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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2001.
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ____ to ____.
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 of organization)
2727 North Loop West, Houston, Texas 77008-1037
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 880-6500
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
Common Units New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None.
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
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 7, 2002, was approximately $465.7
million. This figure assumes that the Enterprise Products 1998 Unit Option Plan
Trust, Enterprise Products 2000 Rabbi Trust, EPOLP 1999 Grantor Trust, the
directors and executive officers of the General Partner and Shell US Gas & Power
LLC were affiliates of the registrant.
The registrant had 51,524,515 Common Units outstanding as of March 7, 2002.
ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS
Page No.
PART I
Glossary
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. 47
Item 8. Financial Statements and Supplementary Data. 50
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure. 50
PART III
Item 10. Directors and Executive Officers of the Registrant. 51
Item 11. Executive Compensation. 54
Item 12. Security Ownership of Certain Beneficial Owners and Management. 57
Item 13. Certain Relationships and Related Transactions. 58
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 61
Financial Statements F-1
Signatures Page S-1
Glossary
The following abbreviations, acronyms or terms used in this Form 10-K are
defined below:
Acadian Gas Acadian Gas LLC and subsidiaries, acquired from Shell in
April 2001
Basell Basell polyolefins and affiliates
BBtu Billion British thermal units, a measure of heating
value
Bcf Billion cubic feet
Bcf/d Billion cubic feet per day
BEF Belvieu Environmental Fuels, an equity investment of
EPOLP
Belle Rose Belle Rose NGL Pipeline LLC, an equity investment of
EPOLP
BP BP Amoco PLC and affiliates
BPD Barrels per day
BRF Baton Rouge Fractionators LLC, an equity investment of
EPOLP
BRPC Baton Rouge Propylene Concentrator, LLC, an equity
investment of EPOLP
Btu British thermal units, a measure of heating value
Company Enterprise Products Partners L.P. and subsidiaries
Devon Energy Devon Energy Corporation, its subsidiaries and
affiliates
Diamond-Koch Refers to affiliates of Valero Energy Corporation and
Koch Industries, Inc.
DIB Deisobutanizer
Dixie Dixie Pipeline Company, an equity investment of EPOLP
Dow Dow Chemical Company and affiliates
Dynegy Dynegy Inc. and affiliates
EBITDA Earnings before interest, taxes, depreciation and
amortization
EPCO Enterprise Products Company, an affiliate of the Company
El Paso El Paso Corporation, its subsidiaries and affiliates
EPIK EPIK Terminalling L.P. and EPIK Gas Liquids, LLC,
collectively, an equity investment of EPOLP
EPOLP Enterprise Products Operating L.P., the operating
subsidiary of the Company (also referred to as the
"Operating Partnership")
EPU Earnings per Unit
Equistar A joint venture of Lyondell Chemical Company, Millennium
Chemicals, Inc. and Occidental Petroleum Corporation
Exxon Mobil Exxon Mobil Corporation and affiliates
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GAAP United States Generally Accepted Accounting Principles
General Partner Enterprise Products GP, LLC, the general partner of the
Company and EPOLP
HSC Denotes our Houston Ship Channel pipeline system
Huntsman Huntsman Corporation and affiliates
Kinder Morgan Kinder Morgan Operating LP "A"
LIBOR London interbank offering rate
Lyondell Lyondell Petrochemical Company and affiliates
Manta Ray A Gulf of Mexico offshore Louisiana natural gas pipeline
system owned by Manta Ray Offshore Gathering Company,
LLC
MBA acquisition Refers to the acquisition of Mont
Belvieu Associates' remaining interest in the Mont
Belvieu NGL fractionation facility in 1999
MBFC Mississippi Business Finance Corporation
MBPD Thousand barrels per day
MLP Denotes the Company as guarantor of certain debt
obligations of EPOLP
MBbls Thousands of barrels
MMBbls Millions of barrels
MMBtu/d Million British thermal units per day, a measure of
heating value
MMBtus Million British thermal units, a measure of heating
value
MMcf Million cubic feet
MMcf/d Million cubic feet per day
Mont Belvieu Mont Belvieu, Texas
MTBE Methyl tertiary butyl ether
Nautilus A Gulf of Mexico offshore Louisiana natural gas pipeline
system owned by Nautilus Pipeline Company, LLC
Nemo Nemo Gathering Company, LLC, an equity investment of
EPOLP
Neptune Neptune Pipeline Company LLC
NGL or NGLs Natural gas liquid(s)
NYSE New York Stock Exchange
Ocean Breeze Ocean Breeze Pipeline Company, LLC
Operating Partnership EPOLP and its subsidiaries
Phillips Phillips Petroleum Company and affiliates
Promix K/D/S Promix LLC, an equity investment of EPOLP
PTR Plant thermal reduction
SEC U.S. Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards issued by
the FASB
SG and A Selling, general and administrative costs
Shell Shell Oil Company, its subsidiaries and affiliates
Starfish Starfish Pipeline Company, LLC, an equity investment of
EPOLP
Sun Sunoco Inc. and affiliates
TNGL acquisition Refers to the acquisition of Tejas Natural Gas Liquids,
LLC, an affiliate of Shell, in 1999
Tri-States Tri-States NGL Pipeline LLC, an equity investment of
EPOLP
VESCO Venice Energy Services Company, LLC, a cost method
investment of EPOLP
Williams Williams Energy Marketing & Trading
Wilprise Wilprise Pipeline Company, LLC, an equity investment of
EPOLP
1998 Trust Enterprise Products 1998 Unit Option Plan Trust, an
affiliate of EPCO
1999 Trust EPOLP 1999 Grantor Trust, a subsidiary of EPOLP
2000 Trust Enterprise Products 2000 Rabbi Trust, an affiliate of
EPCO
PART I
Items 1 and 2. Business and Properties.
General
Enterprise Products Partners L.P., a Delaware limited partnership, 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" or "EPOLP"), the Operating Partnership's
subsidiaries, and a number of investments with industry partners. Unless the
context requires otherwise, references to "we","us","our" or the "Company" are
intended to mean Enterprise Products Partners L.P., our Operating Partnership
and subsidiaries.
Our company was formed in April 1998 to acquire, own and operate all of the NGL
processing and distribution assets of Enterprise Products Company ("EPCO"). Our
General Partner, Enterprise Products GP, LLC, owns a 1.0% general partner
interest in the Company and a 1.0101% general partner interest in EPOLP. At
December 31, 2001, EPCO and its affiliates own 65.2% of our limited partner
interests and 70% of the General Partner with affiliates of Shell owning 23.2%
of our limited partner interests and 30% of the General Partner. Our principal
executive offices are located at 2727 North Loop West, Houston, Texas 77008-1038
and our telephone number is 713-880-6500.
We are a leading North American provider of a wide range of midstream energy
services to our customers located primarily along the central and western Gulf
Coast. Our services include the:
. gathering, transmission and storage of natural gas from both onshore
and offshore Louisiana developments;
. purchase and sale of natural gas in south Louisiana;
. processing of natural gas into a merchantable and transportable
product that meets industry quality specifications by removing NGLs
and impurities;
. fractionation of mixed NGLs produced as by-products of oil and natural
gas production into their component products: ethane, propane,
isobutane, normal butane and natural gasoline;
. conversion of normal butane to isobutane through the process of
isomerization;
. production of MTBE from isobutane and methanol;
. transportation of NGL products to customers by pipeline and railcar;
. production of high purity propylene from refinery-sourced
propane/propylene mix;
. import and export of certain NGL and petrochemical products through
our dock facilities;
. transportation of high purity propylene by pipeline; and
. storage of NGL and petrochemical products.
Business Strategy
Our business strategy is to (i) capitalize on expected increases in natural gas
and NGL production resulting from development activities in the deepwater and
continental shelf areas of the Gulf of Mexico, (ii) develop and invest in joint
venture projects with strategic partners that will provide the raw materials for
the project or purchase the project's end products, (iii) expand our asset base
through accretive acquisitions of complementary midstream energy assets from
major energy companies that seek to divest "non-core" assets and from companies
that are required by regulatory agencies to divest assets, and (iv) increase our
fee-based cash flows by investing in fee-based pipelines and other businesses.
Cautionary Statement regarding Forward-Looking Information and Risk Factors
This annual report on Form 10-K contains various forward-looking statements and
information that are based on our beliefs and those of the General Partner, as
well as assumptions made by and information currently available to us. When used
in this document, words such as "anticipate," "project," "expect," "plan,"
"forecast," "intend," "could," "believe," "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 we and
the General Partner believe that such expectations reflected in such
forward-looking statements are reasonable, neither we nor the
1
General Partner can give any assurance that such expectations will prove to be
correct. Such statements are subject to a variety of risks, uncertainties and
assumptions. If one or more of these risks or uncertainties materialize, or if
underlying assumptions prove incorrect, our actual results may vary materially
from those we anticipated, estimated, projected or expected.
An investment in our securities involves a degree of risk. Among the key risk
factors that may have a direct bearing on our results of operation and financial
condition are:
. competitive practices in the industries in which we compete;
. fluctuations in oil, natural gas and NGL prices and production due to
weather and other natural and economic forces;
. operational and systems risks;
. environmental liabilities that are not covered by indemnity or
insurance;
. the impact of current and future laws and governmental regulations
(including environmental regulations) affecting the NGL industry in
general and our operations in particular;
. the loss of a significant customer;
. the use of financial instruments to hedge commodity and other risks
which prove to be economically ineffective; and
. the failure to complete one or more new projects on time or within
budget.
The prices of natural gas and NGLs are subject to fluctuations in response to
changes in supply, market uncertainty and a variety of additional factors that
are beyond our control. These factors include the level of domestic oil, natural
gas and NGL production and development, the availability of imported oil and
natural gas, actions taken by foreign oil and natural gas producing nations and
companies, the availability of transportation systems with adequate capacity,
the availability of competitive fuels and products, fluctuating and seasonal
demand for oil, natural gas and NGLs, and conservation and the extent of
governmental regulation of production and the overall economic environment.
In addition, we must obtain access to new natural gas volumes for our processing
business in order to maintain or increase gas plant throughput levels to offset
natural declines in field reserves. The number of wells drilled by third-parties
to obtain new volumes 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 our control.
The products that we process, sell or transport are principally used as
feedstocks in petrochemical manufacturing and in the production of motor
gasoline and as fuel for residential and commercial heating. A reduction in
demand for our products or services by industrial customers, whether because of
general economic conditions, reduced demand for the end products made with NGL
products, increased competition from petroleum-based products due to pricing
differences, adverse weather conditions, governmental regulations affecting
prices and production levels of natural gas or the content of motor gasoline or
other reasons, could have a negative impact on our results of operation. A
material decrease in natural gas production or crude oil refining, as a result
of depressed commodity prices or otherwise, or a decrease in imports of mixed
butanes, could result in a decline in volumes processed and sold by us.
Lastly, our expectations regarding future capital expenditures are only
forecasts regarding these matters. These forecasts may be substantially
different from actual results due to various uncertainties including the
following key factors: (a) the accuracy of our estimates regarding capital
spending requirements, (b) the occurrence of any unanticipated acquisition
opportunities, (c) the need to replace unanticipated losses in capital assets,
(d) changes in our strategic direction and (e) unanticipated legal, regulatory
and contractual impediments with regards to our construction projects.
For a description of the tax and other risks of owning our limited partner
interests, see our registration documents (together with any amendments thereto)
filed with the SEC on Form S-1/A dated July 21, 1998, Form S-3 dated December
21, 1999 and Form S-3 dated February 23, 2001.
2
Recent Acquisitions and related developments
During 2001, we completed or initiated approximately $860 million of capital
spending on internal growth projects, equity investments and business
acquisitions. These include $226 million paid to Shell for the purchase of
Acadian Gas (an onshore Louisiana natural gas pipeline system) and a combined
$112 million paid to El Paso for equity interests in four Gulf of Mexico natural
gas pipelines (primarily offshore systems). During the first quarter of 2002, we
completed the purchase of a propylene fractionation facility, 30 hydrocarbon
salt dome storage wells and related equipment located in Mont Belvieu, Texas
from Diamond-Koch for $368 million.
Also, we issued the last installment of 3.0 million non-distribution bearing,
convertible Special Units to Shell in August 2001 under an agreement executed as
part of the 1999 TNGL acquisition. The value of these new Units increased the
purchase price of the TNGL acquisition by $117 million to a final amount of
approximately $529 million.
For a further discussion of the pipeline and storage acquisitions, please see
the "Pipelines" discussion on page 8. Additional information regarding the
issuance of the new Special Units can be found in Note 7 of the Notes to
Consolidated Financial Statements beginning on page F-7.
The Company's Operations
We have five reportable operating segments: Fractionation, Pipelines,
Processing, Octane Enhancement and Other. Fractionation primarily includes NGL
fractionation, isomerization services, and propylene fractionation. Pipelines
consists of liquids and natural gas pipeline systems, storage and import/export
terminal services. Processing includes the natural gas processing business and
NGL merchant activities. Octane Enhancement represents our equity interest in a
facility that produces motor gasoline additives to enhance octane (currently
producing MTBE). The Other segment consists primarily of fee-based marketing
services.
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.
Fractionation
NGL fractionation
Our NGL fractionation operations include seven NGL fractionators with a combined
gross processing capacity of 558 MBPD with a net processing capacity to us of
290 MBPD. A summary of our NGL fractionation facilities at December 31, 2001 is
as follows:
NGL Gross Our Our Net
Fractionation Capacity, Ownership Capacity,
Facility Location MBPD Interest MBPD
---------------------------------------------------------------
Mont Belvieu Texas 210 62.5% 131
Norco Louisiana 70 100% 70
BRF Louisiana 60 32.24% 19
Promix Louisiana 145 33.33% 48
Tebone Louisiana 30 33.7% 10
Venice Louisiana 36 13.1% 5
Petal Mississippi 7 100% 7
--------- ---------
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
3
industrial fuel. Isobutane is fractionated from mixed butane (a mixed 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, 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 of 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 a blendstock for motor gasoline or as a 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 from natural gas, mixed NGLs are typically transported to
a centralized facility for fractionation. Recoveries of mixed NGLs by gas
processing plants represent the most important source of throughput for our NGL
fractionators and is generally governed by the degree to which NGL prices exceed
the cost (principally that of natural gas as a feedstock and as a fuel) of
separating the mixed NGLs from the 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 by NGL extraction, the mixed NGL
recovery levels of gas processing plants may be reduced, leading to a reduction
in volumes available for NGL fractionation.
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 crude oil refineries to our NGL fractionation facilities
are typically transported by NGL pipelines and, to a lesser extent, by railcar
and truck. We also take delivery of mixed NGL imports through our Houston Ship
Channel import terminal, which is connected to our Mont Belvieu complex via
pipeline.
The majority of our NGL fractionation facilities process mixed NGL streams for
third-party customers and our NGL merchant business by charging them a toll
fractionation fee. Toll fee arrangements typically include a base cents per
gallon fee for mixed NGLs processed subject to adjustment for changes in certain
fractionation expenses. Exclusive to our Norco facility, we are paid for
fractionation services by receiving a percentage of NGLs fractionated for
third-party customers (i.e., in-kind fees). The results of operation of our NGL
fractionation business are dependent upon the volume of mixed NGLs processed and
either the level of toll processing fees charged (in toll fee-based operations)
or the value of NGLs received (applicable to in-kind fee arrangements only). The
NGL fractionation business exhibits little to no seasonal variation. Lastly, we
are exposed to the pricing risks of NGLs only to the extent that we receive
in-kind fees for our services, since our customers generally retain title to the
mixed NGL streams that we process and the NGL products that are ultimately
produced.
Management believes that sufficient volumes of mixed NGLs, especially those
originating from Gulf Coast 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 along the Gulf
Coast. In addition, significant volumes of mixed NGLs are contractually
committed to our facilities by joint owners and third-party customers.
Although competition for NGL fractionation services is primarily based on the
fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and
distribute NGL products is also an important competitive factor and is a
function of the existence of the necessary pipeline and storage infrastructure.
NGL fractionators connected to extensive transportation and distribution systems
such as ours have direct access to larger markets than those with less extensive
connections. We compete with a number of NGL fractionators in Texas, Louisiana
and Kansas. Our Mont Belvieu NGL fractionator competes directly with three local
facilities having an estimated combined processing capacity of 475 MBPD and
indirectly with two other Texas facilities having a combined processing capacity
of 210 MBPD. In addition, our facilities compete on a more limited basis with
two facilities in Kansas and
4
several facilities in Louisiana. Finally, we also compete with a number of
producers who operate small NGL fractionators at individual field processing
facilities.
Principal NGL fractionation facilities
During 2001, our NGL fractionation facilities processed mixed NGLs at an average
rate of 204 MBPD or 70% of capacity, both amounts on a net basis. The following
table shows net processing volumes and capacity (both in MBPD) and the
corresponding overall utilization rates of our NGL fractionation facilities for
the last three years:
NGL For Year Ended December 31,
----------------------------------
Fractionation Facility 2001 2000 1999
---------------------------------------------------------------
Mont Belvieu 110 106 78
Norco 41 47 48
BRF 14 15 13
Promix 30 34 30
Other 9 11 15
----------------------------------
Total net volume 204 213 184
==================================
Net capacity 290 290 264
==================================
Utilization rate 70% 73% 70%
==================================
Mont Belvieu. We operate one of the largest NGL fractionation facilities in the
United States with a gross processing capacity of 210 MBPD at Mont Belvieu,
Texas. 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. Our Mont
Belvieu NGL fractionation facility is supported by long-term fractionation
agreements with Burlington Resources, Chevron Texaco and Duke Energy (accounting
for 63 MBPD of net processing volume in 2001), each of which is a significant
producer of NGLs and a co-owner of the facility. We own an effective 62.5%
interest in this facility.
Norco. We own and operate an NGL fractionation facility at Norco, Louisiana. The
Norco facility receives mixed NGLs via pipeline from the Yscloskey, Toca and
Crawfish gas processing plants in Louisiana and has a gross processing capacity
of 70 MBPD. During 2001, long-term in-kind fee arrangements exclusive to this
facility accounted for approximately 40 MBPD of processing volume.
BRF. We operate and own a 32.24% interest in BRF, which owns a 60 MBPD NGL
fractionation facility and related pipeline transportation assets located near
Baton Rouge, Louisiana. The BRF facility processes mixed NGLs provided by the
co-owners of the facility (Williams, BP and Exxon Mobil) from production areas
in Alabama, Mississippi and southern Louisiana including offshore Gulf of Mexico
areas.
Promix. We operate and own a 33.33% 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 NGL salt dome storage wells and a barge loading
facility. Promix receives mixed NGLs from numerous gas processing plants located
in southern Louisiana.
Isomerization
Our isomerization business includes three butamer reactor units and eight
associated DIBs located in Mont Belvieu, Texas, which comprise the largest
commercial isomerization complex in the United States. These facilities have an
average combined production capacity of 116 MBPD of isobutane. We own the
isomerization facilities with the exception of one of the butamer reactor units,
which we control through a long-term lease. We operate the facilities.
5
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 2001 2000 1999
----------------------------------------------------------------
Production 80 74 74
===================================
Capacity 116 116 116
===================================
Utilization rate 69% 64% 64%
===================================
Our commercial isomerization units convert normal butane into mixed butane,
which is subsequently fractionated into normal butane, isobutane and high purity
isobutane. The demand for commercial isomerization services depends upon the
industry's requirements for high purity isobutane and isobutane in excess of
naturally occurring isobutane produced from NGL fractionation and refinery
operations. 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 operation of this business
are generally dependent upon the volume of normal and mixed butanes processed
and the level of toll processing fees charged to customers. The principal uses
of isobutane are for alkylation, propylene oxide and in the production of MTBE.
We use the isomerization facilities to convert normal butane into isobutane
(including high purity grade) for our toll processing customers, including our
isobutane merchant business that is part of our Processing segment. Our larger
third-party toll processing customers (such as Lyondell and Huntsman) operate
under long-term contracts in which they supply normal butane feedstock and pay
us toll processing fees based on the volume of isobutane produced. We, as well
as our partners in BEF, use the high purity isobutane produced by these
facilities to meet our feedstock obligations of the MTBE plant under tolling
arrangements. Our isobutane merchant business uses the isomerization facilities
to meet the requirements of its isobutane sales contracts when the processing of
Company-owned inventories of normal and/or mixed butanes is necessary. During
2001, 18 MBPD of isobutane production was attributable to our merchant
activities, 14 MBPD to BEF-related contracts, with the balance related to
various toll processing arrangements.
In the isomerization market, we compete with facilities located in Kansas,
Louisiana and New Mexico. Competitive factors affecting this business include
the level of toll processing fees charged, the quality of isobutane that can be
produced and access to pipeline and storage infrastructure. We believe that our
isomerization facilities benefit from the integrated nature of the Mont Belvieu
complex with its extensive connections to pipeline and storage assets.
Propylene fractionation
Our propylene fractionation business consists of three polymer grade propylene
facilities and one chemical grade propylene plant. These assets include a
controlling interest in a polymer grade propylene fractionation facility ("Mont
Belvieu III") recently purchased from Diamond-Koch (see "2002 developments"
below). The following table summarizes our propylene fractionation business
assets and ownership at March 1, 2002:
Propylene Gross Our Effective Our Net
Fractionation Capacity, Ownership Capacity,
Facility Location MBPD Interest MBPD
--------------------------------------------------------------------
Mont Belvieu I Texas 17 100% 17
Mont Belvieu II Texas 14 100% 14
Mont Belvieu III Texas 41 66.67% 27.3
BRPC Louisiana 23 30% 7
--------- ---------
Total 95 65.3
========= =========
6
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 can also be produced from chemical grade propylene
feedstock. Likewise, chemical grade propylene is also a by-product of olefin
(ethylene) production. Approximately 50% 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 a basic petrochemical used in plastics, synthetic fibers and foams.
Overall, the propylene fractionation business exhibits little seasonality.
During 2001, our propylene fractionation facilities produced at an average rate
of 31 MBPD or 82% 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 our facilities for the last three years:
Propylene For Year Ended December 31,
----------------------------------
Fractionation Facility 2001 2000 1999
---------------------------------------------------------------
Mont Belvieu I and II 27 29 28
BRPC 4 4
----------------------------------
Total net volume 31 33 28
==================================
Net capacity 38 35 31
==================================
Utilization rate 82% 94% 90%
==================================
We compete with numerous producers of polymer grade propylene, which include
many of the major refiners on the Gulf Coast. Generally, the propylene
fractionation business competes in terms of the level of toll processing fees
charged and access to pipeline and storage infrastructure. Our propylene
fractionation units have been designed to be cost efficient which allows us to
be very competitive in terms of processing fees. In addition, our facilities are
connected to extensive pipeline transportation and storage facilities, which
provide our customers with operational flexibility.
2002 developments
On February 1, 2002, we completed the purchase of various propylene
fractionation assets from affiliates of Valero Energy Corporation and Koch
Industries, Inc. (collectively, "Diamond-Koch") and certain inventories of
refinery grade propylene, propane and polymer grade propylene owned by such
affiliates for approximately $239 million (subject to certain post-closing
adjustments). The primary asset purchased was a 66.67% interest in a 41 MBPD
(27.3 MBPD, net) polymer grade propylene fractionation facility located in Mont
Belvieu, Texas (deemed "Mont Belvieu III"). When combined with our existing Mont
Belvieu I and II facilities, we own 58.3 MBPD of net processing capacity at this
key industry hub.
Principal propylene fractionation facilities
Mont Belvieu I and II. We operate two polymer grade propylene fractionation
facilities (Mont Belvieu I and II) in Mont Belvieu, Texas having a combined
capacity of 31 MBPD. We own a 54.6% interest in Mont Belvieu I and all of Mont
Belvieu II. We lease the remaining 45.4% interest in Mont Belvieu I from a
customer, Basell.
Results of operation for our polymer grade propylene plants are generally
dependent upon toll processing arrangements and propylene merchant activities.
Under toll processing arrangements, we are paid fees based on throughput of
refinery grade propylene used to produce polymer grade propylene. Our largest
toll processing customers in 2001 were Huntsman and Equistar. In our propylene
merchant business, we have several long-term polymer grade propylene sales
agreements, the largest of which is with Basell. In order to meet our merchant
obligations, we have entered into several long-term agreements to purchase
refinery grade propylene. In order to limit the exposure to price risk in the
merchant side of this business, we attempt to match the timing and price of our
7
feedstock purchases with those of the sales of end products. During 2001, 10
MBPD of our net polymer grade propylene production was associated with toll
processing operations with the balance attributable to merchant activities.
We are able to unload barges carrying refinery grade propylene using our import
terminal located on the Houston Ship Channel. We are also able to receive
supplies of refinery grade propylene through our Mont Belvieu truck and rail
unloading facility and from refineries and other producers connected to our HSC
pipeline system. In turn, polymer grade propylene is transported to customers by
truck or pipeline.
Beginning in February 2002, we are also able to load and unload volumes of
polymer grade propylene as a result of our 50% investment in Olefins Terminal
Corporation located in Seabrook, Texas. For more information regarding this
facility, see page 13.
BRPC. We operate and own a 30% interest in BRPC, which owns a 23 MBPD chemical
grade propylene production facility located near Baton Rouge, Louisiana. This
unit, located across the Mississippi River from Exxon Mobil's refinery and
chemical plant, fractionates refinery grade propylene produced by Exxon Mobil
into chemical grade propylene for a toll processing fee. Results of operation of
BRPC are dependent upon the volume of refinery grade propylene processed and the
level of fees charged to Exxon Mobil.
Pipelines
Our Pipelines segment owns or has interests in approximately 4,800 miles of
natural gas and liquids transportation and distribution pipelines located
primarily along the central and western Gulf Coast of the U.S. This segment also
includes our storage and import/export terminal services.
Natural gas pipelines
The Company entered the natural gas pipeline business in 2001. During the last
year, we invested $338 million in such businesses including $226 million paid to
Shell for the purchase of Acadian Gas (an onshore Louisiana system) and a
combined $112 million paid to El Paso for equity interests in four Gulf of
Mexico natural gas pipelines (primarily Gulf of Mexico offshore Louisiana
systems). The acquisition of these businesses represent strategic investments
for the Company. We believe 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 our midstream energy
service relationship with long-term NGL customers (producers, petrochemical
suppliers and refineries) and provide us with opportunities to generate
additional fee-based cash flows.
The following table summarizes our natural gas pipeline assets and ownership
interests at December 31, 2001:
Length Our
In Ownership
Natural Gas Pipelines Miles Interest
---------------------------------------------------
Acadian Gas 1,015 100%
Stingray 379 50%
Manta Ray and Nautilus 336 25.67%
Evangeline 27 49.5%
Nemo 24 33.92%
------
Total 1,781
======
Our natural gas pipeline systems provide for the gathering, transmission and
storage of natural gas from both onshore and offshore Louisiana developments.
Typically, these systems receive natural gas from producers, other pipelines or
shippers through system interconnects and redeliver the natural gas at other
points throughout the system. Generally, natural gas pipeline transportation
agreements generate revenue for these systems based on a transportation fee per
unit of volume (generally in MMBtus) transported. Natural gas pipelines (such as
our Acadian Gas system) may also gather and purchase natural gas from producers
and suppliers and resell such natural
8
gas to customers such as electric utility companies, local natural gas
distribution companies and industrial customers. As such, our Acadian Gas
operation could be exposed to commodity price risk to the extent it takes title
to natural gas volumes through certain of its contracts. Our Gulf of Mexico
systems generally do not take title to the natural gas that they transport; the
shipper retains title and the associated commodity price risk.
Within their market area, our onshore systems compete with other natural gas
pipeline companies on the basis of price (in terms of transportation rates
and/or natural gas selling prices), service and flexibility. Our competitive
position within the onshore market is positively affected by our longstanding
relationships with customers and the limited number of delivery pipelines
connected (or capable of being connected) to the customers we serve. In
addition, our financial flexibility gives our customers confidence in our
ability to deliver on contracts. Conversely, we are exposed to concentrations of
customers in certain market segments (such as the chemical/refining industry in
south Louisiana) in which the business cycle could affect their creditworthiness
and/or ability to continue business with us. Our Gulf of Mexico offshore
pipeline systems compete primarily on the basis of transportation rates and
service. These pipelines are strategically situated to gather a substantial
volume of the natural gas production in the offshore Louisiana area from both
continental shelf and deepwater developments.
Our onshore and offshore systems are affected by natural gas exploration and
production activities. If these exploration and production activities decline as
a result of a weakened domestic economy or due to natural depletion of the oil
and gas fields they are connected to, then throughput volumes on these pipelines
will decline, thereby affecting our earnings from these investments. We actively
seek to offset the loss of volumes due to natural depletion by seeking
connections to new customers and fields.
In light of the complex, interconnected nature of the pipeline networks and the
varying diameter of pipe used and pressure employed, the utilization of these
assets is measured in MMBtu/d of natural gas transported.
Principal natural gas pipelines
Acadian Gas and Evangeline. In April 2001, we acquired Acadian Gas from Shell
for approximately $226 million using proceeds from the issuance of our $450
million Senior Notes B. Acadian Gas is involved in the purchase, sale,
transportation and storage of natural gas in Louisiana. Its assets are comprised
of the 438-mile Acadian and 577-mile Cypress natural gas pipelines and a leased
natural gas storage facility. Acadian Gas owns a 49.5% equity interest in
Evangeline, which owns a 27-mile natural gas pipeline. We operate the Acadian
Gas and Evangeline systems.
Overall, the Acadian Gas and Evangeline systems are comprised of 1,042 miles of
pipeline. During 2001, these systems had an average throughput of 783,485
MMBtu/d of natural gas during the period in which we owned or had an interest in
these assets, on a net basis.
The Acadian Gas and Evangeline systems link supplies of natural gas from Gulf of
Mexico production (through connections with offshore pipelines) and various
onshore developments to industrial, electric and local gas distribution
customers primarily located in Louisiana. In addition, these systems have
interconnects with twelve interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at the Henry
Hub.
Stingray. In January 2001, we purchased a 50% interest in the Stingray natural
gas pipeline system and a related natural gas dehydration facility from El Paso.
We own our interest in these assets through our 50% equity investment in
Starfish, a joint venture with Shell. The Stingray system is a 379-mile,
FERC-regulated natural gas pipeline system that transports natural gas and
condensate from certain production areas located in the Gulf of Mexico offshore
Louisiana to onshore transmission systems located in south Louisiana. The
natural gas dehydration facility is connected to the onshore terminus of the
Stingray system in south Louisiana. During 2001, this system transported 300,000
MMBtu/d of natural gas, on a net basis. Shell is the operator of these systems
and owns the remaining equity interest in Starfish.
Manta Ray, Nautilus and Nemo. In conjunction with our purchase of the Stingray
interest, we also acquired from El Paso a 25.67% interest in the Manta Ray and
Nautilus natural gas pipeline systems located in the Gulf of Mexico offshore
Louisiana. The Manta Ray system comprises approximately 235 miles of unregulated
pipelines and related
9
equipment and the Nautilus system comprises approximately 101 miles of
FERC-regulated pipelines. Our ownership of the Manta Ray and Nautilus systems is
through our unconsolidated affiliate, Neptune. We also purchased from El Paso a
33.92% interest in the 24-mile Nemo natural gas pipeline, which became
operational in August 2001.
Like Stingray, Shell is the operator of the Manta Ray and Nemo systems. Shell is
the administrative agent for Nautilus. Shell and Marathon are our co-owners in
Neptune and Shell owns the remaining interest in Nemo. These systems transported
a combined 265,914 MMBtu/d of natural gas during 2001, as measured on a net
basis.
Liquids pipelines
Our liquids pipelines transport mixed NGLs and hydrocarbons to NGL fractionation
plants, distribute purity NGL products and propylene to petrochemical plants and
refineries and deliver propane to customers along the Dixie pipeline. Our
pipelines provide transportation services to customers on a fee basis. As such,
the results of operation for this business are generally dependant upon the
volume of product transported and the level of fees charged to customers (which
include our 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 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 at refineries.
The following table summarizes our principal liquids pipeline transportation and
distribution networks at December 31, 2001:
Length Our
In Ownership
Liquids Pipelines Miles Interest
-------------------------------------------------------
Dixie 1,301 19.88%
Louisiana Pipeline System 536 100%
Lou-Tex Propylene 291 100%
Lou-Tex NGL 206 100%
HSC 175 100%
Tri-States 169 33.33%
Lake Charles/Bayport 164 50%
Chunchula 117 100%
Belle Rose 48 41.67%
Wilprise 30 37.35%
------
Total liquids pipelines 3,037
======
10
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, utilization is
measured in terms of throughput (in MBPD, on a net basis).
For Year Ended December 31,
-------------------------------
Liquids Pipelines 2001 2000 1999
---------------------------------------------------------------------
Dixie 26 14 14
Louisiana Pipeline System 138 115 74
Lou-Tex Propylene 27 23
Lou-Tex NGL 29 30
HSC 133 106 99
Tri-States, Wilprise and Belle Rose 36 42 41
Lake Charles/Bayport 6 5 5
Chunchula 5 6 7
-------------------------------
Total liquids pipelines 400 341 240
===============================
In the markets we serve, we compete with a number of intrastate and interstate
liquids pipeline companies (including those affiliated with major oil and gas
companies) and barge and truck fleet operators. In general, our liquids
pipelines compete with these entities in terms of transportation rates and
service. We believe that our pipeline systems are cost effective and allow for
significant flexibility in rendering transportation services for our customers.
Principal liquids pipelines
Dixie. The Dixie pipeline is a 1,301-mile propane pipeline which transports
propane supplies from Mont Belvieu, Texas and Louisiana to markets in the
southeastern United States. We own a 19.88% interest in Dixie. An affiliate of
Phillips operates the system.
Louisiana Pipeline System. The Louisiana Pipeline System is a 536-mile 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 our gas processing plants and other facilities located in
Louisiana. In general, we own and operate these pipelines.
Lou-Tex Propylene. 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. We own
and operate this system.
Lou-Tex NGL. The Lou-Tex NGL pipeline system consists of a 206-mile NGL pipeline
used to provide transportation services for NGL products and refinery grade
propylene between the Louisiana and Texas markets. We also use this pipeline to
transport mixed NGLs from our Louisiana gas processing plants to our Mont
Belvieu NGL fractionation facility. We own and operate this pipeline system.
HSC. The HSC pipeline system is a collection of NGL and petrochemical pipelines
aggregating 175 miles in length extending from our Houston Ship Channel
import/export terminal facility to Mont Belvieu, Texas. This pipeline is used to
deliver products to third-party petrochemical plants and refineries as well as
to deliver feedstocks to our Mont Belvieu facilities. This system is also used
to transport MTBE produced by BEF to delivery locations along the Houston Ship
Channel. We own and operate this pipeline system.
Tri-States, Belle Rose and Wilprise. We participate in pipeline joint ventures
which supply mixed NGLs to the BRF and Promix NGL fractionators. We own a 33.33%
interest in Tri-States, which owns a 169-mile NGL pipeline that extends from
Mobile Bay, Alabama to near Kenner, Louisiana. In addition, we own a 41.67%
interest
11
in and operate Belle Rose, which owns a 48-mile NGL pipeline that extends from
near Kenner, Louisiana to Promix. Lastly, we own a 37.35% interest in Wilprise,
which owns a 30-mile NGL pipeline that extends from near Kenner, Louisiana to
Sorrento, Louisiana. An affiliate of Williams operates the Tri-States and
Wilprise systems.
Lake Charles/Bayport. Our Lake Charles/Bayport system is a 164-mile propylene
pipeline used to distribute polymer grade propylene from Mont Belvieu to
Basell's polypropylene plants in Lake Charles, Louisiana and Bayport, Texas and
to Aristech's facility in La Porte, Texas. A segment of the pipeline is jointly
owned by us and Basell, and another segment is leased from Exxon Mobil.
Chunchula. The Chunchula pipeline system is a 117-mile NGL pipeline extending
from the Alabama-Florida border to our storage and NGL fractionation facilities
in Petal, Mississippi for further distribution. We own and operate this system.
Storage and import/export terminal
Storage. Our hydrocarbon storage facilities and NGL import/export terminal are
integral parts of our pipeline operations. In general, our storage wells are
used to store NGLs and petrochemical products for customers and ourselves. The
profitability of storage operations is primarily dependent upon the volume of
material stored and the level of fees charged. In January 2002, we completed the
purchase of Diamond-Koch's Mont Belvieu storage assets for $129 million. These
facilities include 30 storage wells with a useable capacity of 68 MMBbls and
allow for the storage of mixed NGLs, ethane, propane, butanes, natural gasoline
and olefins (such as ethylene), polymer grade propylene, chemical grade
propylene and refinery grade propylene. With the addition of the former
Diamond-Koch facilities, we own and operate 95 MMBbls of storage capacity at
Mont Belvieu.
We also own storage facilities located at Breaux Bridge, Napoleonville, Sorrento
and Venice, Louisiana having a gross capacity of 33 MMBbls and a net capacity of
14.8 MMBbls. Our Mississippi storage assets are comprised of facilities located
at or near Petal and Hattiesburg having a gross capacity of 12 MMBbls and a net
capacity of 9.5 MMBbls. Of the facilities located in Louisiana and Mississippi,
we operate those located in Breaux Bridge, Louisiana and Petal, Mississippi.
Affiliates of Koch, Dynegy and Shell operate the remaining facilities.
The following table summarizes our storage assets by state at March 1, 2002:
Gross Net
Capacity, Capacity,
Storage Assets MMBbls MMBbls
------------------------------------------------------
Texas 95 95
Louisiana 33 14.8
Mississippi 12 9.5
----------------------------
Total 140 119.3
============================
When used in conjunction with our processing operations, these wells allow us to
mix various batches of feedstock and maintain a sufficient supply and stable
composition of feedstock to our processing facilities. At times, we provide some
of our processing customers with short-term storage services (typically 30 days
or less) at nominal amounts when they cannot take immediate delivery of
products. Intersegment revenues for the Pipelines segment include those fees
charged to our various merchant businesses for use of the storage facilities.
We are primarily in the merchant storage business with our focus being to
attract customers to store products in our wells for a fee. Our competitors in
this area are other merchant storage and pipeline companies such as Texas
Eastern Pipeline Partners Company ("TEPPCO"), Dynegy and Equistar. In addition,
major oil and gas companies such as Exxon Mobil and Phillips occasionally use
their proprietary storage assets in a merchant role thereby entering into
competition with us and other merchant providers. Our Mont Belvieu facilities
(including those recently acquired from Diamond-Koch) represent the largest
merchant storage facilities in the world for NGLs and olefins. We compete with
other service providers primarily in terms of the fees charged, pipeline
connections and dependability. We believe that due to the integrated nature of
our operations, our storage customers have access to a competitively priced,
flexible and dependable network of assets.
12
Import/Export terminal. We lease and operate an NGL import facility located on
the Houston Ship Channel that enables NGL tankers to be offloaded at their
maximum unloading rate of 10,000 barrels per hour, thus minimizing laytime and
increasing the number of vessels that can be offloaded. This facility is
primarily used to offload volumes bound for our facilities in Mont Belvieu.
Typically, our import activity exhibits little seasonality; however, throughput
can be positively affected when domestic demand for NGLs exceeds supply making
it profitable to transport NGLs by barge or ship from overseas locations or
other domestic ports. For example, imports of normal butane destined for our
isomerization plants increased significantly during the second quarter of 2001
due to demand for isobutane. In addition, we own a 50% interest in EPIK, which
owns NGL export facilities at the same terminal including an NGL product chiller
and related equipment used for loading refrigerated marine tankers. The export
terminal can load vessels of refrigerated propane and butane at rates up to
5,000 barrels per hour. Traditionally, EPIK's export volumes are higher during
the winter months due to increased propane exports. The profitability of import
and export activities primarily depends upon the quantities loaded and offloaded
and the throughput fees associated with each activity.
The following table shows volumes loaded and offloaded through our import/export
terminal over the last three years (in MBPD, on a net basis).
For Year Ended December 31,
-------------------------------
Facility 2001 2000 1999
-------------------------------------------------------------------
NGL import facility 45 9 14
EPIK 8 17 10
-------------------------------
Total imports and exports 53 26 24
===============================
When compared to 2000, export activity declined as strong domestic pricing for
products reduced the economic need to export. Normal butane imports were higher
in 2001 due to increased isobutane production.
Our NGL import and EPIK's NGL export facility have a small number of
competitors, primarily Dynegy and Dow. These operations compete primarily in
terms of service (i.e., the ability to quickly load or offload vessels). Our
competitive position is enhanced because our extensive storage and pipeline
assets at Mont Belvieu allow us to load and offload ships very efficiently.
In February 2002, we acquired a 50% interest in Olefins Terminal Corporation
("OTC"). Our interest in OTC was acquired in connection with the purchase of the
Mont Belvieu III propylene fractionation facility from Diamond-Koch. OTC owns a
dock facility located in Seabrook, Texas for the receipt, storage, handling and
redelivery of polymer grade propylene.
Processing
The Processing segment consists of our natural gas processing business and
related merchant activities. At the core of our natural gas processing business
are twelve processing plants located on the Louisiana and Mississippi Gulf Coast
with a gross natural gas processing capacity of 11.61 Bcf/d (3.25 Bcf/d on a net
basis). Our net share of the NGL production from these plants, in addition to
NGLs we purchase on a merchant basis and a portion of the production from our
Mont Belvieu isomerization facilities, support the merchant activities included
in this operating segment.
The majority of the operating margin earned by our natural gas processing plants
is based on the relative economic value of the mixed NGLs extracted by the gas
plants as compared to the costs of extracting the mixed NGLs (principally that
of natural gas as a feedstock and as a fuel, plus plant operating expenses).
Natural gas processing arrangements where the processor (i.e., the Company)
takes title to the NGLs extracted from the natural gas stream are defined as
"keepwhole contracts". The processor reimburses producers (e.g., Shell and
others) for the market value of the energy extracted based upon the Btus (a
measure of heat value) consumed from the natural gas stream in the form of fuel
and mixed NGLs, multiplied by the market value of natural gas. The processor
derives a profit margin to the extent the market value of the NGLs extracted
exceeds the costs of extraction.
13
The most significant contract affecting our natural gas processing business is
the 20-year Shell Processing Agreement which grants us 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 deepwater
developments. This is a life of lease dedication which may extend the agreement
well beyond twenty years. Shell is the largest oil and gas producer and holds
one of the largest lease positions in the deepwater Gulf of Mexico. Generally,
this contract has 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
(i.e., life of lease dedication); plus
. the right to all title, interest and ownership in the mixed NGL stream
extracted by our gas plants 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.
We believe that natural gas and its associated NGL production from the Gulf of
Mexico will significantly increase in the coming years as a result of advances
in seismic and deepwater development technologies and continued capital spending
for exploration and production by major oil companies.
Several deepwater Gulf of Mexico developments began production during 2001.
These include Shell's Ursa, Brutus, Oregano, Crosby, Einset and Serrano
developments. As a result of these new streams of rich natural gas, in the
fourth quarter of 2001, we set a record for equity NGL production at 80 MBPD.
Had NGL demand supported full extraction, our equity NGL production during the
fourth quarter would have been in excess of 90 MBPD.
North American natural gas demand increased by 9 Bcf/d from 1980 to 2001, from
63 Bcf/d to approximately 72 Bcf/d. Because of its environmental and economic
advantages, natural gas has become the preferred fuel for new power generation
facilities. By 2005, industry expectations are that natural gas demand will
increase by an additional 9 Bcf/d to 81 Bcf/d. By 2010 and 2015, natural gas
demand is expected to increase to 93 Bcf/d and 102 Bcf/d, respectively. To
supply this demand, natural gas producers are challenged to find new sources of
gas.
The five key frontier gas supply areas that are expected to support the growing
demand for natural gas are Alaska, the Mackenzie Delta in Northwest Canada,
imports of liquefied natural gas ("LNG"), the deepwater Gulf of Mexico and the
Rocky Mountains. At present, the industry expects the Alaska and Mackenzie Delta
natural gas volumes will take eight to ten years to bring to market in light of
regulatory and environmental permitting, the execution of customer and
right-of-way agreements, pipeline construction requirements and other factors.
In the case of LNG, currently there are only four LNG import terminals in the
United States. Of the eleven terminals proposed to date, most would commence
operations in 2005 or later. In addition, a new fleet of LNG tankers must be
built to facilitate a major increase in LNG imports.
In the near term, the most viable sources of new natural gas supply are the
deepwater Gulf of Mexico and the Rocky Mountains. Production from deepwater Gulf
of Mexico areas is expected to increase from 2.9 Bcf/d in 2000 to approximately
5.7 Bcf/d by 2010 and 8.2 Bcf/d by 2015. New supplies from deepwater Gulf of
Mexico are expected to supply 20% of natural gas demand growth in the United
States by 2010 and 25% by 2015. The deepwater Gulf of Mexico developments are
even more strategic to the United States in terms of crude oil and condensate
production. In 2000, the Gulf of Mexico accounted for 24% of domestic crude oil
and condensate production. It is forecasted that by 2005, 37% of domestic crude
oil and condensate production will originate from the Gulf of Mexico (primarily
from deepwater developments)and by 2010, this percentage is expected to grow to
43% total domestic production.
Since natural gas from deepwater developments is primarily associated with the
production of crude oil, it usually contains a higher content of NGLs (in
quantities in excess of four gallons per Mcf of gas, referred to as "rich"
natural gas) than that of natural gas produced from continental shelf and
land-based production, which generally contains one to one and a half gallons of
NGLs per Mcf of gas. To meet the quality specifications of interstate pipelines
and end-use consumers, deepwater natural gas must be processed to remove the
NGLs or at least the heaviest NGL components. On an energy equivalent basis,
NGLs generally have a greater economic value as a raw material for
petrochemicals and motor gasoline than their value in natural gas.
14
Our 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 us to extract NGLs
from a raw natural gas stream when the market value of the NGLs exceeds the cost
(principally that of natural gas as a feedstock and as a fuel) of extracting the
mixed NGLs. After extraction, we transport the mixed NGLs 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 our merchant business to meet contractual requirements or sold on
spot and forward markets.
The following table lists our gas processing plants, their processing capacities
and corresponding ownership interest:
Gross Gas Net Gas
Gas Processing Our Processing
Processing Capacity Ownership Capacity
Facility Location (Bcf/d) Interest (Bcf/d)
--------------------------------------------------------------------
Yscloskey Louisiana 1.85 28.2% 0.52
Calumet Louisiana 1.60 35.4% 0.57
North Terrebonne Louisiana 1.30 33.7% 0.44
Venice Louisiana 1.30 13.1% 0.17
Toca Louisiana 1.10 57.1% 0.63
Pascagoula Mississippi 1.00 40% 0.40
Sea Robin Louisiana 0.95 15.5% 0.15
Blue Water Louisiana 0.95 7.4% 0.07
Iowa Louisiana 0.50 2% 0.01
Patterson II Louisiana 0.60 2% 0.01
Neptune Louisiana 0.30 66% 0.20
Burns Point Louisiana 0.16 50% 0.08
---------- ----------
Total 11.61 3.25
========== ==========
The natural gas throughput capacities of the plants are based on practical
limitations. Our utilization of these gas plants depends upon general economic
and operating conditions and is generally measured in terms of equity NGL
production. Equity NGL production is defined as the volume of NGLs extracted by
the gas plants to which we take title under the terms of processing agreements
or as a result of our plant ownership interests. Equity NGL production can be
adversely affected by high natural gas costs and/or low purity NGL product
prices. Our equity NGL production averaged 63 MBPD during 2001, 72 MBPD during
2000 and 67 MBPD during 1999.
As noted previously, we take title to a portion of the mixed NGLs that are
extracted by the gas plants. Once this mixed NGL volume is fractionated into
purity NGL products (ethane, propane, normal butane, isobutane and natural
gasoline), we use them to meet contractual requirements or sell them on spot and
forward markets as part of our overall merchant business activities. In our
isomerization merchant activities, we are party to a number of isobutane sales
contracts. In order to fulfill our obligations under these sales contracts, we
can purchase isobutane on the spot market for resale, sell our isobutane in
inventory or pay our isomerization business (which is part of the Fractionation
segment) a toll processing fee to process our inventories of imported or
domestically-sourced normal and mixed butanes into isobutane.
Since we take title to NGLs and are obligated under certain of our gas
processing contracts to pay market value for the energy extracted from the
natural gas stream, we are exposed to various risks, primarily that of commodity
price fluctuations. The prices of natural gas and NGLs are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of additional factors that are beyond our control. We attempt to mitigate these
risks through the use of commodity financial instruments. For a general
discussion regarding our commodity financial instruments, see Item 7A of this
Form 10-K.
Some of our exposure to commodity price risk is mitigated because natural gas
having a high content of NGLs must be processed in order to meet pipeline
quality specifications and to be suitable for ultimate consumption. To the
15
extent that natural gas is not processed and does not meet pipeline quality
specifications, this unprocessed natural gas and its associated crude oil
production may be subject to being shut-in (i.e., to not being processed and
made marketable). Therefore, producers are motivated to reach contractual
arrangements that are acceptable to gas processors in order for gas processing
services to be available on a continuous basis (e.g., through natural gas cost
reductions and other economic incentives to gas processors).
The consumption of NGL products in the United States can be separated into 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 cases, such as residential and commercial heating, a substitution of
other hydrocarbon products for NGL products would require a significant expense
or delay, but for other uses, such as the production of motor gasoline,
ethylene, industrial fuels and petrochemical feedstocks, such a substitution can
be readily made without significant delay or expense.
Because certain NGL products compete with other refined petroleum products in
the fuel and petrochemical feedstock markets, NGL product prices are set by or
in competition with refined petroleum products. Increased production and
importation of NGLs and NGL products in the United States may decrease NGL
product prices in relation to refined petroleum alternatives and thereby
increase consumption of NGL products as NGL products are substituted for other
more expensive refined petroleum products. Conversely, a decrease in the
production and importation of NGLs and NGL products could increase NGL product
prices in relation to refined petroleum product prices and thereby decrease
consumption of NGLs. However, because of the relationship of crude oil and
natural gas production to NGL production, we believe any imbalance in the prices
of NGLs and NGL products and alternative products would be temporary. Our gas
processing business does not exhibit a high degree of seasonality.
Our gas processing business and related merchant activities encounter
competition from fully integrated oil companies, intrastate pipeline companies,
major interstate pipeline companies and their non-regulated affiliates, and
independent processors. Each of our competitors has varying levels of financial
and personnel resources and competition generally revolves around price, service
and location issues. Our integrated system affords us flexibility in meeting our
customers' needs. While many companies participate in the gas processing
business, few have a presence in significant downstream activities such as NGL
fractionation and transportation, import/export services and merchant activities
as we do. Our competitive or leading strategic position and sizeable presence in
these downstream businesses allows us to extract incremental value while
offering our customers enhanced services, including comprehensive service
packages.
Our merchant activities utilize a fleet of approximately 625 railcars, the
majority of which are under short and long-term leases. The railcars are used to
deliver feedstocks to our facilities and to transport NGL products throughout
the United States. We have 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. This segment also includes
our 13.1% investment in VESCO. VESCO owns an integrated complex comprised of the
Venice gas processing plant, a fractionation facility, storage assets and gas
gathering pipelines in Louisiana.
Octane Enhancement
The Octane Enhancement segment consists of our 33.33% interest in BEF, which
owns a facility that produces motor gasoline additives to enhance octane. Our
partners in BEF are affiliates of Sun and Devon Energy. The BEF facility
currently produces MTBE and is located within our Mont Belvieu complex. The
gross capacity of the MTBE facility is approximately 15 MBPD with a net capacity
of 5 MBPD. For the years 2001, 2000 and 1999, net production averaged 5 MBPD. An
affiliate, EPCO, operates the facility.
The production of MTBE is driven by oxygenated fuel programs enacted under the
federal Clean Air Act Amendments of 1990 and other legislation and as an
additive to increase octane in motor gasoline. Any changes to the oxygenated
fuel 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 and could
have a negative impact on our operations. Although oxygenated fuel requirements
can be satisfied by using other products such as ethanol, MTBE has gained the
broadest acceptance due to its ready availability and
16
history of acceptance by refiners. Additionally, motor gasoline containing MTBE
can be transported through pipelines, which is a significant competitive
advantage over alcohol blends such as ethanol.
MTBE demand is linked to motor gasoline requirements in certain urban areas of
the United States designated as carbon monoxide and ozone non-attainment areas
by the Clean Air Act Amendments of 1990 and the California oxygenated motor
gasoline program. Motor gasoline demand in turn is affected by many factors,
including the price of motor gasoline (which is generally dependent upon crude
oil prices) and overall economic conditions. BEF has a ten-year off-take
agreement with Sun under which Sun is obligated to purchase all of BEF's MTBE
production through September 2004. Beginning in June 2000 and for the remaining
term of this agreement, Sun is required to purchase all of the plant's MTBE
production at spot-market related prices. Sun uses this MTBE primarily to
satisfy the gasoline blending requirements of its markets located in the eastern
United States.
Historically, the spot price for MTBE has been at a modest premium to gasoline
blend values. BEF is exposed to commodity price risk due to the market-related
pricing provisions of the Sun off-take agreement. In general, MTBE prices are
stronger during the April to September period of each year, which corresponds
with the summer driving season. Future MTBE demand is highly dependent upon
environmental regulation, federal legislation and the actions of individual
states (see Recent Regulatory Developments below).
Each owner of BEF is responsible for supplying one-third of the facility's
isobutane feedstock requirements through June 2004. We, along with the other two
co-owners, use high purity isobutane produced at our Mont Belvieu facilities to
meet this obligation. The methanol feedstock used by BEF is purchased from
third-parties under long-term contracts and transported to Mont Belvieu using
our HSC pipeline system. Lastly, BEF's MTBE production is transported to a
location on the Houston Ship Channel for delivery to Sun using our HSC pipeline
system.
The MTBE market has a number of producers, including a number of refiners who
produce MTBE for internal consumption in the manufacture of reformulated motor
gasoline. In general, MTBE producers compete in terms of price and production
(in terms of economies of scale and quality of product). While the Sun contract
is in effect, BEF is not directly exposed to its competition, although it is
affected by market pricing through the Sun off-take agreement. The world-class
scale of the BEF facility, combined with the technological advances incorporated
into its construction and maintenance, make it one of the most efficient
domestic MTBE plants in operation.
Recent Regulatory Developments. In recent years, MTBE has been detected in water
supplies. The major source of ground water contamination appears to be leaks
from underground storage tanks. Although these detections have been limited and
the great majority have been well below levels of public health concern, there
have been calls for the phase-out of MTBE in motor gasoline in various federal
and state governmental agencies and advisory bodies. For additional information
regarding the impact of environmental regulation on BEF, see "Impact of the
Clean Air Act's oxygenated fuels programs on our BEF investment" on page 22.
Alternative uses of the BEF facility. In light of these regulatory developments,
the owners of BEF have been formulating a contingency plan for use of the BEF
facility if MTBE were banned or significantly curtailed. Management is exploring
possible conversion of the BEF facility from MTBE production to alkylate
production. We believe that if MTBE usage is banned or significantly curtailed,
the motor gasoline industry would need a substitute additive to maintain octane
levels in motor gasoline and that alkylate would be an attractive substitute.
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 would range from $20 million to $90 million, with our share
of these costs ranging from $6.7 million to $30 million.
Other
This operating segment is primarily comprised of fee-based marketing services.
For a small number of clients, we perform NGL marketing services for which we
charge a commission. The clients we serve are primarily located in the states of
Washington, California and Illinois. We utilize the resources of our merchant
businesses to perform these services. Commissions are generally based on either
a percentage of the final sales price negotiated on behalf of the client or on a
fixed-fee per gallon basis. Our fee-based marketing services handle
approximately 23 MBPD of various NGL products with the period of highest
activity occurring during the summer months. The principal elements of
competition in this business are price and quality of service. This segment also
includes other
17
engineering services, construction equipment rentals and computer network
services that support other operations and business activities.
Employees
We do not have any employees. An affiliate, EPCO, employs all the persons
necessary for the operation of our business. At December 31, 2001, EPCO employed
898 employees involved in the management and operations of our business, none of
whom were members of a union. We reimburse EPCO for the services of certain of
its employees under a long-term services agreement (see "EPCO Agreement" on page
59).
Major Customers
Our revenues are derived from a wide customer base. Our largest customer, Shell
and its affiliates, accounted for 10.5% and 9.5% of consolidated revenues in
2001 and 2000, respectively. Approximately 80% of our revenues from Shell and
its affiliates are attributable to sales of NGL products which are recorded in
our Processing segment. For additional information regarding significant
customers of the last three fiscal years, see Note 15 of the Notes to the
Consolidated Financial Statements.
Regulation and Environmental Matters
Regulation of our interstate common carrier liquids pipelines
Our Chunchula, Lou-Tex Propylene, Lou-Tex NGL, Lake Charles/Bayport and Dixie
pipelines along with certain pipelines of the Louisiana Pipeline System are
interstate common carrier liquids pipelines subject to regulation by the Federal
Energy Regulatory Commission ("FERC") under the October 1, 1977 version of the
Interstate Commerce Act ("ICA").
As interstate common carriers, these pipelines provide service to any shipper
who requests transportation services, provided that products tendered for
transportation satisfy the conditions and specifications contained in the
applicable tariff. The ICA requires us to maintain tariffs on file with the FERC
that set forth the rates we charge for providing transportation services on our
interstate common carrier pipelines as well as the rules and regulations
governing these services.
The ICA gives the FERC authority to regulate the rates we charge for service on
the interstate common carrier pipelines. The ICA requires, among other things,
that such rates be "just and reasonable" and nondiscriminatory. The ICA permits
interested persons to challenge proposed new or changed rates and authorizes the
FERC to suspend the effectiveness of such rates for a period of up to seven
months and to investigate such rates. If, upon completion of an investigation,
the FERC finds that the new or changed rate is unlawful, it is authorized to
require the carrier to refund the revenues in excess of the prior tariff 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 during any of the twelve months preceding enactment that had not been
subject to complaint, protest or investigation 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 pipeline and portions of the Louisiana Pipeline System
are covered by the grandfathered provisions of the Energy Policy Act.
18
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.
We believe that the rates charged for transportation services on the interstate
pipelines we own or have an interest in 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 as well as the
novelty and uncertainty related to the FERC's new indexing methodology, we
cannot predict what rates we will be allowed to charge in the future for service
on our interstate common carrier pipelines. Furthermore, because rates charged
for transportation services must be competitive with those charged by other
transporters, the rates set forth in our tariffs will be determined based on
competitive factors in addition to regulatory considerations.
In a 1995 decision involving Lakehead Pipe Line Company ("Lakehead"), an
unrelated pipeline limited partnership, the FERC partially disallowed the
inclusion of income taxes in that partnership's cost of service. Subsequent
appeals of these rulings were resolved by settlement and were not adjudicated.
In another FERC proceeding involving SFPP, L.P. ("SFPP"), another unrelated
pipeline limited partnership, the FERC held that the limited partnership may not
claim an income tax allowance for income attributable to non-corporate partners,
both individuals and other entities. SFPP and other parties to the proceeding
have appealed the FERC's order to the U.S. Court of Appeals for the District of
Columbia Circuit, which is holding the appeals in abeyance while the FERC
resolves requests for rehearing of its orders. The effect of the FERC's policy
stated in the Lakehead proceeding (and the results of the ongoing SFPP
litigation regarding that policy) on us is uncertain. Our rates are set using
the indexing method and/or have been grandfathered. It is possible that a party
might challenge our grandfathered rates (set when the assets were held by our
corporate predecessor) on the basis that our master limited partnership
structure constitutes a substantial change in circumstances, potentially lifting
the grandfathering protection, and further a party might contend that, in light
of the Lakehead and related-rulings and the creation of our master limited
partnership structure, our rates are not just and reasonable. While it is not
possible to predict the likelihood that such challenges would succeed at the
FERC, if such challenges were to be raised and succeed, application of the
Lakehead and related-rulings would reduce our permissible income tax allowance
in any cost-of-service based rate, to the extent income tax is attributed to
partnership interests held by individual partners rather than corporations.
Regulation of our interstate natural gas pipelines
The Stingray and Nautilus natural gas pipeline systems are regulated by the FERC
under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each
system operates under separate FERC-approved tariffs that establish rates, terms
and conditions under which each system provides services to its customers. In
addition, the FERC's authority over natural gas companies that provide natural
gas pipeline transportation or storage services in interstate commerce includes
the certification and construction of new facilities; the extension or
abandonment of services and facilities; the maintenance of accounts and records;
the acquisition and disposition of facilities; the initiation and
discontinuation of services; and various other matters. As noted above, the
Stingray and Nautilus systems have tariffs established through FERC filings that
have a variety of terms and conditions, each of which affect the operations of
each system and its ability to recover fees for the services it provides.
Generally, changes to these fees or terms can only be implemented upon approval
by the FERC.
Commencing in 1992, the FERC issued Order No. 636 and subsequent orders
(collectively, "Order No. 636"), which require interstate pipelines to provide
transportation and storage services separate, or "unbundled," from the
pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide
open-access transportation and storage services on a basis that is equal for all
shippers. The FERC has stated that it intends for Order No. 636 to foster
19
increased competition within all phases of the natural gas industry. The courts
have largely affirmed the significant features of Order No. 636 and numerous
related orders pertaining to the individual pipelines, although the FERC
continues to review and modify its open access regulations.
In 2000, the FERC issued Order No. 637 and subsequent orders (collectively,
"Order No. 637"), which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things, Order No. 637
revised FERC pricing policy by waiving price ceilings for short-term released
capacity for a two-year period, and effected changes in FERC regulations
relating to scheduling procedures, capacity segmentation, pipeline penalties,
rights of first refusal and information reporting. Most major aspects of Order
No. 637 are pending judicial review. We cannot predict whether and to what
extent FERC's market reforms will survive judicial review and, if so, whether
the FERC's actions will achieve the goal of increasing competition in markets in
which our natural gas is sold. However, we do not believe that the operations of
Nautilus and Stingray (or our other pipeline and storage operations which are
indirectly affected by the extent and nature of FERC's jurisdiction over
activities in interstate commerce) will be affected in any materially different
way than other companies with whom we compete.
In addition to its jurisdiction over Stingray and Nautilus under the Natural Gas
Act and the Natural Gas Policy Act, the FERC also has jurisdiction over Stingray
and Nautilus, as well as Manta Ray, under the Outer Continental Shelf Lands Act
("OCSLA"). The OCSLA requires that all pipelines operating on or across the
outer continental shelf provide open-access, non-discriminatory transportation
service on their systems. Commencing in April 2000, FERC issued Order Nos. 639
and 639-A (collectively, "Order No. 639"), which required "gas service
providers" operating on the outer continental shelf to make public their rates,
terms and conditions of service. The purpose of Order No. 639 was to provide
regulators and other interested parties with sufficient information to detect
and remedy discriminatory conduct by such service providers. In a recent
decision, the U.S. District Court for the District of Columbia permanently
enjoined the FERC from enforcing Order No. 639, on the basis that the FERC did
not possess the requisite rulemaking authority under the OCSLA for issuing Order
No. 639. FERC's appeal of the court's decision is pending in the U.S. Court of
Appeals for the District of Columbia Circuit. We cannot predict the outcome of
this appeal, nor can we predict what further action FERC will take with respect
to this matter.
On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket No.
RM01-10. The proposed rules would expand FERC's current standards of conduct to
include a regulated transmission provider and all of its energy affiliates. It
is not known whether FERC will issue a final rule in this docket and, if it
does, whether we could, as a result, incur increased costs and difficulty in our
operations.
Additional proposals and proceedings that might affect the natural gas industry
are pending before Congress, the FERC and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there is no assurance
that the less stringent regulatory approach recently pursued by the FERC and
Congress will continue.
Regulation of our intrastate common carrier liquids and natural gas pipelines
Certain portions of the Louisiana Pipeline System and all of the Acadian Gas
natural gas pipeline system are intrastate common carrier pipelines that are
subject to various Louisiana state laws and regulations that affect the rates we
charge and the terms of service.
Other state and local regulation of our operations
Our business 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.
Potential impact of regulation on our electrical cogeneration assets
We cogenerate electricity for internal consumption at our Mont Belvieu complex.
If this electricity were sold to third parties, our 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 us 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
20
the rates, finances, or organization of electric utilities. However, since such
electric power is consumed entirely at our facilities, the cogeneration
activities are not subject to public utility regulation under federal or Texas
law.
General environmental matters
Our operations are subject to federal, state and local laws and regulations
relating to the release of pollutants into the environment or otherwise relating
to protection of the environment. We believe that our operations and facilities
are in general compliance with applicable environmental regulations. However,
risks of process upsets, accidental releases or spills are associated with our
operations and there can be no assurance that significant costs and liabilities
will not be incurred, including those related to claims for damage to property
and persons.
The 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 cases,
criminal penalties or, in rare cases, injunctions. We believe that the cost of
compliance with environmental laws and regulations will not have a significant
effect on our results of operations or financial position. 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 cost, we may be unable to pass
these increases on to customers. We 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.
We currently own or lease, and have 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 or otherwise released on various properties that we own or lease or
have owned or leased during the operating history of those facilities. In
addition, a small number of these properties may have been operated by third
parties over whom we had no control as to such entities' handling of
hydrocarbons or other wastes and the manner in which such substances may have
been disposed of or released. State and federal laws applicable to oil and
natural gas wastes and properties have gradually become more strict and,
pursuant to such laws and regulations, we could be required to remove or
remediate previously disposed wastes or property contamination, including
groundwater contamination. We do not believe that there presently exists
significant surface or subsurface contamination of our properties by
hydrocarbons or other solid wastes.
We generate 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
currently classified as nonhazardous may be designated as hazardous in the
future, resulting in wastes being subject to more rigorous and costly disposal
requirements. Such changes in the regulations may result in our incurring
additional capital expenditures or operating expenses.
Potential impact of the Superfund law on our operations
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 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 parties the costs they
incur. We may generate "hazardous substances" in the course of our normal
business operations. As such, we may be responsible under CERCLA for all or part
of the costs required to clean up sites at which such wastes have been disposed;
however, we have not been notified of any potential responsibility for cleanup
costs under CERCLA.
21
General impact of the Clean Air Act on our operations
Our operations 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 our pipelines and processing and storage
facilities. For example, the Mont Belvieu processing and storage facilities are
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 of the country in this "severe"
category. One of the other consequences of this non-attainment status is the
potential imposition of lower limits on emissions of certain pollutants,
particularly oxides of nitrogen which are produced through combustion, such as
in the gas turbines at the Mont Belvieu complex.
Regulations imposing more strict air emissions requirements on existing
facilities in the Houston-Galveston area were issued in December 2000. These
regulations may necessitate extensive redesign and modification of our Mont
Belvieu facilities to achieve the air emissions reductions needed for federal
Clean Air Act compliance. The technical practicality and economic reasonableness
of these regulations have been challenged under state law in litigation filed on
January 19, 2001, against the Texas Natural Resource Conservation Commission and
its principal officials in the District Court of Travis County, Texas, by a
coalition of major Houston-Galveston area industries including the Company.
Until this litigation is resolved, the precise level of technology to be
employed and the cost for modifying the facilities to achieve the required
amount of reductions cannot be determined. Currently, the litigation has been
stayed by agreement of the parties pending the outcome of expanded, cooperative
scientific research to more precisely define sources and mechanisms of air
pollution in the Houston-Galveston area. Completion of this research and
formulation of the regulatory response are anticipated in mid-2002. Regardless
of the results of this research and the outcome of the litigation, expenditures
for air emissions reduction projects will be spread over several years, and we
believe that adequate liquidity and capital resources will exist for us to
undertake them. We have budgeted capital funds in 2002 to begin making
modifications to certain Mont Belvieu facilities that will result in air
emission reductions. The methods employed to achieve these reductions will be
compatible with whatever regulatory requirements are eventually put in place.
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. We believe our operations are in substantial compliance with applicable
air requirements.
Impact of the Clean Air Act's oxygenated fuels programs on our BEF investment
We have a 33.33% ownership interest in BEF, which owns a facility currently
producing MTBE. The production of MTBE is driven by oxygenated fuels programs
enacted under the federal Clean Air Act Amendments of 1990 and other
legislation. Any change 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. In 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.
Subsequently, the EPA denied California's request for a waiver of the oxygenate
requirement and the state is now reconsidering the timing of its MTBE ban.
Legislation recently introduced in the U.S. Senate, as part of a new Energy
Bill, would eliminate the Clean Air Act's oxygenate requirement in order to
facilitate the elimination of MTBE in fuel by a certain date, while protecting
the fuel alcohol market (primarily ethanol) through a renewable fuels mandate.
No such provision exists in the Energy Bill passed by the U.S. House in 2001.
Legislation introduced in the U.S. House in 2001 to allow California to ban MTBE
was defeated. No assurance can be given as to whether the federal government or
individual states will ultimately adopt legislation banning or promoting the use
of MTBE as part of their clean air programs.
Impact of the Clean Water Act on our operations
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 pursuant to these
22
laws require companies that discharge into federal and state waters obtain
National Pollutant Discharge Elimination System ("NPDES") and/or state permits
authorizing these discharges. These 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. We believe that our operations are in substantial compliance with such
laws and regulations.
Impact of environmental regulation on our underground storage operations
We currently own and operate underground storage caverns that have been created
in naturally occurring salt domes in Texas, Louisiana and Mississippi. These
storage caverns are used to store natural gas, NGLs, NGL products and various
petrochemicals. 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 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. We believe that our salt dome storage operations, including
the caverns, brine pits and brine disposal wells, are in substantial compliance
with applicable statutes.
Safety regulation issues
Our pipelines are subject to regulation by the U.S. Department of Transportation
under the Hazardous Liquid Pipeline Safety Act ("HLPSA") and the Natural Gas
Pipeline Safety Act, as amended ("NGPSA"), 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 whereas the NGPSA covers natural gas pipelines and
facilities. Both sets of regulations require pipeline owners and/or operators to
comply with regulations issued under them, to permit access to and allow copying
of records and to make certain reports and provide information as required by
the U.S. Secretary of Transportation. Separate legislation to increase the
stringency of federal pipeline safety requirements was passed by each of the
House and Senate in 2001; however, the two measures have not been reconciled in
a conference committee or moved to final passage by the U.S. Congress. We
believe that our pipeline operations are in substantial compliance with
applicable HLPSA and NGPSA requirements; however, due to the possibility of new
or amended laws or the reinterpretation of existing laws, there can be no
assurance that future compliance with these pipeline safety requirements will
not have an impact on our results of operations or financial position.
The workplaces associated with our company-operated processing, storage and
pipeline facilities are subject to the requirements of the federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. We believe that
our facilities are in substantial compliance with OSHA requirements, including
general industry standards, record keeping requirements and monitoring of
occupational exposure to regulated substances.
In general, we expect expenditures associated with industry and regulatory
safety standards (such as those described above) will increase in the future.
Although such expenditures cannot be accurately estimated at this time, we
believe that such expenditures will not have a significant effect on our
operations.
Title to Properties
Our real property holdings fall into two basic categories: (1) parcels that we
own in fee, such as the land at the Mont Belvieu complex and (2) parcels in
which our interest derives from leases, easements, rights-of-way, permits or
licenses from landowners or governmental authorities permitting the use of such
land for our operations. The fee sites upon which our major facilities are
located have been owned by us or our predecessors in title for many years
without any material challenge known to us relating to title to the land upon
which the assets are located, and we believe that the Company has satisfactory
title to such fee sites. We have no knowledge of any challenge to the underlying
fee title of any material lease, easement, right-of-way or license held by us or
to our title to any material lease, easement, right-of-way, permit or license,
and we believe that the Company has satisfactory title to all of its material
leases, easements, rights-of-way and licenses.
23
Item 3. Legal Proceedings.
On occasion, we are named as a defendant in litigation relating to our normal
business operations. Although we are insured against various business risks to
the extent we believe it is prudent, there is no assurance that the nature and
amount of such insurance will be adequate, in every case, to indemnify us
against liabilities arising from future legal proceedings as a result of our
ordinary business activity. EPCO has indemnified us against any litigation that
was pending at the date of our formation in April 1998.
We are a party to litigation instituted in January 2001 in connection with air
emission control regulations in the Houston-Galveston area (see "General impact
of the Clean Air Act on our operations" on page 22 for additional information on
this subject). Other than this litigation, we are aware of no significant
litigation, pending or threatened, that may have a significant adverse effect on
our 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 our Unitholders during the fourth
quarter of 2001.
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 NYSE) and the
amount of quarterly cash distributions paid per Common and Subordinated Unit.
Cash Distribution History
-------------------------------------------------------
Per Per
Common Subordinated Record Payment
High Low Unit Unit Date Date
---------------------------------------------------------------------------
1999
1st Quarter $ 18.50 $ 14.94 $ 0.4500 $ 0.0700 Apr. 30, 1999 May 12, 1999
2nd Quarter $ 18.63 $ 15.06 $ 0.4500 $ 0.3700 Jul. 30, 1999 Aug. 11, 1999
3rd Quarter $ 20.69 $ 17.88 $ 0.4500 $ 0.4500 Oct. 29, 1999 Nov. 10, 1999
4th Quarter $ 20.38 $ 17.00 $ 0.5000 $ 0.5000 Jan. 31, 2000 Feb. 10, 2000
2000
1st Quarter $ 20.88 $ 18.25 $ 0.5000 $ 0.5000 Apr. 28, 2000 May 10, 2000
2nd Quarter $ 22.75 $ 19.50 $ 0.5250 $ 0.5250 Jul. 31, 2000 Aug. 10, 2000
3rd Quarter $ 28.94 $ 22.13 $ 0.5250 $ 0.5250 Oct. 31, 2000 Nov. 10, 2000
4th Quarter $ 31.88 $ 23.50 $ 0.5500 $ 0.5500 Jan. 31, 2001 Feb. 9, 2001
2001
1st Quarter $ 36.80 $ 26.50 $ 0.5500 $ 0.5500 Apr. 30, 2001 May 10, 2001
2nd Quarter $ 43.75 $ 33.20 $ 0.5875 $ 0.5875 Jul. 31, 2001 Aug. 10, 2001
3rd Quarter $ 48.35 $ 39.50 $ 0.6250 $ 0.6250 Oct. 31, 2001 Nov. 9, 2001
4th Quarter $ 52.60 $ 43.60 $ 0.6250 $ 0.6250 Jan. 31, 2002 Feb. 11, 2002
The quarterly cash distribution amounts shown in the table correspond to the
cash flows for the quarters indicated. The actual cash distributions (i.e.,
payments to our limited partners) occur within 45 days after the end of such
quarter. The increased quarterly cash distribution rates are attributable to the
growth in cash flow that we have achieved through the completion of new
projects, improved operating results and accretive acquisitions. Although the
payment of such quarterly cash distributions is not guaranteed, we expect to
continue to pay comparable cash distributions in the future.
As of March 1, 2002, there were approximately 192 Unitholders of record which
includes an estimated 9,900 beneficial owners of our Common Units.
Two-for-one split of Limited Partner Units. On February 27, 2002, we announced
that the Board of Directors of the General Partner had approved a two-for-one
split for each class of our Units. The partnership Unit split will be
accomplished by distributing one additional partnership Unit for each
partnership Unit outstanding to holders of record on April 30, 2002. The Units
will be distributed on May 15, 2002. All references to number of Units or
earnings per Unit contained in this document relate to the pre-split Units,
except if indicated otherwise.
25
Item 6. Selected Financial Data.
The following table sets forth for the periods and at the dates indicated, our
selected historical financial data. The selected historical financial data have
been derived from our audited financial statements for the periods indicated.
The selected historical income statement data for each of the three years ended
December 31, 2001, 2000 and 1999 and the selected balance sheet data as of
December 31, 2001 and 2000 should be read in conjunction with the audited
financial statements for such periods included elsewhere in this report. In
addition, information regarding results of operations and capital resources and
liquidity can be found under Item 7 of this report.
The dollar amounts in the table, except per Unit data, are in thousands.
Additionally, certain reclassifications have been made to prior year's financial
statements to conform to the current year presentation.
2001 (1) 2000 (1) 1999 (1) 1998 (9) 1997
------------------------------------------------------------
Income statement data:
Revenues $3,179,727 $3,073,139 $1,346,456 $754,573 $1,035,963
Gross operating margin (2) $ 376,783 $ 320,615 $ 179,195 $ 99,627 $ 128,710
Operating income $ 287,688 $ 243,734 $ 132,351 $ 50,473 $ 75,680
Net income $ 242,178 $ 220,506 $ 120,295 $ 10,077 $ 52,163
Basic net income per Unit (3) $ 3.39 $ 3.25 $ 1.79 $ 0.17 $ 0.94
Diluted net income per Unit (4) $ 2.77 $ 2.64 $ 1.64 $ 0.17 $ 0.94
Balance sheet data (at period end):
Total assets (5) $2,431,193 $1,951,368 $1,494,952 $741,037 $ 697,713
Long-term debt (6) $ 855,278 $ 403,847 $ 295,000 $ 90,000 $ 230,237
Combined equity/Partners' equity (7) $1,146,922 $ 935,959 $ 789,465 $562,536 $ 311,885
Other financial data:
Cash distributions declared per
Common Unit (8) $ 2.3875 $ 2.10 $ 1.85 $ 0.77 n/a
________________________________________________________________________________
(1) Results of operations for the years 2001, 2000 and 1999 have been materially
impacted by acquisitions. In 2001, we acquired Acadian Gas and certain Gulf of
Mexico natural gas pipeline systems. In 1999, we acquired the TNGL natural gas
processing and NGL businesses from Shell. These acquisitions have significantly
increased revenues, gross operating margin, operating income and net income
since their respective completions.
(2) Gross operating margin 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.
(3) Net income allocable to our limited partners divided by the weighted-average
number of Common and Subordinated Units outstanding during the period.
(4) Net income allocable to our limited partners divided by the weighted-average
number of Common, Subordinated and Special Units outstanding during the period.
(5) Total assets have increased significantly since 1999 primarily as a result
of acquisitions.
(6) Long-term debt increased in 2001 and 2000 as a result of the issuance of
public debt to finance acquisitions and other general partnership purposes.
Long-term debt increased in 1999 over 1998 as a result of borrowings under
revolving credit facilities to finance the TNGL and MBA acquisitions in 1999.
The decrease in long-term debt in 1998 compared to 1997 is due to use of the
proceeds from our initial public offering in July 1998 to paydown debt assumed
from EPCO.
(7) Partners' equity increased in 2001 and 2000 in part as a result of the
issuance of an additional 6.0 million Special Units to Shell in connection with
the TNGL acquisition. Using present value techniques, the 3.0 million Special
Units issued during 2000 were valued at approximately $55 million while the 3.0
million Special Units issued during 2001 were valued at $117 million. See Note 7
of the Notes to Consolidated Financial Statements for additional information
regarding our capital structure.
(8) Cash distributions began after our initial public offering of Common Units
on July 27, 1998. See Item 5 for additional information regarding cash
distributions.
(9) Net income for 1998 includes a $27 million extraordinary charge on early
extinguishment of debt.
26
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 our
audited consolidated financial statements and notes thereto included elsewhere
herein as well as the other portions of this report on Form 10-K. In addition,
the reader should review "Cautionary Statement regarding Forward-Looking
Information and Risk Factors" beginning on page 1 of this report for information
regarding forward-looking statements made in this discussion and certain risks
inherent in our business. Other risks involved in our business are discussed
under Item 7A "Quantitative and Qualitative Disclosures about Market Risks"
beginning on page 47 of this report. Additionally, please see Part III, Item 13
for a discussion of related-party issues such as the EPCO Agreement and our
relationship with Shell.
General
During the last three years, we have completed or initiated several acquisitions
and investments having a combined value of over $1.4 billion. These include $571
million in natural gas processing and NGL businesses, $438 million in natural
gas and other pipeline businesses and $368 million in propylene fractionation
and NGL/petrochemical storage assets. Specifically, we have completed the
following acquisitions and asset purchases:
. $529 million paid to acquire TNGL's natural gas processing and NGL
businesses (1999);
. $42 million paid to acquire an additional interest in the Mont Belvieu
NGL fractionation facility (1999);
. $100 million paid to acquire the Lou-Tex Propylene pipeline (2000);
. $226 million paid to acquire the Acadian Gas natural gas pipeline
network (2001);
. $112 million invested in four Gulf of Mexico natural gas pipeline
systems (2001);
. $129 million paid to purchase storage assets in Mont Belvieu
(initiated 2001, completed January 2002); and
. $239 million paid to purchase a controlling interest in a propylene
fractionation facility and related assets in Mont Belvieu (initiated
2001, completed February 2002).
During 2001, we issued the last installment of 3.0 million Special Units to
Shell valued at approximately $117 million. These new Special Units were issued
in connection with the TNGL acquisition that was completed in 1999, resulting in
a final total purchase price of $529 million.
We entered the natural gas pipeline business in 2001 by completing the
acquisition of Acadian Gas and investments in four Gulf of Mexico natural gas
pipeline systems. In April 2001, we acquired Acadian Gas (an onshore Louisiana
system) from an affiliate of Shell for $226 million using proceeds from the
issuance of public debt. Acadian Gas and its affiliates are involved in the
purchase, sale, transportation and storage of natural gas in Louisiana. Its
assets include 1,042 miles of natural gas pipelines and a leased natural gas
storage facility. In January 2001, we paid El Paso $112 million for equity
interests in four Gulf of Mexico offshore Louisiana natural gas pipeline
systems. These systems are comprised of 739 miles of regulated and non-regulated
natural gas pipelines. The acquisition of these businesses represent strategic
investments for the Company. We believe 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 our
midstream energy service relationship with long-term NGL customers (producers,
petrochemical suppliers and refineries). These assets also provide opportunities
for enhanced services to customers and generate additional fee-based cash flows.
2002 developments. In January 2002, we completed the acquisition of
Diamond-Koch's ("D-K") Mont Belvieu storage assets from affiliates of Valero
Energy Corporation and Koch Industries, Inc. for $129 million. These facilities
include 30 storage wells with a useable capacity of 68 MMBbls and allow for the
storage of mixed NGLs, ethane, propane, butanes, natural gasoline and olefins
(such as ethylene), polymer grade propylene, chemical grade propylene and
refinery grade propylene. With the inclusion of the former D-K facilities, we
own and operate 95 MMBbls of storage capacity at Mont Belvieu, one of the
largest such facilities in the world. In addition, we completed the purchase of
D-K's 66.7% interest in a propylene fractionation facility and related assets in
February 2002 at a cost of approximately $239 million. Including this purchase,
we effectively own 58.3 MBPD of net propylene fractionation capacity in Mont
Belvieu and have access to additional customers at this key industry hub.
27
Our outlook for first half of 2002
The year 2001 was an economically challenging period for the NGL and
petrochemical industries. The domestic NGL industry was adversely affected by
abnormally high natural gas prices during the first quarter of 2001 resulting in
a substantial reduction in NGL extraction rates at virtually all gas processing
plants industry wide. As natural gas prices moderated during the remainder of
2001, industry wide extraction rates returned to normalized levels resulting in
increased volumes and profitability across many of our business operations.
Our outlook for the first half of 2002 is more favorable than what we
experienced during the first half of 2001. Overall, we expect NGL extraction
rates for the gas processing industry to continue near the levels sustained
during the fourth quarter of 2001 due to stabilized processing margins. Should
this forecast be realized, our equity NGL production rate would approximate 75
to 85 MBPD during the first half of 2002 as compared to 54 MBPD during the same
period in 2001. Our outlook is based on the market price of natural gas
remaining within the historical norm in terms of its relative value to other
forms of energy. After peaking at near $10 per MMBtu in January 2001, natural
gas prices decreased to near $2 per MMBtu during the fourth quarter of 2001
which is within the historical norm. The forecasted market price of natural gas
for the first half of 2002 should continue to make it economically attractive to
recover NGLs at higher levels even though downstream demand has been reduced due
to the downturn in the world economy. Barring any major disruptions, industry
expectations are that natural gas market prices will remain stable for the first
half of 2002 due to strong supply.
Drilling activity in the Gulf of Mexico increased significantly in early 2001 in
response to the abnormally high price of natural gas during that period. With
the moderation in energy prices over the last half of 2001, drilling activity
began to decline (continuing into early 2002). Over time, however, we expect
that the improving domestic economy and new gas fired electric generation
facilities will increase demand for natural gas and thus strengthen the price
and stimulate increased drilling. As drilling increases, we expect our Gulf of
Mexico natural gas pipeline systems to benefit; however, if drilling activity
continues to be suppressed over the longer-term, these investments could be
adversely affected by reduced volumes.
We expect Acadian Gas to benefit from two new gas-fired cogeneration facilities
commencing operations during 2002, one of which should begin operations during
the second quarter of 2002. This will help to offset lower pipeline throughput
volumes expected in the first five months of 2002 caused by a seasonal decrease
in natural gas demand due to warmer weather. By the end of the second quarter of
2002, pipeline throughput volumes should rise due to an increase in gas
consumption by electricity providers as a result of the beginning of summer air
conditioning demands.
We expect that utilization of our Lou-Tex NGL pipeline will be higher during the
first half of 2002 as a result of additional pipeline throughput volumes
(primarily propane and butane coming from Louisiana locations and a continuation
of raw make production volumes being moved from the Sea Robin gas processing
facility to Mont Belvieu). Due to a mild winter in the continental U.S., we are
capturing additional revenue from transporting propane on this system out of
Louisiana to Mont Belvieu for export to overseas markets. The relatively warm
winter in the southeastern U.S. has also adversely affected propane shipments on
the Dixie pipeline system; therefore, some of their propane shipments are being
diverted to Mont Belvieu for storage, export, petrochemical and other uses.
As a result of these increased propane exports, we project that EPIK will have a
full loading schedule extending early into the second quarter of 2002. Export
activity will decline during the summer months when demand for propane for
heating is reduced. Our import terminal is expected to have a typical first
quarter as imports are historically low during this period and 2002 looks to be
no exception. However, we expect that the second quarter of 2002 will provide
opportunities for importing cargoes of mixed butane and anticipate that the
unloading facility will be heavily utilized. The HSC pipeline should benefit
from an increase in exports during the first quarter and an increase in imports
during the second quarter. We may also see an increase in pipeline shipments of
propane/propylene mix due to the purchase of the D-K propylene fractionator.
Lastly, throughput volumes on the Tri-States, Wilprise and Belle Rose systems
are expected to average 45 MBPD during the first half of 2002 compared to 24
MBPD during the first half of 2001. The lower rate in 2001 was due to lower NGL
extraction rates by gas processing facilities.
28
We expect continued strong demand for our hydrocarbon storage services due to
the continued recovery of NGLs by gas processing facilities. With the purchase
of D-K's Mont Belvieu storage assets, we will be offering additional
opportunities to customers during 2002 in the form of expanded services,
options, and flexibility for the delivery and/or consumption of their NGLs.
These additional services should provide additional margins as we integrate the
former D-K assets with our existing Mont Belvieu operations.
NGL fractionation services at Mont Belvieu will remain competitive due to excess
NGL fractionation capacity at this industry hub. To offset lower fractionation
tolling fees, we have increased feed rates at our Mont Belvieu NGL fractionation
facility over the last year with the addition of newly contracted volumes such
as the mixed NGL stream coming from the Sea Robin gas processing plant in
Louisiana (via the Lou-Tex NGL pipeline). During the first quarter of 2002, our
isomerization business has benefited from increased refinery demand for
isobutane. The market price spread between normal butane and isobutane during
the first quarter of 2002 has been two to four cents higher than normal levels
as a result of this strong demand, which should benefit margins in our
Processing segment's merchant business. We expect isobutane pricing to trend
toward the historical norm by the end of the first quarter and remain so during
the second quarter. Propylene fractionation unit margins are expected to remain
flat during the first half of 2002 due to the weak economy and additional
supplies coming to market from new third party facilities. If the domestic
economy improves as anticipated during 2002, we expect that the demand for
propylene fractionation services will increase as the market absorbs the
additional market supply.
Our MTBE facility underwent its annual maintenance turnaround in January 2002.
Equity earnings from this facility for the first quarter of 2002 are expected to
benefit from strong MTBE pricing caused by a number of other MTBE units
undergoing maintenance turnarounds which reduced overall MTBE supply. As we
enter the second quarter of 2002, MTBE pricing is expected to further strengthen
as refiners begin purchasing MTBE in preparation for gasoline blending
requirements for the upcoming summer driving season.
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
-------------------------------------------------------------------------------
(1) (2) (1) (1) (1) (1) (1)
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 (3) $7.00 $28.81 $0.43 $0.55 $0.63 $0.69 $0.23
Second quarter $4.61 $27.88 $0.33 $0.46 $0.53 $0.63 $0.19
Third quarter $2.84 $26.60 $0.25 $0.41 $0.50 $0.49 $0.16
Fourth quarter $2.38 $20.40 $0.21 $0.33 $0.39 $0.38 $0.18
________________________________________________________________________________
(1) Natural gas, NGL and polymer grade propylene prices represent an
average of index prices
(2) Crude Oil price is representative of West Texas Intermediate
(3) Natural gas prices peaked at approximately $10 per MMBtu in January
2001
29
Our Accounting Policies
In our financial reporting process, we employ methods, estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities as of the date of the financial statements.
These methods, estimates and assumptions also affect the reported amounts of
revenues and expenses during the reporting period. Investors should be aware
that actual results could differ from these estimates should the underlying
assumptions prove to be incorrect. Examples of these estimates and assumptions
include depreciation methods and estimated lives of property, plant and
equipment, amortization methods and estimated lives of qualifying intangible
assets, revenue recognition policies and mark-to-market accounting procedures.
The following describes the estimation risk in each of these significant
financial statement items:
Property, plant and equipment. Property, plant and equipment is recorded at cost
and is depreciated using the straight-line method over the asset's estimated
useful life. Our plants, pipelines and storage facilities have estimated useful
lives of five to 35 years. Our miscellaneous transportation equipment have
estimated useful lives of three to 35 years. Depreciation is the systematic and
rational allocation of an asset's cost, less its residual value (if any), to the
periods it benefits. Straight-line depreciation results in depreciation expense
being incurred evenly over the life of the asset. The determination of an
asset's estimated useful life must take a number of factors into consideration,
including technological change, normal deterioration and actual physical usage.
If any of these assumptions subsequently change, the estimated useful life of
the asset could change and result in an increase or decrease in depreciation
expense. Additionally, if we determine that an asset's undepreciated cost may
not be recoverable due to economic obsolescence, the business climate, legal and
other factors, we would review the asset for impairment and record any necessary
reduction in the asset's value as a charge against earnings. At December 31,
2001 and 2000, the net book value (or undepreciated cost) of our property, plant
and equipment was $1.3 billion and $1.0 billion. For additional information
regarding our property, plant and equipment see Note 3 of the Notes to
Consolidated Financial Statements.
Intangible assets. Our recorded intangible assets primarily include the values
assigned to contract-based assets that have a fixed or definite term. At
December 31, 2001, the principal item recorded as an intangible asset was the
20-year Shell natural gas processing agreement. The value of this contract is
being amortized on a straight-line basis over its contract term (currently $11.1
million annually from 2002 through July 2019). If the economic life of this
contract were later determined to be impaired due to negative changes in Shell's
natural gas exploration and production activities in the Gulf of Mexico, then we
might need to reduce the amortization period of this asset to less than the
contractually-stated 20-year life of the agreement. Such a change would increase
the annual amortization charge at that time. At December 31, 2001, the
unamortized value of this contract was $194.4 million.
Revenue recognition. In general, we recognize revenue from our customers when
all of the following criteria are met: (i) firm contracts are in place, (ii)
delivery has occurred or services have been rendered, (iii) pricing is fixed and
determinable and (iv) collectibility is reasonably assured. When contracts
settle (i.e., either physical delivery of product has taken place or the
services designated in the contract have been performed), we determine if an
allowance is necessary and record accordingly. The revenues that we record are
not materially based on estimates. We believe the assumptions underlying any
revenue estimates that we might use will not prove to be significantly different
from actual amounts due to the short-term nature of these estimates.
Of the contracts that we enter into with customers, the majority fall within
five main categories as described below:
. Tolling (or throughput) arrangements where we process or transport
customer volumes for a cash fee (usually on a per gallon or other unit
of measurement basis);
. In-kind fractionation arrangements where we process customer mixed NGL
volumes for a percentage of the end NGL products in lieu of a cash fee
(exclusive to our Norco NGL fractionation facility);
. Merchant contracts where we sell products to customers at
market-related prices for cash;
. Storage agreements where we store volumes or reserve storage capacity
for customers for a cash fee; and
. Fee-based marketing services where we market volumes for customers for
either a percentage of the final cash sales price or a cash fee per
gallon handled.
A number of tolling (or throughput) arrangements are utilized in our
Fractionation and Pipeline segments. Examples include NGL fractionation,
isomerization and pipeline transportation agreements. Typically, we recognize
revenue
30
from tolling arrangements once contract services have been performed. At times,
the tolling fees we or our affiliates charge for pipeline transportation
services are regulated by such governmental agencies as the FERC. A special type
of tolling arrangement, an "in-kind" contract, is utilized by various customers
at our Norco NGL fractionation facility. An in-kind processing contract allows
us to retain a contractually-determined percentage of NGL products produced for
the customer in lieu of a cash tolling fee per gallon. Revenue is recognized
from these "in-kind" contracts when we sell (at market-related prices) and
deliver the fractionated NGLs that we retained.
Our Processing segment businesses employ tolling and merchant contracts. If a
customer pays us a cash tolling fee for our natural gas processing services, we
record revenue to the extent that natural gas volumes have been processed and
sent back to the producer. If we retain mixed NGLs as our fee for natural gas
processing services, we record revenue when the NGLs (in mixed and/or
fractionated product form) are sold and delivered to customers using merchant
contracts. In addition to the Processing segment, merchant contracts are
utilized in the Fractionation segment to record revenues from the sale of
propylene volumes and in the Pipelines segment to record revenues from the sale
of natural gas. Our merchant contracts are generally based on market-related
prices as determined by the individual agreements.
We have established an allowance for doubtful accounts to cover potential bad
debts from customers. Our allowance amount is generally determined as a
percentage of revenues for the last twelve months. In addition, we may also
increase the allowance account in response to specific identification of
customers involved in bankruptcy proceedings and the like. We routinely review
our estimates in this area to ascertain that we have recorded ample reserves to
cover forecasted losses. If unanticipated financial difficulties were to occur
with a significant customer or customers, there is the possibility that the
allowance for doubtful accounts would need to be increased to bring the
allowance up to an appropriate level based on the new information obtained. Our
allowance for doubtful accounts at December 31, 2001 was $20.6 million.
Fair value accounting for financial instruments. Our earnings are also affected
by use of the mark-to-market method of accounting required under GAAP for
certain financial instruments. We use financial instruments such as swaps,
forwards and other contracts to manage price risks associated with inventories,
firm commitments and certain anticipated transactions, primarily within our
Processing segment. Currently none of these financial instruments qualify for
hedge accounting treatment and thus the changes in fair value of these
instruments are recorded on the balance sheet and through earnings (i.e., using
the "mark-to-market" method) rather than being deferred until the firm
commitment or anticipated transaction affects earnings. The use of mark-to-
market accounting for financial instruments results in a degree of non-cash
earnings volatility that is dependent upon changes in underlying indexes,
primarily commodity prices. Fair value for the financial instruments we employ
is determined using price data from highly liquid markets such as the NYMEX
commodity exchange. At December 31, 2001, our financial statements reflected
$5.6 million of mark-to-market income related to commodity financial instruments
whose longest maturity date was December 2002. For additional information
regarding our use of financial instruments to manage risk and the earnings
sensitivity of these instruments to changes in underlying commodity prices, see
Item 7A on page 47.
Additional information regarding the significant accounting policies underlying
preparation of our financial statements (including revenue recognition) can be
found in Note 1 of the Notes to Consolidated Financial Statements on page F-7.
Our results of operations
We have five reportable operating segments: Fractionation, Pipelines,
Processing, Octane Enhancement and Other. Fractionation primarily includes NGL
fractionation, isomerization and propylene fractionation. Pipelines consists of
liquids and natural gas pipeline systems, storage and import/export terminal
services. Processing includes our natural gas processing business and related
merchant activities. Octane Enhancement represents our interest in a facility
that produces motor gasoline additives to enhance octane (currently producing
MTBE). The Other operating segment primarily consists of fee-based marketing
services.
Our management evaluates segment performance based on gross operating margin
("gross operating margin" or "margin"). Gross operating margin 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
31
and administrative expenses. Segment gross operating margin is exclusive of
interest expense, interest income amounts, dividend income, minority interest,
extraordinary charges and other income and expense transactions.
We include equity earnings from unconsolidated affiliates in segment gross
operating margin and as a component of revenues. Our equity investments with
industry partners are a vital component of our business strategy and a means by
which we conduct our operations to align our interests with a supplier of raw
materials to a facility or a consumer of finished products from a facility. This
method of operation also enables us to achieve favorable economies of scale
relative to the level of investment and business risk assumed versus what we
could accomplish on a stand alone basis. Many of these businesses perform
supporting or complementary roles to our other business operations. For example,
we use the Promix NGL fractionator to process NGLs extracted by our gas plants.
The NGLs received from Promix then can be sold by our merchant businesses.
Another example would be our relationship with the BEF MTBE facility. Our
isomerization facilities process normal butane for this plant and our HSC
pipeline transports MTBE for delivery to BEF's storage facility on the Houston
Ship Channel.
Our gross operating margin by segment (in thousands of dollars) along with a
reconciliation to consolidated operating income for the past three years were as
follows:
For Year Ended December 31,
-------------------------------
2001 2000 1999
-------------------------------
Gross Operating Margin by segment:
Fractionation $ 118,610 $129,376 $110,424
Pipeline 96,569 56,099 31,195
Processing 154,989 122,240 28,485
Octane enhancement 5,671 10,407 8,183
Other 944 2,493 908
-------------------------------
Gross Operating margin total 376,783 320,615 179,195
Depreciation and amortization 48,775 35,621 23,664
Retained lease expense, net 10,414 10,645 10,557
Loss (gain) on sale of assets (390) 2,270 123
Selling, general and administrative expenses 30,296 28,345 12,500
-------------------------------
Consolidated operating income $ 287,688 $243,734 $132,351
===============================
Our significant plant production and other volumetric data for the last three
years were as follows:
For Year Ended December 31,
--------------------------
2001 2000 1999
--------------------------
MBPD, Net
---------
Equity NGL Production 63 72 67
NGL Fractionation 204 213 184
Isomerization 80 74 74
Propylene Fractionation 31 33 28
Octane Enhancement 5 5 5
Major NGL and Petrochemical Pipelines 454 367 264
BBtu/D, Net
-----------
Natural Gas Pipelines 1,349 n/a n/a
Year ended December 31, 2001 compared to year ended December 31, 2000
Revenues, costs and expenses and operating income. Fiscal 2001 was our best year
ever as measured in terms of revenues, gross operating margin and operating
income. Our revenues were a record $3.2 billion in 2001 compared to $3.1 billion
in 2000. Operating costs and expenses increased to $2.9 billion in 2001 from
$2.8 billion in 2000. Gross operating margin increased to $376.8 million in 2001
from $320.6 million in 2000. Operating income also posted a record $287.7
million in 2001 versus $243.7 million in 2000. The increases in revenues and
costs and
32
expenses are primarily due to our natural gas pipeline acquisitions completed in
2001 (Acadian Gas and the Gulf of Mexico lines) offset by lower product prices
in 2001 relative to 2000. The increase in gross operating margin and operating
income is primarily attributable to acquisitions and new construction, plus a
rise in income relating to commodity hedging activities offset by generally
lower product prices.
Fractionation. Gross operating margin from our Fractionation segment decreased
to $118.6 million in 2001 from $129.4 million in 2000. NGL fractionation margin
for 2001 declined $21.0 million from 2000, primarily as the result of a $19.3
million decrease in "in-kind" fractionation fees at our Norco facility. An
in-kind arrangement allows us to receive NGL volumes in lieu of cash
fractionation fees (Norco being our only facility with this type of contract).
The decline in NGL fractionation margin is related to the NGL volumes received
during 2000 having a higher value than those received during 2001. Net volumes
at the NGL fractionation facilities decreased to 204 MBPD in 2001 compared to
213 MBPD in 2000. The decrease in throughput is due to lower NGL extraction
rates at gas processing facilities in early 2001 (due to the abnormally high
cost of natural gas) versus 2000 when the industry was maximizing NGL
production. The isomerization business posted an $8.4 million increase in margin
for 2001 over 2000 on volumes of 80 MBPD. Isomerization margins were bolstered
by increased demand during the second quarter of 2001 for services linked to
refinery activities, primarily gasoline blending. Gross operating margin from
propylene fractionation increased $0.3 million in 2001 over 2000 due to
additional margins from BRPC which did not commence operations until July 2000.
Net volumes at our propylene fractionation facilities declined slightly to 31
MBPD in 2001 from 33 MBPD in 2000.
Pipelines. Our Pipelines segment posted a record gross operating margin of $96.6
million in 2001, compared to $56.1 million in 2000. Of the $40.5 million
increase in margin, $20.0 million is attributable to natural gas pipelines
acquired in 2001 (i.e., Acadian Gas and the Gulf of Mexico systems). Acadian Gas
added $11.8 million in margin with the Gulf of Mexico systems contributing $8.2
million. On a net basis, these pipeline systems transported an average of 1,349
BBtu/d of natural gas.
Net liquid transportation volumes increased to 454 MBPD in 2001 from 367 MBPD in
2000. The majority of this increase is attributable to a rise in commercial
butane imports related to seasonal demand for isobutane production. This
activity contributed to a $5.2 million combined increase in margin from our
import terminal and HSC pipeline system. Additionally, margin from the Louisiana
Pipeline System increased $1.1 million in 2001 due to increased demand for
transportation services (with volumes increasing by 23 MBPD in 2001, a 20%
increase year-to-year). Also, our recently completed Lou-Tex NGL pipeline added
$12.2 million to margin during 2001 (construction of this system being completed
in the fourth quarter of 2000). This pipeline benefited from the movement of
mixed NGLs out of Louisiana to our Mont Belvieu processing facility during 2001.
Processing. Earnings from our Processing segment were a record $155.0 million in
2001, up 27% from $122.2 million in 2000. This segment is comprised of our
natural gas processing business and related merchant activities. The increase in
margin is primarily due to the positive impact of our commodity hedging
activities.
2001 was a very challenging year for gas processors industry wide. The
volatility of natural gas prices and the depressed nature of NGL prices
throughout 2001 created an environment requiring processors to be proactive in
meeting the needs of the marketplace. The unusually poor processing economics of
the first quarter of 2001 (due to the abnormally high cost of energy relative to
the value of our NGL production during that time) yielded to improved market
conditions during the second half of 2001 as energy costs moderated. In general,
prices received for our NGL production approximated a weighted-average of 43
cents per gallon in 2001 compared to 57 cents per gallon in 2000. In contrast,
the cost of natural gas averaged $4.20 per MMBtu in 2001 (peaking at near $10
per MMBtu during the first quarter of 2001) versus $3.84 per MMBtu in 2000.
Equity NGL production averaged 63 MBPD in 2001 compared to 72 MBPD in 2000. The
decline in volume is related to the 2000 period reflecting near maximized NGL
recoveries supported by strong NGL economics. The 2001 equity NGL production
rate reflects less favorable extraction economics (as described above) but is
greatly improved relative to the first quarter of 2001's 46 MBPD when energy
costs peaked. With the improvement in processing margins in late 2001, we posted
a record equity NGL production of 80 MBPD during the fourth quarter of 2001.
33
We employ various hedging strategies to mitigate the effects of fluctuating
commodity prices (primarily NGL and natural gas prices) on our gas processing
business and related merchant activities. Margin for 2001 includes $101.3
million of income from commodity hedging activities, an increase of $74.5
million over such income in 2000. The loss in value of our NGL production has
been mitigated (or in some cases, exceeded) by such income during 2001. Without
this income, margin from gas processing would have declined $54.7 million
year-to-year.
A large number of our commodity financial instruments are currently based on the
historical relationship between natural gas prices and NGL prices. This type of
hedging strategy utilizes the forward sale of natural gas at a fixed-price with
the expected margin on the settlement of the position offsetting or mitigating
changes in the anticipated margins on NGL merchant activities and the value of
our equity NGL production. During 2001, we benefited from the general decline in
natural gas prices relative to our fixed positions. The decline in natural gas
prices allowed us to realize net cash gains on the settlement and closeout of
certain positions of approximately $95.7 million. The $5.6 million difference
between the realized amount and the $101.3 million in income from these
financial instruments represents the non-cash mark-to-market income on positions
open at December 31, 2001 (based on market prices at that date).
If natural gas prices had not declined to the degree seen during the year, we
would have recognized less income (or potentially even a loss) on hedging
activities offset somewhat by correlative higher NGL prices which would have
increased the value of our NGL production. A variety of factors influence
whether or not our hedging strategies are successful. For additional information
regarding our commodity financial instruments, see Item 7A "Quantitative and
Qualitative Disclosures about Market Risk" beginning on page 47.
We are exposed to settlement risk (a form of credit risk) with our
counterparties to these financial instruments. On all transactions where we are
exposed to settlement risk, management analyzes the counterparty's financial
condition prior to entering into an agreement, establishes credit limits and
monitors the appropriateness of these limits on an ongoing basis. In December
2001, Enron North America (the counterparty to some of our commodity financial
instruments) filed for protection under Chapter 11 of the U.S. Bankruptcy Code.
As a result, we recognized a charge to earnings of $10.6 million for all amounts
owed to us by Enron. The Enron amounts were unsecured and the amount that we may
ultimately recover, if any, is not presently determinable.
Our merchant activities benefited from (i) strong propane demand in the first
quarter of 2001 for heating and (ii) isobutane in the second quarter of 2001 for
refining. Overall, margin from merchant activities improved $9.9 million
year-to-year. Processing margin also benefited from the reversal of $9.4 million
in excess reserves associated with the gas processing plants.
Octane Enhancement. Equity earnings from our BEF investment declined $4.7
million year-to-year on stable net volumes of 5 MBPD in both periods. The
decrease in earnings is primarily attributable to lower MTBE and by-product
prices.
Other. Gross operating margin from our Other segment was $0.9 million in 2001
compared to $2.5 million in 2000. The decrease is primarily due to a rise in
operating costs of plant support functions.
Selling, general and administrative expenses. These expenses increased to $30.3
million in 2001 from $28.3 million in 2000. The increase is primarily due to
expenses related to the additional staff and resources deemed necessary to
support our expansion activities resulting from acquisitions and other business
development.
Interest expense. Interest expense for 2001 increased by $19.1 million over that
for 2000 . The increase is primarily due to the issuance of our $450 million of
public debt in January 2001 (the Senior Notes B, see page 41). The proceeds from
this debt were used to acquire the Gulf of Mexico pipelines from El Paso,
Acadian Gas from Shell and to finance internal growth and other general
partnership purposes.
Interest expense for both 2001 and 2000 benefited from income attributable to
interest rate hedging activity. During the last two years, we used interest rate
swaps in order to effectively convert a portion of our fixed-rate debt into
variable-rate debt. With the decline in variable interest rates over the last
two years, our swaps provided income to offset fixed-rate-based interest
expense. For 2001, we recognized a $13.2 million benefit related to these swaps
compared with a $10.0 million benefit recorded in 2000.
34
During 2001, two of our three swaps that were outstanding at January 1, 2001
were terminated (closing instruments having a notional value of $100 million).
One swap was terminated by a counterparty exercising its early termination
option while the other counterparty negotiated an early closeout of its
position. This left us with one swap outstanding at December 31, 2001 having a
notional amount of $54 million. This swap has an early termination option that
is exercisable in March 2003. For additional information regarding our exposure
to interest rate risk, see page 49.
Year ended December 31, 2000 compared to year ended December 31, 1999
Revenues, costs and expenses and operating income. Our revenues increased to
$3.1 billion in 2000 compared to $1.3 billion in 1999 while operating costs and
expenses increased to $2.8 billion in 2000 versus $1.2 billion in 1999. Gross
operating margin increased to $320.6 million in 2000 compared to $179.2 million
in 1999 resulting in a year-to-year increase in operating income of $111.4
million to $243.7 million in 2000 from $132.3 million in 1999. The year-to-year
increase in revenues, operating costs and expenses, gross operating margin and
operating income is primarily attributable to the TNGL acquisition. The 1999
period includes five months of margins associated with TNGL operations (August
through December) whereas the 2000 period includes twelve months.
Fractionation. The gross operating margin of our Fractionation segment increased
to $129.4 million in 2000 from $110.4 million in 1999. The additional margin
from the NGL fractionators acquired from Shell in the TNGL acquisition was the
primary reason for a $29.7 million increase in NGL fractionation margin in 2000
over 1999. As noted previously, 1999 includes five months of margin from the
TNGL assets whereas the 2000 period includes twelve months. Net NGL
fractionation volume increased to 213 MBPD in 2000 from 184 MBPD in 1999. The
increase in net NGL fractionation volume is attributable to higher production
rates at our Mont Belvieu NGL fractionator. Our ownership in this facility
increased to 62.5% from 37.5% as a result of the July 1999 MBA acquisition.
For 2000, gross operating margin from our isomerization business decreased $7.8
million compared to 1999 primarily due to higher fuel and other operating costs,
plus the expenses related to the refurbishment of an isomerization unit.
Isomerization volumes were 74 MBPD in both 2000 and 1999. Gross operating margin
from propylene fractionation decreased $1.4 million in 2000 from 1999 levels
primarily due to higher energy costs. Net volumes at these facilities improved
to 33 MBPD in 2000 from 28 MBPD in 1999 due to the startup of the BRPC propylene
concentrator in July 2000.
Pipelines. Gross operating margin from our Pipelines segment was $56.1 million
in 2000 compared to $31.2 million in 1999. Overall liquids 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 HSC pipeline 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 Shell was completed at a cost of approximately $99.5 million.
Construction of the Lou-Tex NGL pipeline was completed during the fourth quarter
of 2000 at a cost of approximately $87.9 million.
Processing. Our Processing segment generated $122.2 million in gross operating
margin during 2000 compared to $28.5 million in 1999. The $93.7 million increase
is primarily due to 2000 including twelve months of gas processing (and related
merchant activity) margins from the TNGL businesses; whereas 1999 includes only
five 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. Gross operating margin from our Octane Enhancement segment
increased to $10.4 million in 2000 from $8.2 million in 1999. This segment
consists entirely of our investment in BEF, a joint venture facility that
currently produces MTBE. Equity earnings for 2000 improved over 1999 levels
primarily due to higher than normal MTBE market prices during the second and
third quarters of 2000 and lower debt service costs (BEF made its final note
payment in May 2000 and, as a result, now owns the facility debt-free). In
addition, the 1999 period
35
reflects a $1.5 million non-cash charge related to the write-off of certain
start-up expenses. MTBE production, on a net basis, was 5 MBPD in both 2000 and
1999.
Other. Gross operating margin from our 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.
Selling, general and administrative expenses. These expenses increased to $28.3
million in 2000 from $12.5 million in 1999. The increase is primarily due to
expenses related to the additional staff and resources deemed necessary to
support our expansion activities resulting from acquisitions and other business
development.
Interest expense. Interest expense increased to $33.3 million in 2000 from $16.4
million in 1999. The increase is attributable to a rise in average debt levels
from $213 million in 1999 to $408 million in 2000. Debt levels have increased
over the previous year primarily due to capital expenditures for assets such as
the Lou-Tex propylene and Lou-Tex NGL pipelines and the issuance of $404 million
in debt instruments (the Senior Notes A and MBFC Loan) in March 2001. Interest
expense for 2000 includes a $10.0 million benefit related to interest rate
swaps.
Our liquidity and capital resources
General. Our primary cash requirements, in addition to normal operating expenses
and debt service, are for capital expenditures (both sustaining and
expansion-related), business acquisitions and distributions to partners. We
expect to fund our short-term needs for such items as operating expenses,
sustaining capital expenditures and quarterly distributions to partners with
operating cash flows. Capital expenditures for long-term needs resulting from
internal growth 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. Our debt service
requirements are expected to be funded by operating cash flows and/or
refinancing arrangements.
Operating cash flows primarily reflect the effects of net income adjusted for
depreciation and amortization, equity income and cash distributions from
unconsolidated affiliates, fluctuations in fair values of financial instruments
and changes in operating accounts. The net effect of changes in operating
accounts is generally the result of timing of sales and purchases near the end
of each period. Cash flows from operations are directly linked to earnings from
our business activities. Like our results of operations, these cash flows are
exposed to certain risks including fluctuations in NGL and energy prices,
competitive practices in the midstream energy industry and the impact of
operational and systems risks. The products that we process, sell or transport
are principally used as feedstocks in petrochemical manufacturing and in the
production of motor gasoline and as fuel for residential and commercial heating.
Reduced demand for our products or services by industrial customers, whether
because of general economic conditions, reduced demand for the end products made
with NGL products, increased competition from petroleum-based products due to
pricing differences or other reasons, could have a negative impact on earnings
and thus the availability of cash from operating activities. For a more complete
discussion of these and other risk factors pertinent to our businesses, see page
1.
As noted above, certain of our 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, 2001, availability under our revolving credit facilities was $400
million (which may be increased by an additional $100 million under certain
conditions). We issued $450 million of public debt in January 2001 (the "Senior
Notes B") using the remaining availability under the December 1999 $800 million
universal shelf registration. The proceeds of this offering were used to acquire
Acadian Gas and the Gulf of Mexico natural gas pipeline systems, to finance the
cost to construct certain NGL pipelines and related projects and for working
capital and other general partnership purposes. On February 23, 2001, we filed a
$500 million universal shelf registration (the "February 2001 Shelf") covering
the issuance of an unspecified amount of equity or debt securities or a
combination thereof. For additional information regarding our debt, see the
section below labeled "Long-term debt."
In June 2000, we received approval from our Unitholders to increase by
25,000,000 the number of Common Units available (and unreserved) for general
partnership purposes during the Subordination Period. This increase has improved
our future financial flexibility in any potential expansion project or business
acquisition. After taking
36
into account the Units issued in connection with TNGL acquisition, 27,275,000
Units are available (and unreserved) on a pre-split basis (see "Two-for-one
split of Limited Partner Units" below) for general partnership purposes during
the Subordination Period which generally extends until the first day of any
quarter beginning after June 30, 2003 when certain financial tests have be
satisfied. After this period expires, we may prudently issue an unlimited number
of Units for general partnership purposes.
If deemed necessary, we believe that additional financing arrangements can be
obtained at reasonable terms. Furthermore, we believe that maintenance of our
investment grade credit ratings combined with a continued ready access to debt
and equity capital at reasonable rates and sufficient trade credit to operate
our businesses efficiently provide a solid foundation to meet our long and
short-term liquidity and capital resource requirements.
Credit ratings. Our current investment grade credit ratings of Baa2 by Moody's
Investor Service and BBB by Standard and Poors highlight our financial
flexibility. The outlook for both of the ratings is stable. We maintain regular
communications with these rating agencies which independently judge our
creditworthiness based on a variety of quantitative and qualitative factors. In
May 2001, Moody's upgraded their rating of us from Baa3 to Baa2. They cited that
our operating capabilities and growth opportunities had been significantly
enhanced by the acquisition of Acadian Gas and the purchase of equity interests
in four Gulf of Mexico natural gas pipeline systems. We believe that the
maintenance of an investment grade credit rating is important in managing our
liquidity and capital resource requirements.
Two-for-one split of Limited Partner Units. On February 27, 2002, we announced
that the Board of Directors of the General Partner had approved a two-for-one
split for each class of our Units. The partnership Unit split will be
accomplished by distributing one additional partnership Unit for each
partnership Unit outstanding to holders of record on April 30, 2002. The Units
will be distributed on May 15, 2002. All references to number of Units or
earnings per Unit contained in this document relate to the pre-split Units,
except if indicated otherwise.
Consolidated cash flows for year ended December 31, 2001 compared to year ended
December 31, 2000
Operating cash flows. Cash flows from operating activities were $283.3 million
in 2001 versus $360.9 million in 2000. After adjusting for changes in operating
accounts which are generally the result of timing of sales and purchases near
the end of each period, adjusted cash flow from operating activities would be
$320.4 million in 2001 as compared to $289.8 million in 2000. Cash flow from
operating activities before changes in operating accounts is an important
measure of our liquidity. It provides an indication of our success in generating
core cash flows from the assets and investments that we own. The $30.7 million
increase for 2001 is attributable to our strong earnings as discussed earlier
under "Our results of operations - Year ended December 31, 2001 compared to year
ended December 31, 2000."
Investing cash flows. During 2001, we used $491.2 million of cash to finance
investing activities compared to $268.8 million in 2000. Over the last two
years, we have funded $384.3 million in internal growth projects. Of this
amount, $336.2 million in capital expenditures has been devoted to various
pipeline projects including $99.5 million spent to purchase the Lou-Tex
Propylene pipeline (2000), $90.5 million to construct the Lou-Tex NGL pipeline
($83.7 million spent in 2000 with the remainder spent in 2001) and $64.1 million
in expansion activities related to our Louisiana Pipeline System (2001). We
spent $9.5 million on sustaining capital expenditures during the last two years
with $6.0 million in such charges recorded during 2001.
Our investing cash outflows for 2001 include the $225.7 million paid to acquire
Acadian Gas from Shell. This amount is subject to certain post-closing
adjustments expected to be completed during the first half of 2002. In
addition, our investments in and advances to unconsolidated affiliates increased
$84.7 million in 2001 due to the $112.0 million paid to purchase equity
interests in several Gulf of Mexico natural gas pipeline systems from El Paso.
Financing cash flows. Our financing activities generated $279.5 million of cash
receipts during 2001 compared to cash payments of $36.9 million in 2000. Cash
flows from financing activities are primarily affected by repayments of debt,
borrowings under debt agreements and distributions to partners. Cash flow from
financing activities in 2001 includes proceeds from the $450 million Senior
Notes B issued in January 2001 whereas the 2000 period includes
37
proceeds from the $350 million Senior Notes A and $54 million MBFC loan and the
associated repayments on various bank credit facilities.
Cash distributions to partners and the minority interest increased to $166.0
million in 2001 from $141.0 million in 2000 primarily due to (i) increases in
the quarterly distribution rate and (ii) the conversion of 5.0 million of
Shell's Special Units into Common Units. See Note 9 of the Notes to Consolidated
Financial Statements for a history of quarterly distribution rates and increases
since the first quarter of 1999. Our cash distribution policy (as managed by the
General Partner at its sole discretion) has allowed us to retain a significant
amount of cash flow for reinvestment in the growth of the business. Over the
last two years, we have retained approximately $275.0 million to fund expansions
and business acquisitions. We believe that our cash distribution policy provides
the partnership with financial flexibility in executing its growth strategy.
In July 2000, the General Partner instituted a two-year buy-back program (the
"Buy Back Program") that would allow Enterprise Products Partners L.P. ("EPPLP",
on a stand-alone basis) to repurchase and retire up to 1.0 million of its
publicly-owned Common Units. Our intent under the Buy Back Program is to
reacquire Common Units during periods of temporary market weakness at price
levels that would be accretive to our remaining Unitholders. Under this original
program, EPPLP repurchased and retired 28,400 Common Units during 2000 at a cost
of $0.8 million.
During the first quarter of 1999, we established a revocable grantor trust (the
"Trust") to fund potential future obligations under the EPCO Agreement with
respect to EPCO's long-term incentive plan (through the exercise of options
granted to EPCO employees or directors of the General Partner). At December 31,
2001, this consolidated Trust owned 163,600 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 receive
distributions; however, they are excluded from the calculation of earnings per
Unit.
In September 2001, the General Partner modified the Buy Back Program to allow
both EPPLP and the Trust to repurchase Common Units. Under the modified terms of
the program, purchases made by EPPLP will be retired whereas the Units purchased
by the Trust will remain outstanding and not be retired. At December 31, 2001,
575,200 additional publicly-owned Common Units (on a pre-split basis) could be
repurchased under the Buy Back Program by EPPLP and/or the Trust.
Purchases made under this program by EPPLP will be funded by special cash
distributions from the Operating Partnership whereas purchases made by the Trust
will be funded by cash contributions from the Operating Partnership. These
purchases will be balanced with our plans to grow the Company through
investments in internally-developed projects and acquisitions, while maintaining
an investment grade debt rating. The Trust purchased 396,400 Common Units under
this program during 2001 at a cost of $18.0 million. The Trust subsequently
reissued 500,000 treasury units for proceeds of $22.6 million. For additional
information regarding the Trust, see Note 7 of the Notes to Consolidated
Financial Statements.
At December 31, 2001, we had $5.8 million in restricted cash required by the
NYMEX commodity exchange to facilitate financial instrument and physical
purchase transactions. This amount can fluctuate over time depending on the
physical volumes underlying the contracts, market price of the commodity and
type of transactions executed. During 2001, our restricted cash balance required
by the exchange varied, reaching a peak of $13.4 million in July.
Consolidated cash flows for year ended December 31, 2000 compared to year ended
December 31, 1999
Operating cash flows. Cash flows from operating activities were $360.9 million
in 2000 compared to $177.9 million in 1999. After adjusting for changes in
operating accounts which are generally the result of timing of sales and
purchases near the end of each period, adjusted cash flow from operating
activities increased $139.8 million to $289.8 million in 2000 compared to $150.0
million in 1999. The $139.8 million increase in adjusted cash flow from
operating activities between periods is primarily due to the impact of the TNGL
acquisition as discussed earlier under "Our results of operations - Year ended
December 31, 2000 compared to year ended December 31, 1999."
Investing cash flows. We invested $268.8 million during 2000 (primarily in
internal growth projects) compared to $271.2 million spent during 1999
(primarily for acquisitions). Fiscal 1999 reflects $208.1 million in net cash
38
payments resulting from the TNGL and MBA acquisitions. Our capital expenditures
increased substantially in 2000 over 1999 primarily due to the purchase of the
Lou-Tex Propylene pipeline ($99.5 million) and construction costs related to the
Lou-Tex NGL pipeline ($83.7 million).
Investments in and advances to unconsolidated affiliates during 1999 include our
share of costs ($38.2 million) to complete construction and commence operations
of the BRF facility and Wilprise and Tri-States pipelines. Our 2000 expenditures
include $19.4 million paid to purchase an additional 8.4% interest in Dixie. The
1999 and 2000 amounts also include a combined $26.2 million in costs to
construct the BRPC facility, which was completed in July 2000.
Financing cash flows. Our financing activities resulted in net cash payments of
$36.9 million in 2000 versus net cash receipts of $74.4 million in 1999. Fiscal
2000 includes proceeds from the issuance of Senior Notes A and the MBFC Loan and
the associated repayments on various bank credit facilities. Financing
activities in 1999 include the borrowings under bank credit facilities to
finance the TNGL and MBA acquisitions and $4.7 million paid by the Trust to
repurchase (and treat as Treasury Units) 267,200 of our publicly-traded Common
Units. Distributions to partners and the minority interest increased to $141.0
million in 2000 compared to $112.9 million in 1999 primarily due to increases in
the quarterly distribution rate. Lastly, EPPLP repurchased and retired 28,400
Common Units during 2000 under its Buy-Back Program (see page 38) at a cost of
$0.8 million.
Cash requirements for future growth
We are committed to the long-term growth and viability of the Company. Our
strategy involves expansion through business acquisitions and internal growth
projects. In recent years, major oil and gas companies have sold non-strategic
assets in the midstream natural gas industry in which we operate. We forecast
that this trend will continue, and expect independent oil and natural gas
companies to consider similar disposal options. Management continues to analyze
potential acquisitions, joint venture or similar transactions with businesses
that operate in complementary markets and geographic regions. We believe that
the Company is well positioned to continue to grow through acquisitions that
will expand its platform of assets and through internal growth projects. Our
goal for fiscal 2002 is to invest at least $400 million in such opportunities
that will be accretive to our investors.
The funds needed to achieve this goal can be attained through a combination of
operating cash flows, debt or equity. During January and February 2002, we spent
approximately $367.5 million to acquire hydrocarbon storage and propylene
fractionation facilities and related assets from D-K. Of this amount,
approximately $238.5 million was funded by a drawdown on our Multi-Year and
364-Day credit facilities leaving $161.5 million of unused commitments available
under these credit agreements. The increase in outstanding debt will translate
into additional debt service costs during 2002.
Another stated goal of management is to increase the distribution rate to our
investors by at least 10% annually. At the end of 2001, the annual rate was
$2.50 per Common Unit. We forecast that operating cash flows will be sufficient
in 2002 to increase the rate to at least $2.75 per Common Unit (on a pre-split
basis). On February 27, 2002, we announced an increase in the quarterly
distribution from $0.625 per Common Unit to $0.67 per Common Unit on a pre-split
basis. Based on the number of distribution-bearing Units projected to be
outstanding during 2002, we project that this goal will translate into cash
distributions increasing by approximately $50 million over the amounts paid to
partners and the minority interest during 2001.
Future capital expenditures. During 2002, we forecast that approximately $79.3
million will be spent on expansion capital projects, of which $64.5 million is
related to our Pipelines segment. In addition, we expect to spend $6.0 million
on sustaining capital expenditures. We generally classify improvements and major
renewals of existing assets as sustaining capital expenditures and all other
capital spending on existing and new assets referred to as expansion capital
expenditures. Both expansion and sustaining capital expenditures are recorded as
cash outlays for property, plant and equipment. Maintenance, repairs and minor
renewals are charged to operations as incurred. Our unconsolidated affiliates
forecast a combined $62.2 million in capital expenditures during 2002 of which
we will fund approximately $20.8 million.
39
The following table shows our projected capital spending by operating segment
for 2002 (in thousands of dollars):
Expenditure Type
--------------------------------
Investments In
Operating Property, Plant Unconsolidated
Segment And Equipment Affiliates Total
--------------------------------------------------------------------
Fractionation $ 7,255 $ 7,929 $ 15,184
Pipelines 65,997 12,278 78,275
Processing 5,841 5,841
Octane Enhancement 560 560
Other 6,200 6,200
----------------------------------------
Total $85,293 $20,767 $106,060
========================================
At December 31, 2001, we had $5.3 million in outstanding purchase commitments
attributable to capital projects. Of this amount, $5.0 million is related to the
construction of assets that will be recorded as property, plant and equipment
and $0.3 million is associated with capital projects of our unconsolidated
affiliates which will be recorded as additional investments.
New environmental regulations in the state of Texas may necessitate extensive
redesign and modification of the our Mont Belvieu facilities to achieve the air
emissions reductions needed for federal Clean Air Act compliance in the
Houston-Galveston, Texas area. The technical practicality and economic
reasonableness of these regulations have been challenged under state law in
litigation filed on January 19, 2001, against the Texas Natural Resource
Conservation Commission and its principal officials in the District Court of
Travis County, Texas, by a coalition of major Houston-Galveston area industries
including the Company. Until this litigation is resolved, the precise level of
technology to be employed and the cost for modifying the facilities to achieve
the required amount of reductions cannot be determined. Currently, the
litigation has been stayed by agreement of the parties pending the outcome of
expanded, cooperative scientific research to more precisely define sources and
mechanisms of air pollution in the Houston-Galveston area. Completion of this
research and formulation of the regulatory response are anticipated in
mid-2002. Regardless of the results of this research and the outcome of the
litigation, expenditures for air emissions reduction projects will be spread
over several years, and we believe that adequate liquidity and capital resources
will exist for us to undertake them. We have budgeted capital funds in 2002 to
begin making modifications to certain Mont Belvieu facilities that will result
in air emission reductions. The methods employed to achieve these reductions
will be compatible with whatever regulatory requirements are eventually put in
place. For additional information regarding the impact of the Clean Air Act on
our operations, see page 22 of this report on Form 10-K.
40
Long-term debt
Our long-term debt consisted of the following at:
December 31,
---------------------
2001 2000
---------------------
Borrowings under:
Senior Notes A, 8.25% fixed rate, due March 2005 $ 350,000 $ 350,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000
---------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to hedging a portion of
fixed-rate debt (see Note 6 of Notes to Consolidated Financial Statements) 1,653
Less unamortized discount on:
Senior Notes A (117) (153)
Senior Notes B (258)
Less current maturities of long-term debt -
---------------------
Long-term debt $ 855,278 $ 403,847
=====================
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, 2001. See below for a
complete description of these facilities.
At December 31, 2001, we had a total of $75 million of standby letters of credit
capacity under our Multi-Year Credit Facility of which $2.4 million was
outstanding.
We act as guarantor of certain debt obligations of our primary consolidated
subsidiary, the Operating Partnership. This parent-subsidiary guaranty provision
exists under our Senior Notes, MBFC Loan and two current revolving credit
facilities. In the descriptions that follow, the term "MLP" denotes us in this
guarantor role.
Senior Notes A. On March 13, 2000, we 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 "Senior Notes A").
These notes were issued to retire certain revolving credit loan balances that
were created as a result of the TNGL acquisition and other general partnership
activities.
The Senior Notes A 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 our ability, with certain exceptions, to
incur debt secured by liens and engage in sale and leaseback transactions. We
were in compliance with these restrictive covenants at December 31, 2001.
Senior Notes B. On January 24, 2001, we 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 "Senior Notes B").
These notes were issued to finance the acquisition of Acadian Gas, Neptune, Nemo
and Starfish; to cover construction costs of certain NGL pipelines and related
projects; and to fund other general partnership activities.
The Senior Notes B were issued under the same indenture as Senior Notes A and
therefore are subject to similar terms and restrictive covenants. The Senior
Notes B are guaranteed by the MLP through an unsecured and unsubordinated
guarantee. We were in compliance with the restrictive covenants at December 31,
2001.
MBFC Loan. On March 27, 2000, we executed a $54 million loan agreement with the
Mississippi Business Finance Corporation ("MBFC") having a 8.70% fixed-rate and
a maturity date of March 1, 2010. In general, the proceeds
41
from this loan were used to retire certain revolving credit loan balances
attributable to acquiring and constructing the Pascagoula, Mississippi natural
gas processing facility.
The MBFC Loan is subject to a make-whole redemption right and is guaranteed by
the MLP through an unsecured and unsubordinated guarantee. The indenture
agreement contains an acceleration clause whereby the outstanding principal and
interest on the loan may become due and payable if our credit ratings decline
below a Baa3 rating by Moody's (currently Baa2) and below a BBB- rating by
Standard and Poors (currently BBB). Under these circumstances, the trustee (as
defined in the indenture agreement) may, and if requested to do so by holders of
at least 25% in aggregate of the principal amount of the outstanding underlying
bonds, shall accelerate the maturity of the MBFC Loan, whereby the principal and
all accrued interest would become immediately due and payable. If such an event
occurred, we would have the option (a) to redeem the MBFC loan or (b) to provide
an alternate credit agreement (as defined in the indenture agreement) to support
our obligation under the MBFC loan, with both options exercisable within 120
days of receiving notice of the decline in our credit ratings from the ratings
agencies.
The loan agreement contains certain covenants including maintaining appropriate
levels of insurance on the Pascagoula facility and restrictions regarding
mergers. We were in compliance with the restrictive covenants at December 31,
2001.
Multi-Year Credit Facility. On November 17, 2000, we entered into a $250 million
five-year revolving credit facility that includes a sublimit of $75 million for
letters of credit. The November 17, 2005 maturity date may be extended for one
year at our option with the consent of the lenders, subject to the extension
provisions in the agreement. We can increase the amount borrowed under this
facility, with the consent of the Administrative Agent (whose consent may not be
unreasonably withheld), 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 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 guarantee.
Proceeds from this credit facility will be used for working capital,
acquisitions and other general partnership purposes. No borrowing was
outstanding for this credit facility at December 31, 2001. In February 2002, we
borrowed $200 million under this facility to complete our purchase of D-K's Mont
Belvieu, Texas propylene fractionation assets.
Our obligations under this bank credit facility are unsecured general
obligations and are non-recourse to the General Partner. As defined within the
agreement, borrowings under this bank credit facility will generally bear
interest at either (i) the greater of the Prime Rate or the Federal Funds
Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an
applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the
interest rate at the time of each borrowing.
Our credit agreement contains various affirmative and negative covenants to,
among other things, (i) incur certain indebtedness, (ii) grant certain liens,
(iii) enter into certain merger or consolidation transactions and (iv) make
certain investments. In addition, we may not directly or indirectly make any
distribution in respect of our partnership interests, except those payments in
connection with the Buy-Back Program (not to exceed $30 million in the
aggregate, see Note 7) and distributions from Available Cash from Operating
Surplus, both as defined within the agreement.
The credit agreement also requires that we satisfy certain financial covenants
at the end of each fiscal quarter. As defined within the agreement, we (i) must
maintain Consolidated Net Worth of $750 million and (ii) not permit our ratio of
Consolidated Indebtedness to Consolidated EBITDA, including pro forma
adjustments (as defined within the agreement), for the previous four quarter
period to exceed 4.0 to 1.0. If we fail to maintain these financial covenants,
either the unused commitments under this facility will terminate or the
outstanding principal balance (in whole or part at the discretion of the
lenders) will be immediately payable or both. Since these ratios are dependent
to a varying degree upon earnings, any sustained decline in our profitability
would have a negative impact on these calculations. The Company was in
compliance with the restrictive covenants at December 31, 2001.
42
364-Day Credit Facility. In conjunction with the Multi-Year Credit Agreement, we
entered into a 364-day $150 million revolving bank credit facility. In November
2001, we and our lenders amended the revolving credit agreement to extend the
maturity date to November 15, 2002 with an option to convert any revolving
credit balance outstanding at November 15, 2002 to a one-year term loan.
We can increase the amount borrowed under this facility, with the consent of the
Administrative Agent (whose consent may not be unreasonably withheld), 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
Multi-Year Credit Facility do 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 guarantee. No borrowing was outstanding for this credit facility at
December 31, 2001. In February 2002, we borrowed approximately $38.5 million
under this facility to complete our purchase of D-K's Mont Belvieu, Texas
propylene fractionation assets.
Our obligations under this bank credit facility are unsecured general
obligations and are non-recourse to the General Partner. As defined within the
agreement, borrowings under this bank credit facility will generally bear
interest at either (i) the greater of the Prime Rate or the Federal Funds
Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an
applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the
interest rate at the time of each borrowing.
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, 2001.
Limitations on certain actions by the Company and financial condition covenants
of this bank credit facility are substantially consistent with those existing
for the Multi-Year Credit Facility as described previously. We were in
compliance with the restrictive covenants at December 31, 2001.
February 2001 Shelf
On February 23, 2001, we filed a $500 million universal shelf registration (the
"February 2001 Shelf") covering the issuance of an unspecified amount of equity
or debt securities or a combination thereof. We expect 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
our funding requirements and the availability of alternative funding sources. We
routinely review acquisition opportunities.
For additional information regarding our debt, see Note 6 of the Notes to
Consolidated Financial Statements beginning on page F-18 of this report on Form
10-K.
43
Summary of contractual obligations and material commercial commitments
The following table summarizes our contractual obligations and material purchase
and other commitments for the periods shown (as of December 31, 2001):
Contractual Obligation 2003 2006
Or Material Commercial Through Through After
Commitment Total 2002 2005 2007 2007
- -----------------------------------------------------------------------------------------------------
Contractual Obligation (expressed in
terms of millions of dollars payable
per period:)
Long-term debt $ 854.0 $ 350.0 $ 504.0
Operating leases $ 15.8 $ 5.1 $ 9.5 $ 0.3 $ 0.9
Capital spending:
Property, plant and equipment $ 5.0 $ 5.0
Investments in unconsolidated
affiliates $ 0.3 $ 0.3
Other commitments (expressed in terms
of millions of dollars potentially payable
per period):
Letters of Credit under Multi-Year
Credit Facility $ 2.4 $ 2.4
Other Material Contractual Obligations
(Purchase commitments expressed in terms
of minimum volumes under contract
per period:)
NGLs (MBbls) 28,530 9,588 18,602 340
Natural gas (BBtus) 142,040 13,726 39,718 25,596 63,000
Long-term debt. Long-term debt includes our obligations under Senior Notes A and
B and the MBFC Loan.
Operating leases. We lease certain equipment and processing facilities under
noncancelable and cancelable operating leases. The amounts shown in the table
represent minimum future rental payments due on such leases with terms in excess
of one year.
The operating lease commitments shown above exclude the expense associated with
various equipment leases contributed to us by EPCO at our formation for which
EPCO has retained the liability. During 2001, 2000 and 1999, our non-cash lease
expense associated with these EPCO "retained" leases was $10.4 million, $10.6
million and $10.6 million, respectively. Lease and rental expense (including
Retained Leases) included in operating income for the years ended December 31,
2001, 2000 and 1999 was approximately $23.4 million, $21.2 million and $20.6
million. EPCO has assigned us the purchase options associated with the retained
leases. Should we decide to exercise our purchase options under the retained
leases, up to $26.0 million will be payable in 2004, $3.4 million in 2008 and
$3.1 million in 2016.
Capital spending. We have capital spending commitments attributable to various
capital projects. Of this amount, $5.0 million is related to the construction of
assets that will be recorded as property, plant and equipment and $0.3 million
is associated with capital projects of our unconsolidated affiliates which will
be recorded as additional investments.
44
NGL and natural gas purchase commitments. In addition, we have long-term
purchase commitments for NGL products and related-streams (including natural
gas) with several suppliers. The purchase prices contained within these
contracts approximate market value at the time of delivery. Our purchase
commitments for NGLs are stated in thousands of barrels and for natural gas in
BBtus.
For additional information regarding our commitments, please see Note 11 of the
Notes to Consolidated Financial Statements.
Impact of recent accounting developments
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business
Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS
No. 141 prohibits the use of the pooling-of-interest method for business
combinations initiated after June 30, 2001 and also applies to all business
combinations accounted for by the purchase method that are completed after June
30, 2001. There are also transition provisions that apply to business
combinations completed before July 1, 2001, that were accounted for by the
purchase method. SFAS No. 142 became effective January 1, 2002 for all goodwill
and other intangible assets recognized in our consolidated balance sheet at that
date, regardless of when those assets were initially recognized. We adopted SFAS
No. 141 on January 1, 2002.
Within six months our adoption of SFAS No. 142 (by June 30, 2002), we will have
completed a transitional impairment review to identify if there is an impairment
to the December 31, 2001 recorded goodwill or intangible assets of indefinite
life using a fair value methodology. Professionals in the business valuation
industry will be consulted to validate the assumptions used in such
methodologies. Any impairment loss resulting from the transitional impairment
test will be recorded as a cumulative effect of a change in accounting principle
for the quarter ended June 30, 2002. Subsequent impairment losses will be
reflected in operating income in the Statements of Consolidated Operations.
At January 1, 2002, our intangible assets included the values assigned to the
20-year Shell natural gas processing agreement (the "Shell agreement") and the
excess cost of the purchase price over the fair market value of the assets
acquired from Mont Belvieu Associates (the "MBA excess cost"), both of which
were initially recorded in 1999. The value of the Shell agreement ($194.4
million net book value at December 31, 2001) is being amortized on a
straight-line basis over its contract term. Likewise, the MBA excess cost ($7.9
million net book value at December 31, 2001) was being amortized on a
straight-line basis over 20 years. Based upon initial interpretations of the new
accounting standards, we anticipate that the intangible asset related to the
Shell agreement will continue to be amortized over its contract term ($11.1
million annually for 2002 through July 2019); however, the MBA excess cost will
be reclassified to goodwill in accordance with the new standard and its
amortization will cease (currently, $0.5 million annually). This goodwill would
then be subject to impairment testing as prescribed in SFAS No. 142. We are
continuing to evaluate the comprehensive provisions of SFAS No. 142 and will
fully adopt the standard during 2002 within the prescribed time periods.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143,
"Accounting for Asset Retirement Obligations", in June 2001. This statement
establishes accounting standards for the recognition and measurement of a
liability for an asset retirement obligation and the associated asset retirement
cost. This statement is effective for our fiscal year beginning January 1, 2003.
We are continuing to evaluate the provisions of this statement. In August 2001,
the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets". This statement addresses financial accounting and reporting
for the impairment and/or disposal of long-lived assets. We adopted this
statement effective January 1, 2002 and determined that it will have no material
impact on our financial statements as of that date.
Uncertainties regarding our investment in BEF
We have a 33.3% ownership interest in BEF, which owns a facility currently
producing MTBE. The production of MTBE is driven by oxygenated fuels programs
enacted under the federal Clean Air Act Amendments of 1990 and other
legislation. Any change 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. In 1999, the Governor of California ordered the phase-out of MTBE in
California by the end of
45
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. Subsequently,
the EPA denied California's request for a waiver of the oxygenate requirement
and the state is now reconsidering the timing of its MTBE ban.
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 by
individual states such as California. Legislation introduced in the U.S. House
to prevent states from banning MTBE was defeated in 2001. No assurance can be
given as to whether the federal government or individual states will ultimately
adopt legislation banning or promoting the use of MTBE as part of their clean
air programs.
In light of these regulatory developments, the owners of BEF have been
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. We believe that if
MTBE usage is banned or significantly curtailed, the motor gasoline industry
would need a substitute additive to maintain octane levels in motor gasoline and
that alkylate would be an attractive substitute. 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 would range
from $20 million to $90 million, with our share of these costs ranging from $6.7
million to $30 million.
We issued the last installment of Special Units to Shell in August 2001
On or about June 30, 2001, Shell met certain year 2001 performance criteria for
the issuance of the last installment of 3.0 million non-distribution bearing,
convertible contingency Units (referred to as Special Units when issued). Under
a contingent unit agreement with Shell executed as part of the 1999 TNGL
acquisition, we issued these Special Units on August 2, 2001. The issuance of
these new Special Units had an impact on diluted earnings per Unit beginning
with the third quarter of 2001.
The value of these Special Units was determined to be $117.1 million using
present value techniques. This amount increased the purchase price of the TNGL
acquisition and the value of the Shell Processing Agreement when the additional
Special Units were issued and recorded in August 2001. This amount also
increased the equity position of Shell in the Company by $117.1 million with the
General Partner contributing $1.2 million to maintain its respective ownership
in the Company. The $117.1 million increase in value of the Shell Processing
Agreement will be amortized over the remaining life of the contract. As a
result, amortization expense will increase by approximately $6.5 million
annually.
We converted a portion of Shell's Special Units into Common Units in August 2001
In accordance with existing agreements with Shell, 5.0 million of Shell's
original issue of Special Units (issued in connection with the TNGL acquisition)
converted into Common Units on August 2, 2001. The conversion had an impact on
basic earnings per Unit and cash distributions to Shell beginning with the third
quarter of 2001. Of the 14.5 million Special Units that remain outstanding at
December 31, 2001, 9.5 million are scheduled to convert into Common Units in
August 2002 with the balance of 5.0 million converting in August 2003.
Response to September 11, 2001 Terrorist Attacks
Following the recent terrorist attacks in the United States, we instituted a
review of security measures and practices and emergency response capabilities
for all facilities and sensitive infrastructure. In connection with this
activity, we participated in security coordination efforts with law enforcement
and public safety authorities, industry mutual-aid groups and regulatory
agencies. As a result of these steps, we believe that security measures,
techniques and equipment have been enhanced as appropriate on a
location-by-location basis. Further evaluation will be ongoing, with additional
measures to be taken as specific governmental alerts, additional information
about improving security and new facts come to our attention.
46
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
We are exposed to financial market risks, including changes in commodity prices
in our natural gas and NGL businesses and in interest rates with respect to a
portion of our debt obligations. We may use financial instruments (i.e.,
futures, forwards, swaps, options and other financial instruments with similar
characteristics) to mitigate the risks of certain identifiable and anticipated
transactions, primarily in our Processing segment. In general, the types of
risks hedged are those relating to the variability of future earnings and cash
flows caused by changes in commodity prices and interest rates. As a matter of
policy, we do not use financial instruments for speculative (or trading)
purposes.
Apart from the disclosures below, additional information regarding our financial
instruments (financial assets and liabilities) can be found under Note 13 in the
Notes to Consolidated Financial Statements.
Commodity financial instruments. Our Processing and Octane Enhancement segments
are directly exposed to commodity price risk through their respective business
operations. The prices of natural gas, NGLs and MTBE are subject to fluctuations
in response to changes in supply, market uncertainty and a variety of additional
factors that are beyond our control. These factors include the level of domestic
oil, natural gas and NGL production and development, the availability of
imported oil and natural gas, actions taken by foreign oil and natural gas
producing nations, the availability of transportation systems with adequate
capacity, the availability of alternative fuels and products, seasonal demand
for oil, natural gas and NGLs, conservation, the extent of governmental
regulation of production and the overall economic environment.
In order to manage the risks associated with our Processing segment, we may
enter into swaps, forwards, commodity futures, options and other commodity
financial instruments with similar characteristics that are permitted by
contract or business custom to be settled in cash or with another financial
instrument. The primary 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. We do not
hedge our exposure to the MTBE markets. Also, in our Pipelines segment, we may
utilize a limited number of commodity financial instruments to manage the price
Acadian Gas charges certain of its customers for natural gas and/or the price
Acadian Gas pays for the natural gas it purchases.
We have adopted a commercial policy to manage our exposure to the risks of our
natural gas and NGL businesses. The objective of this policy is to assist us in
achieving our profitability goals while maintaining a portfolio with an
acceptable level of risk, defined as remaining within the position levels
established by the General Partner. We enter into risk management transactions
to manage price risk, basis risk, physical risk or other risks related to our
commodity positions on both a short-term (less than 30 days) and long-term basis
(not to exceed 18 months). At December 31, 2001, we had open commodity financial
instruments that settle at different dates through December 2002. The General
Partner oversees our strategies associated with physical and financial risks,
approves specific activities subject to the commercial policy (including
authorized products, instruments and markets) and establishes specific
guidelines and procedures for implementing and ensuring compliance with the
policy.
We assess the risk of our commodity financial instruments portfolio using a
sensitivity analysis model. The sensitivity analysis performed on this portfolio
measures the potential income or loss (i.e., the change in fair value of the
portfolio) based on a hypothetical 10% movement in the underlying quoted market
prices of the commodity financial instruments outstanding at the dates noted
within the table. In general, we derive the quoted market prices used in the
model from those actively quoted on commodity exchanges (ex. NYMEX) for
instruments of similar duration. In those rare instances where prices are not
actively quoted, we employ regression analysis techniques possessing strong
correlation factors.
47
The sensitivity analysis model takes into account the following primary factors
and assumptions:
. the current quoted market price of natural gas;
. the current quoted market price of NGLs;
. changes in the composition of commodities hedged (i.e., the mix
between natural gas and related NGLs);
. fluctuations in the overall volume of commodities hedged (for both
natural gas and related NGL hedges outstanding);
. market interest rates, which are used in determining the present
value; and
. a liquid market for such financial instruments.
An increase in fair value of the commodity financial instruments (based upon the
factors and assumptions noted above) approximates the income that would be
recognized if all of the commodity financial instruments were settled at the
dates noted within the table. Conversely, a decrease in fair value of the
commodity financial instruments would result in the recording of a loss.
The sensitivity analysis model does not include the impact that the same
hypothetical price movement would have on the hedged commodity positions to
which they relate. Therefore, the impact on the fair value of the commodity
financial instruments of a change in commodity prices would be offset by a
corresponding gain or loss on the hedged commodity positions, assuming:
. the commodity financial instruments function effectively as hedges of
the underlying risk;
. the commodity financial instruments are not closed out in advance of
their expected term; and
. as applicable, anticipated underlying transactions settle as expected.
We routinely review our open commodity financial instruments in light of current
market conditions. If market conditions warrant, some instruments may be closed
out in advance of their contractual settlement dates thus realizing income or
loss depending on the specific exposure. When this occurs, we may enter into new
commodity financial instruments to reestablish the hedge of the commodity
position to which the closed instrument relates.
These commodity financial instruments may not qualify for hedge accounting
treatment under the specific guidelines of SFAS No. 133 because of
ineffectiveness. A hedge is normally regarded as effective if, among other
things, at inception and throughout the term of the financial instrument, we
could expect changes in the fair value of the hedged item to be almost fully
offset by the changes in the fair value of the financial instrument. Currently,
the majority of our commodity financial instruments do not qualify as effective
accounting hedges under the guidelines of SFAS No. 133, with the result being
that changes in the fair value of these positions are recorded on the balance
sheet and in earnings through mark-to-market accounting. The use of
mark-to-market accounting for these commodity financial instruments results in a
degree of non-cash earnings fluctuation that is dependent upon changes in the
underlying commodity prices. Even though these instruments do not qualify for
hedge accounting treatment under the specific guidelines of SFAS No. 133, we
continue to view these financial instruments as economically hedging our
commodity price risk exposure as this was the business intent when such
contracts were executed. This characterization is consistent with the actual
economic performance of the contracts to date and we expect these financial
instruments to continue to mitigate (or offset) commodity price risk in the
future. The specific accounting for these contracts, however, is consistent with
the requirements of SFAS No. 133. For additional information regarding our
commodity financial instruments, see Note 13 of the Notes to Consolidated
Financial Statements.
48
Sensitivity Analysis for Commodity Financial Instruments Portfolio
Estimates of Fair Value ("FV") and Earnings Impact ("EI")
due to selected changes in quoted market prices at dates selected
Resulting December 31, March 7,
------------------
Scenario Classification 2000 2001 2002
- ---------------------------------------------------------------------- -----------------------------
(in millions of dollars)
-----------------------------
FV assuming no change in quoted market prices Asset (Liability) $ (38.6) $ 5.6 $ (5.5)
FV assuming 10% increase in quoted market prices Asset (Liability) (56.3) (0.3) (18.4)
EI assuming 10% increase in quoted market prices Income (Loss) (17.7) (5.9) (12.9)
FV assuming 10% decrease in quoted market prices Asset (Liability) (20.9) 11.4 7.4
EI assuming 10% decrease in quoted market prices Income (Loss) 17.7 5.8 12.9
At December 31, 2000, the fair value of the commodity financial instruments
portfolio was a $38.6 million liability. At this date, our portfolio was
primarily comprised of natural gas-based hedging instruments that were
negatively affected by the unusually high natural gas prices that occurred at
the end of 2000 and beginning of 2001. At December 31, 2001, the value of the
financial instruments outstanding at that time reflected a $5.6 million asset
primarily due to the moderation of natural gas prices. The portfolio value was
also affected, to a lesser degree, by periodic changes in the composition of
commodities hedged and settlements of certain open positions. At March 7, 2002,
the value of the financial instruments outstanding at that time was a $5.5
million liability primarily due to an increase in natural gas prices.
Historical income or loss resulting from commodity hedging activities are a
component of our operating costs and expenses as reflected in the Statements of
Consolidated Operations. We recognized income of $101.3 million of such income
during fiscal 2001, of which $95.7 million was realized through cash settlement
of the commodity hedges.
Interest rate swaps. Our interest rate exposure results from variable-rate
borrowings from commercial banks and fixed-rate borrowings pursuant to the
Senior Notes and MBFC Loan. We manage our exposure to changes in interest rates
by utilizing interest rate swaps. The objective of holding interest rate swaps
is to manage debt service costs by converting a portion of fixed-rate debt into
variable-rate debt or a portion of variable-rate debt into fixed-rate debt. 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. We believe it is prudent to maintain an appropriate mixture of
variable-rate and fixed-rate debt.
We assess interest rate cash flow risk by identifying and measuring changes in
interest rate exposure that impact future cash flows and evaluating hedging
opportunities. We use analytical techniques to measure our exposure to
fluctuations in interest rates, including cash flow sensitivity analysis to
estimate the expected changes in interest rates on future cash flows. The
General Partner oversees the strategies associated with financial risks and
approves instruments that are appropriate for our requirements.
Our interest rate swap agreements were dedesignated as hedging instruments after
the adoption of SFAS No. 133; therefore, the swaps are accounted for on a
mark-to-market basis. However, these financial instruments continue to be
effective in achieving the risk management activities for which they were
intended. As a result, the change in fair value of these instruments will be
reflected on the balance sheet and in earnings (as a component of interest
expense) using mark-to-market accounting.
At December 31, 2000, we had three interest rate swaps outstanding having a
combined notional value of $154 million (attributable to fixed-rate debt) with
an estimated fair value of $2.0 million (an asset). Due to the early termination
of two of the swaps, the notional amount and fair value of the remaining swap
was $54 million and $2.3 million (an asset), respectively, at December 31, 2001.
49
We recorded $13.2 million of income from our interest rates swaps during 2001
and $10.0 million during 2000. The income recognized in 2001 from these swaps
includes the $2.3 million in non-cash mark-to-market income at December 31, 2001
(attributable to the sole remaining swap). The remaining $10.9 has been
realized. No mark-to-market income was recorded prior to the implementation of
SFAS No. 133.
The fair value of the remaining swap at December 31, 2001 would increase to $2.5
million if quoted market interest rates were to decline by 10%; conversely, the
fair value would decline to $2.1 million if rates were to rise by 10%. For
additional information regarding our interest rate swaps, see Note 13 of the
Notes to Consolidated Financial Statements.
At December 31, 2001, our fixed-rate debt obligations aggregated $854.0 million
principal amount and had a fair value of $894.0 million. Since these instruments
are fixed interest rates, they do not expose us to risk of loss in earnings due
to changes in market interest rates. However, the fair value of these
instruments would increase to approximately $920.6 million if the respective
yields to maturity for these debt obligations were to decline by 10% from their
levels at December 31, 2001. In general, such an increase in fair value would
impact earnings and cash flows only if we elected to reacquire all or a portion
of these instruments in the open market prior to their maturity.
Counterparty settlement risk issues
We are exposed to credit risk with our counterparties in terms of settlement
risk associated with the financial instruments. On all transactions were we are
exposed to settlement risk, we analyze the counterparty's financial condition
prior to entering into an agreement, establish credit and/or margin limits and
monitor the appropriateness of these limits on an ongoing basis.
On December 2, 2001, Enron Corp., or Enron, (NYSE, symbol "ENE") announced that
it and certain of its subsidiaries were filing voluntary petitions for Chapter
11 reorganization with the U.S. Bankruptcy Court for the Southern District of
New York. At the time of its bankruptcy filing, Enron North America, a
subsidiary of Enron, was the counterparty to a number of our commodity financial
instruments. As a result, we established a $10.6 million reserve for all amounts
owed to us by Enron. The Enron amounts were unsecured and the amount that we may
ultimately recover, if any, is not presently determinable. Of the reserve amount
established, $4.3 million was attributable to various unbilled commodity
financial instrument positions that terminate during the first quarter of 2002.
Currently, we do not anticipate any material change in this estimate.
At December 31, 2001, receivables and other current assets associated with our
counterparties totaled $9.9 million, net of the Enron reserve. Of the $9.9
million, $9.6 million is with counterparties rated as investment grade by
prominent rating agencies.
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" on page F-1.
Item 9. Changes in and disagreements with Accountants on Accounting and
Financial Disclosure.
None.
50
PART III
Item 10. Directors and Executive Officers of the Registrant.
As is commonly the case with publicly-traded master limited partnerships, we do
not directly employ any of the persons responsible for the management or
operations of our business. These functions are performed by the employees of
EPCO (pursuant to the EPCO Agreement, see page 59) under the direction of the
Board of Directors and executive officers of the General Partner.
Notwithstanding any limitation on its obligations or duties, our General Partner
is liable for all debts we incur (to the extent not paid by us), except to the
extent that such indebtedness or other obligations are non-recourse to the
General Partner. Whenever possible, the General Partner intends to make any such
indebtedness or other obligations non-recourse to it.
Audit and Conflicts Committee
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 our business,
approved by all of our partners and not a breach by the General Partner or its
Board of Directors of any duties they may owe us or our 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;
. overseeing the independence and performance of our 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 our policies,
procedures and practices at all levels;
. reviewing areas of potential significant financial risk to our
businesses; 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 committee 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 our expense, special legal, accounting or other
consultants or experts it deems necessary in the performance of its duties.
51
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) 69 Director and Chairman of the Board
O.S. Andras (1,3) 66 Director, President and Chief Executive Officer
Randa Duncan Williams (3) 40 Director
J. R. Eagan 47 Director
J. A. Berget (1) 49 Director
Dr. Ralph S. Cunningham (2) 61 Director
Curtis R. Frasier (1) 47 Director
Lee W. Marshall, Sr. (2) 69 Director
Richard S. Snell (2) 59 Director
Richard H. Bachmann (1,3) 49 Director, Executive Vice President,
Chief Legal Officer and Secretary
Michael A. Creel (3) 48 Executive Vice President and Chief Financial
Officer
A.J. ("Jim") Teague (3) 57 Executive Vice President
William D. Ray (3) 66 Executive Vice President
Charles E. Crain (3) 68 Senior Vice President
A. Monty Wells (3) 56 Senior Vice President
W. ("Bill") Ordemann (3) 42 Senior Vice President
Gil H. Radtke (3) 41 Senior Vice President
Michael J. Knesek (3) 47 Vice President and Principal
Accounting Officer
W. Randall Fowler (3) 45 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 Chairman of the Board and a Director of the General
Partner in April 1998. Mr. Duncan has served as Chairman of the Board of our
predecessor, EPCO, since 1979.
O.S. Andras was elected President, Chief Executive Officer and a Director of the
General Partner in April 1998. Mr. Andras served as President and Chief
Executive Officer of EPCO from 1996 to February 2001.
Randa Duncan Williams was elected a Director of the General Partner in April
1998. In February 2001, she was promoted to President and Chief Executive
Officer of EPCO from her previous position of Group Executive Vice President of
EPCO, a position she had held since 1994. Ms. Williams is the daughter of Dan L.
Duncan.
J. R. (Jeri) Eagan was elected a Director of the General Partner in October
2000. Since 1999, Ms. Eagan has served in various executive-level positions with
Shell and currently holds the office of Chief Financial Officer of Shell Oil
Company in addition to that of Vice President Finance & Commercial Operations of
a Shell subsidiary. From 1994 to 1999, she worked on several assignments in
Shell's London office.
J.A. (Jorn) Berget was elected a Director of the General Partner in November
2000. Since 1995, Mr. Berget has served in various managerial positions with
Shell, including Vice President and General Manager for one of its
52
subsidiaries since 2000. 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 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
serves as a director of Tetra Technologies, Inc. (a publicly-traded energy
services and chemicals company) and Agrium, Inc. (a Canadian publicly-traded
agricultural chemicals company) and was a former director of EPCO from 1987 to
1997. Mr. Cunningham serves as Chairman of our Audit and Conflicts Committee.
Curtis R. Frasier was elected a Director of the General Partner in November
1999. Mr. Frasier has held various executive-level positions with Shell
including President of its midstream enterprise business.
Lee W. Marshall, Sr. was elected a Director of the General Partner in April
1998. Mr. Marshall has been the Chief Executive Officer and principal owner of
Bison Resources, LLC since 1991. He has also served in senior management
positions with Union Pacific Resource and Tenneco Oil. Mr. Marshall is a member
of our Audit and Conflicts Committee.
Richard S. Snell was elected 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 firm in 1993. He is currently a partner with the law firm of Thompson &
Knight LLP in Houston, Texas and is a certified public accountant. Mr. Snell is
a member of our Audit and Conflicts Committee.
Richard H. Bachmann was elected a Director of the General Partner in June 2000.
He has served as Executive Vice President and Chief Legal Officer of the General
Partner and EPCO since January 1999. Previously, he was a partner with the legal
firms of Snell & Smith P.C. and Butler & Binion.
Michael A. Creel was elected an Executive Vice President 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. From 1997 to 1999 he held a series of positions
with a Shell affiliate, including Senior Vice President, Chief Financial Officer
and Treasurer. From 1995 to 1997, Mr. Creel was Vice President and Treasurer of
NorAm Energy Corp.
A.J. ("Jim") Teague was elected an Executive Vice President of the General
Partner in November 1999. From 1998 to 1999 he served as President of a Shell
affiliate and from 1997 to 1998 was President of Marketing and Trading for
Mapco, Inc..
William D. Ray was elected an Executive Vice President of the General Partner in
April 1998. Mr. Ray has served as EPCO's Executive Vice President for Marketing
and Supply since 1985.
Charles E. Crain was elected a Senior Vice President of the General Partner in
April 1998. Mr. Crain has served as Senior Vice President of Operations for EPCO
since 1991.
A. Monty Wells was elected a Senior Vice President of the General Partner in
June 2000. Mr. Wells has served in a number of managerial positions with EPCO
since 1980 including Vice President of Marketing and Supply.
W. ("Bill") Ordemann was elected a Senior Vice President of the General Partner
in September 2001. Mr. Ordemann has served in executive-level positions in our
NGL businesses since 1999. From 1996 to 1999, he served as a Vice President of
two Shell affiliates, including TNGL.
Gil H. Radtke was elected a Senior Vice President of the General Partner in
February 2002. Mr. Radtke joined the Company in connection with our purchase of
Diamond-Koch's storage and propylene fractionation assets in January and
February 2002. Before joining the Company, Mr. Radtke served as President of the
Diamond-Koch joint venture where he was responsible for its storage, propylene
fractionation, pipeline and NGL fractionation businesses. Mr. Radtke was
employed by Valero Energy Corporation (a partner in the Diamond-Koch joint
venture) for the last eighteen years in various commercial and analysis roles.
53
Michael J. Knesek was elected 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.
W. Randall Fowler was elected Treasurer and a Vice President of the General
Partner in August 2000. Mr. Fowler joined the Company 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.
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 2001. The Company believes all of these filings were satisfied by the
General Partner.
Due to administrative and record keeping errors in connection with Unit options
issued by EPCO to certain officers and directors of the General Partner, Form 4
reports were filed in April 2001 by Richard H. Bachmann (one transaction),
Charles E. Crain (one transaction), Michael A. Creel (one transaction), W.
Randall Fowler (one transaction), Michael J. Knesek (one transaction), William
D. Ray (one transaction) and A. Monty Wells (one transaction) with respect to
being granted Unit options in February 2001, and a Form 4 report was filed in
October 2001 by Richard S. Snell (one transaction) with respect to being granted
Unit options in October 2000. Due to record keeping errors, a Form 4 Report was
filed late in October 2001 by O.S. Andras in connection with open market
purchases of our Common Units in September 2001(two transactions).
In April 2001 Form 4 reports were filed by Dan L. Duncan and EPCO with respect
to the issuance of Unit options by EPCO to certain officers and directors of the
General Partner in February 2001.
As of March 1, 2002, 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.
We do not directly employ any of the persons responsible for managing or
operating our businesses. Instead, our businesses are managed by the General
Partner, the executive officers of which are employees of, and the compensation
of whom is paid by, EPCO. In January 2000, we began reimbursing EPCO for our
portion of the compensation EPCO pays individuals it employs as a result of our
expansion activities (through the construction of new facilities, business
acquisitions or the like). In addition, we pay EPCO an annual Administrative
Services Fee to cover a portion of EPCO's total compensation costs for all other
individuals it employs for the management and operation of our businesses.
Currently, the Administrative Services Fee is $16.0 million annually (this
amount is subject to a 10% escalation per year, if so approved by the Audit and
Conflicts Committee). For a more complete discussion of the EPCO Agreement,
including the Administrative Services Fee, see page 59.
The compensation of O.S. Andras, the General Partner's Chief Executive Officer,
is paid solely by EPCO without any reimbursement by us. Of the EPCO employees
serving our General Partner whose compensation is wholly or partially-reimbursed
by us, the four most highly compensated (in terms of our reimbursement) at
December 31, 2001 were A.J. ("Jim") Teague, W. ("Bill") Ordemann, William D. Ray
and Charles E. Crain, collectively the "Named Executive Officers". The
compensation of Mr. Ray and Mr. Crain is reimbursed to EPCO through our payment
of the Administrative Services Fee. The compensation of Mr. Teague and Mr.
Ordemann is wholly reimbursable by us apart from the Administrative Services
Fee. The Named Executive Officers have also received certain equity-based awards
as part of their compensation from EPCO, the expense of which awards are subject
to reimbursement by us to the extent that an individual's compensation is not
reimbursed as part of the Administrative Services Fee. As a result, we will be
responsible for all of the costs associated with the awards granted to Mr.
Teague and Mr. Ordemann. The cost of any awards granted to Mr. Ray and Mr. Crain
will be covered by our payment of the Administrative Services Fee with EPCO
solely bearing any shortfall in reimbursement.
54
The Administrative Services Fee paid to EPCO for the years ended December 31,
2001, 2000 and 1999 was $15.1 million, $13.8 million and $12.5 million. As noted
above, this base amount partially reimbursed EPCO for the costs it incurred in
managing and operating our businesses, including the compensation of Mr. Ray and
Mr. Crain.
The following table sets forth certain compensation information for the
reimbursable, expansion-related Named Executive Officers for the fiscal years
ended December 31, 2001, 2000 and 1999. The information for Mr. Andras has been
omitted since his compensation is wholly-paid by EPCO with no reimbursement by
us. The information for Mr. Ray and Mr. Crain is not included since their
compensation (along with other EPCO employees working on our behalf as discussed
above) is fully reimbursed through the Administrative Services Fee.
Summary Compensation Table
Long Term
Compensation
Annual ----------------
Compensation Securities
Name and -------------------- Underlying All Other
Principal Position Year Salary Bonus Options (#) (4) Compensation (5)
- ------------------------------------ -------------------- ---------------- ----------------
O. S. Andras, 2001 -- -- -- --
Chief Executive Officer (1) 2000 -- -- -- --
1999 -- -- -- --
A. J. ("Jim") Teague, 2001 $ 344,970 $ 80,000 50,000 $10,275
Executive Vice President 2000 $ 322,500 $ 35,000 50,000 $10,200
1999 (3) n/a n/a 50,000 n/a
William D. Ray, 2001 -- -- -- --
Executive Vice President (2) 2000 -- -- -- --
1999 -- -- -- --
Charles E. Crain, 2001 -- -- -- --
Senior Vice President (2) 2000 -- -- -- --
1999 -- -- -- --
W. ("Bill") Ordemann, 2001 $ 179,115 $160,000 (6) 20,000 $10,905
Senior Vice President 2000 $ 156,094 $ 15,000 -- $10,200
1999 (3) n/a n/a 10,000 n/a
________________________________________________________________________________
(1) The information for Mr. Andras has been omitted since his compensation is
wholly-paid by EPCO with no reimbursement by us.
(2) The information for Mr. Ray and Mr. Crain is not included since their
compensation is included in the Administrative Services Fee.
(3) Prior to January 1, 2000, EPCO waived its right to reimbursement from us for
the compensation paid to employees that it had hired in connection with the
expansion of our business. EPCO elected to charge us only the Administrative
Services Fee during 1999; therefore, we did not bear the expense of
reimbursement for the compensation of these individuals.
(4) Although EPCO waived its right to collect reimbursement for the base
salaries, bonuses and other dollar compensation paid to the reimbursable,
expansion-related Named Executive Officers in 1999 (see (3) above), these
individuals received Common Unit Options that were not exercised/exercisable
until after 1999. When the options are ultimately exercised, we will be
responsible for reimbursing EPCO for expenditures associated with these awards.
(5) 2001 and 2000 amounts represent contributions made by EPCO to the 401(K)
plan of the Named Executive Officers.
(6) Mr. Ordemann's 2001 bonuses include a $100,000 retention bonus agreed to
when he joined us in connection with the TNGL acquisition.
55
Common Unit Option Grants During 2001
The following table provides certain information concerning individual grants of
options to purchase Common Units during the fiscal year ended December 31, 2001
to each of the reimbursable, expansion-related Named Executive Officers.
% of Total Potential Realizable
Options Value at Assumed
Number of Granted to Annual Rates of Unit
Securities Expansion Price Appreciation
Underlying Employees in Exercise for Option Term (1)
Options Fiscal Year Price Expiration -------------------------
Name Granted (#) 2001 ($/Unit) Date 5% ($) 10% ($)
- -----------------------------------------------------------------------------------------------------
A. J. ("Jim") Teague 50,000 12.99% $ 31.85 1/31/2010 $ 878,000 $ 2,162,500
W. ("Bill") Ordemann 20,000 5.19% $ 31.85 1/31/2010 $ 351,200 $ 865,000
_______________________________________________________________________________
(1) The amounts shown under these columns are the result of calculations at the
5% and 10% rates required by the SEC and are not intended to forecast future
appreciation of the Common Unit price.
Unit Options Exercised and Fiscal Year-End Values
The following table provides certain information concerning each exercise of
options to purchase Common Units during the fiscal year ended December 31, 2001
by each of the reimbursable, expansion-related Named Executive Officers and the
value of unexercised options as of December 31, 2001:
Number of Value of
Units Securities Underlying Unexercised
Acquired Unexercised Options In-the-Money Options
Through Value at December 31, 2001 at December 31, 2001 (2)
Exercise of Realized ($) ---------------------------- ---------------------------
Name Options (#) (1) Exercisable Unexercisable Exercisable Unexercisable
- -------------------------------------------------------------------------------- ---------------------------
A. J. ("Jim") Teague 50,000 $ 1,137,500 -- 100,000 $ -- $ 1,931,250
W. ("Bill") Ordemann -- $ -- -- 30,000 $ -- $ 594,500
_______________________________________________________________________________
(1) The "Value Realized" represents the difference between the exercise price of
the Common Unit options and the market (sale) price of the Common Units on the
date of exercise without considering any taxes which may have been owed.
(2) The value is based on $47.05 per Common Unit, which was the closing price
reported on the NYSE on December 31, 2001.
56
Compensation of Directors
No additional compensation is paid to employees of EPCO or Shell who also serve
as directors of the General Partner. During fiscal 2001, the three independent
outside directors each received (i) an annual retainer of $18,000, (ii) $1,000
for each meeting of the Board of Directors that they attend and (iii) $500 for
each meeting of the Audit and Conflicts Committee that they attend. In addition,
an annual retainer of $500 is paid to each independent outside director who also
serves as the chairman of a committee of the Board of Directors. These retainers
and fees are an expense of the General Partner. The three independent outside
directors have also been granted options to acquire Common Units. When these are
exercised, the costs will be charged to the General Partner.
We have indemnified each director for his or her actions associated with being a
director of the General Partner 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 1, 2002,
regarding the beneficial ownership of our Common, Subordinated and Special Units
by (i) all persons known by the General Partner to beneficially own more than
five percent of the Common Units, (ii) the directors and certain executive
officers of the General Partner and (iii) all directors, executive and other
officers of the General Partner as a group.
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) 33,640,415 65.1% 21,409,870 100.0% -- 0.0%
Shell (2) 6,000,000 11.6% 0.0% 14,500,000 100.0%
Dan L. Duncan (1,3) 34,965,533 67.7% 21,409,870 100.0% -- 0.0%
O.S. Andras 1,220,600 2.4% -- 0.0% -- 0.0%
Randa Duncan Williams -- 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 (4) 10,000 0.0% -- 0.0% -- 0.0%
Curtis R. Frasier -- 0.0% -- 0.0% -- 0.0%
Lee W. Marshall, Sr. (4) 10,000 0.0% -- 0.0% -- 0.0%
Richard S. Snell 3,100 0.0% -- 0.0% -- 0.0%
Richard H.
Bachmann (5) 43,467 0.1% -- 0.0% -- 0.0%
Michael A. Creel 5,000 0.0% -- 0.0% -- 0.0%
A.J. Teague 26,080 0.1% -- 0.0% -- 0.0%
Charles E. Crain (6) 61,660 0.1% -- 0.0% -- 0.0%
All directors and
executive officers
as a group
(19 persons) (7) 36,412,838 70.5% 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 Duncan
Williams, a director of the General Partner. The address of EPCO and Mr. Duncan
is 2727 North Loop West, Houston, Texas 77008.
(2) The Special Units were issued to Shell US Gas & Power LLC (an affiliate of
Shell) as part of the TNGL acquisition. The address for this affiliate of Shell
is 1301 McKinney, Ste. 700, Houston, Texas 77010.
57
(3) In addition to the Units held by EPCO, Dan Duncan has beneficial ownership
of an additional 1,625,118 Common Units held by the Enterprise Products 1998
Unit Option Plan Trust, Enterprise Products 2000 Rabbi Trust and the EPOLP 1999
Grantor Trust.
(4) Dr. Cunningham's and Mr. Marshall's beneficial ownership amounts represent
options (under an EPCO Unit option plan) to purchase 10,000 Common Units within
60 days of March 21, 2002.
(5) Mr.Bachmann's beneficial ownership amount includes options (under an EPCO
Unit option plan) to purchase 40,000 Common Units within 60 days of March 21,
2002.
(6) Mr.Crain's beneficial ownership amount includes options (under an EPCO Unit
option plan) to purchase 20,000 Common Units within 60 days of March 21, 2002.
(7) Cumulatively, this group includes Common Unit options (under an EPCO Unit
option plan) to purchase 129,061 Common Units within 60 days of March 21, 2002.
For a discussion of our Partners' Equity and Units in general, see Note 7 of the
Notes to the Consolidated Financial Statements. Subordinated Units and Special
Units are non-voting until their conversion in Common Units.
Item 13. Certain Relationships and Related Transactions.
Relationship with EPCO and its affiliates
We have an extensive and ongoing relationship with EPCO and its affiliates. EPCO
is majority-owned and controlled by Dan L. Duncan, Chairman of the Board and a
director of the General Partner. In addition, three other members of the Board
of Directors (O.S. Andras, Randa Duncan Williams and Richard H. Bachmann) and
the remaining executive and other officers (see Item 10 for a listing of these
individuals) of the General Partner are employees of EPCO. The principal
business activity of the General Partner is to act as our managing partner.
Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises
sole voting and dispositive power with respect to the Common and Subordinated
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 Duncan Williams, a director of the General Partner. 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, trust affiliates of EPCO (Enterprise Products 1998 Unit Option Plan
Trust and the Enterprise Products 2000 Rabbi Trust) purchase Common Units for
the purpose of granting options to certain directors of the General Partner,
EPCO management and certain key employees. During 2001, these trusts purchased
211,518 Common Units on the open market or through privately negotiated
transactions. At December 31, 2001, these trusts owned a total of 1,461,518
Common Units. In November 2001, EPCO directly purchased 500,000 Common Units at
market prices for $22.6 million from our consolidated trust, EPOLP 1999 Grantor
Trust, on behalf of a key executive and Director of the General Partner.
Our 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.
58
EPCO Agreement
As stated previously, we have no employees. All of our management,
administrative and operating functions are performed by employees of EPCO
pursuant to the EPCO Agreement (in effect since July 1998). Under the terms of
the EPCO Agreement, EPCO agreed to:
. employ the personnel necessary to manage our business and affairs
(through the General Partner);
. employ the operating personnel involved in our business for which we
reimburse EPCO at cost (based upon EPCO's actual salary costs and
related fringe benefits);
. allow us 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;
. grant an irrevocable, non-exclusive worldwide license to all of the
EPCO trademarks and trade names used our business;
. indemnify us against any losses resulting from certain lawsuits; and
. 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 us for one dollar
per year and to assign its purchase option under such leases to us.
EPCO remains liable for the lease payments associated with these
assets.
Operating costs and expenses (as shown in the audited Statements of Consolidated
Operations) treat the full amount of lease payments being made by EPCO as a
non-cash operating expense (with the offset to Partners' Equity on the
Consolidated Balance Sheet). In addition, operating costs and expenses include
compensation charges for EPCO's employees who operate the facilities.
Pursuant to the EPCO Agreement, we reimburse EPCO for our portion of the costs
of certain of its employees who manage our business and affairs. In general, our
reimbursement of EPCO's expense associated with administrative positions that
were active at the time of our initial public offering in July 1998 is capped by
the Administrative Services Fee that we pay (currently at $16 million annually).
The General Partner, with the approval and consent of the Audit and Conflicts
Committee, may agree to annual increases of such fee up to ten percent per year
during the 10-year term of the EPCO Agreement. Any difference between the actual
costs of this "pre-expansion" group (including those associated with
equity-based awards granted to certain individuals within this group) and the
Administrative Services Fee will be retained by EPCO (i.e., EPCO solely bears
any shortfall in reimbursement for this group).
Beginning in January 2000, we began reimbursing EPCO for our share of the
compensation of administrative personnel that it had hired in response to our
expansion and business development activities (through the construction of new
facilities, business acquisitions or the like). EPCO began hiring "expansion"
administrative personnel after our initial public offering in connection with
the TNGL acquisition and other development activities. In general, we reimburse
EPCO for our share of its compensation expense associated with these "expansion"
administrative positions, including those costs attributable to equity-based
awards.
The following table summarizes of the Administrative Services Fee paid to EPCO
during the last three years. In addition, the table shows the total compensation
reimbursed to EPCO for operations personnel and "expansion" administrative
positions.
For Year Ended December 31,
---------------------------------
2001 2000 1999
---------------------------------
(in millions of dollars)
Administrative Services Fee
paid to EPCO $ 15,125 $ 13,750 $ 12,500
Compensation reimbursed to EPCO 48,507 44,717 26,889
---------------------------------
Total $ 63,632 $ 58,467 $ 39,389
=================================
The Administrative Services Fee has increased each year from its initial $12.0
million per annum rate with the approval of the Audit and Conflicts Committee as
prescribed in the EPCO Agreement. The increase in
59
reimbursable compensation payments made to EPCO is primarily the result of the
TNGL (1999) and Acadian Gas (2001) acquisitions. EPCO waived the reimbursement
of "expansion" administrative personnel compensation through December 1999. As
noted earlier, we began reimbursing EPCO for the employment costs of the
"expansion" administrative employees beginning in January 2000, hence the
significant increase for this line item in the table between 1999 and 2000.
We elected to prepay EPCO a discounted amount of $15.7 million for the 2002
Administrative Services Fee in December 2001 (the undiscounted amount was $16.0
million). We will owe EPCO for any undiscounted amount above the $16.0 million
if the General Partner approves an increase in the fee during 2002.
Other related party transactions with EPCO or its affiliates
The following is a summary of the other ongoing significant relationships and
transactions between us and EPCO and or 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 $0.8 million in management fees to EPCO during 2001.
. We have entered into an agreement with EPCO to provide trucking
services to us for the loading and transportation of NGL products.
During 2001, we paid $9.0 million for these services.
. In the normal course of business, we may, on occasion, engage in
transactions with EPCO involving the buying and selling of NGL
products. We did not record any such transactions with EPCO during
2001.
Relationships with Shell
We have an extensive and ongoing relationship with Shell as a partner, customer
and vendor. Shell, through its subsidiary Shell US Gas & Power LLC, owns
approximately 23.2% of our partnership interests and 30.0% of the General
Partner. Currently, 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 our Processing segment (see page 14 for a
discussion of the 20-year Shell Processing Agreement). Apart from operating
expenses arising from the Shell Processing Agreement, the Company also sells NGL
and petrochemical products to Shell. During 2001, revenues from Shell aggregated
$333.3 million while purchases from Shell totaled $705.4 million.
Shell accounted for 10.5% of consolidated revenues in 2001 (up from 9.5% of
consolidated revenues in 2000). Approximately 80% of our revenues from Shell
during 2001 and 2000 are attributable to the sale of NGL products as recorded in
our Processing segment. See Note 10 of the Notes to the Consolidated Financial
Statements for additional information regarding related party transactions.
In April 2001, we acquired Acadian Gas from Shell from approximately $226
million in an arms-length negotiated transaction (through a bidding process)
that was approved by the Board of Directors of the General Partner, with the
three Shell representatives abstaining. See page 8 for a discussion of the
assets involved in this acquisition.
In January 2001, we purchased equity interests in four Gulf of Mexico natural
gas pipeline systems (Stingray, Manta Ray, Nautilus and Nemo) from El Paso.
Shell also owns equity interests in and operates and/or administers each of
these pipelines. During 2001, our portion of the management and operating fees
for these pipeline systems paid to Shell was $0.8 million. See page 8 for a more
detailed discussion of these pipeline systems.
60
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 as of September 22, 2000. (Exhibit 10.1 to
Form 8-K filed on September 26, 2000).
2.2 Purchase and Sale Agreement dated as of January 16, 2002 by and between
Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas
Operating L.P. (Exhibit 10.1 to Form 8-K filed February 8, 2002).
2.3 Purchase and Sale Agreement dated as of January 31, 2002 by and between D-K
Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as
Sellers, and Enterprise Products Operating L.P., as Buyer. (Exhibit 10.2 to
Form 8-K filed February 8, 2002).
3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise
Products Operating L.P. (Exhibit 3.2 to Registration Statement of 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 by and 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 "B" to the
Schedule 13 D 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 13
D 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).
61
4.6 Form of Global Note representing $350 million principal amount of 8.25%
Senior Notes due 2005 (the "Senior Notes A"). (Exhibit 4.2 on Form 8-K
filed March 10, 2000).
4.7 $250 million Multi-Year Revolving Credit Agreement (the "Multi-Year Credit
Facility") among Enterprise Products Operating L.P., 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 4.2 on Form
8-K filed January 25, 2001).
4.8 $150 Million 364-Day Revolving Credit Agreement (the "364-Day Credit
Facility") among 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 Multi-Year Credit Facility) 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 364-Day Credit Facility) 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 (the "Senior Notes B"). (Exhibit 4.1 to Form 8-K
filed January 25, 2001).
4.12 First Amendment to Multi-Year Credit Facility dated April 19, 2001.
(Exhibit 4.12 to Form 10-Q filed May 14, 2001).
4.13*First Amendment to 364-Day Credit Facility dated November 6, 2001,
effective as of November 16, 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 among 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 among 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 among 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).
62
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,
filed on May 13, 1998).
10.8 Restated Operating Agreement for the Mont Belvieu Fractionation
Facilities Chambers County, Texas among 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 among Enterprise Products Company, Texaco Producing Inc., El
Paso Hydrocarbons Company, Champlin Petroleum Company and Mont Belvieu
Associates dated July 17, 1985. (Exhibit 10.11 to Registration Statement
on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
10.10 Amendment to Propylene Facility and Pipeline Agreement and Propylene
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 and Propylene
Sales 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 among 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).
10.13 Fifth Amendment to Conveyance of Gas Processing Rights dated as of April
1, 2001 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell
Exploration & Production Company, Shell Offshore, Inc., Shell
Consolidated Energy Resources, Inc., Shell Land & Energy Company and
Shell Frontier Oil & Gas, Inc. (Exhibit 10.13 to Form 10-Q filed on
August 13, 2001).
10.14 Enterprise Products Company 1998 Long-Term Incentive Plan (Exhibit 10.1
to Registration Statement on Form S-8, File No. 333-36856, filed on May
12, 2000).
10.15 Enterprise Products GP, LLC 1999 Long-Term Incentive Plan (Exhibit 10.2
to Registration Statement on Form S-8, File No. 333-36856, filed on May
12, 2000).
10.16 Form of Option Agreement under the 1998 Long-Term Incentive Plan and the
1999 Long-Term Incentive Plan (Exhibit 10.3 to the Registration Statement
on Form S-8, File No. 333-36856, filed on May 12, 2000).
12.1* Computation of ratio of earnings to fixed charges for each of the five
years ended December 31, 2001, 2000, 1999, 1998 and 1997.
21.1* List of subsidiaries.
23.1* Consent of Deloitte & Touche.
* An asterisk indicates that an exhibit is filed in conjunction with this
report. All other documents are incorporated by reference as indicated in
their descriptions.
63
(b) Reports on Form 8-K
Form 8-K filed November 13, 2001. In accordance with Regulation FD, we notified
our investors and the SEC that representatives of our General Partner were to
make a presentation to equity analysts and others on November 13, 2001
concerning the Company. We noted that interested parties could view the
presentation materials on our website, www.epplp.com
-------------
64
INDEX TO FINANCIAL STATEMENTS
Page
Enterprise Products Partners L.P.
Independent Auditors' Report F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000 F-3
Statements of Consolidated Operations
for the Years Ended December 31, 2001, 2000 and 1999 F-4
Statements of Consolidated Cash Flows
for the Years Ended December 31, 2001, 2000 and 1999 F-5
Statements of Consolidated Partners' Equity
for the Years Ended December 31, 2001, 2000 and 1999 F-6
Notes to Consolidated Financial Statements F-7
Supplemental Schedule
Schedule II - Valuation and Qualifying Accounts
All schedules, except the one listed above, have been omitted because they are
either not applicable, not required or the information called for therein
appears in the consolidated financial statements or notes thereto.
F-1
Independent Auditors' Report
Enterprise Products Partners L.P.:
We have audited the accompanying consolidated balance sheets of Enterprise
Products Partners L.P. and subsidiaries (the "Company") as of December 31, 2001
and 2000, 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, 2001. 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 Company's management. 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, 2001 and 2000, 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, 2001 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.
As discussed in Note 13 to the consolidated financial statements, the Company
changed its method of accounting for derivative instruments in 2001.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 8, 2002
F-2
ENTERPRISE PRODUCTS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
December 31,
-------------------------
ASSETS 2001 2000
-------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of
$5,752 at December 31, 2001) $ 137,823 $ 60,409
Accounts receivable - trade, net of allowance for doubtful accounts of
$20,642 at December 31, 2001 and $10,916 at December 31, 2000 256,927 409,085
Accounts receivable - affiliates 4,375 6,533
Inventories 69,443 93,222
Prepaid and other current assets 50,207 12,107
-------------------------
Total current assets 518,775 581,356
Property, Plant and Equipment, Net 1,306,790 975,322
Investments in and Advances to Unconsolidated Affiliates 398,201 298,954
Intangible assets, net of accumulated amortization of $13,084 at
December 31, 2001 and $5,374 at December 31, 2000 202,226 92,869
Other Assets 5,201 2,867
-------------------------
Total $ 2,431,193 $ 1,951,368
=========================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $ 54,269 $ 96,559
Accounts payable - affiliates 29,885 56,447
Accrued gas payables 233,536 377,126
Accrued expenses 22,460 21,488
Accrued interest 24,302 10,068
Other current liabilities 44,764 24,691
-------------------------
Total current liabilities 409,216 586,379
Long-Term Debt 855,278 403,847
Other Long-Term liabilities 8,061 15,613
Minority Interest 11,716 9,570
Commitments and Contingencies
Partners' Equity
Common Units (51,360,915 Units outstanding at December 31, 2001 and
46,257,315 at December 31, 2000) 651,872 514,896
Subordinated Units (21,409,870 Units outstanding at December 31, 2001
and December 31, 2000) 193,107 165,253
Special Units (14,500,000 Units outstanding at December 31, 2001 and
16,500,000 at December 31, 2000) 296,634 251,132
Treasury Units acquired by Trust, at cost (163,600 Common Units outstanding
at December 31, 2001 and 267,200 at December 31, 2000) (6,222) (4,727)
General Partner 11,531 9,405
-------------------------
Total Partners' Equity 1,146,922 935,959
-------------------------
Total $ 2,431,193 $ 1,951,368
=========================
See Notes to Consolidated Financial Statements
F-3
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
(Dollars in thousands, except per Unit amounts)
For Year Ended December 31,
---------------------------------------
2001 2000 1999
---------------------------------------
REVENUES
Revenues from consolidated operations $ 3,154,369 $ 3,049,020 $ 1,332,979
Equity income in unconsolidated affiliates 25,358 24,119 13,477
---------------------------------------
Total 3,179,727 3,073,139 1,346,456
COST AND EXPENSES
Operating costs and expenses 2,861,743 2,801,060 1,201,605
Selling, general and administrative 30,296 28,345 12,500
---------------------------------------
Total 2,892,039 2,829,405 1,214,105
---------------------------------------
OPERATING INCOME 287,688 243,734 132,351
---------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (52,456) (33,329) (16,439)
Interest income from unconsolidated affiliates 31 1,787 1,667
Dividend income from unconsolidated affiliates 3,462 7,091 3,435
Interest income - other 7,029 3,748 886
Other, net (1,104) (272) (379)
---------------------------------------
Other income (expense) (43,038) (20,975) (10,830)
---------------------------------------
INCOME BEFORE MINORITY INTEREST 244,650 222,759 121,521
MINORITY INTEREST (2,472) (2,253) (1,226)
---------------------------------------
NET INCOME $ 242,178 $ 220,506 $ 120,295
=======================================
ALLOCATION OF NET INCOME TO:
Limited partners $ 236,570 $ 217,909 $ 119,092
=======================================
General partner $ 5,608 $ 2,597 $ 1,203
=======================================
BASIC EARNINGS PER UNIT
Income before minority interest $ 3.43 $ 3.28 $ 1.80
=======================================
Net income per Common and Subordinated unit $ 3.39 $ 3.25 $ 1.79
=======================================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 2.80 $ 2.67 $ 1.65
=======================================
Net income per Common, Subordinated
and Special unit $ 2.77 $ 2.64 $ 1.64
=======================================
See Notes to Consolidated Financial Statements
F-4
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)
For Year Ended December 31,
---------------------------------
2001 2000 1999
---------------------------------
OPERATING ACTIVITIES
Net income $ 242,178 $ 220,506 $ 120,295
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 51,903 41,045 25,315
Equity in income of unconsolidated affiliates (25,358) (24,119) (13,477)
Distributions received from unconsolidated affiliates 45,054 37,267 6,008
Leases paid by EPCO 10,309 10,537 10,557
Minority interest 2,472 2,253 1,226
Loss (gain) on sale of assets (390) 2,270 123
Changes in fair market value of financial instruments (see Note 13) (5,697)
Net effect of changes in operating accounts (37,143) 71,111 27,906
---------------------------------
Operating activities cash flows 283,328 360,870 177,953
---------------------------------
INVESTING ACTIVITIES
Capital expenditures (149,896) (243,913) (21,234)
Proceeds from sale of assets 568 92 8
Business acquisitions, net of cash received (225,665) (208,095)
Collection of notes receivable from unconsolidated affiliates 6,519 19,979
Investments in and advances to unconsolidated affiliates (116,220) (31,496) (61,887)
---------------------------------
Investing activities cash flows (491,213) (268,798) (271,229)
---------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 449,717 598,818 350,000
Long-term debt repayments (490,000) (154,923)
Debt issuance costs (3,125) (4,043) (3,135)
Cash distributions paid to partners (164,308) (139,577) (111,758)
Cash distributions paid to minority interest by Operating Partnership (1,687) (1,429) (1,140)
Unit repurchased and retired (770)
Cash contributions from EPCO to minority interest 105 108 86
Treasury Units purchased by Trust (18,003) (4,727)
Treasury Units reissued by Trust 22,600
Increase in restricted cash (5,752)
---------------------------------
Financing activities cash flows 279,547 (36,893) 74,403
---------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 71,662 55,179 (18,873)
CASH AND CASH EQUIVALENTS, JANUARY 1 60,409 5,230 24,103
---------------------------------
CASH AND CASH EQUIVALENTS, DECEMBER 31 $ 132,071 $ 60,409 $ 5,230
=================================
See Notes to Consolidated Financial Statements
F-5
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY
(Dollars in thousands)
Limited Partners
--------------------------------
Common Subord. Special Treasury General
Units Units Units Units Partner Total
--------------------------------------------------------------------
Balance, 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 Shell
in connection with TNGL
acquisition $210,436 2,126 212,562
Cash distributions
to Unitholders (81,993) (28,647) (1,118) (111,758)
Treasury Units acquired by
consolidated Trust $ (4,727) (4,727)
--------------------------------------------------------------------
Balance, 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 Shell in
connection with
contingency agreement 55,241 557 55,798
Conversion of 1.0 million
Shell 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)
--------------------------------------------------------------------
Balance, December 31, 2000 514,896 165,253 251,132 (4,727) 9,405 935,959
Net income 163,795 72,775 5,608 242,178
Leases paid by EPCO 7,078 3,128 103 10,309
Additional Special Units
issued to Shell in
connection with
contingency agreement 117,066 1,183 118,249
Conversion of 5.0 million
Shell Special Units into
Common Units 72,554 (72,554)
Cash distributions
to Unitholders (109,969) (49,510) (4,829) (164,308)
Treasury Units acquired by
consolidated Trust (18,003) (18,003)
Treasury Units reissued by
consolidated Trust 16,508 16,508
Gain on reissuance of Treasury
Units by consolidated Trust 3,518 1,461 990 61 6,030
--------------------------------------------------------------------
Balance, December 31, 2001 $ 651,872 $ 193,107 $296,634 $ (6,222) $ 11,531 $ 1,146,922
====================================================================
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. including its consolidated subsidiaries is a
publicly-traded Delaware limited partnership listed on the New York Stock
Exchange under symbol "EPD". Unless the context requires otherwise, references
to "we","us","our" or the "Company" are intended to mean Enterprise Products
Partners L.P. and subsidiaries. We (including our 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"). We conduct substantially all of our
business through the Operating Partnership, in which we own 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. We and the General Partner are affiliates of
EPCO.
Prior to their consolidation, EPCO and its affiliate 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 our
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, we became the successor
to the NGL operations of EPCO.
Effective July 27, 1998, we filed a registration statement pursuant to an
initial public offering of 12,000,000 Common Units. The Common Units sold for
$22 per unit. We received approximately $243.3 million net of underwriting
commissions and offering costs.
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 our accounts and those of
our majority-owned subsidiaries, after elimination of all material intercompany
accounts and transactions. In general, investments in which we own 20% to 50%
and exercise significant influence over operating and financial policies are
accounted for using the equity method. Investments in which we own less than 20%
are accounted for using the cost method unless we exercise 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, we
consider all highly liquid investments with an original maturity of less than
three months at the date of purchase to be cash equivalents.
FINANCIAL 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. We are required to recognize
in earnings changes in fair value of these financial instruments that are not
offset by changes in the fair value of the inventories, firm commitments and
certain anticipated transactions. Fair value is generally defined as the amount
at which the financial instrument could be exchanged in a current transaction
between willing parties, not in a forced or liquidation sale.
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 us to commodity or interest
F-7
rate risk and the hedging instrument must reduce that exposure and meet the
hedging requirements of SFAS No. 133. Any contracts held or issued that do not
meet the requirements of a hedge (as defined by SFAS No. 133) will be recorded
at fair value on the balance sheet and any changes in that fair value recognized
in earnings (using mark-to-market accounting). 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 our 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
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, Subordinated 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 cash distributions until they are
converted to 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 the 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, 2001 were not significant to the consolidated
financial statements. Costs of environmental compliance and monitoring
aggregated $1.3 million, $1.3 million and $0.9 million for the years ended
December 31, 2001, 2000 and 1999, respectively. Our estimated liability for
environmental remediation is not discounted.
EXCESS COST OVER UNDERLYING EQUITY IN NET ASSETS (or "excess cost") denotes the
excess of our cost (or purchase price) over our underlying equity in the net
assets of our investees. We have excess cost associated with our investments in
K/D/S Promix L.L.C., Dixie Pipeline Company, Neptune Pipeline Company L.L.C. and
Nemo Pipeline Company, LLC. The excess cost of these investments is reflected in
our 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 and petrochemical products and natural gas
between parties to satisfy timing and logistical needs of the parties. Volumes
borrowed from us under such agreements are included in inventory, and volumes
loaned to us under such agreements are accrued as a liability in accrued gas
payables.
FEDERAL INCOME TAXES are not provided because we are a master limited
partnership. As a result, our 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 our financial statements. State
income taxes are not material to us. 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.
INVENTORIES are valued at the lower of average cost or market (normal trade
inventories of natural gas, NGLs and petrochemicals) or using specific
identification (volumes dedicated to forward sales contracts).
INTANGIBLE ASSETS include the values assigned to a 20-year natural gas
processing agreement and the excess cost of the purchase price over the fair
market value of the assets acquired from Mont Belvieu Associates (the "MBA
excess cost"), both of which were initially recorded in 1999. Of the intangible
values at December 31, 2001, $194.4 million is assigned to the natural gas
processing agreement and is being amortized on a straight-line basis over the
contract term.
F-8
The remaining $7.9 million balance of intangibles relates to the MBA excess cost
which has been amortized on a straight-line basis over 20 years. Upon adoption
of SFAS No. 142 on January 1, 2002, this amount was reclassified to goodwill and
will no longer be amortized but will be subject to periodic impairment testing
in accordance with the new standard. For additional information regarding this
reclassification and other details pertaining to the adoption of SFAS No. 142,
see Note 5.
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. We have 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. 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.
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. These expenditures result in
a long-term benefit to the Company. We generally classify improvements and major
renewals of existing assets as sustaining capital expenditures and all other
capital spending on existing and new assets referred to as expansion capital
expenditures.
RESTRICTED CASH includes amounts held by a brokerage firm as margin deposits
associated with our financial instruments portfolio and for physical purchase
transactions made on the NYMEX exchange. At December 31, 2001, cash and cash
equivalents includes $5.8 million of restricted cash related to these
requirements.
REVENUE is recognized by our five reportable business segments using the
following criteria: (i) persuasive evidence of an exchange arrangement exists,
(ii) delivery has occurred or services have been rendered, (iii) the buyer's
price is fixed or determinable and (iv) 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 our Fractionation segment, we enter into NGL fractionation, isomerization and
propylene fractionation tolling arrangements, NGL fractionation in-kind
contracts and propylene fractionation merchant contracts. Under our tolling
arrangements, we recognize revenue once contract services have been performed.
These tolling 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 of fractionation and isomerization
operations. At our Norco NGL fractionation facility, certain tolling
arrangements involves the retention of a contractually-determined percentage of
the NGLs produced for the processing customer in lieu of a cash tolling fee per
gallon (i.e., an "in-kind" fee). We recognize revenue from these in-kind
contracts when we sell (at market-related prices) and deliver the NGLs retained
by our fractionator to customers. In our propylene fractionation merchant
contracts, we recognize revenue once the products have been delivered to the
customer. These merchant contracts are based upon market-related prices as
determined by the individual contracts.
In our Pipelines segment, we enter into pipeline, storage and product loading
contracts. Under our liquids pipeline and certain natural gas pipeline
throughput contracts, revenue is recognized when volumes have been physically
delivered for the customer through the pipeline. Revenue from this type of
throughput contract is typically based upon a fixed fee per gallon of liquids or
MMBtus of natural gas transported, whichever the case may be, multiplied by the
volume delivered. The throughput fee is generally contractual or as regulated by
the Federal Energy Regulatory Commission ("FERC"). Additionally, we have
merchant contracts associated with our natural gas pipeline business whereby
revenue is recognized once a quantity of natural gas has been delivered to a
customer. These merchant contracts are based upon market-related prices as
determined by the individual contracts.
In our storage contracts, we collect a fee based on the number of days a
customer has NGL or petrochemical volumes in storage multiplied by a storage
rate for each product. Under these contracts, revenue is recognized ratably over
the length of the storage contract based on the storage rates specified in each
contract. Revenues from
F-9
product loading contracts (applicable to EPIK, an unconsolidated affiliate of
the Company) are recorded once the loading services have been performed with the
loading rates stated in the individual contracts.
As part of our Processing business, we have entered into a significant 20-year
natural gas processing agreement with Shell ("Shell Processing Agreement"),
whereby we have the right to process Shell's current and future natural gas
production (including deepwater developments) from the Gulf of Mexico within the
state and federal waters off Texas, Louisiana, Mississippi, Alabama and Florida.
In addition to the Shell Processing Agreement, we have contracts to process
natural gas for other customers.
Under these contracts, the fee for our natural gas processing services is based
upon contractual terms with Shell or other third parties and may be specified as
either a cash fee or 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, we record revenue once the natural gas has been processed and sent
back to Shell or other third parties (i.e., delivery has taken place).
If the contract stipulates that we retain a percentage of the NGLs extracted as
payment for its services, revenue is recorded when the NGLs are sold and
delivered to third parties. The Processing segment's merchant activities may
also buy and sell NGLs in the open market (including forward sales contracts).
The revenues recorded for these contracts are recognized upon the delivery of
the products specified in each individual contract. Pricing under both types of
arrangements is based upon market-related prices plus or minus other determining
factors specific to each contract such as location pricing differentials.
The Octane Enhancement segment consists of our 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 is obligated to purchase all of the facility's MTBE
output at market-related prices through September 2004. Revenue is recognized
once the product has been delivered to Sun.
The Other segment is primarily comprised of fee-based marketing services. We
perform NGL marketing services for a small number of customers for which we
charge 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
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. Our actual results could differ from these
estimates.
2. BUSINESS ACQUISITIONS
Acquisition of Acadian Gas in April 2001
On April 2, 2001, we acquired Acadian Gas from an affiliate of Shell, for
approximately $226 million in cash using proceeds from the issuance of the $450
million Senior Notes B (see Note 6). Acadian Gas is involved in the purchase,
sale, transportation and storage of natural gas in Louisiana. Its assets are
comprised of the 438-mile Acadian and 577-mile Cypress natural gas pipelines and
a leased natural gas storage facility. Acadian Gas owns an approximate 49.5% of
Evangeline which owns a 27-mile natural gas pipeline. We operate the systems.
Overall, the Acadian Gas and Evangeline systems are comprised of 1,042 miles of
pipeline with an optimal design capacity of 1.1 Bcf/d.
The Acadian Gas and Evangeline systems link supplies of natural gas from Gulf of
Mexico production (through connections with offshore pipelines) and various
onshore developments to industrial, electrical and local distribution customers
primarily located in Louisiana. In addition, these systems have interconnects
with twelve interstate and four intrastate pipelines and a bi-directional
interconnect with the U.S. natural gas marketplace at the Henry Hub.
F-10
The Acadian Gas acquisition was accounted for under the purchase method of
accounting and, accordingly, the initial purchase price has been allocated to
the assets acquired and liabilities assumed based on their estimated fair values
at April 1, 2001 as follows (in millions):
Current assets $ 83,123
Investments in unconsolidated affiliates 2,723
Property, plant and equipment 225,169
Current liabilities (83,890)
Other long-term liabilities (1,460)
---------
Total purchase price $ 225,665
=========
The balances related to the Acadian Gas acquisition included in the consolidated
balance sheet dated December 31, 2001 are based upon preliminary information and
are subject to change as additional information is obtained. The initial
purchase price is subject to certain post-closing adjustments attributable to
working capital items and is expected to be finalized during the first half of
2002.
Historical information for periods prior to April 1, 2001 do not reflect any
impact associated with the Acadian Gas acquisition.
Pro forma effect of business combinations
The following table presents selected unaudited pro forma information for the
years ended December 31, 2001 and 2000 as if the acquisition of Acadian Gas had
been made as of the beginning of the years presented. This table also
incorporates selected unaudited pro forma information for the year ended
December 31, 2000 relating to our equity investments in Starfish and Neptune
(see Note 4).
The pro forma information is based upon data currently available to and certain
estimates and assumptions by management and, as a result, are not necessarily
indicative of our financial results had the transactions actually occurred on
these dates. Likewise, the unaudited pro forma information is not necessarily
indicative of our future financial results.
For Year Ended December 31,
---------------------------
2001 2000
---------------------------
Revenues $3,391,654 $3,673,049
Income before extraordinary item
and minority interest $ 248,934 $ 217,223
Net income $ 246,419 $ 215,026
Allocation of net income to
Limited partners $ 240,745 $ 212,483
General Partner $ 5,674 $ 2,542
Units used in earnings per Unit calculations
Basic 69,726 67,108
Diluted 85,393 82,444
Income per Unit before minority interest
Basic $ 3.49 $ 3.20
Diluted $ 2.85 $ 2.60
Net income per Unit
Basic $ 3.45 $ 3.17
Diluted $ 2.82 $ 2.58
F-11
3. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation are as follows:
Estimated
Useful Life
In Years 2001 2000
-------------------------------------
Plants and pipelines 5-35 $1,398,843 $1,108,519
Underground and other storage facilities 5-35 127,900 109,760
Transportation equipment 3-35 3,736 2,620
Land 15,517 14,805
Construction in progress 98,844 34,358
-----------------------
Total 1,644,840 1,270,062
Less accumulated depreciation 338,050 294,740
-----------------------
Property, plant and equipment, net $1,306,790 $ 975,322
=======================
Depreciation expense for the years ended December 31, 2001, 2000 and 1999 was
$43.4 million, $33.3 million and $22.4 million, respectively. The increase in
depreciation expense is primarily due to acquisitions and expansion capital
projects over the last three years.
4. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
We own interests in a number of related businesses that are accounted for under
the equity 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 our operating segments, see Note
15.
The following table shows investments in and advances to unconsolidated
affiliates at:
December 31,
-------------------
2001 2000
-------------------
Accounted for on equity basis:
Fractionation:
BRF $ 29,417 $ 30,599
BRPC 18,841 25,925
Promix 45,071 48,670
Pipeline:
EPIK 14,280 15,998
Wilprise 8,834 9,156
Tri-States 26,734 27,138
Belle Rose 11,624 11,653
Dixie 37,558 38,138
Starfish 25,352
Neptune 76,880
Nemo 12,189
Evangeline 2,578
Octane Enhancement:
BEF 55,843 58,677
Accounted for on cost basis:
Processing:
VESCO 33,000 33,000
-------------------
Total $398,201 $298,954
===================
F-12
The following table shows equity in income (loss) of unconsolidated affiliates
for the year ended December 31:
For Year Ended December 31,
--------------------------------
2001 2000 1999
--------------------------------
Fractionation:
BRF $ 1,583 $ 1,369 $ (336)
BRPC 1,161 (284) 16
Promix 4,201 5,306 630
Other 1,256
Pipeline:
EPIK 345 3,273 1,173
Wilprise 472 497 160
Tri-States 1,565 2,499 1,035
Belle Rose 103 301 (29)
Dixie 2,092 751
Starfish 4,122
Ocean Breeze 32
Neptune 4,081
Nemo 75
Evangeline (145)
Other 1,389
Octane Enhancement:
BEF 5,671 10,407 8,183
--------------------------------
Total $ 25,358 $ 24,119 $ 13,477
================================
At December 31, 2001, our share of accumulated earnings of equity method
unconsolidated affiliates that had not been remitted to us was approximately
$7.0 million.
Fractionation segment:
At December 31, 2001, the Fractionation segment included the following
unconsolidated affiliates accounted for using the equity method:
. Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in
an 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.
. K/D/S Promix LLC ("Promix") - a 33.33% interest in an NGL fractionation
facility and related storage assets located in south Louisiana. Our
investment includes excess cost over the underlying equity in the net
assets of Promix of $8.0 million. The excess cost, which relates to plant
assets, is being amortized against our share of Promix's earnings over a
period of 20 years, which is the estimated useful life of the plant assets
that gave rise to the difference. The unamortized balance of excess cost
was $7.0 million at December 31, 2001.
The combined balance sheet information for the last two years and results of
operations data for the last three years of the Fractionation segment's equity
method investments are summarized below. As used in the following tables, gross
operating margin for equity investments represents operating income before
depreciation and amortization expense (both on operating assets) and selling,
general and administrative costs.
F-13
As Of or For The
Year Ended December 31,
-----------------------------
2001 2000 1999
-----------------------------
BALANCE SHEET DATA:
Current Assets $ 27,424 $ 31,168
Property, plant and equipment, net 251,519 264,618
Other assets 67
-------------------
Total assets $278,943 $295,853
===================
Current liabilities $ 9,950 $ 13,661
Combined equity 268,993 282,192
-------------------
Total liabilities and combined equity $278,943 $295,853
===================
INCOME STATEMENT DATA:
Revenues $ 76,480 $ 71,287 $36,293
Gross operating margin 36,321 33,240 14,970
Operating income 22,396 19,997 5,930
Net income 22,738 20,661 4,200
Pipelines segment:
At December 31, 2001, our Pipelines operating segment included the following
unconsolidated affiliates 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. We own 50% of EPIK Gas
Liquids, LLC which owns 1% of such facilities. We do not exercise control
over these entities; therefore, we are precluded from consolidating such
entities into our financial statements.
. Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in an NGL
pipeline system located in southeastern Louisiana.
. Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% interest
in an NGL pipeline system located in Louisiana, Mississippi and Alabama.
. Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.67% interest in an NGL
pipeline system located in south Louisiana.
. Dixie Pipeline Company ("Dixie") - an aggregate 19.88% interest in a
1,301-mile propane pipeline and associated facilities extending from Mont
Belvieu, Texas to North Carolina. Our investment includes excess cost over
the underlying equity in the net assets of Dixie of $37.4 million. The
excess cost, which relates to pipeline assets, is being amortized against
our share of Dixie's earnings over a period of 35 years, which is the
estimated useful life of the pipeline assets that gave rise to the
difference. The unamortized balance of excess cost over the underlying
equity in the net assets of Dixie was $35.7 million at December 31, 2001.
. Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural
gas gathering system and related dehydration and other facilities located
in south Louisiana and the Gulf of Mexico offshore Louisiana.
. Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in the natural
gas gathering and transmission systems owned by Manta Ray Offshore
Gathering Company, LLC and Nautilus Pipeline Company LLC located in the
Gulf of Mexico offshore Louisiana.
. Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas
gathering system located in the Gulf of Mexico offshore Louisiana that
became operational in August 2001.
. Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp.
(collectively, "Evangeline") - an approximate 49.5% aggregate interest in a
natural gas pipeline system located in south Louisiana. We acquired our
interest in Evangeline as a result of the Acadian Gas acquisition (see Note
2 for a description of this acquisition).
F-14
The combined balance sheet information for the last two years and results of
operations data for the last three years of the Pipelines segment's equity
method investments are summarized below:
As Of or For The
Year Ended December 31,
-----------------------------
2001 2000 1999
-----------------------------
BALANCE SHEET DATA:
Current Assets $ 68,325 $ 25,464
Property, plant and equipment, net 515,327 188,724
Other assets 50,265 3,666
-------------------
Total assets $633,917 $217,854
===================
Current liabilities $ 62,347 $ 31,085
Other liabilities 57,965 4,018
Combined equity 513,605 182,751
-------------------
Total liabilities and combined equity $633,917 $217,854
===================
INCOME STATEMENT DATA:
Revenues $305,404 $ 96,270 $52,386
Gross operating margin 98,682 51,414 24,845
Operating income 54,459 41,757 19,988
Net income 41,015 31,241 15,637
Equity investments in Gulf of Mexico natural gas pipeline systems in January
2001
On January 29, 2001, we acquired a 50% equity interest in Starfish which owns
the Stingray natural gas pipeline system and a related natural gas dehydration
facility. The Stingray system is a 379-mile, FERC-regulated natural gas pipeline
system that transports natural gas and condensate from certain production areas
located in the Gulf of Mexico offshore Louisiana to onshore transmission systems
located in south Louisiana. The natural gas dehydration facility is connected to
the onshore terminal of the Stingray system in south Louisiana. The optimal
design capacity of the Stingray pipeline is 1.2 Bcf/d. Shell is the operator of
these systems and owns the remaining equity interests in Starfish.
In addition to Starfish, we acquired a 25.67% interest in Ocean Breeze Pipeline
Company ("Ocean Breeze") and Neptune and a 33.92% interest in Nemo. Ocean Breeze
and Neptune collectively owned the Manta Ray and Nautilus natural gas pipeline
systems located in the Gulf of Mexico offshore Louisiana. The Manta Ray system
comprises approximately 235 miles of unregulated pipelines and related equipment
with an optimal design capacity of 0.75 Bcf/d and the Nautilus system comprises
approximately 101 miles of FERC-regulated pipelines with an optimal design
capacity of 0.6 Bcf/d. The Nemo system, which became operational in August 2001,
comprises 24-mile natural gas pipeline with an optimal design capacity of 0.3
Bcf/d. Like Stingray, Shell is the operator of the Manta Ray and Nemo systems.
Shell is the administrative agent for Nautilus.. In November 2001, Ocean Breeze
was merged into Neptune with the Company retaining its 25.67% interest in
Neptune. Shell and Marathon are the co-owners of Neptune and Shell owns the
remaining interest in Nemo.
The cash purchase price of the Starfish interest was $25 million with the
purchase price of the Ocean Breeze, Neptune and Nemo interests being $87
million. The investments were paid for using proceeds from the issuance of the
$450 million Senior Notes B (see Note 6).
Our investment in Neptune and Nemo includes excess cost over the underlying
equity in the net assets of these entities of $13.5 million. The excess cost,
which relates to pipeline assets, is being amortized against our share of
earnings from Neptune and Nemo over a period of 35 years, which is the estimated
useful life of the pipeline assets that gave rise to the difference. The
unamortized balance of excess cost over the underlying equity in the net assets
of Neptune and Nemo was $12.4 million and $0.7 million, respectively, at
December 31, 2001.
F-15
Historical information for periods prior to January 1, 2001 do not reflect any
impact associated with our equity investments in Starfish, Neptune and Nemo.
Octane Enhancement segment:
At December 31, 2001, the Octane Enhancement segment included our 33.33%
interest in Belvieu Environmental Fuels ("BEF"), a facility located in southeast
Texas that produces motor gasoline additives to enhance octane. The BEF facility
currently produces MTBE. The production of MTBE is driven by oxygenated fuel
programs enacted under the federal Clean Air Act Amendments of 1990 and other
legislation and as an additive to increase octane in motor gasoline. Any changes
to these oxygenated fuel 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 reduce the demand for MTBE and
could have an adverse effect on our results of operations.
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 have
been well below levels of public health concern, there have been calls for the
phase-out of MTBE in motor gasoline in various federal and state governmental
agencies and advisory bodies.
In light of these regulatory developments, the owners of BEF have been
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. The Company believes
that if MTBE usage is banned or significantly curtailed, the motor gasoline
industry would need a substitute additive to maintain octane levels in motor
gasoline and that alkylate would be an attractive substitute. 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
would range from $20 million to $90 million, with our share of these costs
ranging from $6.7 million to $30 million.
Balance sheet information for the last two years and results of operations data
for the last three years for BEF are summarized below:
As Of or For The
Year Ended December 31,
------------------------------
2001 2000 1999
------------------------------
BALANCE SHEET DATA:
Current Assets $ 29,301 $ 20,640
Property, plant and equipment, net 140,009 150,603
Other assets 10,067 11,439
-------------------
Total assets $179,377 $182,682
===================
Current liabilities $ 13,352 $ 8,042
Other liabilities 3,438 5,779
Combined equity 162,587 168,861
-------------------
Total liabilities and combined equity $179,377 $182,682
===================
INCOME STATEMENT DATA:
Revenues $213,734 $258,180 $193,219
Gross operating margin 28,701 43,328 43,479
Operating income 15,984 30,529 30,025
Income before accounting change 17,014 31,220 29,029
Net income 17,014 31,220 24,550
Processing segment:
At December 31, 2001, our 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 company owning a
F-16
natural gas processing plant, fractionation facilities, storage, and gas
gathering pipelines in Louisiana. We account for this investment using the cost
method.
5. RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business
Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS
No. 141 prohibits the use of the pooling-of-interest method for business
combinations initiated after June 30, 2001 and also applies to all business
combinations accounted for by the purchase method that are completed after June
30, 2001. There are also transition provisions that apply to business
combinations completed before July 1, 2001, that were accounted for by the
purchase method. SFAS No. 142 is effective for our fiscal year that began
January 1, 2002 for all goodwill and other intangible assets recognized in our
consolidated balance sheet at that date, regardless of when those assets were
initially recognized. We adopted SFAS No. 141 on January 1, 2002.
Within six months of our adoption of SFAS No. 142 (by June 30, 2002), we will
have completed a transitional impairment review to identify if there is an
impairment to the December 31, 2001 recorded goodwill or intangible assets of
indefinite life using a fair value methodology. Professionals in the business
valuation industry will be consulted to validate the assumptions used in such
methodologies. Any impairment loss resulting from the transitional impairment
test will be recorded as a cumulative effect of a change in accounting principle
for the quarter ended June 30, 2002. Subsequent impairment losses will be
reflected in operating income in the Statements of Consolidated Operations.
At January 1, 2002, our intangible assets included the values assigned to the
20-year Shell natural gas processing agreement (the "Shell agreement") and the
excess cost of the purchase price over the fair market value of the assets
acquired from Mont Belvieu Associates (the "MBA excess cost"), both of which
were initially recorded in 1999. The value of the Shell agreement ($194.4
million net book value at December 31, 2001) is being amortized on a
straight-line basis over its contract term. Likewise, the MBA excess cost ($7.9
million net book value at December 31, 2001) was being amortized on a
straight-line basis over 20 years. Based upon initial interpretations of the new
accounting standards, we anticipate that the intangible asset related to the
Shell agreement will continue to be amortized over its contract term ($11.1
million annually for 2002 through July 2019); however, the MBA excess cost will
be reclassified to goodwill in accordance with the new standard and its
amortization will cease (currently, $0.5 million annually). This goodwill would
then be subject to impairment testing as prescribed in SFAS No. 142. We are
continuing to evaluate the complex provisions of SFAS No. 142 and will fully
adopt the standard during 2002 within the prescribed time periods.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143,
"Accounting for Asset Retirement Obligations", in June 2001. This statement
establishes accounting standards for the recognition and measurement of a
liability for an asset retirement obligation and the associated asset retirement
cost. This statement is effective for our fiscal year beginning January 1, 2003.
We are continuing to evaluate the provisions of this statement. In August 2001,
the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets". This statement addresses financial accounting and reporting
for the impairment and/or disposal of long-lived assets. We adopted this
statement effective January 1, 2002 and determined that it will have no material
impact on our financial statements as of that date.
F-17
6. LONG-TERM DEBT
Our long-term debt consisted of the following at:
December 31,
----------------------
2001 2000
----------------------
Borrowings under:
Senior Notes A, 8.25% fixed rate, due March 2005 $ 350,000 $ 350,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000
---------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,653
Less unamortized discount on:
Senior Notes A (117) (153)
Senior Notes B (258)
Less current maturities of long-term debt --
---------------------
Long-term debt $ 855,278 $ 403,847
=====================
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, 2001. See below for a
complete description of these facilities.
At December 31, 2001, we had a total of $75 million of standby letters of credit
capacity under our $250 Million Multi-Year Credit Facility of which $2.4 million
was 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 Senior Notes, MBFC Loan and its
two current revolving credit facilities. In the descriptions that follow, the
term "MLP" denotes Enterprise Products Partners L.P. in this guarantor role.
Senior Notes A. On March 13, 2000, we 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 "Senior Notes A").
These notes were issued to retire certain revolving credit loan balances that
were created as a result of the TNGL acquisition and other general partnership
activities.
The Senior Notes A 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 our ability, with certain exceptions, to
incur debt secured by liens and engage in sale and leaseback transactions. We
were in compliance with these restrictive covenants at December 31, 2001.
Senior Notes B. On January 24, 2001, we 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 "Senior Notes B").
These notes were issued to finance the acquisition of Acadian Gas, Ocean Breeze,
Neptune, Nemo and Starfish; to cover construction costs of certain NGL pipelines
and related projects; and to fund other general partnership activities.
The Senior Notes B were issued under the same indenture as Senior Notes A and
therefore are subject to similar terms and restrictive covenants. The Senior
Notes B are guaranteed by the MLP through an unsecured and unsubordinated
guarantee. We were in compliance with the restrictive covenants at December 31,
2001.
F-18
MBFC Loan. On March 27, 2000, we executed a $54 million loan agreement with the
Mississippi Business Finance Corporation ("MBFC") having a 8.70% fixed-rate and
a maturity date of March 1, 2010. In general, the proceeds from this loan were
used to retire certain revolving credit loan balances attributable to acquiring
and constructing the Pascagoula, Mississippi natural gas processing facility.
The MBFC Loan is subject to a make-whole redemption right and is guaranteed by
the MLP through an unsecured and unsubordinated guarantee. The indenture
agreement contains an acceleration clause whereby the outstanding principal and
interest on the loan may become due and payable if our credit ratings decline
below a Baa3 rating by Moody's (currently Baa2) and below a BBB- rating by
Standard and Poors (currently BBB). Under these circumstances, the trustee (as
defined in the indenture agreement) may, and if requested to do so by holders of
at least 25% in aggregate of the principal amount of the outstanding underlying
bonds, shall accelerate the maturity of the MBFC Loan, whereby the principal and
all accrued interest would become immediately due and payable. If such an event
occurred, we would have the option (a) to redeem the MBFC loan or (b) to provide
an alternate credit agreement (as defined in the indenture agreement) to support
our obligation under the MBFC loan, with both options exercisable within 120
days of receiving notice of the decline in our credit ratings from the ratings
agencies.
The loan agreement contains certain covenants including maintaining appropriate
levels of insurance on the Pascagoula facility and restrictions regarding
mergers. We were in compliance with the restrictive covenants at December 31,
2001.
Multi-Year Credit Facility. On November 17, 2000, we entered into a $250 million
five-year revolving credit facility that includes a sublimit of $75 million for
letters of credit. The November 17, 2005 maturity date may be extended for one
year at our option with the consent of the lenders, subject to the extension
provisions in the agreement. We can increase the amount borrowed under this
facility, with the consent of the Administrative Agent (whose consent may not be
unreasonably withheld), 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 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 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, 2001.
Our obligations under this bank credit facility are unsecured general
obligations and are non-recourse to the General Partner. As defined within the
agreement, borrowings under this bank credit facility will generally bear
interest at either (i) the greater of the Prime Rate or the Federal Funds
Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an
applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the
interest rate at the time of each borrowing.
The credit agreement contains various affirmative and negative covenants
applicable to the Company to, among other things, (i) incur certain
indebtedness, (ii) grant certain liens, (iii) enter into certain merger or
consolidation transactions and (iv) make certain investments. In addition, we
may not directly or indirectly make any distribution in respect of its
partnership interests, except those payments in connection with the Buy-Back
Program (not to exceed $30 million in the aggregate, see Note 7) and
distributions from Available Cash from Operating Surplus, both as defined within
the agreement.
The credit agreement also requires that we satisfy certain financial covenants
at the end of each fiscal quarter. As defined within the agreement, we (i) must
maintain Consolidated Net Worth of $750 million and (ii) not permit our ratio of
Consolidated Indebtedness to Consolidated EBITDA, including pro forma
adjustments (as defined within the agreement), for the previous four quarter
period to exceed 4.0 to 1.0. We were in compliance with the restrictive
covenants at December 31, 2001.
364-Day Credit Facility. In conjunction with the Multi-Year Credit Agreement, we
entered into a 364-day $150 million revolving bank credit facility. In November
2001, we and our lenders amended the revolving credit agreement to extend the
maturity date to November 15, 2002 with the option to convert any revolving
credit balance outstanding at November 15, 2002 to a one-year term loan.
F-19
We can increase the amount borrowed under this facility, with the consent of the
Administrative Agent (whose consent may not be unreasonably withheld), 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
Multi-Year Credit Facility do 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 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, 2001.
Our obligations under this bank credit facility are unsecured general
obligations and are non-recourse to the General Partner. As defined within the
agreement, borrowings under this bank credit facility will generally bear
interest at either (i) the greater of the Prime Rate or the Federal Funds
Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an
applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the
interest rate at the time of each borrowing.
Limitations on certain actions by the Company and financial condition covenants
of this bank credit facility are substantially consistent with those existing
for the Multi-Year Credit Facility as described previously. We were in
compliance with the restrictive covenants at December 31, 2001.
February 2001 Registration Statement
On February 23, 2001, we filed a $500 million universal shelf registration (the
"February 2001 Shelf") covering the issuance of an unspecified amount of equity
or debt securities or a combination thereof. We expect 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
our funding requirements and the availability of alternative funding sources. We
routinely review acquisition opportunities.
Increase in fair value of fixed-rate debt
Upon adoption of SFAS No. 133 (see Note 13), we recorded a $2.3 million fair
value adjustment associated with our fixed-rate debt. The fair value adjustment
is not a cash obligation of the Company and does not alter the amount of our
indebtedness. Under the specific rules of SFAS 133, the fair value adjustment
will be amortized over the remaining life of the fixed-rate debt to which it is
associated, which approximates 10 years. See "Interest Rate Swaps" under Note 13
for additional information concerning this item.
Impact of interest rate swap agreements upon interest expense
During 2001 and 2000, we utilized interest rate swap agreements to manage debt
service costs by converting a portion of our fixed-rate debt into variable-rate
debt. Income or losses sustained on these financial instruments are reflected as
a component of consolidated interest expense. At December 31, 2000, we had three
interest rate swaps outstanding having a combined notional value of $154 million
(attributable to fixed-rate debt) with an estimated fair value of $2.0 million.
Due to the early termination of two of the swaps, the notional amount and fair
value of the remaining swap was $54 million and $2.3 million (an asset),
respectively, at December 31, 2001.
We recorded as a reduction of interest expense $13.2 million from our interest
rates swaps during 2001 and $10.0 million during 2000. The income recognized in
2001 from these swaps includes the $2.3 million in non-cash mark-to-market
income at December 31, 2001 (attributable to the sole remaining swap). The
remaining $10.9 million has been realized. No mark-to-market income was recorded
prior to the implementation of SFAS No. 133. For additional information
regarding our interest rate swaps, see Note 13.
F-20
7. CAPITAL STRUCTURE
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 and 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
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 us 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 Unitholders.
During the Subordination Period (as described under "Subordinated Units" below),
however, we are limited with regards to the number of equity securities that we
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 Units issued in connection with the TNGL acquisition, the number of
Common Units available (and unreserved) to us for general partnership purposes
during the Subordination Period was 27,275,000 at December 31, 2001.
Subordinated Units. The 21,409,870 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 we have 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 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 would convert into Common Units is May 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 May 1, 2003. The remaining 50% of Subordinated Units would
convert on August 1, 2003 should the balance of the conversion requirements be
met.
Special Units. The Special Units issued to Shell in conjunction with the 1999
TNGL acquisition and a related-contingent unit agreement do not accrue
distributions and are not entitled to cash distributions until their conversion
into Common Units on a one for one basis. 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.
We issued 14.5 million Special Units to Shell in August 1999 in connection with
TNGL acquisition. Subsequently, Shell met certain performance criteria in 2000
and 2001 that obligated us to issue an additional 6.0 million Special Units to
Shell - 3.0 million were issued in August 2000 and 3.0 million in August 2001
under a contingent unit agreement. Of the cumulative 20.5 million Special Units
issued, 6.0 million have already converted to Common Units (1.0 million in
August 2000 and 5.0 million in August 2001). The remaining Special Units will
convert to
F-21
Common Units on a one for one basis as follows: 9.5 million in August 2002 and
5.0 million in August 2003. These conversions have a dilutive effect on basic
earnings per Unit.
Under the rules of the New York Stock Exchange, the conversion of Special Units
into Common Units requires the approval of a majority of Common Unitholders. An
affiliate of EPCO, which owns in excess of 62% of the outstanding Common Units,
has voted its Units in favor of past conversions, which provided the necessary
votes for approval.
Buy-Back Program. In 2000, the General Partner authorized us to repurchase and
retire up to 1,000,000 of our publicly-held Common Units. The repurchase and
retirements will be made during periods of temporary market weakness at price
levels that would be accretive to our remaining Unitholders.
In September 2001, the General Partner approved a modification to the Buy-Back
Program that allows both the Company (specifically, Enterprise Products Partners
L.P.) and its consolidated revocable grantor trust (EPOLP 1999 Grantor Trust or
the "Trust") to repurchase Common Units under the program. Under the terms of
the modification, purchases made by the Company will continue to be retired
whereas purchases made by the Trust will remain outstanding and not be retired.
The Common Units purchased by the Trust will be accounted for as Treasury Units.
During 2000, the Company repurchased and retired 28,400 Common Units under this
program. The Trust purchased 396,400 Common Units under this program in 2001. At
December 31, 2001, 575,200 Common Units could be repurchased and/or retired
under this program on a pre-split basis (see Note 16 for a discussion of a
subsequent event involving the declaration of a two-for-one split of Common
Units that will occur in May 2002).
Treasury Units acquired by Trust. During the first quarter of 1999, the
Operating Partnership established the Trust to fund potential future obligations
under the EPCO Agreement with respect to EPCO's long-term incentive plan
(through the exercise of options granted to EPCO employees or directors of the
General Partner). The Common Units purchased by the Trust are accounted for in a
manner similar to treasury stock under the cost method of accounting. The Trust
purchased 267,200 Common Units in 1999 at a cost of $4.7 million and 396,400
Common Units in 2001 at a cost of $18.0 million.
In November 2001, the Trust sold 500,000 Common Units previously held in
treasury to EPCO for $22.6 million. The sales price of the treasury Common Units
sold exceeded the purchase price of the Treasury Units by $6.0 million and has
been credited to Partners' Equity accounts in a manner similar to additional
paid-in capital.
F-22
Unit History. The following table details the outstanding balance of each class
of Units at the end of the periods indicated:
Limited Partners
-------------------------
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
Treasury Units purchased by
consolidated Trust (267,200) 267,200
-------------------------------------------------
Balance, December 31, 1999 45,285,715 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 46,257,315 21,409,870 16,500,000 267,200
Additional Special Units issued to
Coral Energy, LLC in connection
with contingency agreement 3,000,000
Conversion of 5.0 million Coral
Energy, LLC Special Units into
Common Units 5,000,000 (5,000,000)
Treasury Units purchased by
consolidated Trust (396,400) 396,400
Treasury Units reissued by
consolidated Trust 500,000 (500,000)
-------------------------------------------------
Balance, December 31, 2001 51,360,915 21,409,870 14,500,000 163,600
=================================================
8. EARNINGS PER UNIT
Basic earnings per Unit is computed by dividing net income available to limited
partner interests by the weighted-average 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. The following table reconciles the number of Units used in
the calculation of basic earnings per Unit and diluted earnings per Unit for
each of the three years ended December 31, 2001, 2000 and 1999.
The weighted-average number of Common Units outstanding in 2001 and 2000 reflect
the conversion of a portion of Shell's Special Units to Common Units in August
of each year. Specifically, five million Special Units converted to Common Units
in August 2001 and one million Special Units converted in August 2000. The
weighted-average number of Special Units outstanding in 2001 and 2000 reflect
the above conversions and the issuance of three million Special Units in August
2001 and August 2000. See Note 7 for additional information regarding Shell's
Special Units.
F-23
For Year Ended December 31,
-----------------------------------
2001 2000 1999
-----------------------------------
Income before minority interest $ 244,650 $ 222,759 $ 121,521
General partner interest (5,608) (2,597) (1,203)
-----------------------------------
Income before minority interest 239,042 220,162 120,318
available to Limited Partners
Minority interest (2,472) (2,253) (1,226)
-----------------------------------
Net income available to Limited Partners $ 236,570 $ 217,909 $ 119,092
===================================
BASIC EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $ 239,042 $ 220,162 $ 120,318
===================================
Net income available
to Limited Partners $ 236,570 $ 217,909 $ 119,092
===================================
Denominator (weighted-average)
Common Units outstanding 48,316 45,698 45,300
Subordinated Units outstanding 21,410 21,410 21,410
------------------------------------
Total 69,726 67,108 66,710
===================================
Basic Earnings per Unit
Income before minority interest
available to Limited Partners $ 3.43 $ 3.28 $ 1.80
===================================
Net income available
to Limited Partners $ 3.39 $ 3.25 $ 1.79
===================================
DILUTED EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $ 239,042 $ 220,162 $ 120,318
===================================
Net income available
to Limited Partners $ 236,570 $ 217,909 $ 119,092
===================================
Denominator (weighted-average)
Common Units outstanding 48,316 45,698 45,300
Subordinated Units outstanding 21,410 21,410 21,410
Special Units outstanding 15,667 15,336 6,078
------------------------------------
Total 85,393 82,444 72,788
===================================
Diluted Earnings per Unit
Income before minority interest
available to Limited Partners $ 2.80 $ 2.67 $ 1.65
===================================
Net income available
to Limited Partners $ 2.77 $ 2.64 $ 1.64
===================================
9. DISTRIBUTIONS
We intend, 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
F-24
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. We made incentive
distributions to the General Partner of $3.2 million during 2001 and $0.4
million during 2000.
The following table is a summary of cash distributions to partnership interests
since the first quarter of 1999.
Cash Distribution History
--------------------------------------------------------
Per Per
Common Subordinated Record Payment
Unit Unit Date Date
--------------------------------------------------------
1999
1st Quarter $ 0.4500 $ 0.0700 Apr. 30, 1999 May 12, 1999
2nd Quarter $ 0.4500 $ 0.3700 Jul. 30, 1999 Aug. 11, 1999
3rd Quarter $ 0.4500 $ 0.4500 Oct. 29, 1999 Nov. 10, 1999
4th Quarter $ 0.5000 $ 0.5000 Jan. 31, 2000 Feb. 10, 2000
2000
1st Quarter $ 0.5000 $ 0.5000 Apr. 28, 2000 May 10, 2000
2nd Quarter $ 0.5250 $ 0.5250 Jul. 31, 2000 Aug. 10, 2000
3rd Quarter $ 0.5250 $ 0.5250 Oct. 31, 2000 Nov. 10, 2000
4th Quarter $ 0.5500 $ 0.5500 Jan. 31, 2001 Feb. 9, 2001
2001
1st Quarter $ 0.5500 $ 0.5500 Apr. 30, 2001 May 10, 2001
2nd Quarter $ 0.5875 $ 0.5875 Jul. 31, 2001 Aug. 10, 2001
3rd Quarter $ 0.6250 $ 0.6250 Oct. 31, 2001 Nov. 9, 2001
4th Quarter $ 0.6250 $ 0.6250 Jan. 31, 2002 Feb. 11, 2002
The quarterly cash distribution amounts shown in the table correspond to the
cash flows for the quarters indicated. The actual cash distributions (i.e.,
payments to our limited partners) occur within 45 days after the end of such
quarter.
10. RELATED PARTY TRANSACTIONS
We have no employees. All management, administrative and operating functions are
performed by employees of EPCO pursuant to the EPCO Agreement (in effect since
July 1998). Under the terms of the EPCO Agreement, EPCO agreed to:
. employ the personnel necessary to manage our business and affairs
(through the General Partner);
. employ the operating personnel involved our business for which we
reimburse EPCO at cost (based upon EPCO's actual salary costs and
related fringe benefits);
. allow us 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;
. grant us an irrevocable, non-exclusive worldwide license to use all of
the EPCO trademarks and trade names;
. indemnify us against any losses resulting from certain lawsuits; and
to
. sublease to us 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 for one
dollar per year and to assign its' purchase option under such leases
to us. EPCO remains liable for the lease payments associated with
these assets.
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Operating costs and expenses (as shown in the audited Statements of Consolidated
Operations) treat the full amount of lease payments being made by EPCO as a
non-cash operating expense (with the offset to Partners' Equity on the
Consolidated Balance Sheet). In addition, operating costs and expenses include
compensation charges for EPCO's employees who operate the facilities.
Pursuant to the EPCO Agreement, we reimburse EPCO for our portion of the costs
of certain of its employees who manage our business and affairs. In general, our
reimbursement of EPCO's expense associated with administrative positions that
were active at the time of our initial public offering in July 1998 is capped by
the Administrative Services Fee that we pay (currently at $16 million annually).
The General Partner, with the approval and consent of the Audit and Conflicts
Committee, may agree to annual increases of such fee up to ten percent per year
during the 10-year term of the EPCO Agreement. Any difference between the actual
costs of this "pre-expansion" group (including those associated with
equity-based awards granted to certain individuals within this group) and the
Administrative Services Fee will be retained by EPCO (i.e., EPCO solely bears
any shortfall in reimbursement for this group).
Beginning in January 2000, we began reimbursing EPCO for our share of the
compensation of administrative personnel that it had hired in response to our
expansion and business development activities (through the construction of new
facilities, business acquisitions or the like). EPCO began hiring "expansion"
administrative personnel during 1999 in connection with the TNGL acquisition and
other development activities. In general, we reimburse EPCO for our share of its
compensation expense associated with these "expansion" administrative positions,
including those costs attributable to equity-based awards.
The following table summarizes the Administrative Services Fee paid to EPCO
during the last three years. In addition, the table shows the total compensation
reimbursed to EPCO for operations personnel and "expansion" administrative
positions.
For Year Ended December 31,
---------------------------------
2001 2000 1999
---------------------------------
Administrative Services Fee
paid to EPCO $ 15,125 $ 13,750 $ 12,500
Compensation reimbursed to EPCO 48,507 44,717 26,889
---------------------------------
Total $ 63,632 $ 58,467 $ 39,389
=================================
We elected to prepay EPCO a discounted amount of $15.7 million for the 2002
Administrative Services Fee in December 2001 (the undiscounted amount was $16.0
million). We will owe EPCO for any undiscounted amount above the $16.0 million
if the General Partner approves an increase in the fee during 2002.
Other related party and similar transactions with EPCO or its affiliates
EPCO also operates the facilities owned by BEF and EPIK and charges them for
actual salary costs and related fringe benefits. In addition, EPCO is paid a
management fee by these entities in lieu of reimbursement for the actual cost of
providing management services; such charges aggregated $0.8 for 2001, $0.9
million for 2000 and $0.8 million in 1999.
We have entered into an agreement with EPCO to provide trucking services related
to the loading and transportation of NGL products. EPCO charged us $9.0 million
in 2001, $7.9 million in 2000 and $5.7 million in 1999 for these services. On
occasion, in the normal course of business, we may engage in transactions with
EPCO involving the buying and selling of NGL products. No such sales or
purchases were transacted with EPCO during 2001 and 2000; however, we purchased
a net $20.6 million of such products from EPCO during 1999.
In addition, trust affiliates of EPCO (Enterprise Products 1998 Unit Option Plan
Trust and the Enterprise Products 2000 Rabbi Trust) purchase Common Units for
the purpose of granting options to EPCO management and certain key employees
(many of whom also serve in similar capacities with the General Partner). During
2001, these trusts purchased 211,518 Common Units on the open market or through
privately negotiated transactions. At December 31, 2001, these trusts owned a
total of 1,461,518 Common Units. In November 2001, EPCO directly purchased
F-26
500,000 Common Units at market prices from our consolidated trust, EPOLP 1999
Grantor Trust, on behalf of a key executive.
Our 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.
Relationships with Shell
We have an extensive and ongoing relationship with Shell as a partner, customer
and vendor. Shell, through its subsidiary Shell US Gas & Power LLC, owns
approximately 23.2% of our limited partnership interests and 30.0% of the
General Partner. Currently, three members of the Board of Directors of the
General Partner are employees of Shell.
The most significant contract affecting our natural gas processing business is
the 20-year Shell Processing Agreement which grants us 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 deepwater
developments. Shell is the largest oil and gas producer and holds one of the
largest lease positions in the deepwater Gulf of Mexico. Generally, this
contract has 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 our gas plants 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.
Apart from operating expenses arising from the Shell Processing Agreement, we
also sell NGL and petrochemical products to Shell.
The following table shows the related party amounts by major category in the
Company's Statements of Consolidated Operations for the last three years. The
table also shows the total amounts paid to EPCO separately under the EPCO
Agreement for employee-related costs for the last three years.
For Year Ended December 31,
---------------------------------
2001 2000 1999
---------------------------------
Revenues from consolidated operations
Unconsolidated affiliates $ 173,684 $ 61,988 $ 40,352
Shell 333,333 292,741 56,301
EPCO and subsidiaries 5,439 4,750 9,148
Operating costs and expenses
Unconsolidated affiliates 41,062 58,202 20,696
Shell 705,440 736,655 188,570
EPCO and subsidiaries 10,075 9,492 35,046
EPCO Agreement 63,632 58,467 39,389
11. COMMITMENTS AND CONTINGENCIES
Redelivery Commitments
From time to time, we store NGL, petrochemical and natural gas volumes for third
parties under various processing, storage and similar agreements. Under the
terms of these agreements, we are generally required to redeliver to the owner
volumes on demand. We are insured for any physical loss of such volumes due to
catastrophic events. At
F-27
December 31, 2001, NGL and petrochemical volumes aggregating 320 million gallons
were due to be redelivered to their owners along with 887,414 MMBtus of natural
gas.
Lease Commitments
We lease 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, 2001 are as follows:
2002 $ 5,115
2003 4,862
2004 4,324
2005 279
2006 181
Thereafter 1,077
---------
Total minimum obligations $ 15,838
=========
The operating lease commitments shown above exclude the expense associated with
various equipment leases contributed to us by EPCO at our formation for which
EPCO has retained the liability. During 2001, 2000 and 1999, our non-cash lease
expense associated with these EPCO "retained" leases was $10.4 million, $10.6
million and $10.6 million, respectively.
Lease and rental expense (including Retained Leases) included in operating
income for the years ended December 31, 2001, 2000 and 1999 was approximately
$23.4 million, $21.2 million and $20.6 million. EPCO has assigned us the
purchase options associated with the retained leases. Should we decide to
exercise our purchase options under the retained leases, up to $26.0 million
will be payable in 2004, $3.4 million in 2008 and $3.1 million in 2016.
Purchase Commitments
Gas purchase commitments. We have long-term purchase commitments for NGL
products and related-streams including natural gas with several suppliers. The
purchase prices contained within these contracts approximate market value at the
time of delivery. The following table shows our long-term volume commitments
under these contracts.
2002 2003 2004 2005 2006 Thereafter
-------------------------------------------------------
NGLs (000s barrels):
Ethane 2,154 2,154 1,677 1,089 126
Propane 2,898 2,826 1,899 900 102
Isobutane 498 498 387 252 30
Normal Butane 1,134 964 735 303 34
Natural Gasoline 1,944 1,944 1,488 846 48
Other 960 460 180
------------------------------------------
Total NGLs 9,588 8,846 6,366 3,390 340
==========================================
Natural gas (BBtus) 13,726 13,726 12,996 12,996 12,996 75,600
=======================================================
Capital spending commitments. As of December 31, 2001, we had capital
expenditure commitments totaling approximately $5.3 million, of which $0.3
million relates to our portion of internal growth projects of unconsolidated
affiliates.
Litigation
We are indemnified for any litigation pending as of the date of our formation by
EPCO. We are sometimes named as a defendant in litigation relating to our normal
business operations. Although we insure against various business
F-28
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 us against liabilities arising from future legal proceedings as a
result of ordinary business activity. Except as noted below, management is not
aware of any significant litigation, pending or threatened, that would have a
significant adverse effect on our financial position or results of operations.
Our operations 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 our pipelines and processing and storage
facilities. For example, the Mont Belvieu processing and storage facilities are
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 of the country in this "severe"
category. One of the other consequences of this non-attainment status is the
potential imposition of lower limits on emissions of certain pollutants,
particularly oxides of nitrogen which are produced through combustion, as in the
gas turbines at the Mont Belvieu complex.
Regulations imposing more strict air emissions requirements on existing
facilities in the Houston-Galveston area were issued in December 2000. These
regulations may necessitate extensive redesign and modification of our Mont
Belvieu facilities to achieve the air emissions reductions needed for federal
Clean Air Act compliance. The technical practicality and economic reasonableness
of these regulations have been challenged under state law in litigation filed on
January 19, 2001, against the Texas Natural Resource Conservation Commission and
its principal officials in the District Court of Travis County, Texas, by a
coalition of major Houston-Galveston area industries, including us. Until this
litigation is resolved, the precise level of technology to be employed and the
cost for modifying the facilities to achieve the required amount of reductions
cannot be determined. Currently, the litigation has been stayed by agreement of
the parties pending the outcome of expanded, cooperative scientific research to
more precisely define sources and mechanisms of air pollution in the
Houston-Galveston area. Completion of this research is anticipated in mid-2002.
12. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
For Year Ended December 31,
--------------------------------
2001 2000 1999
--------------------------------
(Increase) decrease in:
Accounts receivable $ 230,629 $(93,716) $(152,363)
Inventories 30,862 (21,452) 7,471
Prepaid and other current assets (25,524) 2,352 (7,523)
Intangible assets (5,226)
Other assets 162 (1,410) 1,164
Increase (decrease) in:
Accounts payable (82,075) 18,723 (6,276)
Accrued gas payable (197,916) 143,457 206,178
Accrued expenses (1,576) 4,978 (27,788)
Accrued interest 14,234 8,743 863
Other current liabilities 3,073 6,540 5,884
Other liabilities (9,012) 8,122 296
--------------------------------
Net effect of changes in operating accounts $ (37,143) $ 71,111 $ 27,906
================================
Cash payments for interest, net of $2,946,
$3,277 and $153 capitalized in 2001,
2000 and 1999, respectively $ 37,536 $ 17,774 $ 15,780
================================
On April 1, 2001, we paid approximately $225.7 million in cash to Shell to
acquire Acadian Gas. This acquisition was recorded using the purchase method of
accounting and as a result the initial purchase price has been allocated to
F-29
various balance sheet asset and liability accounts. For additional information
regarding the acquisition of Acadian Gas (including the allocation of the
purchase price), see Note 2.
On August 1, 1999, we paid $166 million in cash and issued 14.5 million
non-distribution bearing, convertible Special Units (valued at $210.4 million at
time of issuance) to Shell in connection with the TNGL acquisition. Also, we
issued 6.0 million additional non-distribution bearing, convertible Special
Units to Shell based on Shell having met certain performance criteria in
calendar years 2000 and 2001. Of the 6.0 million additional Special Units
issued, 3.0 million were issued in 2000 and 3.0 million during 2001. The value
of the Special Units issued in 2000 was $55.2 million while the value of those
issued during 2001 was $117.1 million, both values determined using present
value techniques. The $172.3 million combined value of these two issues
increased the overall purchase price of the TNGL acquisition and was allocated
to the intangible asset, Shell Processing Agreement. In addition, during 2000,
we increased the value of the Shell Processing Agreement by $25.2 million for
non-cash purchase accounting adjustments related to the acquisition. The offset
to such adjustment was various working capital accounts. With these adjustments
completed, the final purchase price of TNGL increased to $528.8 million.
On July 1, 1999, we paid approximately $42.1 million in cash to EPCO and Kinder
Morgan and assumed approximately $4 million of debt in connection with the
acquisition of an additional interest in the Mont Belvieu NGL fractionation
facility.
As a result of our adoption of SFAS No. 133 on January 1, 2001, we record
various financial instruments relating to commodity positions and interest rate
swaps at their respective fair values using mark-to-market accounting. During
2001, we recognized a net $5.7 million in non-cash mark-to-market income related
to increases in the fair value of these financial instruments. See Note 13 for
additional information on our financial instruments.
13. FINANCIAL INSTRUMENTS
We are exposed to financial market risks, including changes in commodity prices
in our natural gas and NGL businesses and in interest rates with respect to a
portion of its debt obligations. We may use financial instruments (i.e.,
futures, forwards, swaps, options, and other financial instruments with similar
characteristics) to mitigate the risks of certain identifiable and anticipated
transactions, primarily in its Processing segment. In general, the types of
risks hedged are those relating to the variability of future earnings and cash
flows caused by changes in commodity prices and interest rates. As a matter of
policy, we do not use financial instruments for speculative (or trading)
purposes.
Our disclosure of fair value estimates are determined using available market
information and appropriate valuation methodologies. We must use considerable
judgment, however, in interpreting market data and to develop the related
estimates of fair value. Accordingly, the estimates presented herein are not
necessarily indicative of the amounts that we could realize upon disposition of
the financial instruments. The use of different market assumptions and/or
estimation methodologies may have a material effect on our estimates of fair
value.
Commodity financial instruments
Our Processing and Octane Enhancement segments are directly exposed to commodity
price risk through their respective business operations. The prices of natural
gas, NGLs and MTBE are subject to fluctuations in response to changes in supply,
market uncertainty and a variety of additional factors that are beyond our
control. In order to manage the risks associated with its Processing segment, we
may enter into swaps, forwards, commodity futures, options and other commodity
financial instruments with similar characteristics that are permitted by
contract or business custom to be settled in cash or with another financial
instrument. The primary 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. We do not
hedge our exposure to the MTBE markets. Also, in its Pipelines segment, we may
utilize a limited number of commodity financial instruments to manage the price
Acadian Gas charges certain of its customers for natural gas.
We have adopted a commercial policy to manage our exposure to the risks of its
natural gas and NGL businesses. The objective of this policy is to assist us in
achieving our profitability goals while maintaining a portfolio with an
acceptable level of risk, defined as remaining within the position limits
established by the General Partner. We enter
F-30
into risk management transactions to manage price risk, basis risk, physical
risk or other risks related to its commodity positions on both a short-term
(less than 30 days) and long-term basis, not to exceed 18 months. The General
Partner oversees the our strategies associated with physical and financial risks
(such as those mentioned previously), approves specific activities subject to
the policy (including authorized products, instruments and markets) and
establishes specific guidelines and procedures for implementing and ensuring
compliance with the policy.
On January 1, 2001, we adopted SFAS No. 133 (as amended and interpreted) which
required us to recognize the fair value of our commodity financial instrument
portfolio on the balance sheet based upon then current market conditions. The
fair market value of the then outstanding commodity financial instruments
portfolio was a net payable of $42.2 million (the "cumulative transition
adjustment") with an offsetting equal amount recorded in Other Comprehensive
Income ("OCI"). The amount in OCI was fully reclassified to earnings during
2001.
At December 31, 2001, we had open commodity financial instruments that settle at
different dates extending through December 2002. We routinely review our
outstanding instruments in light of current market conditions. If market
conditions warrant, some instruments may be closed out in advance of their
contractual settlement dates thus realizing income or loss depending on the
specific exposure. When this occurs, we may enter into a new commodity financial
instrument to reestablish the economic hedge to which the closed instrument
relates.
These commodity financial instruments may not qualify for hedge accounting
treatment under the specific guidelines of SFAS No. 133 because of
ineffectiveness. A hedge is normally regarded as effective if, among other
things, at inception and throughout the term of the financial instrument, we
could expect changes in the fair value of the hedged item to be almost fully
offset by the changes in the fair value of the financial instrument. Currently,
a majority of our commodity financial instruments do not qualify as effective
hedges under the guidelines of SFAS No. 133, with the result being that changes
in the fair value of these positions are recorded on the balance sheet and in
earnings through mark-to-market accounting. The use of mark-to-market accounting
for these commodity financial instruments results in a degree of non-cash
earnings volatility that is dependent upon changes in the underlying commodity
prices. Even though these financial instruments do not qualify for hedge
accounting treatment under the specific guidelines of SFAS No. 133, we continue
to view these financial instruments as hedges inasmuch as this was the intent
when such contracts were executed. This characterization is consistent with the
actual economic performance of these contracts to date and we expect these
financial instruments to continue to mitigate (or offset) commodity price risk
in future. The specific accounting for these contracts, however, is consistent
with the requirements of SFAS No. 133.
We recognized income of $101.3 million in 2001 from our commodity hedging
activities that is treated as a decrease of operating costs and expenses in the
Statements of Consolidated Operations. Of this amount, $95.7 million was
realized during 2001. The remaining $5.6 million represents mark-to-market
income on positions open at December 31, 2001 (based on market prices at that
date).
Interest rate swaps
Our interest rate exposure results from variable-rate borrowings from commercial
banks and fixed-rate borrowings pursuant to its Senior Notes and MBFC Loan. We
manage its exposure to changes in interest rates by utilizing interest rate
swaps. The objective of holding interest rate swaps is to manage debt service
costs by converting a portion of fixed-rate debt into variable-rate debt or a
portion of variable-rate debt into fixed-rate debt. 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. We believe that
it is prudent to maintain an appropriate mixture of variable-rate and fixed-rate
debt.
We assess interest rate cash flow risk by identifying and measuring changes in
interest rate exposure that impact future cash flows and evaluating hedging
opportunities. We use analytical techniques to measure its exposure to
fluctuations in interest rates, including cash flow sensitivity analysis to
estimate the expected impact of changes in interest rates on our future cash
flows.
The General Partner oversees the strategies associated with financial risks and
approves instruments that are appropriate for our requirements. The notional
amount of an interest rate swap does not represent exposure to credit
F-31
loss. We monitor our positions and the credit ratings of counterparties.
Management believes the risk of incurring a credit loss is remote, and that if
incurred, such losses would be immaterial.
At December 31, 2001, we had one interest rate swap outstanding having a
notional amount of $54 million extending through March 2010. Under this
agreement, we exchanged a fixed-rate of 8.70% for a variable-rate that ranged
from 4.28% to 7.66% during 2001 (the variable-rate may fluctuate over time
depending on market conditions). If it elects to do so, the counterparty may
terminate this swap in March 2003. During 2001, two counterparties terminated
their swap agreements with us either through early termination clauses or
negotiation. The closed agreements had a combined notional amount of $100
million.
Upon adoption of SFAS No. 133, we were required to recognize the fair value of
the interest rate swaps on the balance sheet offset by an equal increase in the
fair value of associated fixed-rate debt and, therefore, the adoption of the new
standard had no impact on earnings at transition. Subsequently, it was
determined that the interest rate swaps would not qualify for hedge accounting
treatment under SFAS No. 133 due to differences between the maturity dates of
the swaps and the associated fixed-rate debt; thus, changes in the fair value of
the interest rate swaps would be recorded in earnings through mark-to-market
accounting (i.e., the interest rate swaps were deemed ineffective under SFAS No.
133). As a result, the increase in fair value of the associated fixed-rate debt
will not be adjusted for future changes in its fair value and will be amortized
to earnings over the remaining life of the underlying debt instrument, which
approximates 10 years.
We recognized income of $13.2 million in 2001 from our interest rate swaps that
is treated as a reduction of interest expense in the Statements of Consolidated
Operations. Of this amount, $2.3 million represents the mark-to-market income on
the remaining swap at December 31, 2001 (estimated fair value of swap based on
market rates at that date). The balance of $10.9 million was realized during
2001.
The $2.3 million estimated fair value of the remaining swap at December 31, 2001
is based on market rates (assuming its early termination option in March 2003 is
exercised). The fair value estimate represents the amount that we would receive
to terminate the swap, taking into consideration current interest rates.
Future issues concerning SFAS No. 133
Due to the complexity of SFAS No. 133, the FASB is continuing to provide
guidance about implementation issues. Since this guidance is still continuing,
our initial conclusions regarding the application of SFAS No. 133 upon adoption
may be altered. As a result, additional SFAS No. 133 transition adjustments may
be recorded in future periods as we adopt new FASB interpretations.
Other fair value information
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 estimated fair value of our fixed-rate long-term
debt is estimated based on quoted market prices for debt of similar terms and
maturities. No variable rate long-term debt was outstanding at December 31,
2001.
F-32
The following table summarizes the estimated fair values of our various
financial instruments at December 31, 2001 and 2000:
2001 2000
--------------------- --------------------
Carrying Fair Carrying Fair
Financial Instruments Amount Value Amount Value
- ------------------------------------------------------------------------ --------------------
Financial assets:
Cash and cash equivalents $ 137,823 $ 137,823 $ 60,409 $ 60,409
Accounts receivable (1) 261,302 261,302 415,618 415,618
Commodity financial instruments (2) 9,992 9,992 n/a n/a
Interest rate swaps (3) 2,324 2,324 n/a n/a
Financial liabilities:
Accounts payable and accrued expenses 364,452 364,452 561,688 561,688
Fixed-rate debt (principal amount) 854,000 894,005 404,000 423,836
Commodity financial instruments (4) 3,206 3,206 725 705
Off-balance sheet instruments: (5)
Interest rate swaps receivable n/a n/a 2,030 2,030
Commodity financial instruments payable n/a n/a 40,020 39,266
- --------------------------------------------------------------------------------
(1) 2001 includes a $1.2 million receivable related to the remaining
interest rate swap
(2) 2001 values are a component of other current assets in our consolidated
balance sheet
(3) 2001 value represents the aggregate fair value of the remaining swap
(net of the $1.2 million receivable reflected under accounts receivable).
$1.3 million of the $2.3 million mark-to-market value is a component of
other current assets while the balance of $1.0 million is reflected in
other assets.
(4) 2001 values are a component of other current liabilities in our
consolidated balance sheet
(5) Prior to our adoption of SFAS No. 133 on January 1, 2001, interest rate
swaps and certain commodity financial instruments were off-balance sheet
instruments. As a result of SFAS No. 133, these financial instruments are
now recorded as part of balance sheet assets and liabilities, as the
circumstances warrant.
14. SIGNIFICANT CONCENTRATIONS OF RISK
Credit Risk. A substantial portion of our revenues are derived from various
companies in the NGL and petrochemical industry, located in the United States.
Although this concentration could affect our overall exposure to credit risk
since these customers might be affected by similar economic or other conditions,
management believes we are exposed to minimal credit risk, since the majority of
our business is conducted with major companies within the industry including
those with whom it has joint operations. We do not require collateral for our
accounts receivable.
Nature of Operations. We are subject to a number of risks inherent in the
industry in which it operates, including fluctuating gas and liquids prices. Our
financial condition and results of operation 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, weather and a variety of additional
factors that are beyond our control.
In addition, we must obtain access to new natural gas volumes along the Gulf
Coast of the United States for its processing business in order to maintain or
increase gas plant throughput levels to offset natural declines in field
reserves. The number of wells drilled by third-parties to obtain new volumes
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 our control.
The products that we process, sell or transport are principally used as
feedstocks in petrochemical manufacturing and in the production of motor
gasoline and as fuel for residential and commercial heating. A reduction in
demand
F-33
for our products or services by industrial customers, whether because of
general economic conditions, reduced demand for the end products made with NGL
products, increased competition from petroleum-based products due to pricing
differences, adverse weather conditions, governmental regulations affecting
prices and production levels of natural gas or the content of motor gasoline or
other reasons, could have a negative impact on our results of operation. A
material decrease in natural gas production or crude oil refining, as a result
of depressed commodity prices or otherwise, or a decrease in imports of mixed
butanes, could result in a decline in volumes processed and sold by us.
Counterparty risk. From time to time, we have credit risk with our
counterparties in terms of settlement risk associated with its financial
instruments. On all transactions where we are exposed to credit risk, we analyze
the counterparty's financial condition prior to entering into an agreement,
establish credit and/or margin limits and monitor the appropriateness of these
limits on an ongoing basis.
In December 2001, Enron Corp., or Enron, filed for protection under Chapter 11
of the U.S. Bankruptcy Code. As a result, we established a $10.6 million reserve
for amounts owed to us by Enron North America, a subsidiary of Enron. Enron
North America was our counterparty to various past financial instruments. The
Enron amounts were unsecured and the amount that we may ultimately recover, if
any, is not presently determinable. Of the reserve amount established, $4.3
million was attributable to various unbilled commodity financial instrument
positions that terminate during the first quarter of 2002.
F-34
15. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial
information is available and that are regularly evaluated 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.
We have five reportable operating segments: Fractionation, Pipelines,
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
primarily includes NGL fractionation, isomerization, and polymer grade propylene
fractionation services. Pipelines consists of both liquids and natural gas
pipeline systems, storage and import/export terminal services. Processing
includes the natural gas processing business and its related merchant
activities. Octane Enhancement represents our equity interest in BEF, 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.
We evaluate segment performance based on 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.
We include equity earnings from unconsolidated affiliates in segment gross
operating margin and as a component of revenues. Our equity investments with
industry partners are a vital component of our business strategy and a means by
which we conduct our operations to align our interests with a supplier of raw
materials to a facility or a consumer of finished products from a facility. This
method of operation also enables us to achieve favorable economies of scale
relative to the level of investment and business risk assumed versus what we
could accomplish on a stand alone basis. Many of these businesses perform
supporting or complementary roles to our other business operations. For example,
we use the Promix NGL fractionator to process NGLs extracted by our gas plants.
The NGLs received from Promix then can be sold by our merchant businesses.
Another example would be our relationship with the BEF MTBE facility. Our
isomerization facilities process normal butane for this plant and our HSC
pipeline transports MTBE for delivery to BEF's storage facility on the Houston
Ship Channel.
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
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.
F-35
Information by operating segment, together with reconciliations to the
consolidated totals, is presented in the following table:
Operating Segments
------------------------------------------------------------- Adjs.
Octane and Consol.
Fractionation Pipelines Processing Enhancement Other Elims. Totals
--------------------------------------------------------------------------------------
Revenues from
external customers:
2001 $324,276 $403,430 $2,424,281 $2,382 $3,154,369
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
Intersegment revenues:
2001 158,853 89,907 683,524 389 $(932,673)
2000 177,963 55,690 630,155 375 (864,183)
1999 118,103 43,688 216,720 444 (378,955)
Equity income in
unconsolidated affiliates:
2001 6,945 12,742 $ 5,671 25,358
2000 6,391 7,321 10,407 24,119
1999 1,566 3,728 8,183 13,477
Total revenues:
2001 490,074 506,079 3,107,805 5,671 2,771 (932,673) 3,179,727
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
Gross operating margin
by segment:
2001 118,610 96,569 154,989 5,671 944 376,783
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
Segment assets:
2001 357,122 717,348 124,555 8,921 98,844 1,306,790
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:
2001 93,329 216,029 33,000 55,843 398,201
2000 105,194 102,083 33,000 58,677 298,954
1999 99,110 85,492 33,000 63,004 280,606
Our revenues are derived from a wide customer base. Shell accounted for 10.5% of
consolidated revenues in 2001 (up from 9.5% of consolidated revenues in 2000).
No single external customer accounted for more than 10% of consolidated revenues
during 2000 and 1999. Approximately 80% of our revenues from Shell during 2001
and 2000 are attributable to sales of NGL products which are recorded in our
Processing segment. No single third-party customer provided more than 10% of
consolidated revenues during 2000 or 1999. All consolidated revenues were earned
in the United States. Our operations are centered along the Texas, Louisiana and
Mississippi Gulf Coast areas.
F-36
A reconciliation of segment gross operating margin to consolidated income before
minority interest follows:
For Year Ended December 31,
-----------------------------------
2001 2000 1999
--------- --------- ---------
Total segment gross operating margin $ 376,783 $ 320,615 $ 179,195
Depreciation and amortization (48,775) (35,621) (23,664)
Retained lease expense, net (10,414) (10,645) (10,557)
(Gain) loss on sale of assets 390 (2,270) (123)
Selling, general and administrative (30,296) (28,345) (12,500)
--------- --------- ---------
Consolidated operating income 287,688 243,734 132,351
Interest expense (52,456) (33,329) (16,439)
Interest income from unconsolidated affiliates 31 1,787 1,667
Dividend income from unconsolidated affiliates 3,462 7,091 3,435
Interest income - other 7,029 3,748 886
Other, net (1,104) (272) (379)
--------- --------- ---------
$ 244,650 $ 222,759 $ 121,521
Consolidated income before minority interest ========= ========= =========
16. SUBSEQUENT EVENTS (UNAUDITED)
Purchase of Diamond-Koch storage assets. On January 17, 2002, we completed the
purchase of various hydrocarbon storage assets from affiliates of Valero Energy
Corporation and Koch Industries, Inc. The purchase price of the storage assets
was approximately $129 million (subject to certain post-closing adjustments) and
will be accounted for as an asset purchase. The purchase price was funded
entirely by internally generated funds.
The storage facilities include 30 salt dome storage caverns with a total useable
capacity of 68 million barrels, local distribution pipelines and related
equipment. The facilities provide storage services for mixed natural gas
liquids, ethane, propane, butanes, natural gasoline and olefins (such as
ethylene), polymer grade propylene, chemical grade propylene and refinery grade
propylene. The facilities are located in Mont Belvieu, Texas.
Purchase of Diamond-Koch propylene fractionation assets. On February 1, 2002, we
completed the purchase of various propylene fractionation assets from affiliates
of Valero Energy Corporation and Koch Industries, Inc. and certain inventories
of refinery grade propylene, propane and polymer grade propylene owned by such
affiliates. The purchase price of these assets was approximately $238.5 million
(subject to certain post-closing adjustments) and will be accounted for as an
asset purchase. The purchase price was funded by a drawdown on our existing
revolving bank credit facilities.
The propylene fractionation assets being acquired include a 66.67% interest in a
polymer grade propylene fractionation facility located in Mont Belvieu, Texas, a
50.0% interest in an entity which owns a polymer grade propylene export terminal
located on the Houston Ship Channel in La Porte, Texas and varying interests in
several supporting distribution pipelines and related equipment. The propylene
fractionation facility has the gross capacity to produce approximately 41,000
barrels per day of polymer grade propylene.
Both the storage and propylene fractionation acquisitions have been approved by
the requisite regulatory authorities. The post-closing purchase price
adjustments of both transactions are expected to be completed during the second
quarter of 2002.
Two-for-one split of Limited Partner Units. On February 27, 2002, we announced
that the Board of Directors of the General Partner had approved a two-for-one
split for each class of our Units. The partnership Unit split will be
accomplished by distributing one additional partnership Unit for each
partnership Unit outstanding to holders of record on April 30, 2002. The Units
will be distributed on May 15, 2002. All references to number of Units or
earnings per Unit contained in this document relate to the pre-split Units,
except if otherwise indicated.
F-37
17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
------------------------------------------------
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
For the Year Ended December 31, 2001:
Revenues $ 838,326 $ 968,447 $ 729,618 $ 643,336
Operating income 54,417 109,071 87,406 36,794
Income before minority interest 52,804 93,975 75,774 22,097
Minority interest (534) (944) (767) (227)
Net income 52,270 93,031 75,007 21,870
Net income per Unit, basic $ 0.76 $ 1.35 $ 1.04 $ 0.28
Net income per Unit, diluted $ 0.61 $ 1.09 $ 0.85 $ 0.23
Earnings in the fourth quarter of 2001 declined relative to the third quarter of
2001 primarily due to a decrease in the mark-to-market value of our commodity
financial instruments. The decrease was due to (1) the settlement of certain
positions during the fourth quarter, (2) a decrease in the relative amount of
hedging activities at December 31, 2001 versus September 30, 2001 and (3) a
decrease in the value of certain outstanding financial instruments from
September 30, 2001 due to changes in natural gas prices.
F-38
SCHEDULE II
Enterprise Products Partners L.P.
Valuation and Qualifying Accounts
For Years Ended December 31,
----------------------------
2001 2000 1999
---------------------------
Accounts receivable - trade
Allowance for doubtful accounts
Balance at beginning of period $ 10.9 $ 15.9
Increase in allowance account attributable to Enron
bankruptcy that was charged to earnings (1) 6.3
Other allowance account amounts charged to earnings (2.3) $ 3.0
Changes in allowance account charged to other balance
sheet accounts (2) 6.5 12.9
Amounts charged against allowance account (0.8) (5.0)
---------------------------
Balance at end of period $ 20.6 $ 10.9 $ 15.9
===========================
Other current assets
Additional credit reserve for Enron (1)
Balance at beginning of period
Increase in credit reserve attributable to Enron
bankruptcy that was charged to earnings $ 4.3
Amounts charged against credit reserve
-------
Balance at end of period $ 4.3
=======
Other current liabilities
Reserve for inventory gains and losses (3)
Balance at beginning of period $ 5.7 $ 2.9 $ 0.8
Reserve increases charged to earnings 0.5 0.5 2.8
Reserve reconciliation adjustment (4) (2.4) (0.8)
Inventory gains (losses) charged to reserve (1.8) 2.3 0.1
---------------------------
Balance at end of period $ 2.0 $ 5.7 $ 2.9
===========================
________________________________________________________________________________
(1) In December 2001, Enron North America (our counterparty to various past
financial instruments) filed for protection under Chapter 11 of the U.S.
Bankruptcy Code. As a result, we established a $10.6 million reserve for amounts
owed to us by Enron. The Enron amounts were unsecured and the amount that we may
ultimately recover, if any, is not presently determinable. Of the $10.6 million
reserve we established, $6.3 million offsets invoices that had been billed to
Enron as of December 31, 2001 with the remaining $4.3 million in a credit
reserve offsetting various unbilled commodity financial instrument positions.
The unbilled amounts are expected to be settled and invoiced during the first
quarter of 2002.
(2) Prior to the TNGL acquisition in 1999, we did not experience any significant
losses from bad debts and therefore did not require an allowance account. As a
result of the TNGL acquisition in August 1999, we acquired a $12.9 million
allowance for doubtful accounts. In April 2001, we acquired an additional $6.5
million allowance for doubtful accounts in connection with the acquisition of
Acadian Gas.
(3) The reserve for inventory gains and losses generally denotes net underground
NGL storage well product losses.
(4) A review of the reserve balance was performed during the fourth quarter of
2001 and based upon its findings and estimated future losses, a reserve balance
of $2.0 million at December 31, 2001 was deemed appropriate..
F-39
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 21, 2002.
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 21, 2002:
Signature Positions held in General Partner
--------- ---------------------------------
/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 Duncan Williams Director
- --------------------------------------
Randa Duncan Williams
/s/ Richard H. Bachmann Executive Vice President, Chief Legal Officer,
- -------------------------------------- Secretary and Director
Richard H. Bachmann
/s/ Michael A. Creel Chief Financial Officer and Executive Vice
- -------------------------------------- President
Michael A. Creel
/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
S-1