
million in cash.
32
Collectively, the Company acquired interests in five natural gas
gathering and transmission pipeline systems in the Gulf of Mexico totaling
approximately 737 miles of pipeline with an aggregate gross capacity of 2.85
Bcfd. These pipelines and their associated assets are strategically located to
serve continental shelf and deepwater developments in the central Gulf of
Mexico. As with the Acadian acquisition, the El Paso acquisition broadens the
Company's midstream business by providing additional services to customers, and
it benefits from increased natural gas production from deepwater Gulf of Mexico
development. Management believes that the assets acquired from EPE complement
and integrate well with those of the Acadian acquisition.
Stingray owns a 375-mile FERC-regulated two phase natural gas pipeline
system that transports natural gas and injected condensate from the High Island,
West Cameron, East Cameron, Vermillion and Garden Banks areas in the Gulf of
Mexico to onshore transmission systems at Holly Beach and Cameron Parish,
Louisiana. West Cameron is an unregulated dehydration facility located at and
connected to the onshore terminal of Stingray. Shell is the operator of the
Stingray and West Cameron facilities.
Sailfish owns a 25.67% interest in Manta Ray Offshore Gathering
Company, L.L.C. ("Manta Ray") and Nautilus Pipeline Company, L.L.C.
("Nautilus"). Moray owns a 33.92% interest in the Nemo Gathering Company, L.L.C.
("Nemo"). Manta Ray (which is jointly owned by Sailfish, Shell and Marathon Gas
Transmission Company Inc.) owns 237 miles of unregulated natural gas
transmission lines primarily located on the outer continental shelf offshore
Louisiana. Nautilus (which is owned by Sailfish, Shell and Marathon Gas
Transmission Company Inc.) owns 101 miles of FERC-regulated natural gas
pipelines and related facilities extending from points offshore Louisiana to
interconnecting pipelines near the Garden City and Neptune gas processing
facilities. Nemo (which is jointly owned by Moray and Shell) is a development
stage enterprise that is constructing and will operate an offshore Louisiana
natural gas gathering pipeline and related facilities that will connect certain
Shell offshore platform assets to Manta Ray. Management believes that these
assets have a significant upside potential, since Shell and Marathon have
dedicated production from over 1,000 square miles of offshore natural gas leases
to these systems and only a small portion of this total has been developed to
date. Shell is the operator of the Manta Ray, Nautilus and Nemo systems.
Equistar storage facility. In addition to the natural gas pipeline
acquisitions, the Company announced on February 1, 2001 that it had acquired a
NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million.
The salt dome storage cavern, which is located near the Company's Mont Belvieu,
Texas complex, has a capacity of one million barrels. The purchase also includes
adjacent acreage which would support the development of additional storage
capacity.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Revenues, Costs and Expenses and Operating Income. The Company's
revenues increased 128% to $3,073.1 million in 2000 compared to $1,346.5 million
in 1999. The Company's operating costs and expenses increased by 133% to
$2,801.1 million in 2000 versus $1,201.6 million in 1999. Operating income
increased 84% to $243.7 million in 2000 from $132.3 million in 1999. The
principal factors behind the increase in operating income were (a) the
improvement in NGL product prices in 2000 versus 1999 and (b) the additional
margins associated with the businesses acquired in the TNGL acquisition. The
1999 period includes five months of margins associated with the TNGL operations
whereas the 2000 period includes twelve months.
Fractionation. The Company's gross operating margin for the
Fractionation segment increased to $129.4 million in 2000 from $110.4 million in
1999. During 2000, NGL fractionation margin increased $29.7 million over 1999 as
a result of additional margins from the four NGL fractionators acquired from
Shell in the TNGL acquisition (Promix, Tebone, Venice and Norco NGL
fractionators). As noted previously, the 1999 period includes only five months
of margin from these fractionators whereas the 2000 period includes twelve
months. In addition, equity income from BRF reflects twelve months of operations
in 2000 versus six months in 1999. BRF commenced operations in July 1999. Net
NGL fractionation volumes increased from 184 MBPD in 1999 to 213 MBPD in 2000
primarily due to the Company's acquisition of new and previous customers at its
Mont Belvieu NGL fractionator in 2000 and the increased ownership of the Mont
Belvieu NGL fractionator as a result of the MBA acquisition. For 2000, gross
operating margin from the isomerization business decreased $7.8 million compared
to 1999 primarily due to higher fuel and other operating costs and charges
related to the refurbishment of an isomerization unit. Isomerization volumes
were 74 MBPD in both 1999 and 2000 due to strong demand for the Company's
33
services. Gross operating margin from propylene fractionation decreased $1.4
million for 2000 compared to 1999 primarily due to higher energy costs. Net
volumes at these facilities improved to 33 MBPD in 2000 versus 28 MBPD in 1999
due to the startup of the BRPC propylene concentrator in July 2000.
Pipeline. The Company's gross operating margin for the Pipeline segment
was $56.1 million in 2000 compared to $31.2 million in 1999. Overall volumes
increased to 367 MBPD in 2000 from 264 MBPD in 1999. Generally, the $24.9
million increase in margin is attributable to the additional volumes and margins
contributed by the TNGL pipeline and storage assets, higher margins from the
Houston Ship Channel Distribution System and EPIK due to an increase in export
volumes, the margins from the Lou-Tex Propylene Pipeline that was purchased in
March 2000 and margins from the Lou-Tex NGL Pipeline which commenced operations
in late November 2000.
The growth in export volumes is attributable to the installation of
EPIK's new chiller unit that began operations in the fourth quarter of 1999. On
February 25, 2000, the purchase of the Lou-Tex Propylene Pipeline and related
assets from Concha Chemical Pipeline Company, an affiliate of Shell, was
completed at a cost of approximately $100 million. The effective date of the
transaction was March 1, 2000. The Lou-Tex Propylene Pipeline is a 263-mile, 10"
pipeline that transports chemical grade propylene from Sorrento, Louisiana to
Mont Belvieu, Texas. Also acquired in this transaction was a 27.5-mile 6" ethane
pipeline between Sorrento and Norco, Louisiana and a 0.5 million barrel storage
cavern at Sorrento, Louisiana.
The Lou-Tex NGL Pipeline System consists of a recently completed
206-mile NGL pipeline used (i) to provide transportation services for NGL
products and refinery grade propylene between the Louisiana and Texas markets
and (ii) to transport mixed NGLs from the Company's Louisiana gas processing
facilities to the Mont Belvieu NGL fractionation facility. Construction of this
system was completed during the fourth quarter of 2000 at a cost of
approximately $87.9 million.
Processing. The Company's gross operating margin for Processing was
$122.2 million in 2000 compared to $28.5 million in 1999. Due to the TNGL
acquisition, the 1999 margin includes only five months of gas processing
operations whereas the 2000 period includes twelve months. This segment
benefited from a stronger NGL pricing environment in 2000 versus 1999 and a rise
in equity NGL production from 67 MBPD in 1999 to 72 MBPD in 2000.
Octane Enhancement. The Company's gross operating margin for Octane
Enhancement increased to $10.4 million in 2000 from $8.2 million in 1999. This
segment consists entirely of the Company's equity earnings from its 33.3%
investment in BEF, a joint venture facility that currently produces MTBE. The
1999 results include the impact of the Company's $1.5 million pro rata share of
a non-cash write-off of BEF's unamortized balance of deferred start-up costs.
The 2000 results reflect the impact of higher than normal MTBE market prices
during the second quarter and early third quarter and lower debt service costs.
BEF made its final note payment in May 2000 and now owns the MTBE facility
debt-free.
The MTBE facility was temporarily shutdown in early December 2000 for
maintenance. The facility restarted operations in mid-February 2001. MTBE
production, on a net basis, was 5 MBPD in both 1999 and 2000.
Other. The Company's gross operating margin for the Other segment was
$2.5 million in 2000 compared to $0.9 million in 1999. The increase is primarily
due to fee-based marketing services added in the fourth quarter of 1999. Apart
from this portion of the segment's operations, the gross margin contribution of
the other aspects of this segment were insignificant in both 2000 and 1999.
Selling, general and administrative expenses ("SG&A"). SG&A expenses
increased to $28.3 million in 2000 from $12.5 million during 1999. The higher
costs result from an increase in the administrative services fee charged by EPCO
to an average $1.2 million per month in 2000 versus the approximately $1.0
million per month charged in 1999. The remainder of the increase is attributable
to the additional staff and resources deemed necessary to support the Company's
ongoing expansion activities resulting from acquisitions and other business
development.
Interest expense. The Company's interest expense increased to $33.3
million in 2000 from $16.4 million in 1999. The increase is primarily
attributable to a rise in average debt levels to $408 million in 2000 from $213
34
million in 1999. Debt levels have increased over the last year primarily due to
capital expenditures for assets such as the Lou-Tex Propylene Pipeline and
Lou-Tex NGL Pipeline.
Loss on sale of assets. During the second quarter of 2000, the Company
recognized a one-time $2.3 million non-cash charge on the sale of its Longview
Terminal to Huntsman Corporation. The Longview Terminal was part of the
Pipelines segment and was used to unload polymer grade propylene from NGL tank
trucks.
Dividend income from unconsolidated affiliates. The Company received
$7.1 million in cash distributions from its cost method investment in VESCO
during 2000. During 1999, the Company recorded dividend income from Dixie and
VESCO in the amounts of $0.8 million and $2.6 million, respectively. In October
2000, the Company purchased an additional interest in Dixie resulting in a
retroactive change in accounting for this investment from the cost method to the
equity method (see Note 4 of the Notes to the Consolidated Financial Statements
for a description of the Dixie investment).
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Revenues, Costs and Expenses and Operating Income. The Company's
revenues increased 78% to $1,346.5 million in 1999 compared to $754.6 million in
1998. The Company's operating costs and expenses increased by 75% to $1,201.6
million in 1999 versus $685.9 million in 1998. Operating income increased 162%
to $132.3 million in 1999 from $50.5 million in 1998. The principal factor
behind the $81.8 increase in operating income was the TNGL acquisition. Earnings
attributable to these assets from the date of acquisition, August 1, 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 compared to
1998 levels.
Fractionation. The Company's gross operating margin for the
Fractionation segment increased to $110.4 million in 1999 from $66.7 million in
1998. NGL fractionation margin increased $13.7 million over 1998 as a result of
additional margins from the four TNGL fractionators. As noted previously, the
1999 period includes five months of margin from these NGL fractionators whereas
the 1998 period includes none. In addition, the 1999 period reflects six months
of increased ownership of the Mont Belvieu NGL fractionation facility resulting
from the MBA acquisition and six months of equity income from BRF which
commenced operations in July 1999. Net NGL fractionation volumes increased from
73 MBPD in 1998 to 184 MBPD primarily due to the TNGL fractionators and
increased ownership of the Mont Belvieu NGL fractionator. During 1999, gross
operating margin from isomerization increased $19.6 million compared to 1998
levels due to exceptional pricing conditions in the first half of 1999 and
higher overall production. Isomerization volumes increased from 67 MBPD in 1998
to 74 MBPD in 1999. Gross operating margin from propylene fractionation
increased $11.2 million over 1998 levels generally due to increases in polymer
grade propylene prices and higher production rates. Volumes at these facilities
improved to 28 MBPD in 1999 versus 26 MBPD in 1998.
Pipeline. The Company's 1999 gross operating margin for the Pipeline
segment increased $3.9 million compared to 1998. Overall volumes increased to
264 MBPD in 1999 from 200 MBPD in 1998. Of the increase in both margin and
volumes, $4.7 million in margin and approximately 56 MBPD in throughput volumes
are attributable to the TNGL pipeline and related assets. In addition, equity
income from EPIK increased $0.4 million due to increased export volumes. Margins
from the Company's Houston Ship Channel import terminal and pipeline
distribution system decreased $2.0 million in 1999 primarily due to lower import
volumes.
Processing. The Company's 1999 gross operating margin for Processing
increased $29.1 million over 1998 results. The increase is primarily due to the
gas processing operations acquired from TNGL effective August 1, 1999. The gas
processing operations benefited from a favorable NGL pricing environment during
the fourth quarter of 1999 and 67 MBPD of equity NGL production.
Octane Enhancement. The Company's 1999 gross operating margin for
Octane Enhancement decreased $1.6 million from 1998 levels. The decrease is
attributable to a $4.5 million non-cash charge by BEF in January 1999 of which
the Company's share was $1.5 million. MTBE net production volumes averaged 5
MBPD in both 1999 and 1998.
35
Other. The Company's 1999 gross operating margin for the Other segment
increased $4.4 over 1998 levels. The increase is attributable to the fee-based
marketing business acquired from TNGL. 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"). 1999 SG&A
expenses decreased by $5.7 million compared to 1998. The 1999 expenses were
lower due to the fixed administrative fees charged to the Company under the EPCO
Agreement. The fixed administrative service fees partially reimburse EPCO for
the cost of providing certain management and administrative support for the
Company. During 1999, these fixed fees ranged from $1.0 million to $1.1 million
per month. The Audit and Conflicts Committee of the General Partner is
responsible for reviewing and approving any increases in the standard
administrative fees chargeable by EPCO to the Company. For additional
information regarding the EPCO Agreement, see page 52 of this Form 10-K.
Interest expense. The Company's 1999 interest expense increased $1.3
over 1998 primarily due to the amortization of loan origination costs. Average
debt levels in 1999 were generally consistent with those of 1998.
Dividend income from unconsolidated affiliates. As a result of the TNGL
acquisition, the Company owned cost method investments in Dixie and VESCO. As
such, the Company recorded dividend income from these investments as cash
dividends were received. During 1999, the Company recorded dividend income from
Dixie and VESCO in the amounts of $0.8 million and $2.6 million, respectively.
Extraordinary charge on early 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 Company's initial public offering. The extraordinary loss was equal to
the remaining unamortized debt origination costs associated with such debt and
make-whole premiums payable in connection with the repayment of such debt.
Liquidity and Capital Resources
General
The Company's primary cash requirements, in addition to normal
operating expenses, are for capital expenditures (both maintenance and
expansion-related), business acquisitions, distributions to the partners and
debt service. The Company expects to fund its short-term needs for such items as
maintenance capital expenditures and quarterly distributions to the partners
from operating cash flows. Capital expenditures for long-term needs resulting
from future expansion projects and business acquisitions are expected to be
funded by a variety of sources including (either separately or in combination)
cash flows from operating activities, borrowings under bank credit facilities
and the issuance of additional Common Units and public debt. The Company's debt
service requirements are expected to be funded by operating cash flows or
refinancing arrangements.
As noted above, certain of the Company's liquidity and capital resource
requirements are met using borrowings under bank credit facilities and/or the
issuance of additional Common Units or public debt (separately or in
combination). As of December 31, 2000, availability under the Company's bank
credit facilities was $400 million (which may be increased to $500 million under
certain conditions). In addition to the existing bank credit facilities, the
Company issued $450 million of public debt in January 2001 using the remaining
shelf availability under its $800 million December 1999 universal shelf
registration (the "December 1999 Registration Statement"). The proceeds from
this offering were or will be used to acquire the Acadian and EPE natural gas
pipeline systems for $339.2 million and to finance the cost to construct certain
NGL pipelines and related projects and for working capital and other general
partnership purposes. $350 million of shelf availability under the December 1999
Registration Statement was used in March 2000 with the issuance of the $350
Million Senior Notes.
On February 23, 2001, the Company filed a $500 million universal shelf
registration (the "February 2001 Registration Statement") covering the issuance
of an unspecified amount of equity or debt securities or a combination thereof.
For a broader discussion of the Company's outstanding debt and changes therein,
see the section below labeled "Long-term Debt".
36
In June 2000, the Company received approval from its Unitholders to
increase by 25,000,000 the number of Common Units available (and unreserved) to
the Company for general partnership purposes during the Subordination Period.
This increase has improved the future financial flexibility of the Company in
any potential business acquisition (see "Amendment to Partnership Agreement"
below for further details).
If deemed necessary, management believes that additional financing
arrangements can be obtained at reasonable terms. Management believes that
maintenance of the Company's investment grade credit ratings (currently, Baa3 by
Moody's Investor Service and BBB by Standard and Poors) combined with a
continued ready access to debt and equity capital at reasonable rates and
sufficient trade credit to operate its businesses efficiently are a solid
foundation to providing the Company with ample resources to meet its long and
short-term liquidity and capital resource requirements.
Operating, Investing and Financing Cash Flows for Years Ended December
31, 2000 and 1999
Cash flows from operating activities were a $360.7 million inflow in
2000 compared to a $178.0 million inflow in 1999. Cash flows from operating
activities primarily reflect the effects of net income, depreciation and
amortization, extraordinary items, equity income and distributions from
unconsolidated affiliates and changes in working capital. Net income increased
significantly in 2000 over 1999 due to reasons mentioned previously under
"Results of Operation of the Company." Depreciation and amortization expense
increased a combined $15.7 million in 2000 over 1999 primarily the result of
additional capital expenditures and acquisitions. Of the $15.7 million increase,
$4.9 million is attributable to increases in amortization expense associated
with the 20-year Shell natural gas processing agreement, excess cost related to
past acquisitions and loan origination and bond issue costs. The Company
received $37.3 million in distributions from its equity method investments in
2000 compared to $6.0 million in 1999. Of the $31.3 million increase in
distributions, $10.0 million was from BEF and $8.1 million from EPIK.
Distributions from BEF improved period to period due to the strong MTBE prices
and margins during the second quarter of 2000. EPIK's distributions increased as
a result of higher export activity during 2000. In addition, 2000 included $7.0
million in cash receipts from Promix which was acquired as a result of the TNGL
acquisition. 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 used for investing activities was $268.8 million in 2000 compared
to $271.2 million in 1999. Cash outflows included capital expenditures of $243.9
million in 2000 versus $21.2 million in 1999. Capital expenditures in 2000
include $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and
related assets and $83.7 million in construction costs for the Lou-Tex NGL
Pipeline. In addition, capital expenditures include maintenance capital project
costs of $3.5 million in 2000 and $2.4 million in 1999. The 1999 period reflects
$208.1 million in net cash payments resulting from the TNGL and MBA
acquisitions. In 2000, the Company received $6.5 million in payments from its
participation in the BEF note that was purchased during 1998 with the proceeds
from the Company's IPO. BEF made its final note payment in May 2000. With BEF's
final payment, the Company's receivable relating to its participation in the BEF
note was extinguished.
Investing cash outflows in 2000 include $31.5 million in advances to
and investments in unconsolidated affiliates compared to $61.9 million in 1999.
The decrease is primarily due to the completion of the BRF facility and the
Tri-States and Wilprise pipeline systems in 1999. On March 8, 2000, the
Company's offer of February 23, 2000 to buy the remaining 88.5% ownership
interests in Dixie from the other seven owners expired, with no interest being
purchased. In October 2000, the Company announced that a wholly-owned subsidiary
had purchased an additional 3,521 shares of common stock of Dixie from Conoco
Pipe Line Company for approximately $19.4 million. The purchase increased the
Company's economic interest in Dixie to approximately 19.9%.
Cash flows from financing activities were a $36.7 million outflow in
2000 compared to a $74.4 million inflow for 1999. Cash flows from financing
activities are primarily affected by repayments of debt, borrowings under debt
agreements and distributions to partners. 2000 includes proceeds from the $350
Million Senior Notes and the $54 Million MBFC Loan and the associated repayments
on the $200 Million Bank Credit Facility and $350 Million Bank Credit Facility.
For a complete discussion of the $350 Million Senior Notes and the $54 Million
MBFC Loan and the use of proceeds thereof, see the section labeled "Long-term
Debt" below. Financing activities in 1999 include the borrowings associated with
the TNGL and MBA acquisitions and outflows of $4.7 million related to the
purchase of the Company's Common Units by a consolidated trust. Debt issuance
37
costs increased $0.9 million in 2000 due to the issuance of the $350 Million
Senior Notes and the $54 Million MBFC Loan. Distributions to partners and the
minority interest increased to $139.6 million in 2000 from $111.8 million in
1999 primarily due to an increase in the quarterly distribution rate (see page
25 of this Form 10-K for a history of the quarterly distribution rates since the
first quarter of 1999).
In July 2000, the Company announced a 1,000,000 Unit buy-back program
of its publicly-owned Common Units to be executed over a two-year period.
Management's intent is to opportunistically acquire Common Units during periods
of temporary market weakness at price levels that would be accretive to the
Company's remaining Unitholders. The repurchase program will be balanced with
plans to grow the Company through investments in internally developed projects
and acquisitions, while maintaining an investment grade debt rating. The
redemption program will be funded by increased cash distributions from the
Operating Partnership from operating cash flows and borrowings under its bank
credit facilities. During 2000, 28,400 Common Units were repurchased and retired
under this buy-back program at a cost of approximately $0.8 million.
The Company is exposed to various market risks including interest rate
and commodity price risk through its gas processing and related NGL businesses.
These risks may entail significant cash outlays in the future that are not
offset by their underlying hedged positions. For a complete description of the
Company's risk management policies and potential exposures, see "Item 7A.
Quantitative and Qualitative Disclosures about Market Risk" on page 43 of this
Form 10-K report.
Future Capital Expenditures
The Company estimates that its share of currently approved capital
expenditures in the projects of its unconsolidated affiliates will be
approximately $3.1 million during 2001. In addition, the Company forecasts that
$128.8 million will be spent during 2001 on currently approved capital projects
that will be recorded as property, plant and equipment (the majority of which
relate to various pipeline projects).
As of December 31, 2000, the Company had $10.9 million in outstanding
purchase commitments attributable to its capital projects. Of this amount, $10.1
million is related to the construction of assets that will be recorded as
property, plant and equipment and $0.8 million is associated with capital
projects which will be recorded as additional investments in unconsolidated
affiliates.
New Texas environmental regulations may necessitate extensive redesign
and modification of the Company's Mont Belvieu facilities to achieve the air
emissions reductions needed for federal Clean Air Act compliance in the
Houston-Galveston area. Until litigation challenging these regulations is
resolved, the technology to be employed and the cost for modifying the
facilities to achieve enough reductions cannot be determined, and capital funds
have not been budgeted for such work. Regardless of the outcome of this
litigation, expenditures for emissions reduction projects will be spread over
several years, and management believes the Company will have adequate liquidity
and capital resources to undertake them. For additional information about this
litigation, see the discussion under the topic Clean Air Act--General on page 22
of this Form 10-K.
38
Long-term Debt
Long-term debt consisted of the following at:
December 31,
---------------------------------------
2000 1999
---------------------------------------
Borrowings under:
$200 Million Bank Credit Facility (1) $ 129,000
$350 Million Bank Credit Facility (1) 166,000
$350 Million Senior Notes (2) $ 350,000
$54 Million MBFC Loan (3) 54,000
---------------------------------------
Total 404,000 295,000
Less current maturities of long-term debt 129,000
---------------------------------------
Long-term debt (4) $ 404,000 $ 166,000
=======================================
- -------------------------------------------------------------------------------------------
(1) Revolving credit facility closed as of December 31, 2000
(2) 8.25% fixed-rate, due March 2005
(3) 8.70% fixed-rate, due March 2010
(4) Long-term debt does not reflect the $250 Million Multi-Year
Credit Facility or the $150 Million 364-Day Credit Facility. No
amount was outstanding under either of these two revolving
credit facilities at December 31, 2000. See below for a
complete description of these new facilities
On January 24, 2001, the Company completed a public offering of $450
million in principal amount of 7.50% fixed-rate Senior Notes due February 1,
2011 at a price to the public of 99.937% per Senior Note (the "$450 Million
Senior Notes"). The Company received proceeds, net of underwriting discounts and
commissions, of approximately $446.8 million. As noted earlier, the proceeds
from this offering were or will be used to acquire the Acadian and EPE natural
gas pipeline systems for $339.2 million and to finance the cost to construct
certain NGL pipelines and related projects and for working capital and other
general partnership purposes.
The Company expects to use the net proceeds from any sale of securities
under the February 2001 Registration Statement for future business acquisitions
and other general corporate purposes, such as working capital, investments in
subsidiaries, the retirement of existing debt and/or the repurchase of Common
Units or other securities. The exact amounts to be used and when the net
proceeds will be applied to partnership purposes will depend on a number of
factors, including the Company's funding requirements and the availability of
alternative funding sources. The Company routinely reviews acquisition
opportunities.
At December 31, 2000, the Company had a total of $50 million of standby
letters of credit available under its $250 Million Multi-Year Credit Facility
(described below) of which none were outstanding.
$200 Million Bank Credit Facility. On July 27, 1998, the Company
entered into a $200 million bank credit facility that included a $50 million
working capital facility and a $150 million revolving credit facility. On March
15, 2000, the Company used $169 million of the proceeds from the issuance of the
$350 Million Senior Notes to retire this credit facility in accordance with its
agreement with the banks.
$350 Million Bank Credit Facility. On July 28, 1999, the Company
entered into a $350 Million Bank Credit Facility that included a $50 million
working capital facility, a $300 million revolving credit facility and a
sublimit of $40 million for letters of credit. On November 17, 2000, this
facility was retired using funds available under the Company's new $150 Million
364-Day Credit Facility (described below) in accordance with its agreement with
the banks.
$350 Million Senior Notes. On March 13, 2000, the Company completed a
public offering of $350 million in principal amount of 8.25% fixed-rate Senior
Notes due March 15, 2005 at a price to the public of 99.948% per Senior Note.
The Company received proceeds, net of underwriting discounts and commissions, of
approximately $347.7 million. The proceeds were used to pay the entire $169
million outstanding principal balance on the $200 Million Bank Credit Facility
39
and $179 million of the then $226 million outstanding principal balance on the
$350 Million Bank Credit Facility.
The $350 Million Senior Notes are subject to a make-whole redemption
right. The notes are an unsecured obligation and rank equally with existing and
future unsecured and unsubordinated indebtedness and senior to any future
subordinated indebtedness. The notes are guaranteed by the MLP through an
unsecured and unsubordinated guarantee and were issued under an indenture
containing certain restrictive covenants. These covenants restrict the ability
of the Company, with certain exceptions, to incur debt secured by liens and
engage in sale and leaseback transactions. The Company was in compliance with
the restrictive covenants at December 31, 2000.
The issuance of the $350 Million Senior Notes was a takedown under the
December 1999 Registration Statement; therefore, the amount of securities
available was reduced to $450 million. The remaining amount available under the
December 1999 Registration Statement was used to issue the $450 Million Senior
Notes in January 2001.
$54 Million MBFC Loan. On March 27, 2000, the Company executed a $54
million loan agreement with the MBFC which was funded with proceeds from the
sale of Taxable Industrial Revenue Bonds ("Bonds") by the MBFC. The Bonds issued
by the MBFC are 10-year bonds with a maturity date of March 1, 2010 and bear a
fixed-rate interest coupon of 8.70%. The Company received proceeds from the sale
of the Bonds, net of underwriting discounts and commissions, of approximately
$53.6 million. The proceeds were used to pay the then $47 million outstanding
principal balance on the $350 Million Bank Credit Facility and for working
capital and other general partnership purposes. In general, the proceeds of the
Bonds were used to reimburse the Company for costs incurred in acquiring and
constructing the Pascagoula, Mississippi natural gas processing plant.
The Bonds were issued at par and are subject to a make-whole redemption
right by the Company. The Bonds are guaranteed by the MLP through an unsecured
and unsubordinated guarantee. The loan agreement contains certain covenants
including maintaining appropriate levels of insurance on the Pascagoula natural
gas processing facility and restrictions regarding mergers. The Company was in
compliance with the restrictive covenants at December 31, 2000.
$250 Million Multi-Year Credit Facility. On November 17, 2000, the
Company entered into a $250 million five-year revolving credit facility that
includes a sublimit of $50 million for letters of credit. The November 17, 2005
maturity date may be extended for one year at the Company's option with the
consent of the lenders, subject to the extension provisions in the agreement.
The Company can increase the amount borrowed under this facility, without the
consent of the lenders, up to an amount not exceeding $350 million by adding to
the facility one or more new lenders and/or increasing the commitments of
existing lenders, so long as the aggregate amount of the funds borrowed under
this credit facility and the $150 Million 364-Day Credit Facility (described
below) does not exceed $500 million. No lender will be required to increase its
original commitment, unless it agrees to do so at its sole discretion. This
credit facility is guaranteed by the MLP through an unsecured and unsubordinated
guarantee.
Proceeds from this credit facility will be used for working capital,
acquisitions and other general partnership purposes. No amount was outstanding
for this credit facility at December 31, 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 generally bear interest at either (a) the
greater of the Prime Rate or the Federal Funds Effective Rate plus one-half
percent or (b) a Eurodollar rate plus an applicable margin (as defined within
the facility) or (c) a competitively bid rate. The Company elects the basis for
the interest rate at the time of each borrowing.
This credit agreement contains various affirmative and negative
covenants applicable to the Company to, among other things, (i) incur certain
additional indebtedness, (ii) grant certain liens, (iii) enter into certain
merger or consolidation transactions and (iv) make certain investments. In
addition, the Company may not directly or indirectly make any distribution in
respect of its partnership interests, except those payments in connection with
the 1,000,000 Unit Buy-Back Program (not to exceed $30 million in the aggregate)
and distributions from Available Cash from Operating Surplus, both as defined
within the agreement. The bank credit facility requires that the Company satisfy
certain financial covenants at the end of each fiscal quarter: (i) maintain
40
Consolidated Net Worth of $750 million (as defined in the bank credit facility)
and (ii) maintain a ratio of Consolidated Indebtedness (as defined within the
bank credit facility) to Consolidated EBITDA (as defined within the bank credit
facility) for the previous four quarter period of at least 4.0 to 1.0. The
Company was in compliance with these restrictive covenants at December 31, 2000.
$150 Million 364-Day Credit Facility. Also on November 17, 2000, the
Company entered into a 364-day $150 million revolving bank credit facility which
may be converted into a one-year term loan at the end of the initial 364-day
period. Should this facility be converted into a one-year term loan, the
maturity date would be November 16, 2002. Likewise, this maturity date may be
extended for an additional one-year period at the option of the Company (with
the consent of the lenders), subject to the extension provisions in the
agreement; therefore, the ultimate maturity date of this credit facility could
be November 16, 2003. The Company can increase the amount borrowed under this
facility, without the consent of the lenders, up to an amount not exceeding $250
million by adding to the facility one or more new lenders and/or increasing the
commitments of existing lenders, so long as the aggregate amount of the funds
borrowed under this credit facility and the $250 Million Bank Credit Facility
does not exceed $500 million. No lender will be required to increase its
original commitment, unless it agrees to do so at its sole discretion. This
credit facility is guaranteed by the MLP through an unsecured and unsubordinated
guarantee.
Proceeds from this credit facility will be used for working capital,
acquisitions and other general partnership purposes. No amount was outstanding
for this credit facility at December 31, 2000. The Company used operating cash
flows to repay the amount borrowed to retire the $350 Million Bank Credit
Facility in November 2000.
Limitations on certain actions by the Company and financial condition
covenants of this bank credit facility are substantially consistent with those
existing for the $250 Million Multi-Year Credit Facility as described above. The
Company was in compliance with the restrictive covenants at December 31, 2000.
Interest Rate Swaps
The Company's interest rate exposure results from variable-rate
borrowings from commercial banks and fixed-rate borrowings pursuant to the $350
Million Senior Notes and the $54 Million MBFC Loan. The Company uses interest
rate swaps to manage its overall costs of financing. An interest rate swap, in
general, requires one party to pay a fixed-rate on the notional amount while the
other party pays a floating-rate based on the notional amount.
In March 2000, after the issuance of the $350 Million Senior Notes and
the execution of the $54 Million MBFC Loan, 100% of the Company's consolidated
debt were fixed-rate obligations. To maintain a balance between variable-rate
and fixed-rate exposure, the Company entered into interest rate swap agreements
with a notional amount of $154 million by which the Company receives payments
based on a fixed-rate and pays an amount based on a floating-rate. At December
31, 2000, the Company's consolidated debt portfolio interest rate exposure was
62% fixed and 38% floating, after considering the effect of the interest rate
swap agreements. The notional amount does not represent exposure to credit loss.
The Company monitors its positions and the credit ratings of its counterparties.
Management believes the risk of incurring a credit related loss is remote, and
that if incurred, such losses would be immaterial.
The effect of these swaps (none of which are leveraged) was to decrease
the Company's interest expense by $1.2 million during 2000. For further
information regarding the interest rate swaps, see Note 12 of the Notes to the
Consolidated Financial Statements.
Recent Accounting Developments
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments
and Hedging Activities, as amended and interpreted. SFAS 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities.
All derivatives, whether designated in hedging relationships or not, will be
required to be recorded on the balance sheet at fair value. If the derivative is
designated as a fair value hedge, the changes in fair value of the derivative
and the hedged item will be recognized in earnings. If the derivative is
designated as a cash flow hedge, changes in the fair value of the derivative
41
will be recorded as a component of Partners' Equity entitled Other Comprehensive
Income (to the extent the hedge is effective) and will be recognized in the
income statement when the hedged item affects earnings. The ineffective portion
of the hedge is required to be recorded in earnings. SFAS 133 defines new
requirements for designation and documentation of hedging relationships as well
as ongoing effectiveness assessments in order to use hedge accounting. A
derivative that does not qualify as a hedge will be recorded at fair value
through earnings.
The Company expects that at January 1, 2001, it will record a $42.2
million loss in Other Comprehensive Income as a cumulative transition adjustment
for derivatives (commodity contracts) designated in cash flow-type hedges prior
to adopting SFAS 133. In addition, the Company expects to record a $2.1 million
derivative asset and a corresponding increase to its long term debt relating to
derivatives (interest rate swaps) designated in fair-value-type hedges prior to
adopting SFAS 133. The fair value hedges will have no impact to earnings upon
transition.
The Company will reclassify from Other Comprehensive Income $21.7
million as a charge to earnings during the first quarter of 2001 and $20.5
million as a charge to earnings during the remainder of 2001. The actual gain or
loss amount to be recognized in earnings related to these commodity contracts
over time is dependent upon the final settlement price associated with the
commodity prices.
Amendment to Partnership Agreement
The Partnership Agreement generally authorizes the Company to issue an
unlimited number of additional limited partner interests and other equity
securities 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 is
limited with regards to the number of equity securities that it may issue that
rank senior to 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).
In April 2000, the Company mailed a Proxy Statement to its public
Unitholders asking them to consider and vote for a proposal to amend the
Partnership Agreement to increase the number of additional Common Units that may
be issued during the Subordination Period without the approval of a Unit
Majority from 22,775,000 Common Units to 47,775,000 Common Units. The primary
purpose of the requested increase was to improve the future financial
flexibility of the Company since 20,500,000 Common Units of the 22,775,000
Common Units available to the partnership during the Subordination Period were
reserved for issuance in connection with the TNGL acquisition. At a special
meeting of the Unitholders and General Partner held on June 9, 2000, this
proposal was approved by 90.7% of the public Unitholders. The amendment
increases the number of Common Units available (and unreserved) to the Company
for general partnership purposes during the Subordination Period from 2,275,000
to 27,275,000.
MTBE Facility
The Company owns a 33.3% 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 Amendments of 1990 and other legislation. Any changes to these
programs that enable localities to elect to not participate in these programs,
lessen the requirements for oxygenates or favor the use of non-isobutane based
oxygenated fuels would reduce the demand for MTBE. On March 25, 1999, the
Governor of California ordered the phase-out of MTBE in California by the end of
2002 due to allegations by several public advocacy and protest groups that MTBE
contaminates water supplies, causes health problems and has not been as
beneficial in reducing air pollution as originally contemplated. In addition,
legislation to amend the federal Clean Air Act has been introduced in the U.S.
House of Representatives to 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 foster the elimination of MTBE in fuel.
42
No assurance can be given as to whether this or similar legislation ultimately
will be adopted or whether the U.S. Congress or the EPA might take steps to
override the MTBE ban in California.
In light of the regulatory climate, the owners of BEF are formulating a
contingency plan for use of the BEF facility if MTBE were banned or
significantly curtailed. The owners of BEF are exploring a possible conversion
of the BEF facility from MTBE production to alkylate production. One conversion
alternative is expected to result in similar operating margin as that currently
anticipated from the facility if it were to remain in MTBE service. If this
approach were taken, the cost to convert the facility would range from $20
million to $25 million, with the Company's share being $6.7 million to $8.3
million. A second conversion alternative would increase both production capacity
and overall margin and cost between $50 million and $90 million, with the
Company's share being $16.7 million to $30 million. Management anticipates that
if MTBE is banned alkylate demand will rise as producers use it to replace MTBE
as an octane enhancer. Greater alkylate production would be expected to increase
isobutane consumption nationwide and result in improved isomerization margins
for the Company.
Sun, the MTBE facility's major customer and one of the partners of BEF,
has entered into a contract with BEF to take all of the MTBE production through
September 2004.
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 a portion of 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 generally does not use
derivative financial instruments for speculative (or trading) purposes.
The Company has adopted a commercial policy to manage its exposure to
the risks generated by its gas processing and related NGL businesses and
long-term debt. The objective of this policy is to assist the Company in
achieving its profitability goals while maintaining a portfolio of conservative
risk, defined as remaining within the position limits established by the General
Partner. The Company will enter into risk management transactions to manage
price risk, basis risk, physical risk, interest rate risk or other risks related
to the energy commodities and long-term debt on both a short-term (less than 30
days) and long-term basis, not to exceed 18 months. The General Partner oversees
the strategies of the Company associated with physical and financial risks,
approves specific activities of the Company subject to the policy (including
authorized products, instruments and markets) and establishes specific
guidelines and procedures for implementing and ensuring compliance with the
policy.
Interest rate risk
Variable-rate Debt. At December 31, 2000 and 1999, the Company had no
derivative instruments in place to cover any potential interest rate risk on its
variable-rate debt obligations. Variable-rate debt obligations expose the
Company to possible increases in interest expense and decreases in earnings if
interest rates were to rise. During 2000 and 1999, the Company's had
variable-rate long-term debt outstanding under the $200 Million, $350 Million
and $150 Million 364-Day bank credit facilities. At December 31, 2000, the
Company had no variable-rate debt outstanding.
If the weighted average base interest rates selected on the
variable-rate long-term debt during 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. If the same calculation were performed on the variable-rate
long-term debt outstanding during 2000, interest expense would have increased by
approximately $1.0 million with a corresponding decrease in earnings before
minority interest.
Fixed-rate Debt. In March 2000, the Company entered into interest rate
swaps whereby the fixed-rate of interest on a portion of the $350 Million Senior
Notes and the $54 Million MBFC Loan was effectively swapped for floating-rates
tied to the six month London Interbank Offering Rate ("LIBOR"). Interest rate
43
swaps are used to manage the Company's overall costs of financing. An interest
rate swap, in general, requires one party to pay a fixed-rate on the notional
amount while the other party pays a floating-rate based on the notional amount.
To maintain a balance between variable-rate and fixed-rate exposure,
the Company entered into interest rate swap agreements with a notional amount of
$154 million by which the Company receives payments based on a fixed-rate and
pays an amount based on a floating-rate. At December 31, 2000, the Company's
consolidated debt portfolio interest rate exposure was 62% fixed and 38%
floating, after considering the effect of the interest rate swap agreements. The
notional amount does not represent exposure to credit loss. The Company monitors
its positions and the credit ratings of its counterparties. Management believes
the risk of incurring a credit related loss is remote, and that if incurred,
such losses would be immaterial.
The effect of these swaps (none of which are leveraged) was to decrease
the Company's interest expense by $1.2 million during 2000. Following is
selected information on the Company's portfolio of interest rate swaps at
December 31, 2000:
Interest Rate Swap Portfolio at December 31, 2000 (1)
(Dollars in millions)
Early Fixed /
Notional Termination Floating
Amount Period Covered Date (2) Rate (3)
- --------------------------------------------------------------------------------
$ 50.0 March 2000 - March 2005 March 2001 8.25% / 7.3100%
$ 50.0 March 2000 - March 2005 March 2001 (4) 8.25% / 7.3150%
$ 54.0 March 2000 - March 2010 March 2003 8.70% / 7.6575%
- --------------------------------------------------------------------------------
(1) All swaps outstanding at December 31, 2000 were entered into for the
purpose of managing a portion of the financing costs associated with
fixed-rate debt.
(2) In each case, the counterparty has the option to terminate the interest
rate swap on the Early Termination Date.
(3) In each case, the Company is the floating-rate payor. The floating rate
was the rate in effect as of December 31, 2000.
(4) Swap was terminated by the bank effective March 15, 2001.
If the six month LIBOR rates applicable to the notional amounts of
these interest rate swap agreements during 2000 were to have been 10% higher
than the six month LIBOR rates actually used in the swap agreements, assuming no
changes in fixed-rate debt levels, interest expense for 2000 would have
increased by $0.8 million, with a corresponding decrease in earnings before
minority interest.
In connection with the implementation of SFAS 133, the fair value of
the interest rate swaps were recorded on the balance sheet as a $2.1 million
receivable with an offsetting gain recorded in earnings on January 1, 2001. The
value recorded for the interest rate swap agreements represents the fair value
of these derivative instruments using current market interest rates. In
accordance with SFAS 133, the value of the interest rate swaps will be
redetermined each reporting period based upon then current market interest
rates. The value assigned to the interest rate swap agreements is predicated
upon the expected life of the swap agreements as influenced by current market
interest rates. The change in the value of these instruments during each
measurement period will result in either an increase or a decrease in earnings.
At December 31, 2000, the Company's fixed-rate debt obligations
aggregated $404.0 million and had a fair value of $423.8 million. Since these
instruments have fixed-interest rates, they do not expose the Company to the
risk of loss in earnings due to changes in market interest rates. However, the
fair value of these instruments would increase to approximately $435.8 million
if interest rates were to decline by 10% from their levels at December 31, 2000.
In general, such an increase in fair value would impact earnings and cash flows
only if the Company were to reacquire all or a portion of these instruments in
the open market prior to their maturity.
44
Other. At December 31, 2000 and 1999, the Company had $60.4 million and
$5.2 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 gas
processing and related NGL businesses. 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 production and inventories, firm
commitments and certain anticipated transactions.
The following table presents the hypothetical changes in fair values
arising from immediate selected potential changes in the quoted market prices of
derivative commodity instruments outstanding at the dates noted within the
table. The fair value of the commodity futures at the dates noted below are
estimates 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 respective balance sheet dates.
Impact of a 10% increase Impact of a 10% decrease
Asset (liability) in market prices in market prices
Fair value ------------------------------------ ------------------------------------
at date indicated Increase(Decrease) Increase)Decrease)
assuming no in Fair Value in Fair Value
change in Adjusted estimate due to increase Adjusted estimate due to decrease
market prices of Fair Value in market prices of Fair Value in market prices
------------------ ------------------------------------ ------------------------------------
Estimated impact of changes
in quoted market prices
on commodity futures at:
(in millions of dollars)
December 31, 1999 $ (0.5) $ 1.2 $ 1.7 $ (2.2) $ (1.7)
December 31, 2000 (38.6) (56.3) (17.7) (20.9) 17.7
March 12, 2001 (11.5) (34.3) (22.8) 11.5 23.0
The fair value of the commodity futures at December 31, 1999 was estimated at
$0.5 million payable. The fair value of the commodity futures at December 31,
2000 was estimated at $38.6 million payable. The increase is primarily due to an
increase in volumes hedged, a change in the composition of commodities hedged
and higher natural gas prices. On March 12, 2001, the fair value of commodities
hedged was $11.5 million payable. The change from December 31, 2000 was
primarily due to the settlement of certain open positions, lower natural gas
prices and a change in the composition of commodities hedged.
To the extent that the hedged positions are effective, gains or losses 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 above.
Beginning in January 2001 with the implementation of SFAS 133, the ineffective
portion of such hedged positions will be recorded in earnings. See "Recent
Accounting Developments" on page 41 for additional information regarding the
accounting treatment of hedged commodity positions under SFAS 133.
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 on Accounting and
Financial Disclosure.
None.
45
PART III
Item 10. Directors and Executive Officers of the Registrant.
Company Management
As is commonly the case with publicly-traded master limited
partnerships, the Company does not directly employ any of the persons
responsible for the management of the Company. These functions are performed by
the employees of EPCO (pursuant to the EPCO Agreement) under the direction of
the Board of Directors and executive officers of the General Partner.
In accordance with NYSE rules, the Board of Directors of the General
Partner has named three of its members to serve on its Audit and Conflicts
Committee. The members of the Audit and Conflicts Committee are financially
literate and independent nonexecutive directors, free from any relationship that
would interfere with the exercise of independent judgment. The Audit and
Conflicts Committee 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.
The members of the Audit and Conflicts Committee must have a basic
understanding of finance and accounting and be able to read and understand
fundamental financial statements, and at least one member of the committee shall
have accounting or related financial management expertise. In addition to ruling
in cases involving conflicts of interest, the primary responsibilities of the
Audit and Conflicts Committee include:
- monitoring the integrity of the financial reporting process and its
related systems of internal control;
- ensuring legal and regulatory compliance of the General Partner and
the Company (including its subsidiaries);
- overseeing the independence and performance of the Company's
independent public accountants;
- providing for an avenue of communication among the independent public
accountants, management, internal audit function and the Board of
Directors;
- encouraging adherence to and continuous improvement of the Company's
policies, procedures and practices at all levels;
- reviewing areas of potential significant financial risk to the
Company; and
- approving increases in the administrative service fee payable under
the EPCO Agreement.
Pursuant to its formal written charter adopted in June 2000, the Audit and
Conflicts has the authority to conduct any investigation appropriate to
fulfilling its responsibilities, and it has direct access to the independent
public accountants as well as EPCO personnel. The Audit and Conflicts Committee
has the ability to retain, at the Company's expense, special legal, accounting,
or other consultants or experts it deems necessary in the performance of its
duties.
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.
46
Directors, 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 member of the Board of
Directors serves until such member's death, resignation or removal. The
executive officers are elected for one-year terms and may be removed, with or
without cause, only by the Board of Directors.
Name Age Position with General Partner
- ----------------------------------- ------- ---------------------------------------------------------
Dan L. Duncan (1,3) 68 Director and Chairman of the Board
O.S. Andras (1,3) 65 Director, President and Chief Executive Officer
Randa L. Duncan (3) 39 Director
J. R. Eagan 46 Director
J. A. Berget (1) 48 Director
Dr. Ralph S. Cunningham (2) 60 Director
Curtis R. Frasier (1) 45 Director
Lee W. Marshall, Sr. (2) 68 Director
Richard S. Snell (2) 58 Director
Richard H. Bachmann (1,3) 48 Director, Executive Vice President, Chief Legal Officer
and Secretary
Albert W. Bell (3) 62 Executive Vice President, President and Chief
Operating Officer of Petrochemical Division
A.J. ("Jim") Teague (3) 56 Executive Vice President, President and Chief
Operating Officer of NGL Division
Michael A. Creel (3) 47 Executive Vice President, Chief Financial
Officer and President and Chief Operating Officer of
Natural Gas Division
William D. Ray (3) 65 Executive Vice President
Charles E. Crain (3) 67 Senior Vice President
Michael Falco (3) 64 Senior Vice President
A. Monty Wells (3) 55 Senior Vice President
Michael J. Knesek (3) 46 Vice President and Principal Accounting Officer
W. Randall Fowler (3) 44 Vice President and Treasurer
- -------------------------------------------------------------------------------------------------------
(1) Member of the Executive Committee
(2) Member of the Audit and Conflicts Committee
(3) Executive Officer
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 served as Group
Executive Vice President of EPCO from 1994 to 2001. In February 2001, she became
President and Chief Executive Officer of EPCO and resigned as Group Executive
Vice President of the General Partner in order to devote full attention to the
responsibilities of her new position. 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.
47
J. R. (Jeri) Eagan was elected as a Director of the General Partner in
October 2000. Since 1999, Ms. Eagan has served in various executive-level
positions with Shell Exploration and Production Company ("SEP") and currently
holds the office of Vice President Finance & Commercial Operations. From 1994 to
1999, she worked on several assignments in the London office with Shell
International Petroleum Company. From 1976 to 1994, Ms. Eagan held a number of
managerial and accounting positions with various Shell companies.
J. A. (Jorn) Berget was elected as a Director of the General Partner in
November 2000. Since October 2000, Mr. Berget has served as Vice President and
General Manager for SEP. From 1995 to October 2000, he served in various
managerial positions with Shell Expro including General Manager of the Northern
Business Unit in which he managed Shell assets and activities of the Brent Field
in the United Kingdom. Over the past 20 years, Mr. Berget has held numerous
operating, engineering, planning and managerial positions covering most aspects
of SEP. Mr. Berget also serves as a director of Enventure Global Technologies (a
joint venture between Shell and Halliburton 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 Tetra Technologies, Inc. (a
public energy services and chemicals company), Huntsman Corporation (a privately
held petrochemical corporation), and Agrium, Inc. (a Canadian public
agricultural chemicals company ) 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 Vice President of Shell N.A. Gas & Power, SEP. 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.
Richard S. Snell was elected as a Director of the General Partner in
June 2000. Mr. Snell was an attorney with Snell & Smith, P.C. for seven years
after founding the company in 1993. He is currently a partner with the firm of
Thompson Knight Brown Parker & Leahy, L.L.P. and is a certified public
accountant.
Richard H. Bachmann was elected as a Director of the General Partner in
June 2000. He has served as Executive Vice President and Chief Legal Officer of
the General Partner since 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 a 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.
A.J. ("Jim") Teague was elected as a 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.
48
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.
Michael A. Creel was elected as an Executive Vice President and
President and Chief Operating Officer of the Natural Gas Division of the General
Partner in February 2001, having served as a Senior Vice President of the
General Partner since November 1999. In June 2000, Mr. Creel, a certified public
accountant, assumed the role of Chief Financial Officer of the Company along
with his other 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.
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.
William D. Ray was elected as a Executive Vice President 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.
Charles E. Crain was elected as a Senior Vice President 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 as a 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.
A. Monty Wells was elected as a Senior Vice President of the General
Partner in June 2000. Since joining EPCO in 1980, Mr. Wells has served in a
number of managerial positions including Vice President of Marketing and Supply.
Prior to 1980, he worked in the international natural gas liquids group at
Atlantic Richfield and had responsibilities in ARCO Chemical's hydrocarbon
feedstock group.
Michael J. Knesek was elected as the Principal Accounting Officer and a
Vice President of the General Partner in August 2000. Since 1990, Mr. Knesek, a
certified public accountant, has been the Controller and a Vice President of
EPCO. Mr. Knesek joined EPCO in 1981 as revenue accounting manager and has
served in various managerial accounting positions including general manager of
accounting. Mr. Knesek has over twenty-five years of experience in corporate and
partnership accounting, tax and finance.
W. Randall Fowler was elected as the Treasurer and a Vice President of
the General Partner in August 2000. Mr. Fowler joined EPCO as director of
investor relations in 1999. From 1995 to 1999, Mr. Fowler served in a number of
corporate finance and accounting-related capacities at NorAm Energy Corp.
including Director of Finance Wholesale Energy Marketing and Assistant
Treasurer. Mr. Fowler has over twenty years of experience in corporate finance,
investor relations, strategic planning and accounting.
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 2000. The Company believes all of these filings were
satisfied by the General Partner.
49
Due to administrative and record keeping errors in connection with
employee stock options issued by EPCO to certain officers and directors of the
General Partner, in December 2000 Form 4 reports were filed by: Richard H.
Bachmann with respect to being granted employee stock options in January 2000
(one transaction), by A. W. Bell with respect to being granted employee stock
options in December 1999 and January 2000 (three transactions) and the exercise
of employee stock options in May 1999 and August 2000 (two transactions), by
Charles E. Crain with respect to being granted employee stock options in
December 1999 and January and August 2000 (six transactions), by Michael A.
Creel with respect to being granted employee stock options in January and August
2000 (two transactions), by Ralph S. Cunningham with respect to being granted
employee stock options in January 2000 (one transaction), by W. Randall Fowler
with respect to being granted employee stock options in January 2000 (one
transaction), by Michael J. Knesek with respect to being granted employee stock
options in December 1999 and January 2000 (three transactions) and the exercise
of employee stock options in January 2000 (one transaction), by Lee W. Marshall,
Sr., with respect to being granted employee stock options in January 2000 (one
transaction), by William D. Ray with respect to being granted employee stock
options in December 1999 and January 2000 (four transactions) and the exercise
of employee stock options in January 2000 (2 transactions), by A.J. Teague with
respect to being granted employee stock options in January and July 2000 (two
transactions) and by A. Monty Wells with respect to being granted employee stock
options in December 1999 and January 2000 (two transactions). Also in December
2000 Form 4 reports were filed by Dan L. Duncan and EPCO with respect to the
issuance of employee stock options by EPCO to certain officers and directors of
the General Partner in December 1999 and January, July and August 2000 (thirteen
transactions).
As of March 13, 2001, 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.
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. For a discussion of this related party
transaction, see "EPCO Agreement" under Item 13.
Compensation of Directors
No additional remuneration is paid to employees of EPCO, Shell or the
General Partner who also serve as directors of the General Partner. During
fiscal 2000, the independent directors received an annual retainer of $24,000,
for which each agreed to participate in four regular meetings of the Board of
Directors and four Audit and Conflicts Committee meetings (plus nominal
out-of-pocket expenses in connection with attending the meetings). The
independent directors were also entitled to $500 per meeting when the number of
Board of Directors meetings and Audit and Conflicts Committee meetings exceeded
the four mentioned previously. Effective January 1, 2001, the General Partner
revised its independent director compensation policy to reflect (i) an annual
retainer of $18,000, (ii) $1,000 for each meeting of the Board of Directors
attended by a director, (iii) $500 for each meeting of a committee of the Board
of Directors attended by a committee member and (iv) an annual retainer of $500
for each chairman of a committee of the Board of Directors. Each director is
fully indemnified by the Company for his or her 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 March 22,
2001, regarding the beneficial ownership of (a) the Common Units, (b) the
Subordinated Units and (c) the Special Units of the Company by:
- all persons known by the General Partner to own beneficially more than
five percent of the Common Units;
- the directors and certain executive officers of the General Partner;
and
- all directors and executive officers of the General Partner as a
group.
50
For a discussion of the Company's Partners' Equity and the Units in general, see
Note 7 of the Notes to the Consolidated Financial Statements. Subordinated Units
and Special Units are non-voting.
Common Units Subordinated Units Special Units
------------ ------------------ -------------
Number of Percent Number of Percent Number of Percent
Units of Class Units of Class Units of Class
----- -------- ----- -------- ----- --------
EPCO (1) 33,552,915 71.7% 21,409,870 100.0% - 0.0%
Coral Energy LLC (2) 1,000,000 2.1% - 0.0% 16,500,000 100.0%
Dan Duncan (1,3) 35,070,115 71.7% 21,409,870 100.0% - 0.0%
O.S. Andras 180,600 0.4% - 0.0% - 0.0%
Randa L. Duncan - 0.0% - 0.0% - 0.0%
J. R. Eagan - 0.0% - 0.0% - 0.0%
J. A. Berget - 0.0% 0.0% - 0.0%
Dr. Ralph S. Cunningham - 0.0% - 0.0% - 0.0%
Curtis R. Frasier - 0.0% - 0.0% - 0.0%
Lee W. Marshall, Sr. - 0.0% - 0.0% - 0.0%
Richard S. Snell - 0.0% - 0.0% - 0.0%
Richard H. Bachmann 1,428 0.0% - 0.0% - 0.0%
Albert W. Bell (4) 34,252 0.1% - 0.0% - 0.0%
A.J. Teague (5) 58,000 0.1% - 0.0% - 0.0%
Michael A. Creel 5,000 0.0% - 0.0% - 0.0%
All directors and
executive officers
as a group
(19 persons) (6) 35,457,498 77.6% 21,409,870 100.0% - 0.0%
- -------------------------------------------------------------------------------------------------------------------
(1) EPCO holds its Units through a wholly-owned subsidiary, EPC Partners II,
Inc. Mr. Duncan owns 50.4% 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 General Partner.
The address of EPCO and Mr. Duncan is 2727 North Loop West, Houston, Texas
77008.
(2) Special Units were issued to Coral Energy as part of the TNGL acquisition.
(3) In addition to the Units held by EPCO, Dan Duncan has beneficial ownership
of an additional 1,517,200 Common Units held by the 1998, 1999 and 2000
Trusts (see Item 13).
(4) Includes options (under an EPCO Unit option plan) to purchase 22,681 Common
Units exercisable within 60 days of March 22, 2001.
(5) Includes options (under an EPCO Unit option plan) to purchase 50,000 Common
Units exercisable within 60 days of March 22, 2001.
(6) Includes options (under an EPCO Unit option plan) to purchase 101,403
Common Units exercisable within 60 days of March 22, 2001.
Item 13. Certain Relationships and Related Transactions.
Relationships with EPCO and its affiliates
The Company has an extensive ongoing relationship with EPCO and its
affiliates. EPCO is majority-owned and controlled by Dan L. Duncan, a director
and the Chairman of the Board of the General Partner. In addition, three other
members of the Board of Directors (O.S. Andras, Randa L. Duncan and Richard H.
Bachmann) and the remaining executive officers (see Item 10 for a complete
listing of the executive officers) of the General Partner are employees of EPCO.
The principal business activity of the General Partner is to act as the managing
partner of the Company.
Mr. Duncan owns 50.4% 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 of the General Partner. The Units owned by EPCO are held by
EPC Partners II, Inc. ("EPC II"), a wholly-owned subsidiary of EPCO. At December
51
31, 2000, EPC II owned 33,552,915 Common Units and 21,409,870 Subordinated
Units, representing a 39.3% interest and 25.1% interest, respectively, in the
Company. In addition, EPCO and Dan Duncan, LLC collectively own 70% of the
General Partner which in turn owns a combined 2% interest in the Company. In
addition, the following affiliates of EPCO own Common Units (amounts as of
December 31, 2000):
- Enterprise Products 1998 Unit Option Plan Trust (the "1998 Trust")
held 1,150,000 Common Units. The 1998 Trust was formed for the purpose
of granting options in the Company's Units to management and certain
key employees. The 1998 Trust is no longer accumulating the Company's
Units.
- Enterprise Products 2000 Rabbi Trust (the "2000 Trust") held 100,000
Common Units. The 2000 Trust was formed for general investment
purposes and for granting additional options in Company's Units to
management and certain key employees. The 2000 Trust may purchase
additional Units on the open market or through privately negotiated
transactions.
The Company's agreements with EPCO are not the result of arm's-length
transactions, and there can be no assurance 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.
Another affiliate of EPCO and the Company, EPOLP 1999 Grantor Trust
(the "1999 Trust"), was formed for the purpose of funding liabilities of a
long-term incentive employee benefit plan. As of December 31, 2000, the 1999
Trust held 267,200 Common Units.
EPCO Agreement
The Company has no employees. All management, administrative and
operating functions are performed by employees of EPCO pursuant to the EPCO
Agreement entered into by EPCO, the General Partner and the Company in July
1998. Under the terms of the agreement, EPCO agreed to (i) manage the business
and affairs of the Company; (ii) employ the operating personnel involved in the
Company's business for which EPCO is reimbursed by the Company at cost (based
upon EPCO's actual salary costs and related fringe benefits); (iii) allow the
Company to participate as named insureds in EPCO's current insurance program
with the costs being allocated among the parties on the basis of formulas set
forth in the agreement; (iv) grant an irrevocable, non-exclusive worldwide
license to all of the trademarks and trade names used in its business to the
Company; (v) indemnify the Company against any losses resulting from certain
lawsuits; and (vi) 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 railcars to the Company for $1 per year
and assigned its purchase options under such leases to the Company. EPCO is
liable for the lease payments associated with these assets. Operating costs and
expenses (as shown on the audited Statements of Consolidated Operations) include
charges for EPCO's employees who operate the Company's various facilities.
Pursuant to the EPCO Agreement, the charges for EPCO's employees who
manage the business and affairs of the Company are reimbursed only under certain
circumstances. SG&A charges to EPCO resulting from the hiring of additional
personnel and other costs associated with the expansion and business development
activities of the Company (through the construction of new facilities or the
completion of acquisitions) are reimbursed by the Company. In lieu of
reimbursement for all other SG&A costs incurred by EPCO, EPCO is entitled to
receive an annual Administrative Services Fee (the "EPCO Fees", initially set at
$12.0 million).
The General Partner, with the approval and consent of the Audit and
Conflicts Committee, may agree to increases in the EPCO Fees of up to 10% each
contract year (defined as August 1 to July 31) during the 10-year term of the
EPCO Agreement. Since the initial contract year ending July 31, 1999, the Audit
and Conflicts Committee has approved two increases in the EPCO Fees. The annual
fee was increased to $13.2 million for the second contract year and subsequently
raised to $14.5 million for the third contract year. The following is a summary
of the SG&A amounts paid to EPCO by the Company during the last three years:
52
2000 1999 1998 (1)
------------------------------------
(in millions of dollars)
------------------------------------
EPCO Fees $ 13.8 $ 12.5 $ 5.1
Expansion-related costs reimbursed to
EPCO by the Company 14.5 - -
------------------------------------
Total $ 28.3 $ 12.5 $ 5.1
====================================
- ---------------------------------------------------------------------------------------
(1) Amount reflects the five-month period during which the EPCO Agreement
was outstanding in 1998 after the initial public offering of the
Company in late July 1998. As noted earlier, the initial payments made
to EPCO were on the basis of $12.0 million annually ($1.0 million per
month).
Other Related Party Transactions with EPCO or its affiliates
The following is a summary of the other ongoing significant
relationships and transactions between EPCO and the Company and its affiliates:
- EPCO is the operator of the plants and facilities owned by BEF and
EPIK and is paid a management fee by these entities in lieu of
reimbursement for the actual cost of providing management services.
BEF and EPIK paid $0.9 million in management fees to EPCO during 2000.
- EPCO and the Company have entered into an agreement pursuant to which
EPCO provides trucking services involving the loading and
transportation of NGL products for the Company. EPCO recorded $7.9
million in revenues for these services during 2000.
- In the normal course of business, the Company may, on occasion, engage
in transactions with EPCO (including its wholly-owned subsidiaries)
involving the buying and selling of NGL products. The Company recorded
net sales to EPCO of $3.2 million during 2000.
Relationships with Shell
Shell, through its subsidiary Coral Energy, owns approximately 20.5% of
the Company and 30.0% of the General Partner. Three members of the Board of
Directors of the General Partner (J.R. Eagan, J.A. Berget and Curtis R. Frasier)
are employees of Shell.
Shell is a significant customer of the gas processing assets. 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:
- 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.
For fiscal 2000, revenues from Shell aggregated $292.7 million while purchases
from Shell totaled $736.7 million.
See Note 10 of the Notes to the Consolidated Financial Statements for additional
information regarding related party transactions.
53
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
*2.1 Purchase and Sale Agreement between Coral Energy, LLC and Enterprise
Products Operating L.P. dated ad of September 22, 2000. (Exhibit 10.1
to Form 8-K filed on September 26, 2000).
*3.1 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).
*3.2 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 as
Exhibit "D" to the Schedule 13D filed September 27, 1999 by Tejas
Energy, LLC).
*3.3 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).
*3.4 Amendment No. 1 to Second Amended and Restated Agreement of Limited
Partnership of Enterprise Products Partners L.P. dated June 9, 2000.
(Exhibit 3.6 to Form 10-Q filed August 11, 2000).
*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 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 as
Exhibit "C" to the Schedule 13D filed September 27, 1999 by Tejas
Energy, LLC).
*4.3 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 as
Exhibit "B" to the Schedule 13D filed September 27, 1999 by Tejas
Energy, LLC).
*4.4 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 as Exhibit "E" to
the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
*4.5 Form of Indenture dated as of March 15, 2000, among Enterprise Products
Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and First Union National Bank, as Trustee. (Exhibit 4.1 on
Form 8-K filed March 10, 2000).
*4.6 Form of Global Note representing $350 million principal amount of 8.25%
Senior Notes Due 2005. (Exhibit 4.2 on Form 8-K filed March 10, 2000).
*4.7 $250 Million Multi-Year Revolving Credit Agreement among Enterprise
Products Operating L.P., First Union National Bank, as administrative
agent; Bank One, NA, as documentation agent; and The Chase Manhattan
54
Bank, as syndication agent and the Several Banks from time to time
parties thereto dated November 17, 2000. (Exhibit 4.2 on Form 8-K filed
January 25, 2001).
*4.8 $150 Million 364-Day Revolving Credit Agreement between Enterprise
Products Operating L.P. and First Union National Bank, as
administrative agent; Bank One, NA, as documentation agent; and The
Chase Manhattan Bank, as syndication agent and the Several Banks from
time to time parties thereto dated November 17, 2000. (Exhibit 4.3 on
Form 8-K filed January 25, 2001).
*4.9 Guaranty Agreement (relating to the $250 Million Multi-Year Revolving
Credit Agreement) by Enterprise Products Partners L.P. in favor of
First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001).
*4.10 Guaranty Agreement (relating to the $150 Million 364-Day Revolving
Credit Agreement) by Enterprise Products Partners L.P. in favor of
First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001).
*4.11 Form of Global Note representing $450 million principal amount of 7.50%
Senior Notes due 2011. (Exhibit 4.1 to Form 8-K filed January 25,
2001).
*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
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 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).
*10.8 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).
*10.9 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
55
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).
*10.10 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).
*10.11 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).
*10.12 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).
12.1 Computation of ratio of earnings to fixed charges for the years ended
December 31, 2000, 1999, 1998, 1997 and 1996.
21.1 List of subsidiaries.
23.1 Consent of Deloitte & Touche LLP.
- ---------------------
* Asterisk indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith
(b) Reports on Form 8-K
None.
56
INDEX TO FINANCIAL STATEMENTS
Page
Enterprise Products Partners L.P.
Independent Auditors' Report F-2
Consolidated Balance Sheets as of December 31, 2000 and 1999 F-3
Statements of Consolidated Operations
for the Years Ended December 31, 2000, 1999 and 1998 F-4
Statements of Consolidated Cash Flows
for the Years Ended December 31, 2000, 1999 and 1998 F-5
Statements of Consolidated Partners' Equity
for the Years Ended December 31, 2000, 1999 and 1998 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, 2000 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, 2000. 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 auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the consolidated financial position of the Company at
December 31, 2000 and 1999, and the results of its consolidated operations and
its consolidated cash flows for each of the years in the three-year period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America. 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.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2001
F-2
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Dollars in Thousands)
December 31,
---------------------------------------
ASSETS 2000 1999
---------------------------------------
Current Assets
Cash and cash equivalents $ 60,409 $ 5,230
Accounts receivable - trade, net of allowance for doubtful accounts of
$10,916 in 2000 and $15,897 in 1999 409,085 262,348
Accounts receivable - affiliates 6,533 56,075
Inventories 93,222 39,907
Current maturities of participation in notes receivable from
unconsolidated affiliates 6,519
Prepaid and other current assets 12,143 14,459
---------------------------------------
Total current assets 581,392 384,538
Property, Plant and Equipment, Net 975,322 767,069
Investments in and Advances to Unconsolidated Affiliates 298,954 280,606
Intangible assets, net of accumulated amortization of $5,374 in
2000 and $1,345 in 1999 92,869 61,619
Other Assets 2,984 1,120
---------------------------------------
Total $ 1,951,521 $ 1,494,952
=======================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of long-term debt $ 129,000
Accounts payable - trade $ 96,559 69,294
Accounts payable - affiliate 56,447 64,780
Accrued gas payables 377,126 233,360
Accrued expenses 21,488 16,510
Other current liabilities 34,759 18,176
---------------------------------------
Total current liabilities 586,379 531,120
Long-Term Debt 404,000 166,000
Other Long-Term Liabilities 15,613 296
Minority Interest 9,570 8,071
Commitments and Contingencies
Partners' Equity
Common Units (46,524,515 Units outstanding at December 31, 2000
and 45,552,915 at December 31, 1999) 514,896 439,196
Subordinated Units (21,409,870 Units outstanding in 2000 and 1999) 165,253 136,618
Special Units (16,500,000 Units outstanding at December 31, 2000
and 14,500,000 Units at December 31, 1999) 251,132 210,436
Treasury Units acquired by Trust, at cost (267,200 Units outstanding at
December 31, 2000 and 1999) (4,727) (4,727)
General Partner 9,405 7,942
---------------------------------------
Total Partners' Equity 935,959 789,465
---------------------------------------
Total $ 1,951,521 $ 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,
----------------------------------------------------
2000 1999 1998
----------------------------------------------------
REVENUES
Revenues from consolidated operations $ 3,049,020 $ 1,332,979 $ 738,902
Equity income in unconsolidated affiliates 24,119 13,477 15,671
----------------------------------------------------
Total 3,073,139 1,346,456
754,573
COST AND EXPENSES
Operating costs and expenses 2,801,060 1,201,605 685,884
Selling, general and administrative 28,345 12,500 18,216
----------------------------------------------------
Total 2,829,405 1,214,105
704,100
----------------------------------------------------
OPERATING INCOME 243,734 132,351 50,473
----------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (33,329) (16,439) (15,057)
Interest income from unconsolidated affiliates 1,787 1,667 809
Dividend income from unconsolidated affiliates 7,091 3,435 -
Interest income - other 3,748 886 772
Other, net (272) (379) 358
----------------------------------------------------
Other income (expense)
(20,975) (10,830) (13,118)
----------------------------------------------------
INCOME BEFORE EXTRAORDINARY ITEM
AND MINORITY INTEREST 222,759 121,521 37,355
Extraordinary charge on early extinguishment of debt (27,176)
----------------------------------------------------
INCOME BEFORE MINORITY INTEREST 222,759 121,521 10,179
MINORITY INTEREST (2,253) (1,226) (102)
----------------------------------------------------
NET INCOME $ 220,506 $ 120,295 $ 10,077
====================================================
BASIC EARNINGS PER UNIT
Income before extraordinary item and
minority interest $ 3.28 $ 1.80 $ 0.62
====================================================
Net income $ 3.25 $ 1.79 $ 0.17
====================================================
DILUTED EARNINGS PER UNIT
Income before extraordinary item and
minority interest $ 2.67 $ 1.65 $ 0.62
====================================================
Net income $ 2.64 $ 1.64 $ 0.17
====================================================
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,
--------------------------------------------
2000 1999 1998
--------------------------------------------
OPERATING ACTIVITIES
Net income $ 220,506 $ 120,295 $ 10,077
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 41,016 25,315 19,194
Equity in income of unconsolidated affiliates (24,119) (13,477) (15,671)
Distributions received from unconsolidated affiliates 37,267 6,008 9,117
Leases paid by EPCO 10,537 10,557 4,010
Minority interest 2,253 1,226 102
(Gain) loss on sale of assets 2,270 123 (276)
Net effect of changes in operating accounts 70,958 27,906 (63,171)
--------------------------------------------
Operating activities cash flows 360,688 177,953 (9,442)
--------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (243,913) (21,234) (8,360)
Proceeds from sale of assets 92 8 1,887
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 6,519 19,979 7,228
Investments in and advances to unconsolidated affiliates (31,496) (61,887) (26,842)
--------------------------------------------
Investing activities cash flows (268,798) (271,229) (59,812)
--------------------------------------------
FINANCING ACTIVITIES
Net proceeds from sale of common units 243,296
Long-term debt borrowings 599,000 350,000 90,000
Long-term debt repayments (490,000) (154,923) (257,413)
Debt issuance costs (4,043) (3,135) (1,735)
Net decrease in restricted cash 4,522
Cash dividends paid to partners (139,577) (111,758) (21,645)
Cash dividends paid to minority interest by Operating Partnership (1,429) (1,140)
Units acquired by consolidated trust (4,727)
Unit repurchases (770)
Cash contributions from EPCO to minority interest 108 86 2,478
--------------------------------------------
Financing activities cash flows (36,711) 74,403 59,503
--------------------------------------------
CASH CONTRIBUTION FROM EPCO 14,913
NET CHANGE IN CASH AND CASH EQUIVALENTS 55,179 (18,873) 5,162
CASH AND CASH EQUIVALENTS, JANUARY 1 5,230 24,103 18,941
--------------------------------------------
CASH AND CASH EQUIVALENTS, DECEMBER 31 $ 60,409 $ 5,230 $ 24,103
============================================
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
--------------------------------------------------------------------------------------
Balances, 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)
--------------------------------------------------------------------------------------
Balances, December 31, 1998 433,082 123,829 5,625 562,536
Net income 80,998 38,094 1,203 120,295
Leases paid by EPCO 7,109 3,342 106 10,557
Special Units issued to Coral
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 $ (4,727) (4,727)
--------------------------------------------------------------------------------------
Balances, December 31, 1999 439,196 136,618 210,436 (4,727) 7,942 789,465
Net income 148,656 69,253 2,597 220,506
Leases paid by EPCO 7,117 3,315 105 10,537
Additional Special Units issued to
Coral Energy, LLC in connection
with contingency agreement 55,241 557 55,798
Conversion of 1.0 million Coral
Energy, LLC Special Units into
Common Units 14,513 (14,513) -
Units repurchased and retired in
connection with buy-back program (687) (43) (32) (8) (770)
Cash distributions to Unitholders (93,899) (43,890) (1,788) (139,577)
--------------------------------------------------------------------------------------
Balances, December 31, 2000 $ 514,896 $ 165,253 $ 251,132 $ (4,727) $ 9,405 $ 935,959
======================================================================================
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. and its consolidated subsidiaries (the
"Company") is a publicly-traded Delaware limited partnership listed on the New
York Stock Exchange under symbol "EPD". The Company and its operating
subsidiary, Enterprise Products Operating L.P. (the "Operating Partnership")
were formed in April 1998 to own and operate the natural gas liquids ("NGL")
business of Enterprise Products Company ("EPCO"). The Company conducts
substantially all of its business through its Operating Partnership, in which it
owns a 98.9899% limited partner interest. Enterprise Products GP, LLC (the
"General Partner") owns 1.0101% of the Operating Partnership and 1% of the
Company and serves as the general partner of both entities. 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. The consolidated financial statements include the accounts of the Company
and its majority-owned subsidiaries, after elimination of all material
intercompany accounts and transactions. In general, 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. Investments in
which the Company owns less than 20% are accounted for using the cost method
unless the Company exercises significant influence over operating and financial
policies of the investee in which case the investment is accounted for using the
equity method.
Certain reclassifications have been made to the prior years' financial
statements to conform to the current year presentation. These reclassifications
had no effect on previously reported results of consolidated operations.
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.
DERIVATIVE INSTRUMENTS such as swaps, forwards and other contracts to manage the
price risks associated with inventories, firm commitments and certain
anticipated transactions are used by the Company. Prior to the implementation of
SFAS 133 in January 2001 (see Note 12), the Company deferred the impact of
changes in the market value of these contracts until such time as the hedged
transaction was settled. At that time, the impact of the changes in fair value
of these contracts would be recognized in earnings.
Under SFAS 133, the Company is required to recognize in earnings changes in fair
value of these derivative instruments that are not offset by changes in the fair
value of the inventories, firm commitments and certain anticipated transactions.
F-7
The effective portion of these hedged transactions will be deferred until the
firm commitment or anticipated transaction affects earnings. To qualify as a
hedge, the item to be hedged must expose the Company to commodity or interest
rate risk and the hedging instrument must reduce that exposure and meet the
hedging requirements of SFAS 133. Any contracts held or issued that do not meet
the requirements of a hedge (as defined by SFAS 133) will be recorded at fair
value on the balance sheet and any changes in that fair value recognized in
earnings. If a contract designated as a hedge of commodity risk is terminated,
the associated gain or loss is deferred and recognized in income when the firm
commitment or anticipated transaction affects earnings. A contract designated as
a hedge of an anticipated transaction that is no longer likely to occur is
immediately recognized in earnings.
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.
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. During 2000, 1.0 million Special Units
were converted into Common Units. See Notes 7 and 8 for additional information
on the capital structure and earnings per Unit computation.
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, 2000 were not significant to the consolidated
financial statements. Costs of environmental compliance and monitoring
aggregated $1.1 million, $0.9 million and $1.4 million for the years ended
December 31, 2000, 1999 and 1998. The Company's estimated liability for
environmental remediation is not discounted.
EXCESS COST OVER UNDERLYING EQUITY IN NET ASSETS (or "excess cost") denotes the
excess of the Company's cost (purchase price) over the underlying equity in net
assets of K/D/S Promix, LLC and Dixie Pipeline Company. The excess cost
associated with the Company's investment in K/D/S Promix is being amortized
using the straight-line method over a period of 20 years. The excess cost
related to the Company's investment in Dixie Pipeline Company is being amortized
using the straight-line method over a period of 35 years due to its
classification as a pipeline asset. The excess cost of K/D/S Promix, LLC and
Dixie Pipeline Company is reflected in the Company's investments in and advances
to unconsolidated affiliates for these entities. See Note 4 for a further
discussion of the excess cost related to these investments.
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.
FEDERAL INCOME TAXES are not provided because the Company is a master limited
partnership. As a result, the Company's earnings or losses for Federal income
tax purposes are included in the tax returns of the individual partners.
Accordingly, no recognition has been given to income taxes in the accompanying
financial statements of the Company. State income taxes are not material to the
Company. Net earnings for financial statement purposes may differ significantly
from taxable income reportable to unitholders as a result of differences between
the tax basis and financial reporting basis of assets and liabilities and the
taxable income allocation requirements under the partnership agreement.
F-8
INVENTORIES, consisting of NGLs and NGL products, are carried at the lower of
average cost or market.
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, both of which
were initially recorded in 1999. The $89.3 million in intangibles related to the
natural gas processing agreement is being amortized over the contract term. The
$9.0 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.
See Note 2 for additional information regarding these assets.
LONG-LIVED ASSETS 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 any of the
periods presented.
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 and
improvements to and major renewals of existing assets are capitalized and
depreciated using the straight-line method over the estimated useful life of the
new equipment or modifications. 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.
REVENUE is recognized by the Company's five reportable business segments using
the following criteria: (a) persuasive evidence of an exchange arrangement
exists, (b) delivery has occurred or services have been rendered, (c) the
buyer's price is fixed or determinable and (d) collectibility is reasonably
assured. When the contracts settle (i.e., either physical delivery of product
has taken place or the services designated in the contract have been performed),
a determination of the necessity of an allowance is made and recorded
accordingly.
In the Fractionation segment, the Company enters into NGL fractionation
contracts, isomerization contracts and propylene fractionation and merchant
contracts. Under the propylene merchant contracts, revenue is recognized once
the products have been effectively delivered to the third party. Regarding the
various NGL and propylene fractionation and isomerization contracts whereby a
toll fee is collected, revenue is recognized once the contract services have
been performed. Fractionation and isomerization 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 of these
operations. The propylene merchant contracts are based upon market rates or spot
prices as determined in the individual contracts.
As part of its Pipeline operations, the Company enters into pipeline contracts,
storage contracts and product loading contracts. Under the pipeline contracts,
revenue is recognized once the products have been physically delivered to the
third party through the pipeline. Under the storage contracts whereby a fee is
collected based upon the number of days in storage multiplied by the storage
rate by product, revenue is recognized ratably over the length of the storage
contract. In the absence of a set period under contractual terms, storage
revenue is recognized based upon a daily rate as specified in the applicable
contract. Revenues for product loading contracts (applicable to the operations
of EPIK, an unconsolidated affiliate) are recorded once the loading services
have been performed. Pipeline contracts typically include a throughput fee per
gallon as stated in the contract or as regulated by the Federal Energy
Regulatory Committee ("FERC"). Storage and loading rates are stated in the
individual contracts.
As part of its Processing business, the Company entered into a 20-year natural
gas processing agreement with Shell ("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. This contract serves as an
arrangement between the Company and Shell. In addition to the Shell Processing
Agreement, the Company has contracts to process natural gas for other third
parties.
Under these contracts, the price of the Company's services is based upon
contractual terms with Shell or other third parties and may be specified as
either (i) a cash fee or (ii) the retention of a percentage of the NGLs
extracted from the natural gas stream. If a cash fee for services is stipulated
by the contract, the Company records revenue once the natural gas has been
processed and sent back to Shell or the other third parties (i.e., delivery has
taken place).
F-9
If the contract stipulates that the Company retains a percentage of the NGLs
extracted as payment for its services, the Processing segment's merchant
business records revenues when it sells and delivers such NGL products to third
parties. The Processing segment's merchant business may also buy and sell NGLs
in the open market. The revenues recorded for these contracts are recognized
upon delivery of the products specified in each individual contract. Pricing
under both types of arrangements is based upon market prices plus or minus other
determining factors specific to each contract such as location pricing
differentials.
The Octane Enhancement segment consists of the Company's equity interest in
Belvieu Environmental Fuels ("BEF") which owns and operates a facility that
produces motor gasoline additives to enhance octane. This facility currently
produces MTBE. BEF's operations primarily occur as a result of a contract with
Sunoco, Inc. ("Sun") whereby Sun has agreed to purchase 100 percent of the MTBE
output at market-related negotiated prices. Under the contract with Sun, 100
percent of the MTBE production is delivered to Sun and Sun is obligated to take
title to the product. Revenue is recognized once the product has been physically
delivered to Sun.
The Other segment is primarily comprised of fee-based marketing services. The
Company performs NGL marketing services for a small number of customers for
which it charges a commission. Commissions are based on either a percentage of
the final sales price negotiated on behalf of the client or a fixed-fee per
gallon based on the volume sold for the client. Revenues are recorded at the
time the marketing services are complete.
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 accounting principles generally accepted
in the United States of America. Actual results could differ from these
estimates.
2. ACQUISITIONS
Acquisition of Kinder Morgan and EPCO interest in Mont Belvieu Fractionation
Facility in July 1999
Effective July 1, 1999, the Company acquired Kinder Morgan Operating LP "A"'s
25% interest and EPCO's 0.5% 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 9.0
Liabilities (3.7)
----------------
Total purchase price $ 41.5
================
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 years ending December 31, 2000 and 1999, $0.5 million and $0.2 million of
such amortization was charged to operating costs and expenses.
Acquisition of Tejas Natural Gas Liquids, LLC in August 1999
Effective August 1, 1999, the Company acquired Tejas Natural Gas Liquids, LLC
("TNGL") from a subsidiary of Tejas Energy, LLC, now Coral Energy, LLC, an
affiliate of Shell Oil Company ("Shell") for $166 million in cash and the
issuance of 14.5 million non-distribution bearing, convertible Special Units
valued at $210.4 million. 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
F-10
fractionation, transportation, storage and marketing in Louisiana and
Mississippi. TNGL has varying interests in eleven natural gas processing plants,
four NGL fractionation facilities, four NGL storage facilities, approximately
1,500 miles of pipelines and is party to the Shell Processing Agreement, a 20
year natural gas processing agreement.
The cash portion of the purchase price was funded with borrowings under the
Company's $350 million bank credit facility. The value of the 14.5 million
non-distribution bearing, convertible Special Units was determined using both
present value and Black Scholes Model methodologies and was within a range
provided by an independent investment banker.
In addition to the initial purchase price, the Company agreed to issue to Shell
6.0 million non-distribution bearing, convertible Contingency Units provided
that Shell meets certain performance criteria in calendar years 2000 and 2001
(see Note 7). If Shell met the performance criteria for 2000, 3.0 million of the
Contingency Units would be issued; likewise, if Shell met the 2001 goals, the
remaining 3.0 million Contingency Units would be issued. On June 28, 2000, Shell
met the performance criteria for 2000 and in accordance with its contingent Unit
agreement with Shell, the Company issued the 3.0 million Contingency Units
(deemed "Special Units" once they are issued) on August 1, 2000. The value of
these new Special Units was determined to be $55.2 million using present value
techniques.
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. The
following table reflects the allocation of the initial purchase price, the value
of the 3.0 million new Special Units and purchase accounting adjustments (in
millions):
Current Assets $ 124.3
Investments 128.6
Property 216.9
Intangible asset 89.3
Liabilities (147.4)
----------------
Total Purchase Price $ 411.7
================
The $89.3 million intangible asset is the value assigned to the Shell Processing
Agreement and is being amortized over the contract term. For the years ending
December 31, 2000 and 1999, $3.6 million and $1.1 million of such amortization
was charged to operating costs and expenses. Beginning in December 2000, such
amortization increased to $0.4 million per month. The assets, liabilities and
results of operations of TNGL are included with those of the Company as of
August 1, 1999. If the remainder of the Contingency Units are issued in 2001 (or
at such later date as agreed to by the parties), the purchase price and value of
the Shell Processing Agreement will be adjusted accordingly. Historical
information for periods prior to August 1, 1999 do not reflect any impact
associated with the TNGL acquisition.
Pro Forma effect of Acquisitions
The following table presents unaudited pro forma information for the years ended
December 31, 1999 and 1998 as if the acquisition of TNGL and the Mont Belvieu
fractionator facility had been made as of the beginning of the periods
presented. The pro forma information is based upon information currently
available to and certain estimates and assumptions by management and, as a
result, are not necessarily indicative of the financial results of the Company
had the transactions actually occurred on these dates. Likewise, the unaudited
pro forma information is not necessarily indicative of future financial results
of the Company.
F-11
1999 1998
-------------------------------------
Revenues $ 1,726,516 $ 1,366,450
=====================================
Income before extraordinary item
and minority interest $ 136,415 $ 42,054
=====================================
Net income $ 135,037 $ 14,728
=====================================
Allocation of net income to
Limited partners $ 133,687 $ 14,581
=====================================
General Partner $ 1,350 $ 147
=====================================
Units used in earning per Unit calculations
Basic 66,710 60,124
=====================================
Diluted 81,210 74,624
=====================================
Income per Unit before minority interest
Basic $ 2.02 $ 0.69
=====================================
Diluted $ 1.66 $ 0.56
=====================================
Net income per Unit
Basic $ 2.00 $ 0.24
=====================================
Diluted $ 1.65 $ 0.20
=====================================
Acadian Gas, LLC
On September 25, 2000, the Company announced that it had executed a definitive
agreement to purchase Acadian Gas, LLC ("Acadian") from Coral Energy, an
affiliate of Shell, for $226 million in cash, inclusive of working capital.
Acadian's assets are comprised of the 438-mile Acadian, 577-mile Cypress and
27-mile Evangeline natural gas pipeline systems, which together have over one
billion cubic feet ("Bcf") per day of capacity. These natural gas pipeline
systems are wholly-owned by Acadian with the exception of the Evangeline system
in which Acadian holds an approximate 49.5% interest. The system includes a
leased natural gas storage facility at Napoleonville, Louisiana. Completion of
this transaction is subject to certain conditions, including regulatory
approvals. The purchase is expected to be completed during the first quarter of
2001.
3. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment and accumulated depreciation are as follows:
Estimated
Useful Life
in Years 2000 1999
---------------------------------------------------
Plants and pipelines 5-35 $1,108,519 $ 875,773
Underground and other storage facilities 5-35 109,760 103,578
Transportation equipment 3-35 2,620 2,117
Land 14,805 14,748
Construction in progress 34,358 32,810
----------------------------------
Total 1,270,062 1,029,026
Less accumulated depreciation 294,740 261,957
----------------------------------
Property, plant and equipment, net $ 975,322 $ 767,069
==================================
Depreciation expense for the years ended December 31, 2000, 1999 and 1998 was
$33.3 million, $22.4 million and $18.6 million, respectively.
F-12
4. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
The Company owns interests in a number of related businesses that are accounted
for under the equity method or cost method. The investments in and advances to
these unconsolidated affiliates are grouped according to the operating segment
to which they relate. For a general discussion of the Company's business
segments, see Note 15.
At December 31, 2000, the Company's Fractionation operating segment included the
following unconsolidated affiliates (all accounted for using the equity method):
- Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest
in a natural gas liquid ("NGL") fractionation facility located in
southeastern Louisiana.
- Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest in
a propylene concentration unit located in southeastern Louisiana that
became operational in July 2000.
- K/D/S Promix LLC ("Promix") - a 33.33% interest in a NGL fractionation
facility and related storage facilities located in south Louisiana.
The Company's investment includes excess cost over the underlying
equity in the net assets of Promix of $8.0 million which is being
amortized using the straight-line method over a period of 20 years.
The unamortized balance of excess cost over the underlying equity in
the net assets of Promix was $7.4 million at December 31, 2000.
The combined results of operations for the last three years and financial
position for the last two years of the Company's Fractionation equity method
investments are summarized below:
As of or for the
Year Ended December 31,
2000 1999 1998
----------------------------------------------------
BALANCE SHEET DATA:
Current assets $ 31,168 $ 47,235
Property, plant and equipment, net 264,618 245,855
Other assets 67 854
-----------------------------------
Total assets $ 295,853 $ 293,944
===================================
Current liabilities $ 13,661 $ 32,646
Other liabilities - -
Combined equity 282,192 261,298
-----------------------------------
Total liabilities and combined equity $ 295,853 $ 293,944
===================================
INCOME STATEMENT DATA:
Revenues $ 71,287 $ 36,293 $ 31,881
Gross operating margin 33,240 14,970 12,154
Operating income 19,997 5,930 9,840
Net income 20,661 4,200 9,271
At December 31, 2000, the Company's Pipeline operating segment included the
following unconsolidated affiliates (all accounted for using the equity method):
- EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively,
"EPIK") - a 50% aggregate interest in a refrigerated NGL marine
terminal loading facility located in southeast Texas. The Company owns
50% of EPIK Terminalling L.P. which owns 99% of such facilities. The
Company owns 50% of EPIK Gas Liquids, LLC which owns 1% of such
facilities. The Company does not exercise control over these entities;
therefore, it is precluded from consolidating such entities into its
financial statements.
- Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in a
NGL pipeline system located in southeastern Louisiana.
F-13
- Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33%
interest in a NGL pipeline system located in Louisiana, Mississippi,
and Alabama.
- Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.7% interest in a NGL
pipeline system located in south Louisiana.
- Dixie Pipeline Company ("Dixie") - a 19.9% interest in a corporation
owning a 1,301-mile propane pipeline and associated facilities
extending from Mont Belvieu, Texas to North Carolina. The Company
acquired an 11.5% interest in Dixie as a result of the TNGL
acquisition. On October 6, 2000, the Company purchased an additional
8.4% interest in Dixie from Conoco Pipe Line Company for $19.4 million
in cash. As a result of this purchase, the Company is able to exercise
significant influence over Dixie's operating and financial activities
and changed its method of accounting for the investment in Dixie from
the cost method to the equity method. This change in accounting
methods for Dixie resulted in a immaterial cumulative effect of $0.2
million in expense being recorded in 2000 relating to the period in
which the Company held an ownership interest in Dixie during 1999. The
cumulative effect is recorded as a reduction of current year equity
earnings from Dixie due to its immaterial nature.
As a result of changing from the cost method to the equity method, the
Company's investment in Dixie includes excess cost over the underlying
equity in the net assets of $37.4 million which is being amortized
using the straight-line method over a period of 35 years due to its
classification as a pipeline asset. During 2000, the Company recorded
amortization expense associated with this excess cost of $0.9 million
(including the cumulative effect of $0.2 million related to 1999
mentioned previously), which is reflected in the equity earnings of
Dixie. The unamortized balance of excess cost over the underlying
equity in the net assets of Dixie was $36.3 million at December 31,
2000.
The combined results of operations for the last three years and financial
position for the last two years of the Company's Pipeline equity method
investments are summarized below:
As of or for the
Year Ended December 31,
----------------------------------------------------
2000 1999 1998
----------------------------------------------------
BALANCE SHEET DATA:
Current assets $ 25,464 $ 26,483
Property, plant and equipment, net 188,724 193,237
Other assets 3,666 3,172
-----------------------------------
Total assets $ 217,854 $ 222,892
===================================
Current liabilities $ 31,085 $ 32,873
Other liabilities 4,018 4,317
Combined equity 182,751 185,702
-----------------------------------
Total liabilities and combined equity $ 217,854 $ 222,892
===================================
INCOME STATEMENT DATA:
Revenues $ 96,270 $ 52,386 $ 3,982
Gross operating margin 51,414 24,845 1,869
Operating income 41,757 19,988 1,775
Net income 31,241 15,637 1,777
At December 31, 2000, the Octane Enhancement operating segment included Belvieu
Environmental Fuels ("BEF") in which the Company owns a 33.33% interest. BEF is
a partnership that owns a methyl tertiary butyl ether ("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 elect not to participate in these programs, lessen the
requirements for oxygenates or favor the use of non-isobutane based oxygenated
fuels reduce the demand for MTBE and could have an adverse effect on the
Company's results of operations.
F-14
In recent years, MTBE has been detected in water supplies. The major source of
the ground water contamination appears to be leaks from underground storage
tanks. Although these detections have been limited and the great majority of
these detections have been well below levels of public health concern, there
have been actions calling for the phase-out of MTBE in motor gasoline in various
federal and state governmental agencies.
In light of these developments, the owners of BEF are 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. Depending upon the type of alkylate process
chosen and the level of alkylate production desired, the cost to convert the
facility from MTBE production to alkylate production can range from $20 million
to $90 million, with the Company's share of these costs ranging from $6.7
million to $30 million.
BEF has a ten-year off-take agreement with Sun Company, Inc. ("Sun") under which
Sun is required to purchase all of the plant's MTBE production through September
2004. Through May 31, 2000, Sun was required to pay for the MTBE using the
following pricing structure:
- for the first 193,450,000 gallons of MTBE produced per contract year,
the higher of (i) a contractual floor price or (ii) a toll or spot
market-related price (as defined within the agreement); and,
- a spot market-related price for all volumes in excess of this amount.
The floor price was a price sufficient to cover essentially all of BEF's
operating costs plus principal and interest payments on its bank term loan. In
general, Sun paid the floor price during the periods in which it was in effect.
Beginning June 1, 2000 through the remainder of the agreement, the pricing on
all MTBE delivered to Sun changed to a market-related negotiated price which
generally approximates Gulf Coast MTBE spot prices. The market-related
negotiated price is subject to fluctuations in commodity prices for MTBE. MTBE
spot prices are generally higher during the April to September period of each
year which corresponds with the summer driving season.
The results of operations for the last three years and financial position for
the last two years of the Company's investments in BEF are summarized below:
As of or for the
Year Ended December 31,
----------------------------------------------------
2000 1999 1998
----------------------------------------------------
BALANCE SHEET DATA:
Current Assets $ 20,640 $ 44,261
Property, plant and equipment, net 150,603 161,390
Other assets 11,439 8,313
-----------------------------------
Total assets $ 182,682 $ 213,964
===================================
Current liabilities $ 8,042 $ 41,317
Other liabilities 5,779 4,323
Combined equity 168,861 168,324
-----------------------------------
Total liabilities and combined equity $ 182,682 $ 213,964
===================================
INCOME STATEMENT DATA:
Revenues $ 258,180 $ 193,219 $ 182,001
Gross operating margin 43,328 43,479 47,262
Operating income 30,529 30,025 33,930
Income before accounting change 31,220 29,029 29,401
Net income 31,220 24,550 29,401
The Company's investments in and advances to unconsolidated affiliates also
includes Venice Energy Services Company, LLC ("VESCO"). The VESCO investment
consists of a 13.1% interest in a LLC owning a natural gas processing plant,
fractionation facilities, storage, and gas gathering pipelines in Louisiana.
This investment is accounted for using the cost method.
F-15
During the third quarter of 1999, the Company acquired the remaining interests
in Mont Belvieu Associates, 51%, ("MBA") and Entell NGL Services, LLC, 50%,
("Entell"). After the acquisition of the remaining interests, MBA was dissolved
by the Company and Entell became a wholly owned subsidiary of the Company.
The following table shows investments in and advances to unconsolidated
affiliates at:
December 31,
---------------------------------------
2000 1999
---------------------------------------
Accounted for on equity basis:
BEF $ 58,677 $ 63,004
Promix 48,670 50,496
BRF 30,599 36,789
Tri-States 27,138 28,887
EPIK 15,998 15,258
Belle Rose 11,653 12,064
BRPC 25,925 11,825
Wilprise 9,156 9,283
Dixie 38,138 20,000
Accounted for on cost basis:
VESCO 33,000 33,000
---------------------------------------
Total $ 298,954 $ 280,606
=======================================
The following table shows equity in income (loss) of unconsolidated affiliates
for the year ended December 31:
2000 1999 1998
--------------------------------------------------------
BEF $ 10,407 $ 8,183 $ 9,801
MBA 1,256 5,213
BRF 1,369 (336) (91)
BRPC (284) 16
EPIK 3,273 1,173 748
Wilprise 497 160
Tri-States 2,499 1,035
Promix 5,306 630
Belle Rose 301 (29)
Dixie 751
Other 1,389
--------------------------------------------------------
Total $ 24,119 $ 13,477 $ 15,671
========================================================
At December 31, 2000, the Company's share of accumulated earnings of
unconsolidated affiliates that had not been remitted to the Company was
approximately $26.7 million.
5. NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES
At December 31, 1999, the Company held a participation interest in the bank loan
of BEF for $6.5 million. The BEF bank loan matured on May 31, 2000. With BEF's
final payment, the Company's receivable relating to its participation in the BEF
note was extinguished.
F-16
6. LONG-TERM DEBT
Long-term debt consisted of the following at:
December 31,
---------------------------------------
2000 1999
---------------------------------------
Borrowings under:
$200 Million Bank Credit Facility (1) $ 129,000
$350 Million Bank Credit Facility (1) 166,000
$350 Million Senior Notes (2) $ 350,000
$54 Million MBFC Loan (3) 54,000
---------------------------------------
Total 404,000 295,000
Less current maturities of long-term debt 129,000
---------------------------------------
Long-term debt (4) $ 404,000 $ 166,000
=======================================
Notes to long-term debt table:
------------------------------
(1) Revolving credit facility closed as of December 31, 2000
(2) 8.25% fixed-rate, due March 2005
(3) 8.70% fixed-rate, due March 2010
(4) Long-term debt does not reflect the $250 Million Multi-Year Credit
Facility or the $150 Million 364-Day Credit Facility. No amount was
outstanding under either of these two revolving credit facilities at
December 31, 2000. See below for a complete description of these new
facilities
During the first quarter of 2001, the Company issued $450 Million in additional
Senior Notes and filed a $500 million universal registration statement with the
Securities and Exchange Commission. For a description of these subsequent
events, see Note 16.
At December 31, 2000, the Company had a total of $50 million of standby letters
of credit available under its $250 Million Multi-Year Credit Facility (described
below) of which none were outstanding.
Enterprise Products Partners L.P. acts as guarantor of certain debt obligations
of its major subsidiary, the Operating Partnership. This parent-subsidiary
guaranty provision exists under the Company's $350 Million Senior Notes, $54
Million MBFC Loan, $250 Million Multi-Year Credit Facility and $150 Million
364-Day Credit Facility. In the descriptions that follow, the term "MLP" denotes
Enterprise Products Partners L.P. in this guarantor role.
$200 Million Bank Credit Facility. On July 27, 1998, the Company entered into a
$200 million bank credit facility that included a $50 million working capital
facility and a $150 million revolving credit facility. On March 15, 2000, the
Company used $169 million of the proceeds from the issuance of the $350 Million
Senior Notes to retire this credit facility in accordance with its agreement
with the banks.
During the period in which this bank credit facility was active, the Company
elected the basis of the interest rate at the time of each borrowing. Interest
rates ranged from 7.07% to 7.31% during 2000, with the weighted-average interest
rate charged during 2000 being 7.28%.
$350 Million Bank Credit Facility. On July 28, 1999, the Company entered into a
$350 Million Bank Credit Facility that included a $50 million working capital
facility, a $300 million revolving credit facility and a sublimit of $40 million
for letters of credit. On November 17, 2000, this facility was retired using
funds available under the Company's new $150 Million 364-Day Credit Facility
(described below) in accordance with its agreement with the banks.
During the period in which this bank credit facility was active, the Company
elected the basis of the interest rate at the time of each borrowing. Interest
rates ranged from 7.07% to 7.31% during 2000, with the weighted-average interest
rate charged during 2000 being 7.28%.
$350 Million Senior Notes. On March 13, 2000, the Company completed a public
offering of $350 million in principal amount of 8.25% fixed-rate Senior Notes
due March 15, 2005 at a price to the public of 99.948% per Senior Note. The
Company received proceeds, net of underwriting discounts and commissions, of
F-17
approximately $347.7 million. The proceeds were used to pay the entire $169
million outstanding principal balance on the $200 Million Bank Credit Facility
and $179 million of the then $226 million outstanding principal balance on the
$350 Million Bank Credit Facility.
The $350 Million Senior Notes are subject to a make-whole redemption right. The
notes are an unsecured obligation and rank equally with existing and future
unsecured and unsubordinated indebtedness and senior to any future subordinated
indebtedness. The notes are guaranteed by the MLP through an unsecured and
unsubordinated guarantee and were issued under an indenture containing certain
restrictive covenants. These covenants restrict the ability of the Company, with
certain exceptions, to incur debt secured by liens and engage in sale and
leaseback transactions. The Company was in compliance with the restrictive
covenants at December 31, 2000.
The issuance of the $350 Million Senior Notes was a takedown under the December
1999 Registration Statement; therefore, the amount of securities available was
reduced to $450 million. The remaining amount available under the December 1999
Registration Statement was used to issue the $450 Million Senior Notes in
January 2001 (see Note 16 "Subsequent Events" below for a brief description of
the $450 Million Senior Notes).
After including the effect of interest rate swaps related to this debt
instrument, interest rates for the $350 Million Senior Notes ranged from 7.88%
to 8.05% during 2000, and the weighted-average interest rate at December 31,
2000 was 8.00%.
$54 Million MBFC Loan. On March 27, 2000, the Company executed a $54 million
loan agreement with the MBFC which was funded with proceeds from the sale of
Taxable Industrial Revenue Bonds ("Bonds") by the MBFC. The Bonds issued by the
MBFC are 10-year bonds with a maturity date of March 1, 2010 and bear a
fixed-rate interest coupon of 8.70%. The Company received proceeds from the sale
of the Bonds, net of underwriting discounts and commissions, of approximately
$53.6 million. The proceeds were used to pay the then $47 million outstanding
principal balance on the $350 Million Bank Credit Facility and for working
capital and other general partnership purposes. In general, the proceeds of the
Bonds were used to reimburse the Company for costs incurred in acquiring and
constructing the Pascagoula, Mississippi natural gas processing plant.
The Bonds were issued at par and are subject to a make-whole redemption right by
the Company. The Bonds are guaranteed by the MLP through an unsecured and
unsubordinated guarantee. The loan agreement contains certain covenants
including maintaining appropriate levels of insurance on the Pascagoula natural
gas processing facility and restrictions regarding mergers. The Company was in
compliance with the restrictive covenants at December 31, 2000.
After including the effect of interest rate swaps related to this debt
instrument, interest rates for the Bonds ranged from 7.26% to 7.66% during 2000,
and the weighted-average interest rate at December 31, 2000 was 7.43%.
$250 Million Multi-Year Credit Facility. On November 17, 2000, the Company
entered into a $250 million five-year revolving credit facility that includes a
sublimit of $50 million for letters of credit. The November 17, 2005 maturity
date may be extended for one year at the Company's option with the consent of
the lenders, subject to the extension provisions in the agreement. The Company
can increase the amount borrowed under this facility, without the consent of the
lenders, up to an amount not exceeding $350 million by adding to the facility
one or more new lenders and/or increasing the commitments of existing lenders,
so long as the aggregate amount of the funds borrowed under this credit facility
and the $150 Million 364-Day Credit Facility (described below) does not exceed
$500 million. No lender will be required to increase its original commitment,
unless it agrees to do so at its sole discretion. This credit facility is
guaranteed by the MLP through an unsecured and unsubordinated guarantee.
Proceeds from this credit facility will be used for working capital,
acquisitions and other general partnership purposes. No amount was outstanding
for this credit facility at December 31, 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 generally bear interest at either (a) the greater of
the Prime Rate or the Federal Funds Effective Rate plus one-half percent or (b)
a Eurodollar rate plus an applicable margin (as defined within the facility) or
(c) a competitively bid rate. The Company elects the basis for the interest rate
at the time of each borrowing.
F-18
This credit agreement contains various affirmative and negative covenants
applicable to the Company to, among other things, (i) incur certain additional
indebtedness, (ii) grant certain liens, (iii) enter into certain merger or
consolidation transactions and (iv) make certain investments. In addition, the
Company may not directly or indirectly make any distribution in respect of its
partnership interests, except those payments in connection with the 1,000,000
Unit Buy-Back Program (not to exceed $30 million in the aggregate) and
distributions from Available Cash from Operating Surplus, both as defined within
the agreement. The bank credit facility requires that the Company satisfy
certain financial covenants at the end of each fiscal quarter: (i) maintain
Consolidated Net Worth of $750 million (as defined in the bank credit facility)
and (ii) maintain a ratio of Consolidated Indebtedness (as defined within the
bank credit facility) to Consolidated EBITDA (as defined within the bank credit
facility) for the previous four quarter period of at least 4.0 to 1.0. The
Company was in compliance with these restrictive covenants at December 31, 2000.
$150 Million 364-Day Credit Facility. Also on November 17, 2000, the Company
entered into a 364-day $150 million revolving bank credit facility which may be
converted into a one-year term loan at the end of the initial 364-day period.
Should this facility be converted into a one-year term loan, the maturity date
would be November 16, 2002. Likewise, this maturity date may be extended for an
additional one-year period at the option of the Company (with the consent of the
lenders), subject to the extension provisions in the agreement; therefore, the
ultimate maturity date of this credit facility could be November 16, 2003. The
Company can increase the amount borrowed under this facility, without the
consent of the lenders, up to an amount not exceeding $250 million by adding to
the facility one or more new lenders and/or increasing the commitments of
existing lenders, so long as the aggregate amount of the funds borrowed under
this credit facility and the $250 Million Bank Credit Facility does not exceed
$500 million. No lender will be required to increase its original commitment,
unless it agrees to do so at its sole discretion. This credit facility is
guaranteed by the MLP through an unsecured and unsubordinated guarantee.
Proceeds from this credit facility will be used for working capital,
acquisitions and other general partnership purposes. No amount was outstanding
for this credit facility at December 31, 2000. The Company used operating cash
flows to repay the amount borrowed to retire the $350 Million Bank Credit
Facility in November 2000. For the period in which the Company had an
outstanding principal balance under this credit facility, the interest rate was
7.19%.
Limitations on certain actions by the Company and financial condition covenants
of this bank credit facility are substantially consistent with those existing
for the $250 Million Multi-Year Credit Facility as described above. The Company
was in compliance with the restrictive covenants at December 31, 2000.
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
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") 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 also contains provisions for the allocation of net earnings and losses
to the Unitholders and the General Partner. For purposes of maintaining partner
capital accounts, the Partnership Agreement specifies that items of income and
loss shall be allocated among the partners in accordance with their respective
percentage interests. Normal allocations according to percentage interests are
done only, however, after giving effect to priority earnings allocations in an
amount equal to incentive cash distributions allocated 100% to the General
Partner. As an incentive, the General Partner's percentage interest in quarterly
distributions is increased after certain specified target levels are met. When
19
quarterly distributions exceed $0.506 per Unit, the General Partner receives a
percentage of the excess between the actual distribution rate and the target
level ranging from approximately 15% to 50% depending on the target level
achieved.
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 is
limited with regards to the number of equity securities that it may issue that
rank senior to 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). After adjusting for
the Common Units issued in connection with the TNGL acquisition, the number of
Common Units available (and unreserved ) to the Company for general partnership
purposes during the Subordination Period is currently 27,275,000.
Subordinated Units. The 21,409,872 Subordinated Units have no voting rights
until converted into Common Units at the end of the Subordination Period. The
Subordination Period will generally extend until the first day of any quarter
beginning after June 30, 2003 when the Conversion Tests have 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 each of 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.
The Partnership Agreement stipulates that 50% of the Subordinated Units (or
10,704,936 Subordinated Units) may undergo an early conversion into Common Units
should certain criteria be satisfied. Based upon these criteria, the earliest
that the first 25% of the Subordinated Units (or 5,352,468 Subordinated Units)
would convert into Common Units is April 1, 2002. Should the criteria continue
to be satisfied through the first quarter of 2003, an additional 25% of the
Subordinated Units would undergo an early conversion into Common Units on April
1, 2003. The remaining 10,704,936 Subordinated Units would convert into Common
Units on July 1, 2003 should the balance of the conversion requirements be met.
Special Units. The Special Units issued to Shell do not accrue distributions and
are not entitled to cash distributions until their conversion into Common Units.
For financial accounting and tax purposes, the Special Units are generally not
allocated any portion of net income; however, for tax purposes, the Special
Units are allocated a certain amount of depreciation until their conversion into
Common Units. On August 1, 2000, 1.0 million of the original issue of 14.5
million Special Units converted into Common Units. The remaining 13.5 million
Special Units of the original issue will automatically convert into Common Units
as follows: 5.0 million Units on August 1, 2001 and 8.5 million Units on August
1, 2002.
On June 28, 2000, Shell met certain year 2000 performance criteria for the
issuance of 3.0 million non-distribution bearing, convertible Contingency Units
(referred to as the "second issue" of Special Units). Per an agreement with
Shell, the Company issued these Special Units on August 1, 2000. Shell has the
opportunity to earn an additional 3.0 million non-distribution bearing,
convertible Contingency Units (i.e., a "third issue" of Special Units) based on
certain performance criteria for calendar year 2001. Specifically, Shell will
earn the third issue of Special Units if at any point during calendar year 2001
(or extensions thereto due to force majeure events) gas production by Shell from
its offshore Gulf of Mexico producing properties and leases is 900 million cubic
feet per day for 180 not-necessarily-consecutive days or 350 billion cubic feet
on a cumulative basis. If the year 2001 performance test 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 the third issue of Special Units.
If both the second and third issues of Special Units are earned, 1.0 million of
these Special Units would convert into Common Units on August 1, 2002 and 5.0
million of these Special Units would convert into Common Units on August 1,
2003. Special Units issued to Shell as part of these contingent agreements do
F-20
not accrue distributions and are not entitled to cash distributions until
conversion into Common Units. With regards to income and depreciation allocation
from either a financial accounting or tax basis, these Special Units will be
treated identically to the 14.5 million Special Units originally issued.
Under the rules of the New York Stock Exchange, the conversion feature of the
Special Units into Common Units requires approval of the Company's Unitholders.
With respect to the August 2000 conversion, EPC Partners II, Inc. ("EPC II"),
which owns in excess of 81% of the outstanding Common Units, voted its Units in
favor of conversion, which provided the necessary votes for approval.
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, 2000, 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.
On May 12, 2000, the Company filed a Registration Statement with the Securities
and Exchange Commission for the transfer of up to (i) 1,000,000 Common Units to
fund a long-term incentive plan established by the General Partner and (ii)
1,000,000 Common Units to fund a long-term incentive plan established by
Enterprise Products Company.
Unit History. The following table details the outstanding balance of each class
of Units at the end of the periods indicated:
Common Subordinated Special Treasury
Units Units Units Units
---------------------------------------------------------------
Balance, December 31, 1997 33,552,915 21,409,870
Units issued to public 12,000,000
--------------------------------
Balance, December 31, 1998 45,552,915 21,409,870
Special Units issued to Shell
in connection with TNGL acquisition 14,500,000
Common Units purchased by
consolidated Trust (267,200)
---------------------------------------------------------------
Balance, December 31, 1999 45,552,915 21,409,870 14,500,000 (267,200)
Additional Special Units issued to
Coral Energy, LLC in connection
with contingency agreement 3,000,000
Conversion of 1.0 million Coral
Energy, LLC Special Units into
Common Units 1,000,000 (1,000,000)
Units repurchased and retired in
connection with buy-back program (28,400)
---------------------------------------------------------------
Balance, December 31, 2000 46,524,515 21,409,870 16,500,000 (267,200)
===============================================================
8. EARNINGS PER UNIT
Basic earnings per Unit is computed by dividing net income available to limited
partner interests by the weighted-averaged number of Common and Subordinated
Units outstanding during the period. Diluted earnings per Unit is computed by
dividing net income available to limited partner interests by the
weighted-average number of Common, Subordinated and Special Units outstanding
during the period.
F-21
The following table reconciles the number of shares used in the calculation of
basic earnings per Unit and diluted earnings per Unit for the three years ended
December 31, 2000.
For Year Ended December 31,
--------------------------------------------------------
2000 1999 1998
--------------------------------------------------------
Income before extraordinary item and minority interest $ 222,759 $ 121,521 $ 37,355
General partner interest (2,597) (1,203) (101)
--------------------------------------------------------
Income before extraordinary item and minority
interest available to Limited Partners 220,162 120,318 37,254
Extraordinary charge on early extinguishment of debt (27,176)
Minority interest (2,253) (1,226) (102)
--------------------------------------------------------
Net income available to Limited Partners $ 217,909 $ 119,092 $ 9,976
========================================================
BASIC EARNINGS PER UNIT
Numerator
Income before extraordinary item and minority
interest available to Limited Partners $ 220,162 $ 120,318 $ 37,254
========================================================
Extraordinary charge on early extinguishment of debt $ (27,176)
===================
Net income available to Limited Partners $ 217,909 $ 119,092 $ 9,976
========================================================
Denominator
Weighted-average Common Units outstanding 45,698 45,300 38,714
Weighted-average Subordinated Units outstanding 21,410 21,410 21,410
--------------------------------------------------------
Total 67,108 66,710 60,124
========================================================
Basic Earnings per Unit
Income before extraordinary item and minority
interest available to Limited Partners $ 3.28 $ 1.80 $ 0.62
========================================================
Extraordinary charge on early extinguishment of debt $ (0.45)
===================
Net income available to Limited Partners $ 3.25 $ 1.79 $ 0.17
========================================================
DILUTED EARNINGS PER UNIT
Numerator
Income before extraordinary item and minority
interest available to Limited Partners $ 220,162 $ 120,318 $ 37,254
========================================================
Extraordinary charge on early extinguishment of debt $ (27,176)
===================
Net income available to Limited Partners $ 217,909 $ 119,092 $ 9,976
========================================================
Denominator
Weighted-average Common Units outstanding 45,698 45,300 38,714
Weighted-average Subordinated Units outstanding 21,410 21,410 21,410
Weighted-average Special Units outstanding 15,336 6,078 -
--------------------------------------------------------
Total 82,444 72,788 60,124
========================================================
Basic Earnings per Unit
Income before extraordinary item and minority
interest available to Limited Partners $ 2.67 $ 1.65 $ 0.62
========================================================
Extraordinary charge on early extinguishment of debt $ (0.45)
===================
Net income available to Limited Partners $ 2.64 $ 1.64 $ 0.17
========================================================
The weighted-average impact of the issuance of the second issue of Special Units
(formerly Contingency Units, as described under the "Special Units" section in
Note 7) are included in the diluted earnings per Unit calculation for fiscal
F-22
2000 (beginning August 1, 2000, the effective date of the contingent agreement
between Shell and the Company). The Contingency Units relating to the third
issue of Special Units to be issued upon achieving certain performance criteria
in future periods have been excluded from diluted earnings per Unit because such
tests have not been met at December 31, 2000.
9. 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, 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. As an
incentive, the General Partner's interest in quarterly distributions is
increased after certain specified target levels are met. The Company made
incentive cash distributions to the General Partner of $0.4 million during 2000
and none in prior periods.
On January 17, 2000, the Company declared an increase in its quarterly cash
distribution to $0.50 per Unit. This amount was subsequently raised to $0.525
per Unit on July 17, 2000 and $.550 per Unit on December 7, 2000.
The following is a summary of cash distributions to partnership interests since
the first quarter of 1999:
Cash Distributions
--------------------------------------------------------------------
Per
Per Common Subordinated Record Payment
Unit Unit Date Date
--------------------------------------------------------------------
1999 First Quarter $ 0.450 $ 0.450 Jan. 29, 1999 Feb. 11, 1999
Second Quarter $ 0.450 $ 0.070 Apr. 30, 1999 May 12, 1999
Third Quarter $ 0.450 $ 0.370 Jul. 30, 1999 Aug. 11, 1999
Fourth Quarter $ 0.450 $ 0.450 Oct. 29, 1999 Nov. 10, 1999
2000 First Quarter $ 0.500 $ 0.500 Jan. 31, 2000 Feb. 10, 2000
Second Quarter $ 0.500 $ 0.500 Apr. 28, 2000 May 10, 2000
Third Quarter $ 0.525 $ 0.525 Jul. 31, 2000 Aug. 10, 2000
Fourth Quarter $ 0.525 $ 0.525 Oct. 31, 2000 Nov. 10, 2000
2001 First Quarter $ 0.550 $ 0.550 Jan. 31, 2001 Feb. 9, 2001
(through February 28, 2001)
10. RELATED PARTY TRANSACTIONS
The Company has no employees. All management, administrative and operating
functions are performed by employees of EPCO pursuant to the EPCO Agreement
entered into by EPCO, the General Partner and the Company in July 1998.
Under the terms of the EPCO agreement, EPCO agreed to (i) manage the business
and affairs of the Company; (ii) employ the operating personnel involved in the
Company's business for which EPCO is reimbursed by the Company at cost (based
upon EPCO's actual salary costs and related fringe benefits); (iii) allow the
Company to participate as named insureds in EPCO's current insurance program
with the costs being allocated among the parties on the basis of formulas set
forth in the agreement; (iv) grant an irrevocable, non-exclusive worldwide
license to all of the trademarks and trade names used in its business to the
Company; (v) indemnify the Company against any losses resulting from certain
lawsuits; and (vi) 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 railcars to the Company for $1 per year
F-23
and assigned its purchase options under such leases to the Company. EPCO is
liable for the lease payments associated with these assets. Operating costs and
expenses (as shown on the audited Statements of Consolidated Operations) include
charges for EPCO's employees who operate the Company's various facilities.
Pursuant to the EPCO Agreement, the charges for EPCO's employees who manage the
business and affairs of the Company are reimbursed only under certain
circumstances. SG&A charges to EPCO resulting from the hiring of additional
management personnel and other costs associated with the expansion and business
development activities of the Company (through the construction of new
facilities or the completion of acquisitions) are reimbursed by the Company.
In lieu of reimbursement for all other SG&A costs incurred by EPCO, EPCO is
entitled to receive an annual Administrative Services Fee (the "EPCO Fees",
initially set at $12.0 million). The General Partner, with the approval and
consent of the Audit and Conflicts Committee, may agree to increases in the EPCO
Fees of up to 10% each contract year (defined as August 1 to July 31) during the
10-year term of the EPCO Agreement. Since the initial contract year ending July
31, 1999, the Audit and Conflicts Committee has approved two increases in the
EPCO Fees. The annual fee was increased to $13.2 million for the second contract
year and subsequently raised to $14.5 million for the third contract year.
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 $0.9 million for 2000, $0.8 million for 1999 and $1.7
million for 1998. 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 $10.6 million for both 2000 and 1999 and
$11.3 million for 1998 (of which $4.0 million occurred after the public
offering).
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, transportation of NGL products by truck and plant support services.
As a result of the TNGL acquisition, Shell acquired an ownership interest in the
Company and its General Partner. At December 31, 2000, Shell owned approximately
20.5% of the Company and 30% of the General Partner. Shell is a significant
customer of the gas processing assets. 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.
Generally, the Company's revenues from Shell are derived from the sale of NGL
and petrochemical products with its operating costs and expenses from Shell
primarily due to the purchase of natural gas. The Company has an extensive and
ongoing relationship with Shell as a customer, vendor and limited partner.
F-24
The following table shows the related party amounts by major income statement
category for the last three years:
For the Years Ended
December 31,
---------------------------------------------------
2000 1999 1998
---------------------------------------------------
Revenues from consolidated operations
Unconsolidated affiliates $ 61,988 $ 40,352 $ 36,474
Shell 292,741 56,301
EPCO and subsidiaries 4,750 9,148 19,531
Operating costs and expenses
Unconsolidated affiliates 58,202 20,696 9,270
Shell 736,655 188,570
EPCO and subsidiaries 9,492 35,046 9,997
Selling, general and administrative expenses
Base fees payable under EPCO Agreement 13,750 12,500 5,129
11. COMMITMENTS AND CONTINGENCIES
Redelivery Commitments
From time to time, the Company stores NGL products for third parties under
various processing and similar agreements. Under the terms of these 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, 2000, NGL products aggregating 235
million gallons were due to be redelivered to the owners.
Lease Commitments
The Company leases certain equipment and processing facilities under
noncancelable and cancelable operating leases. Minimum future rental payments on
such leases with terms in excess of one year at December 31, 2000 are as
follows:
2001 $ 7,228
2002 5,048
2003 4,797
2004 4,260
2005 214
Thereafter 1,225
------------
Total minimum obligations $ 22,772
============
Lease expense charged to operations (including Retained Leases) for the years
ended December 31, 2000, 1999 and 1998 was approximately $18.3 million , $20.2
million and $18.5 million, respectively.
F-25
Gas Purchase Commitments
The Company has annual renewable gas purchase contracts with four suppliers. As
of December 31, 2000, the Company is required to make daily purchases as
follows:
- 5,000 million British Thermal Units ("MMBtu") per day through February
28, 2001,
- 13,000 MMBtu per day through March 31, 2001,
- 5,000 MMBtu per day through July 31, 2001,
- 5,000 MMBtu per day through September 30, 2001, and
- 5,000 MMBtu per day through October 31, 2001.
The cost of these natural gas purchase commitments approximate market value at
the time of delivery.
Capital Expenditure Commitments
As of December 31, 2000, the Company had capital expenditure commitments
totaling approximately $10.9 million, of which $0.8 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.
Except as note below, 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.
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,
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 more strict requirements on existing facilities were issued
in December, 2000. These regulations mandate 90% reductions in oxides of
nitrogen emissions from point sources such as the gas turbines at the Company's
Mont Belvieu processing facility. The technical practicality and economic
reasonableness of requiring existing gas turbines to achieve such reductions, as
well as the substantive basis for setting the 90% reduction requirements, have
been challenged under state law in litigation filed in the District Court of
Travis County, Texas, on January 19, 2001, by the Company as part of a coalition
of major Houston-Galveston area industries. In addition to the Company, the
plaintiffs in this case are the BCCA Appeal Group, Equistar Chemicals, LP,
Lyondell Chemical Company, Lyondell-CITGO Refining L.P. and Reliant Energy,
Incorporated; named as defendants are the Texas Natural Resource Conservation
Commission and its chairman, commissioners and executive director. The suit
seeks a ruling that these regulations are invalid and void and asks for a
temporary injunction to stay their effectiveness pending final judgment in the
case. If these regulations stand as issued, they would require substantial
redesign and modification of the Mont Belvieu facilities to achieve the mandated
reductions; however, the precise impact of these requirements on the Company's
operations cannot be determined until this litigation is resolved.
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
F-26
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.
Cash and Cash Equivalents, Accounts Receivable, Accounts Payable and Accrued
Expenses are carried at amounts which reasonably approximate their fair value at
year end due to their short-term nature.
Fixed-rate long term debt. The fair value of the Company's fixed-rate long term
debt is estimated based on the quoted market prices for debt of similar terms
and maturities. No variable rate long-term debt was outstanding at year end.
Interest Rate Swaps. The Company's interest rate exposure results from
variable-rate borrowings from commercial banks and fixed-rate borrowings
pursuant to the $350 Million Senior Notes and the $54 Million MBFC Loan. The
Company manages its exposure to changes in interest rates in its debt portfolio
by utilizing interest rate swaps. An interest rate swap, in general, requires
one party to pay a fixed-rate on the notional amount while the other party pays
a floating-rate based on the notional amount.
In March 2000, after the issuance of the $350 Million Senior Notes and the
execution of the $54 Million MBFC Loan, 100% of the Company's consolidated debt
were fixed-rate obligations. To maintain a balance between variable-rate and
fixed-rate exposure, the Company entered into interest rate swap agreements with
a notional amount of $154 million by which the Company receives payments based
on a fixed-rate and pays an amount based on a floating-rate. At December 31,
2000, the Company's consolidated debt portfolio interest rate exposure was 62
percent fixed and 38 percent floating, after considering the effect of the
interest rate swap agreements. The notional amount does not represent exposure
to credit loss. The Company monitors its positions and the credit ratings of its
counterparties. Management believes the risk of incurring a credit related loss
is remote, and that if incurred, such losses would be immaterial.
Cash flows related to interest rate swap agreements are classified as "Operating
activities cash flows" in the Statements of Consolidated Cash Flows. The net
cash differentials paid or received on interest rate swap agreements are accrued
and recognized as adjustments to interest expense. The effect of these swaps
(none of which are leveraged) was to decrease the Company's interest expense by
$1.2 million during 2000. Following is selected information on the Company's
portfolio of interest rate swaps at December 31, 2000:
Interest Rate Swap Portfolio at December 31, 2000 (1) :
(Dollars in millions)
Early Fixed /
Notional Termination Floating
Amount Period Covered Date (2) Rate (3)
- --------------------------------------------------------------------------------
$ 50.0 March 2000 - March 2005 March 2001 8.25% / 7.3100%
$ 50.0 March 2000 - March 2005 March 2001 (4) 8.25% / 7.3150%
$ 54.0 March 2000 - March 2010 March 2003 8.70% / 7.6575%
Notes to Interest Rate Swap table:
(1) All swaps outstanding at December 31, 2000 were entered into for the
purpose of managing a portion of financing costs associated with its
fixed-rate debt.
(2) In each case, the counterparty has the option to terminate the interest
rate swap on the Early Termination Date.
(3) In each case, the Company is the floating-rate payor. The floating rate was
the rate in effect as of December 31, 2000.
(4) Swap was terminated by the bank effective March 15, 2001.
The $2.0 million fair value of interest rate swap agreements at December 31,
2000 is based on market rates and the early termination option being exercised.
The fair value represents the estimated amount the Company would receive or pay
based on current interest rates.
F-27
Commodity-related transactions. The Company enters into swaps and other
contracts to hedge the price risks associated with inventories, commitments and
certain anticipated transactions. 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 of the General Partner.
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 financial instruments at December 31, 1999 was
estimated at $0.5 million payable by the Company. At December 31, 2000, the
Company had open commodity positions covering 28.8 billion cubic feet of natural
gas and 1.2 million barrels of NGL futures, primarily propane, extending into
December 2001. The fair value of these financial instruments at December 31,
2000 was estimated at $38.6 million payable by the Company. The fair value
estimates at December 31, 2000 and 1999 are 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. To the
extent that the hedged positions are effective, gains or losses 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 below.
The following table summarizes the estimated fair values of the Company's
financial instruments at December 31, 2000 and 1999:
2000 1999
---------------------------- ----------------------------
Carrying Fair Carrying Fair
Financial Instruments Amount Value Amount Value
- -------------------------------------------------------------------------- ----------------------------
Financial assets:
Cash and cash equivalents $ 60,409 $ 60,409 $ 5,230 $ 5,230
Accounts receivable 415,618 415,618 318,423 318,423
Accounts payable and accrued expenses 551,620 551,620 383,944 383,944
Financial liabilities:
Variable-rate debt - - 295,000 295,000
Fixed-rate debt 404,000 423,836 n/a n/a
Commodity futures 725 705 n/a n/a
Off-balance sheet instruments:
Interest rate swaps receivable 2,030 2,030 n/a n/a
Commodity futures payable 40,020 39,266 539 539
Recent Accounting Developments
Effective January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments and
Hedging Activities, as amended and interpreted. SFAS 133 establishes accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts and for hedging activities. All
derivatives, whether designated in hedging relationships or not, will be
required to be recorded on the balance sheet at fair value. If the derivative is
designated as a fair value hedge, the changes in fair value of the derivative
and the hedged item will be recognized in earnings. If the derivative is
designated as a cash flow hedge, changes in the fair value of the derivative
will be recorded as a component of Partners' Equity entitled Other Comprehensive
Income (to the extent the hedge is effective) and will be recognized in the
income statement when the hedged item affects earnings. The ineffective portion
of the hedge is required to be recorded in earnings. SFAS 133 defines new
requirements for designation and documentation of hedging relationships as well
as ongoing effectiveness assessments in order to use hedge accounting. A
derivative that does not qualify as a hedge will be recorded at fair value
through earnings.
The Company expects that at January 1, 2001, it will record a $ 42.2 million
loss in Other Comprehensive Income as a cumulative transition adjustment for
derivatives (commodity contracts) designated in cash flow-type hedges prior to
F-28
adopting SFAS 133. In addition, the Company expects to record a $2.1 million
derivative asset and a corresponding increase to its long term debt relating to
derivatives (interest rate swaps) designated in fair-value-type hedges prior to
adopting SFAS 133. The fair value hedges will have no impact to earnings upon
transition.
The Company will reclassify from Other Comprehensive Income $21.7 million as a
charge to earnings during the first quarter of 2001 and $20.5 million as a
charge to earnings during the remainder of 2001. The actual gain or loss amount
to be recognized in earnings related to these commodity contracts over time is
dependent upon the final settlement price associated with the commodity prices.
13. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Year Ended December 31,
--------------------------------------------------------
2000 1999 1998
--------------------------------------------------------
(Increase) decrease in:
Accounts receivable $ (93,716) $ (152,363) $ 3,699
Inventories (21,452) 7,471 1,361
Prepaid and other current assets 2,316 (7,523) (342)
Intangible assets (5,226)
Other assets (1,527) 1,164 1,781
Increase (decrease) in:
Accounts payable 18,723 (6,276) (40,005)
Accrued gas payable 143,457 206,178 (19,463)
Accrued expenses 4,978 (27,788) (120)
Other current liabilities 15,283 6,747 (10,082)
Other liabilities 8,122 296
--------------------------------------------------------
Net effect of changes in operating accounts $ 70,958 $ 27,906 $ (63,171)
========================================================
Cash payments for interest, net of $3,277,
$153 and $180 capitalized in 2000, 1999
and 1998, respectively $ 17,774 $ 15,780 $ 6,971
========================================================
Capital expenditures for 2000 were $243.9 million compared to $21.2 million for
the same period in 1999. Capital expenditures in 2000 included $99.5 million for
the purchase of the Lou-Tex Propylene Pipeline and related assets and $83.7
million in construction costs for the Lou-Tex NGL Pipeline.
During 2000, the Company increased the gas processing contract by $25.2 million
for non-cash purchase accounting adjustments relating to the TNGL acquisition.
The offset to such adjustment was various working capital accounts.
On August 1, 1999, the Company paid $166 million in cash and issued 14.5 million
non-distribution bearing, convertible Special Units to Shell in connection with
the TNGL acquisition. The value of the 14.5 million Special Units was $210.4
million at time of issuance. On August 1, 2000, the Company issued an additional
3.0 million non-distribution bearing, convertible Special Units to Shell. The
value of these new Special Units was $55.2 million at time of issuance. In both
cases, the value of the Special Units at the time of issuance was recorded as a
non-cash contribution by Shell to the Company. The General Partner made non-cash
contributions to the Company relating to the TNGL acquisition of $2.1 million in
1999 and $0.6 million in 2000. See Note 7 for a discussion of the Special Units
and the performance tests.
On July 1, 1999, the Company paid approximately $42 million in cash to Kinder
Morgan and EPCO and assumed approximately $4 million of debt in connection with
the acquisition of an additional interest in MBA.
F-29
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.
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 which 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
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 Company has five reportable operating segments: Fractionation, Pipeline,
Processing, Octane Enhancement and Other. The reportable segments are generally
organized according to the type of services rendered or process employed and
products produced and/or sold, as applicable. The segments are regularly
evaluated by the Chief Executive Officer of the General Partner. Fractionation
includes NGL fractionation, butane isomerization (converting normal butane into
high purity isobutane) and polymer grade propylene fractionation 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 Company evaluates segment performance on the basis of gross operating
margin. Gross operating margin reported for each segment represents operating
income before depreciation and amortization, lease expense obligations retained
by EPCO, gains and losses on the sale of assets 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.
Consolidated property, plant and equipment and investments in and advances to
unconsolidated affiliates are allocated to each segment on the basis of each
asset's or investment's principal operations. The principal reconciling item
between consolidated property, plant and equipment and segment property is
construction-in-progress. Segment property represents those facilities and
projects that contribute to gross operating margin and is net of accumulated
depreciation on these assets. Since assets under construction do not generally
F-30
contribute to segment gross operating margin, these assets are not included in
the operating segment totals until they are deemed operational.
Segment gross operating margin is inclusive of intersegment revenues, which are
generally based on transactions made at market-related rates. These revenues
have been eliminated from the consolidated totals. 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
2000 $ 396,995 $ 28,172 $ 2,620,975 $ 2,878 $ 3,049,020
1999 247,579 11,498 1,073,171 731 1,332,979
1998 213,966 18,306 506,630 738,902
Intersegment revenues
2000 $ 177,963 $ 55,690 $ 630,155 $ 375 $ (864,183)
1999 118,103 43,688 216,720 444 (378,955)
1998 162,379 37,574 90 383 (200,426)
Equity income in
unconsolidated affiliates
2000 $ 6,391 $ 7,321 $ 10,407 $ 24,119
1999 1,566 3,728 8,183 13,477
1998 5,122 748 9,801 15,671
Total revenues
2000 $ 581,349 $ 91,183 $ 3,251,130 $ 10,407 $ 3,253 $ (864,183) $ 3,073,139
1999 367,248 58,914 1,289,891 8,183 1,175 (378,955) 1,346,456
1998 381,467 56,628 506,720 9,801 383 (200,426) 754,573
Gross operating margin
by segment
2000 $ 129,376 $ 56,099 $ 122,240 $ 10,407 $ 2,493 $ 320,615
1999 110,424 31,195 28,485 8,183 908 179,195
1998 66,627 27,334 (652) 9,801 (3,483) 99,627
Segment property, net
2000 $ 356,207 $ 448,920 $ 126,895 $ 8,942 $ 34,358 $ 975,322
1999 362,198 249,453 122,495 113 32,810 767,069
Investments in and
Advances to
Unconsolidated affiliates
2000 $ 105,194 $ 102,083 $ 33,000 $ 58,677 $ 298,954
1999 99,110 85,492 33,000 63,004 280,606
One Fractionation third-party customer in 1998 provided more than 10% of
consolidated revenues. No single third-party customer provided more than 10% of
consolidated revenues in 2000 or 1999.
All consolidated revenues were earned in the United States. The operations of
the Company are centered along the Texas, Louisiana and Mississippi Gulf Coast
areas.
F-31
Certain reclassifications have been made to the 1999 and 1998 amounts to
conform to the 2000 presentation. Gross operating margin for both the
Fractionation and Pipeline segments in 1999 was increased by $4.1 million each
due to a reclassification of margins for the Tebone and Venice NGL fractionation
and pipeline assets from the Processing segment. Revenues from external
customers for both 1998 and 1999 was adjusted to reflect (i) the
reclassification of equity income in unconsolidated affiliates to a separate
line item in the above table and (ii) the reclassification of certain revenue
items that had previously been classified as adjustments to consolidated
revenues to the segments to which they relate. The effect of the
reclassification of amounts in item (ii) above was to reduce revenues from
external customers for Fractionation by $30.7 million in 1999 and $54.7 million
in 1998 and Pipelines by $5.1 million in 1999 and $0.3 million in 1998.
The Venice NGL fractionation and pipeline assets are part of the Company's
investment in VESCO which is classified under the Processing segment. The
Company views both Tebone and Venice pipeline assets as an integral part of its
Louisiana Pipeline System.
A reconciliation of segment gross operating margin to consolidated income before
minority interest follows:
For the Year Ended December 31,
-------------------------------------------------------
2000 1999 1998
-------------------------------------------------------
Gross Operating Margin by segment:
Fractionation $ 129,376 $ 110,424 $ 66,627
Pipeline 56,099 31,195 27,334
Processing 122,240 28,485 (652)
Octane enhancement 10,407 8,183 9,801
Other 2,493 908 (3,483)
-------------------------------------------------------
Gross Operating Margin total 320,615 179,195 99,627
Depreciation and amortization 35,621 23,664 18,579
Retained lease expense, net 10,645 10,557 12,635
Loss (gain) on sale of assets 2,270 123 (276)
Selling, general and administrative expenses 28,345 12,500 18,216
-------------------------------------------------------
Consolidated operating income $ 243,734 $ 132,351 $ 50,473
=======================================================
16. SUBSEQUENT EVENTS (UNAUDITED)
Manta Ray, Nautilus and Nemo Pipeline Systems
On January 29, 2001, the Company acquired ownership interests in three natural
gas pipeline systems and related equipment located offshore Louisiana in the
Gulf of Mexico from affiliates of El Paso Energy Corp. for $88.1 million in
cash. These systems total approximately 362 miles of pipeline. The Company
acquired a 25.67% interest in each of the Manta Ray and Nautilus pipeline
systems and a 33.92% interest in the Nemo pipeline system. Affiliates of Shell
own an interest in all three systems, and an affiliate of Marathon Oil Company
owns an interest in the Manta Ray and Nautilus systems. The Manta Ray system
comprises approximately 237 miles of pipeline with a capacity of 750 million
cubic fee ("MMcf") per day and related equipment, the Nautilus system comprises
approximately 101 miles of pipeline with a capacity of 600 MMcf per day, and the
Nemo system, when completed in the fourth quarter of 2001, will comprise
approximately 24 miles of pipeline with a capacity of 300 MMcf per day.
Stingray Pipeline System and Related Facilities
On January 29, 2001, the Company and an affiliate of Shell acquired, through a
50/50 owned entity, the Stingray natural gas pipeline system and related
facilities from an affiliate of El Paso for $50.2 million in cash. The Stingray
system comprises approximately 375 miles of pipeline with a capacity of 1.2
F-32
billion cubic feet ("Bcf") per day offshore Louisiana in the Gulf of Mexico.
Shell will be responsible for the commercial and physical operations of the
Stingray system.
$450 Million Senior Notes
On January 24, 2001, the Company completed a public offering of $450 million in
principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a
price to the public of 99.937% per Senior Note (the "$450 Million Senior
Notes"). The Company received proceeds, net of underwriting discounts and
commissions, of approximately $446.8 million. The proceeds from this offering
were or will be used to acquire the Acadian and EPE natural gas pipeline systems
for $339.2 million and to finance the cost to construct certain NGL pipelines
and related projects and for working capital and other general partnership
purposes.
February 2001 Registration Statement
On February 23, 2001, the Company filed a $500 million universal shelf
registration (the "February 2001 Registration Statement") covering the issuance
of an unspecified amount of equity or debt securities or a combination thereof.
The Company expects to use the net proceeds from any sale of securities for
future business acquisitions and other general corporate purposes, such as
working capital, investments in subsidiaries, the retirement of existing debt
and/or the repurchase of Common Units or other securities. The exact amounts to
be used and when the net proceeds will be applied to partnership purposes will
depend on a number of factors, including the Company's funding requirements and
the availability of alternative funding sources. The Company routinely reviews
acquisition opportunities.
17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
--------------------------------------------------------------------------
For the Year Ended December 31, 1999:
Revenues $ 148,877 $ 177,479 $ 445,028 $ 575,072
Operating income 12,068 21,069 40,070 59,144
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
For the Year Ended December 31, 2000:
Revenues $ 753,724 $ 604,010 $ 721,863 $ 993,542
Operating income 75,434 50,046 55,864 62,390
Income before minority interest 70,156 46,026 50,777 55,800
Minority interest (709) (466) (514) (564)
Net income 69,447 45,560 50,263 55,236
Net income per Unit, basic $ 1.03 $ 0.68 $ 0.74 $ 0.81
Net income per Unit, diluted $ 0.85 $ 0.56 $ 0.60 $ 0.65
As a result of the TNGL and MBA acquisitions, 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 as
effective July 1, 1999.
F-33
Enterprise Products Partners L.P. SCHEDULE II
Valuation and Qualifying Accounts
(amounts in millions of dollars)
Year Ended December 31,
----------------------------
1998 1999 2000
----------------------------
Accounts Receivable - trade
Allowance for doubtful accounts (a)
Balance at beginning of period $ 15.9
Reserve increases charged to earnings $ 3.0
Reserve increases charged to other balance sheet accounts 12.9
Amounts charged against reserve (deductions) (5.0)
-------------------
Balance at end of period $ 15.9 $ 10.9
===================
Other current liabilities
Reserve for inventory losses (b)
Balance at beginning of period $ 0.8 $ 0.8 $ 2.9
Reserve increases charged to earnings 10.0 7.3 5.1
Reserve increases charged to other balance sheet accounts
Amounts charged against reserve (deductions) (10.0) (5.2) (2.3)
----------------------------
Balance at end of period $ 0.8 $ 2.9 $ 5.7
============================
(a) As a result of the TNGL acquisition in 1999, the Company acquired a $12.9
million allowance for doubtful accounts. Historically, the Company did not
experience any significant losses from bad debts and therefore did not require
an allowance account.
(b) Generally denotes net underground NGL storage well product losses.
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 March 22, 2001.
ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)
By: Enterprise Products GP, LLC,
as General Partner
By: /s/ Michael J. Knesek
-----------------------------------------
Name: Michael J. Knesek
Title: Vice President, Controller and Principal
Accounting 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 March 22, 2001.
Signature Title
--------- -----
/s/ Dan L. Duncan Chairman of the Board and
- --------------------------------- Director
Dan L. Duncan
/s/ O.S. Andras President, Chief Executive
- --------------------------------- Officer and Director
O.S. Andras
/s/ Randa L. Duncan Director
- ---------------------------------
Randa L. Duncan
/s/ Richard H. Bachmann Executive Vice President,
- --------------------------------- Chief Legal Officer,
Richard H. Bachmann Secretary and Director
/s/ J. A. Berget Director
- ---------------------------------
J. A. Berget
/s/ Dr. Ralph S. Cunningham Director
- ---------------------------------
Dr. Ralph S. Cunningham
/s/ J. R. Eagan Director
- ---------------------------------
J. R. Eagan
/s/ Curtis R. Frasier Director
- ---------------------------------
Curtis R. Frasier
/s/ Lee W. Marshall, Sr. Director
- ---------------------------------
Lee W. Marshall, Sr.
/s/ Richard S. Snell Director
- ---------------------------------
Richard S. Snell
EXHIBIT 12.1
ENTERPRISE PRODUCTS PARTNERS L.P.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(amounts in millions $)
For the Year Ended December 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
----------------------------------------------------------
Income (loss) before minority interest
and equity investments $198.6 $108.0 $ (5.5) $ 37.0 $ 45.7
Add:
Fixed charges 42.6 23.3 21.5 37.6 36.7
Amortization of capitalized interest 0.2 0.1 0.1 0.1 0.1
Distributed income of equity investees 37.3 6.0 9.1 7.3 7.2
Less:
Capitalized interest (3.3) (0.2) (0.2) (2.0) (1.6)
Minority interest (2.3) (1.2) (0.1) (0.5) (0.6)
----------------------------------------------------------
Total Earnings $273.1 $136.0 $ 24.9 $ 79.5 $ 87.5
==========================================================
Fixed charges:
Interest expense 33.3 16.4 15.1 25.7 26.3
Capitalized interest 3.3 0.2 0.2 2.0 1.6
Interest portion of rental expense 6.0 6.7 6.2 9.9 8.8
----------------------------------------------------------
Total $ 42.6 $ 23.3 $ 21.5 $ 37.6 $ 36.7
==========================================================
Ratio of Earnings to Fixed charges 6.41x 5.84x 1.16x 2.11x 2.38x
==========================================================
These computations include the Company and its subsidiaries, and 50% or less
equity companies. For these ratios, "earnings" is the amount resulting from
adding and subtracting the following items.
Add the following, as applicable:
- consolidated pre-tax income before minority interest and income or
loss from equity investees;
- fixed charges;
- amortization of capitalized interest;
- distributed income of equity investees; and
- the Company's share of pre-tax losses of equity investees for which
charges arising from guarantees are included in fixed charges.
From the total of the added items, subtract the following, as
applicable:
- interest capitalized;
- preference security dividend requirements of consolidated
subsidiaries; and
- minority interest in pre-tax income of subsidiaries that have not
incurred fixed charges.
The term "fixed charges" means the sum of the following:
- interest expensed and capitalized;
- amortized premiums, discounts and capitalized expenses related to
indebtedness;
- an estimate of interest within rental expenses (equal to one-third of
rental expense); and
- preference security dividend requirements of consolidated
subsidiaries.
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
Sabine Propylene Pipeline L.P., a Texas limited partnership
EPOLP 1999 Grantor Trust
EXHIBIT 23.1
INDEPENDENT AUDITOR'S CONSENT
We consent to the incorporation by reference in Enterprise Products
Partners L.P.'s and Enterprise Products Operating L.P.'s Post-Effective
Amendment No. 1 to Registration Statement No. 333-36856 of Enterprise Products
Partners L.P. on Form S-8 of our report dated February 28, 2001, appearing in
the Annual Report on Form 10-K of Enterprise Products Partners L.P. for the year
ended December 31, 2000.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 22, 2001